Third biennial transmission assessment 2004-2013 |
Previous | 1 of 3 | Next |
|
This page
All
Subset |
Arizona Corporation Commission Docket No. E-00000D-03-0047 Decision No. _______
THIRD BIENNIAL TRANSMISSION ASSESSMENT 2004-2013
November 30, 2004
Prepared by Arizona Corporation Commission Staff and KEMA Inc. 4400 Fair Lakes Court Fairfax, VA 22033
Executive Summary
A.R.S. 40-360.02.E states "The (Ten-Year) plans shall be reviewed biennially by the commission and the commission shall issue a written decision regarding the adequacy of the existing and planned transmission facilities in this state to meet the present and future energy needs of this state in a reliable manner." This Third Biennial Transmission Assessment ("BTA") was undertaken by the Arizona Corporation Commission ("ACC" or "Commission") Staff ("Staff") to fulfill the above stated statutory obligation. The Ten-Year transmission plans filed in January 2003 and 2004 under Docket No. E-00000D-03-0047 are the subject of this assessment. Of particular interest are the many activities related to the collaborative regional planning process. Reliability Must Run ("RMR") studies were submitted in 2003 and 2004 by industry to address concerns identified in Staff's Second BTA and are also the topic of this assessment. Staff's approach in organizing the Third BTA remained the same as for the Second BTA. Staff relied on analyzing the Ten-Year studies, RMR Studies, and other technical reports and documents filed with the Commission by the various organizations rather than performing technical studies of their own. Staff hired a consulting organization, KEMA, to assist in this effort. Staff uses a set of guiding principles to determine whether the Arizona transmission system will be adequate during the next ten-year period. Staff's guiding principles are based upon best engineering practices established in Arizona, coupled with the use of regional and national reliability council criteria and standards, and related state and federal policies. The reliability of an existing or planned electric system under existing, alternative or future operating conditions can only be determined by technical simulation studies, including load flow, stability and short circuit analysis. Such studies require the application of a set of study criteria to measure the system's performance. In assessing the Arizona transmission system adequacy, Staff and KEMA critically reviewed and analyzed the transmission planning documents assembled by Staff and addressed the following questions: 1. Do the proposed Arizona transmission system plans meet the load serving requirements of the state during the 2004-2013 time period in a reliable manner 2. Was the transmission planning process conducted in accordance with the transmission planning principles and good utility practices accepted by the power industry 3. What steps were taken in the new transmission planning studies to effectively address the Commission's concerns raised in the First and Second BTA about the adequacy of the state's transmission system to reliably support the competitive wholesale market emerging in Arizona
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
i
4. Do the generation interconnection practices in Arizona adequately reflect technical aspects of the generation interconnection policies as defined in Federal Energy Regulatory Commission ("FERC") Orders 2003 and 2003-A 5. Do the transmission plans adequately reflect North America Electric Reliability Council's ("NERC") latest activities related to compliance with the transmission planning standards, as well as compliance with Western Electricity Coordinating Council ("WECC") reliability standards This transmission assessment represents the professional opinion of Commission Staff and its Consultant, KEMA. The BTA is not an evaluation of individual transmission provider's facilities or quality of service. This BTA report does not set Commission policy and d es not recommend specific action for o any individual Arizona transmission provider. It assesses the adequacy of Arizona's transmission system to reliably meet existing and future energy needs of the state. This transmission assessment will not become official unless and until it is adopted by Commission Decision. Staff offers the following conclusions for Commission consideration: 1. The electric industry in Arizona has been very responsive to concerns raised in the Commission's Second BTA. 2. Extensive regional studies addressing the interstate transmission needs have been conducted in a collaborative process. 3. Transmission providers have performed reliability-must-run studies for each local transmission import constrained area they serve and have complied with the Second BTA RMR requirements. 4. Numerous new transmission and generation projects have been announced and filed with the Commission since its First and Second BTAs and some of those projects have been constructed. 5. In general, the existing and proposed Arizona transmission system meets the load serving requirements of the state in a reliable manner: a. Many planned Extra High Voltage ("EHV") and High Voltage ("HV") projects will increase transmission system capability to support increased interstate power transfers, and to provide reliable transfers within the state of Arizona. b. The planned EHV system appears to be adequate throughout the study period. As is often the case, plans for the later years of the period are less well defined than those in the early years. Future reports should include more discussion of alternate additions considered for the final five years of the study period. This will allow the Commission and public to be better informed regarding future possibilities.
ii
Executive Summary November 2004
c. The RMR studies show that the RMR areas will have load-serving capacity sufficient to provide reliable supply during the next ten-year period. Problems are identified in the Yuma area in 2004 and Santa Cruz Country area in 2004-2008, but are addressed in the RMR study. The Phoenix area is determined as deficient in local operating reserves in 2013. The Arizona Public Service Company ("APS") and Salt River Project ("SRP") are currently investigating solutions to mitigate this Phoenix area deficiency. d. The RMR studies show no economic justification for additional transmission projects as an alternative to dispatch of local area generation. However, Staff is concerned with some inconsistent data among the utilities and would like increased transparency in energy production modeling, data and assumptions used in economic studies. Major disturbances in the Phoenix area are being addressed by the Commission in a separate proceeding. Utilities serving major Arizona urban areas should assess existing major facilities regarding such extreme multiple contingencies and describe the actions they have taken to address such contingencies. e. The planned Arizona transmission system meets the WECC and NERC single contingency criteria (N-1). f. Since interconnection of merchant plants commenced at the Palo Verde Hub, the Palo Verde east transmission system capability has increased from 3810 MW to 6970 MW as a result of several transmission upgrades. Two new 500 kV transmission line projects within Arizona are proposed as additional reinforcements in 2007 through 2011. The Palo Verde to TS5 to Raceway and Palo Verde to Browning projects will significantly increase the outlet capability of the Palo Verde Hub to Arizona. 6. No transmission improvements have been made to the pre-existing 2800 MW Palo Verde west transmission system capability to delivery power to California. Therefore, transmission from Palo Verde to California is inadequate to allow all new Palo Verde Hub generation full access to the California market. Three 500 kV transmission projects are being studied to remedy such market limitation between Arizona, California and Nevada. 7. There is very little existing long-term firm transmission capacity available to export or import energy over Arizona's transmission system. Studies investigating transmission additions required between Arizona and California and between New Mexico and Arizona continue to explore the scope, participation and timing of alternative projects.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
iii
8. Some new power plants have interconnected to Arizona's bulk transmission system via a single transmission line or tie rather than continuing Arizona's best engineering practices of multiple lines emanating from power plants. As interconnection of new transmission lines are considered for the Palo Verde Hub, they should be encouraged to terminate at these new power plant switchyards in order to mitigate this regional reliability concern. Concerns outlined by Staff in the above conclusions are not easily or quickly resolved. The public's best interest warrants effective and decisive remedies. Therefore, Staff offers the following recommendations for Commission consideration and action: Continue to support use of: a. "Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability" (attached as Appendix A) to aid Staff in its determination of adequacy and reliability of power plant and transmission line projects, b. NERC and WECC criteria and FERC policies for adequacy and reliability assessments of the transmission system, and c. Collaborative planning study forums of transmission providers, merchant plant developers, and other interested parties for the purpose of: 1. Ensuring consumer benefits of generation additions and costeffective transmission enhancements and interconnections. Endorse Staff's recommendation that: a. RMR studies continue to be performed and filed with ten year plans in even numbered years for inclusion in future BTA reports and that: 1. Future RMR studies provide more transparent information on input data and economic dispatch assumptions, and 2. Arizona utilities collaborate with the Staff to develop and effectively implement more stringent criteria as appropriate for RMR areas in the 2006 BTA. b. All future interconnections proposed at the Palo Verde Hub, either new generation or new transmission line, must perform a risk assessment of the Hub to ascertain to what degree the proposed project mitigates the pre-existing risks to extreme outage events. This assessment must precede a project's application for a CEC with the Commission. The recommendations of the Palo Verde Risk Assessment report should b followed if a e proposed project would otherwise exacerbate the existing risk at the Hub.
iv
Executive Summary November 2004
c. The Fourth BTA address and document: 1. Compliance with single contingency criteria overlapped with the bulk power system facilities maintenance (N-1-1) (for the first year of the BTA analysis) as required by WECC and NERC. 2. Extreme contingency outages studied for Arizona's major generation hubs and major transmission stations including identification of associated risks and consequences if mitigating infrastructure improvements are not planned.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
v
Contents
Executive Summary.............................................................................................................................i List of Figures ..................................................................................................................................ix List of Tables ....................................................................................................................................x 1. Overview .....................................................................................................................................1 1.1 Assessment Authority...........................................................................................................1 1.2 Previous Biennial Transmission Assessments - Conclusions and Recommendations ................. 1 1.2.1 First Biennial Transmission Assessment....................................................................1 1.2.2 Second Biennial Transmission Assessment................................................................2 1.3 Third Biennial Assessment - Purpose and Framework ............................................................ 4 1.3.1 Purpose ................................................................................................................... 4 1.3.2 Framework..............................................................................................................5 2. Related Regulatory Activities ........................................................................................................9 2.1 Relevant FERC Orders and Actions, and Arizona Industry Response.......................................9 2.1.1 FERC Activities Following the August 14, 2003 Blackout .......................................... 9 2.1.2 FERC Large Generation Interconnection Standards .................................................. 14 2.1.3 FERC Standard Market Design ............................................................................... 17 2.1.4 Update on the FERC RTO Order 2000 and WestConnect RTO ................................. 19 2.2 Arizona Corporation Commission Actions ........................................................................... 20 2.2.1 Arizona Implementation of Special Reliability Requirements.................................... 20 2.2.2 Electric Re-Structuring Activities............................................................................ 21 2.2.3 2003 Competitive Resources Solicitation ..................... Error! Bookmark not defined. 2.2.4 Commission Concern on Local Area Transmission Constraints and RMR.................. 21 2.2.5 Arizona Electric Utility Reorganizations .................................................................. 22 2.2.6 Arizona Independent Scheduling Administrator ....................................................... 23 2.3 Western Governors Association Efforts ............................................................................... 24 3. Transmission Planning ................................................................................................................ 27 3.1 Transmission Reliability Standards...................................................................................... 27 3.1.1 NERC Reliability Standards.................................................................................... 27 3.1.2 WECC Reliability Standards ................................................................................... 31 3.1.3 Arizona Utilities Transmission Planning Standards................................................... 34 3.1.4 Transmission Ratings ............................................................................................. 35 3.2 Arizona Transmission Planning Processes ........................................................................... 37 3.2.1 Regional Transmission Planning Affecting Arizona.................................................. 37 3.2.2 Arizona Planning Practices for Local Area Transmission Constraints ........................ 44 4. Adequacy of Existing System......................................................................................................47 4.1 System Description ............................................................................................................ 47 4.2 Local Area Transmission Constraints .................................................................................. 51 4.3 Palo Verde Hub Operational Issues ..................................................................................... 51 4.3.1 Palo Verde Hub Transmission Constraints ............................................................... 52 4.3.2 Palo Verde Risk Assessment................................................................................... 54
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
vii
Contents
5. Adequacy of the Future System...................................................................................................61 5.1 Phoenix-Tucson EHV System Assessment........................................................................... 61 5.2 Arizona-California EHV System Assessment....................................................................... 65 5.3 Arizona-New Mexico EHV System Adequacy..................................................................... 67 5.4 Navajo Transmission Project............................................................................................... 69 5.5 Phoenix-Tucson HV system adequacy................................................................................. 71 5.6 Western Arizona HV System Assessment............................................................................ 78 5.7 Conclusions on Adequacy of EHV and HV Arizona Transmission System............................. 78 6. Local-Area Transmission System.................................................................................................79 6.1 Arizona Reliability Must-Run Generation Requirements....................................................... 79 6.1.1 RMR Conditions and Study Methodology................................................................ 80 6.1.2 Summary of the 2003 and 2004 RMR Studies Process.............................................. 84 6.2 Transmission Import Constraint Areas................................................................................. 87 6.2.1 Phoenix Area RMR Conditions and Imports Assessment .......................................... 87 6.2.2 Yuma Area RMR Conditions and Import Assessment............................................... 97 6.2.3 Tucson Area RMR Conditions and Import Assessment........................................... 103 6.2.4 Mohave Area RMR Conditions and Import Assessment.......................................... 108 6.2.5 Santa Cruz County RMR Conditions and Import Assessment.................................. 110 7. Generation Update .................................................................................................................... 113 7.1 Merchant Plant Ten-Year Plans Reported for the Second BTA............................................ 113 7.2 Status of the Merchant Plant Ten-Year Plans Reported in the Second BTA.......................... 114 7.3 Status of Plants Scheduled for Future Years Operation Reported in the Second BTA............ 115 8. Future Generation ..................................................................................................................... 117 8.1.1 2003 and 2004 Generation Interconnection Requests.............................................. 117 9. Conclusions ............................................................................................................................. 121 10. Recommendations .................................................................................................................... 123 APPENDICES ............................................................................................................................... 125 Appendix A: Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability ................................................................................................................................ 127 Appendix B: 2004 BTA Workshop I and II List Attendees ........................................................ 129 Appendix C: Information Resources ......................................................................................... 133 Appendix D: List of new projects and project changes ............................................................... 135
viii
Contents November 2004
Contents
Figures
Figure 1: Total Transfer Capabilities for Key WECC Transmission Paths (2003) ................................. 33 Figure 2: Western Interconnection Paths ........................................................................................... 34 Figure 3: Six Sub-Regional Planning Groups in the WECC................................................................38 Figure 4: Transmission Area of STEP -AC Planning Group.................................................................41 Figure 5 Areas Covered by SWAT Study Groups..............................................................................42 Figure 6: Arizona EHV Transmission System....................................................................................50 Figure 7 Local Area Transmission Constraints .................................................................................. 51 Figure 8: Palo Verde Transmission System........................................................................................52 Figure 9: Generic Model of Hub Concept .......................................................................................... 58 Figure 10: Arizona EHV Transmission Area System and Plans...........................................................62 Figure 11: Arizona-California Area Transmission System .................................................................. 65 Figure 12: Arizona-California Short-Term Transmission Improvements .............................................. 66 Figure 13: Major Arizona-New Mexico EHV Transmission ............................................................... 67 Figure 14: Navajo Transmission Project Concept...............................................................................69 Figure 15: Phoenix-Tucson Area EHV Transmission System..............................................................71 Figure 16: Phoenix Area HV Transmission System............................................................................72 Figure 17: Tucson Area HV Transmission System ............................................................................. 73 Figure 18: 2003 and 2004 RMR Study Framework ............................................................................ 80 Figure 19: RMR Conditions ............................................................................................................. 81 Figure 20: 2004 BTA Arizona Load Pocket Areas ............................................................................. 87 Figure 21: New Projects Strengthening the Phoenix-Area Transmission System .................................. 89 Figure 22: Phoenix Area Reserves .................................................................................................... 94 Figure 23: Phoenix Area Load Serving Capability..............................................................................96 Figure 24: New Projects Strengthening the Yuma Area Transmission System......................................98 Figure 25: Yuma Area Load Serving Capability............................................................................... 103 Figure 26: Addition of New Projects in TEP.................................................................................... 104 Figure 27: Study System for Mohave County .................................................................................. 109
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
ix
Contents
List of Tables
Table 1: NERC Transmission System Standards-Normal and Contingency Conditions ......................... 29 Table 2: WECC Paths in Arizona ...................................................................................................... 34 Table 3: Existing Arizona Power Plants Owned by Arizona Utilities ................................................... 48 Table 4 Merchant Plant Additions in Arizona Since the First Biennial Transmission Assessment.........49 Table 5: New Transmission Lines and Stations Added Since the Second BTA.....................................50 Table 6: Gross Generation Interconnected to the Hub.........................................................................53 Table 7: Palo Verde transmission and generation capability ................................................................ 53 Table 8: Arizona Planned EHV Transmission Additions ..................................................................... 63 Table 9: Long-Range Transmission "Needs" of Parties in the AZ-NM Region ..................................... 68 Table 10: Arizona Planned HV Transmission Additions ..................................................................... 74 Table 11: Summary 2004 RMR Studies Results.................................................................................85 Table 12: Phoenix Area Facilities Additions ...................................................................................... 91 Table 13: Phoenix Area Critical Outages...........................................................................................92 Table 14: Phoenix Area Maximum Load Serving Capability...............................................................93 Table 15: Generating Unit Operational Characteristics ....................................................................... 95 Table 16: Yuma Area Facility Additions ......................................................................................... 100 Table 17: Yuma Area Critical Outages............................................................................................ 101 Table 18: Yuma Area Maximum Load Serving Capability................................................................ 101 Table 19: TEP Area Facility Additions ............................................................................................ 105 Table 20: TEP Area Critical Outages .............................................................................................. 105 Table 21: SIL, MLSC, and Annual Costs for Dispatch to Mitigate RMR Conditions .......................... 107 Table 22: SIL, MLSC, and Annual Costs for Dispatch to Mitigate RMR Conditions .......................... 110 Table 23: SIL, MLSC, and Annual Costs for Dispatch to Mitigate RMR Conditions .......................... 111 Table 24: Generation Projects Proposed for Interconnection in Arizona............................................. 114 Table 25: Status of Generation Plants Scheduled for Future Years .................................................... 115
x
Contents November 2004
1.
1.1
Overview
Assessment Authority
Arizona statutes require every organization contemplating construction of any transmission line within Arizona during a ten-year period to file a ten-year plan with the Arizona Corporation Commission ("ACC or Commission") on or before January 31 of each year.1 In 1999, the Arizona state legislature placed a statutory obligation with the ACC to biennially review the plans filed with the Commission and "issue a written decision regarding the adequacy of the existing and planned transmission facilities in Arizona to meet the present and future energy needs of the state in a reliable manner."2 In 2001, the Arizona legislature further modified the Arizona Power Plant and Transmission Line Siting statutes resulting in two new statutory requirements related to filing of plans with the Commission. Every organization contemplating construction of a new power plant within Arizona is now required to file a plan with the Commission 90 days before filing an application for a Certificate of Environmental Compatibility ("CEC").3 Additionally, all plans filed with the Commission are to be accompanied by power flow and stability analysis reports showing the effect of plant interconnections on the current (and future) Arizona electric transmission system. 4
1.2
1.2.1
Previous Biennial Transmission Assessments - Conclusions and Recommendations
First Biennial Transmission Assessment
The Utilities Division Staff ("Staff") of the ACC initiated its First Biennial Transmission Assessment ("BTA") in 2000, under Docket No. E-00000A-01-0120. The Commission's decision was rendered in July 2001. In its First BTA, the Commission determined that the State of Arizona ("State") transmission system was not adequate5 to provide reliable supply to the State electrical load, neither for the present nor for the future conditions. These conclusions were based upon the following findings 6 :
1 2
A.R.S. 40-360.02.A A.R.S. 40-360.02.G 3 A.R.S. 40-360.02.B 4 A.R.S. 40-360.02.C.7 5 BTA 2002-2011, Page 2 6 BTA 2002-2011, Page 2
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
1
There was very little additional long-term firm regional transmission capacity available to export or import energy over Arizona's transmission system. Southeastern Arizona utilities relied upon restoration of service, rather than continuity of service, following transmission outages due to service via radial transmission lines. There were transmission import constraints for three geographical load zones in Arizona: the Phoenix metropolitan area, Tucson, and Yuma. Planned transmission enhancements failed to resolve this situation in a timely manner. The existing and planned additions to the Palo Verde t ansmission system failed to r accommodate the full output of all new power plants proposing to interconnect at Palo Verde, requiring procedures to be developed for curtailment and scheduling restriction. Some proposed power plants were being interconnected to Arizona's bulk transmission system via a single transmission line or tie rather than continuing Arizona's best engineering practice of multiple lines emanating from power plants.
The Commission adopted the following two concepts for Staff's measurement of Arizona's transmission system adequacy and security: 1. There should be sufficient transmission import capability to reliably serve all loads in a utility's service area without limiting access to more economical or a less polluting remote generation. 2. New power plants must have sufficient interconnected transmission capacity to reliably deliver their full output without use of remedial action schemes or displacing existing generation at the same interconnection for single contingency (N-1) outages.
1.2.2
Second Biennial Transmission Assessment
The Staff initiated its Second BTA in 2002, under Docket No. E-00000A-02-0065. Written decision No. 65476 of that assessment was rendered on December 19, 2002. In its Second BTA, the Commission concluded that the electric i dustry had been very responsive 7 to n concerns raised in its First BTA. The BTA process was built upon an extensive collaborative transmission planning process open to all stakeholders. In addition, some merchant power plant developers had begun proposing transmission system reinforcements to resolve transmission barriers to the wholesale market. Transmission providers had agreed to participate in Reliability-Must-Run ("RMR") study processes for transmission-constrained areas with which they are interconnected. Most
7
BTA 2002-2011, Executive Summary, Page ii
2
Overview November 2004
importantly, numerous new transmission projects had been announced and filed with the Commission since its First BTA. The Commission concluded that the existing and planned Arizona transmission system generally met the load serving requirements of the state in a reliable manner. However, the Commission had several concerns about the adequacy of the state's transmission system to reliably support the competitive wholesale market emerging in Arizona. These concerns included: Limited access by competitive wholesale generators' to local Arizona markets, due to local transmission import constraints, that results in local RMR generation requirements. Failure of planned Palo Verde transmission system additions to accommodate the full output of all new power plants connected at the Palo Verde Hub. Limited additional long-term firm transmission capacity available to export or import energy over Arizona's transmission system. A single transmission line or tie being used to connect some new power plants to Arizona's bulk transmission system rather than continuing Arizona's best engineering practices of multiple connections from power plants.
The above concerns are not easy to resolve. Nevertheless, the Commission approved and ordered in its Decision No. 65476 the following actions: 1. Continue to support use of the "Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability" to aid Staff in its determination of adequacy and reliability of power plant and transmission line projects. 2. Request Staff to commence rule making proceedings to determine how: a. Utility distribution companies ("UDCs") should ensure sufficient transmission import capacity to reliably serve all loads in its service area without limiting access to more economic al or less polluting remote generation 8 , and b. New power plants should demonstrate sufficient transmission capacity exists to reliably and economically deliver their full output without use of remedial action schemes for single contingency (N-1) outages or displacing existing generation at the interconnection.
8
Each utility distribution company also has an obligation to assure that adequate transmission import capability is available to meet the load requirements of all distribution customers in its service area. This requirement is also coupled with a requirement that Arizona utilities competitively procure 100% of their standard offer requirements, with at least 50% procured through competitive bidding. This later requirement was stayed by the Commission in Decision No. 61969, for Staff to determine the proper level of competitive solicitation. Staff used these guiding principles, criteria, standards and rules for this biennial transmission assessment.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
3
3. Encourage transmission providers to continue to investigate and study, in a collaborative fashion, local area import constraints in accordance with the RMR Study Plan outlined in Section 7.2 of the 2002 BTA. 4. Continue to encourage collaborative study activities between transmission providers and merchant plant developers for the purpose of: a. Ensuring consumer benefits of generation additions and costeffective transmission enhancements and interconnections, and b. Facilitating restructuring of the electric utility industry to reliably serve Arizona consumers at just and reasonable rates via a competitive wholesale market.
1.3
1.3.1
Third Biennial Assessment - Purpose and Framework
Purpose
The Commission undertook the Third BTA, which evaluates the Ten-Year transmission plans filed in January 2003 and 2004, under Docket No. E-00000D-03-0047. This report fulfills the Commission's statutory obligation to review these transmission plans and assess whether the Arizona transmission system is adequate. The 2003 and 2004 RMR Studies are also the subject of this 2004 assessment. Of particular interest are the adjustments made by the industry to address the concerns identified in the Commission's First and Second BTAs. Staff hired a consulting organization, KEMA Inc. ("KEMA") to assist Staff in this effort. The adequacy of an existing or planned electric system is determined by technical simulation studies. Such studies require the use of: databases, software and transmissio n planning reliability standards, and planning assumptions. The process assumes that the Arizona transmission utilities conduct their own studies, participate in the collaborative regional planning process, and present the study results in the TenYear Plan reports and at public workshops. Staff and KEMA reviewed and analyzed all these study reports assembled by Staff, and organized two workshops. Staff relied on the technical reports and documents filed with the Commission by the various organizations, rather than performing technical studies of their own. Staff used a set of guiding principles to aid it in determining the adequacy and reliability of both transmission and generation systems.9 Staff's guiding principles are based upon best engineering practices established in Arizona coupled with the use of Western Electricity Coordinating Council
9
Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability: Appendix A Arizona's Best Engineering Practices, Jerry D. Smith, ACC, pre -filed comments for the Gila Bend Power Plant Hearing, Docket No. E-00000V-00-0106, November 9, 2000
4
Overview November 2004
("WECC")1 0 and North American Electric Reliability Council ("NERC")1 1 planning standards. Staff and KEMA critically reviewed and analyzed the transmission planning documents assembled by Staff and addressed the following questions: 1. Do the proposed Arizona transmission system plans meet the load serving requirements of the state during the 2004-2013 period, in a reliable manner 2. Was the transmission planning process conducted in accordance with the transmission planning principles and good utility practices accepted by the power industry 3. What steps were taken in the new transmission planning studies to effectively address the Commission's concerns raised in the First and Second BTA about the adequacy of the state's transmission system to reliably support the competitive wholesale market emerging in Arizona 4. Do the generation interconnection practices in Arizona adequately reflect technical aspects of the generation interconnection policies as defined in the Federal Energy Regulatory Commission ("FERC") Orders 2003 and 2003-A 5. Do the transmission plans adequately reflect NERC's latest activities related to compliance with the transmission planning standards, as well as compliance with WECC reliability standards
1.3.2
Framework
Staff and KEMA made use of a three-stage process to facilitate the electric industry's participation in the third BTA: 1. Workshop I: Industry Presentation;
2. Preparation of Initial Draft Report and Industry Comments on Draft; and 3. Workshop II: Staff/KEMA Presentation and Final Report.
An overview of each stage is described below. Stage 1. Workshop I: Industry Presentation
Staff and KEMA organized and facilitated a one-day public Workshop on June 30, 2004. Transmission Providers and Regional Planning Groups presented information regarding their transmission expansion plans and related activities to supply native load customers for the next ten years. In addition, merchant transmission and wind generator d velopers reported on their development plans.1 2 The Workshop e
10 11
http://www.wecc.biz/documents/standards/for_approval/2002JulyBODStandards.htm http://www.nerc.com/~filez/pss-psg.html 12 The Workshop presentation materials are located on the ACC website: http://www.cc.state.az.us
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
5
provided an informal setting to promote effective discussions of the presentations from transmission providers and merchant plant developers. The Workshop I participants 1 3 included: Arizona Transmission Providers Merchant Transmission and Generation Developers Arizona Power Plant and Transmission Line Siting Committee ("Siting Committee) Members Consumer Advocates Individual Interested Parties.1 4
The workshop was organized in to four panels--one for each topic. An open period of discussion and audience questions followed each panel presentation. To facilitate focused and meaningful presentations and discussions at the Workshop, Staff requested the participants to discuss four topics. 1. Regional planning updates provided by: Seams Steering Group-Western Interconnection("SSG-WI") Planning Group Southwest Transmission Expansion Plan ("STEP") Southwest Area Transmission ("SWAT") Planning Group
2. Utilities' Updates concerning Ten-Year Transmission Plans, providing details on transmission additions/upgrades/revisions since the Second Biennial Transmission Assessment: Arizona Public Service Company ("APS") Salt River Project ("SRP") Southwest Transmission Cooperative ("SWTC") Tucson Electric Power ("TEP") / UniSource Energy Services ("UES") Western Area Power Administration ("WAPA") Interstate Transmission Projects Located in Arizona
3. Developments at the Palo Verde Hub: Risk Assessment and WECC Catastrophic Outage Guide, presented by Staff Disturbances that occurred on July 28, 2003 and June 14, 2004 Experience of Palo Verde Hub interconnected generation plants
13 14
The list of Workshop I participants is included in Appendix B. The Workshop presentation materials are located on the ACC website: http://www.cc.state.az.us
6
Overview November 2004
4. National and Regional Transmission Issues including: WestConnect/WesTTrans update August 14, 2003 Eastern U.S. blackout implications for Arizona utilities Right of way ("ROW") vegetation management and bark beetle infestation mitigation Federal reliability legislation FERC large generator interconnection rule impacts Technical transmission challenges re: interconnection of renewable generation
In addition to the four panels, the Staff presented their response to the 2004 RMR Study Results. Staff's opinion is that the Transmission Providers presented enough information to allow a suitable assessment of the status of Arizona's transmission system reliability. Stage 2. Preparation of initial draft report and industry comments on draft Staff and KEMA provided the first draft of the 2004 BTA report for industry review and comment. The first draft of the report was based on the utilities' filed plans and the participants' responses to questions raised at Workshop I. 1 5 The draft report and industry comments were placed on the Commission website to expedite the review process. Stage 3. Workshop II: Staff/KEMA presentation and final report Workshop II, organized on September 24, 2004, presented the Staff's response to industry comments on the first draft of the 2004 BTA Report and allowed for discussion and questions. The Workshop again provided an informal setting to promote effective discussions of the p esentations from transmission r providers and merchant plant developers. The Workshop II participants included: 16 Arizona Transmission Providers Merchant Transmission and Generation Developers Siting Committee Members Consumer Advocates Service List Members.1 7
15 16
Transcripts of June 30, 2004 Workshop I The lis t of Workshop II participants is included in Appendix B. 17 The Workshop presentation materials are located on the ACC website: http://www.cc.state.az.us
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
7
The workshop was organized in one main session followed by an open period of discussion and audience questions. To facilitate focused and meaningful presentations and discussions at the Workshop, Staff provided a copy of the draft report several weeks before the Workshop. The Staff and their consultant presented 5 major issues and 6 less significant issues for discussion. The 5 major issues were: 1. Near-term Palo Verde transmission's ability to handle full generation output as discussed on draft BTA, page 3; 2. A similar issue discussed on draft BTA, page 57; 3. How the Arizona system meets the "n-1" criteria and relationship to RMR studies as discussed on draft BTA, page 3; 4. The economic viability of generators at the Palo Verde Hub as discussed on draft BTA, page 57; and 5. The responsibility of generators in regard to transmission expansion as discussed on draft BTA, page 3. The 6 less significant issues were: 1. Specific wording regarding the RMR studies discussed on draft BTA, page 3; 2. Consistency in data used in the RMR studies as discussed on draft BTA, page 49; 3. What party should maintain a study database as discussed on draft BTA, page 19; 4. Inconsistent and inaccurate generation data in Table 15 as discussed on draft BTA, page 96; 5. The need for new capacity in the Phoenix area by 2012 in regard to RMR studies as discussed on draft BTA, page 97; and 6. The treatment of the costs assigned to un-served energy in the RMR studies as discussed on draft BTA, page 97. In addition, there was a presentation by SRP regarding the installed generation and transmission capacity at the Palo Verde Hub during the 2000-2010 period. All the issues presented were resolved successfully as a result of the Workshop discussions and are reflected in this final report.
8
Overview November 2004
2.
Related Regulatory Activities
This section describes selected regulatory and industry activities since the 2002 BTA. Only those activities related to transmission infrastructure, transmission grid expansion at regional and sub-regional levels, transmission congestion, transmission reliability, and transmission rights and pricing are described. This section considers how such activities relate to the transmission expansion, siting and analysis in Arizona.
2.1
2.1.1
Relevant FERC Orders and Actions, and Arizona Industry Response
FERC Activities Following the August 14, 2003 Blackout
On August 14, 2003, an electric power blackout occurred that affected large portions of the Northeast and Midwest United States and Ontario, Canada. The following day, a U.S.-Canada Power System Outage Task Force ("Task Force") was established to investigate the causes of the blackout and recommend measures to reduce the possibility of future outages. The Final Report of this Task Force (April 5, 2004) identified four categories of causes: 1. Inadequate system understanding; 2. Inadequate situational awareness; 3. Inadequate tree trimming; and 4. Inadequate reliability coordinator diagnostic support Although none of the categories related to transmission planning issues, the Final Report found that several entities violated NERC operating policies and planning standards, directly contributing to the blackout. The Final Report found that many of NERC's policies are unclear and ambiguous. In addition the task force report found that tree contact with transmission lines was a precipitating factor in the blackout. The FERC took prompt action in response to recommendations issued by the Task Force by clarifying its power grid reliability policies and objectives. In a related order, FERC directed transmission-operating utilities to report on vegetation management practices in transmission corridors.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
9
2.1.1.1
FERC Policy Statement on Bulk Power System Reliability
FERC issued a Policy Statement on Matters Related to Bulk Power System Reliability. 1 8 (Issued April 19, 2004). This policy statement responded to recommendations in the U.S.-Canada Power System Outage Task Force's Interim and Final Blackout Reports on initiatives FERC should undertake. It also responded to comments submitted after FERC's December 1, 2003 public conference on actions it should take to promote reliable transmission service in interstate commerce. The Policy Statement clarified FERC's policy with regard to: The need to promptly modify existing bulk power system reliability standards, to translate them into clear and enforceable requirements. Public utility compliance with industry reliability standards and possible FERC action to address specific bulk power system reliability issues. Cost recovery of prudent bulk power system reliability expenditures. The need for communication and cooperation between FERC and the States. The need for communication and cooperation among FERC, Canada and Mexico regarding reliability issues. Consideration of reliability in FERC's decision-making. Limitations on utility liability.
The Policy Statement immediately took the following steps: No new Independent System Operator (ISO) or Regional Transmission Operator (RTO) will be allowed to begin operations until its reliability capabilities are functional. FERC will consider the reliability implications of its decisions, as appropriate. FERC will appoint a staff task force to report on potential funding mechanisms for NERC and the regional reliability councils to ensure their independence from the utilities they monitor. The staff task force will work closely with FERC's Canadian counterparts, state regulatory authorities, NERC, regional reliability councils and the industry. FERC staff was directed to draft a memorandum of understanding ("MOU") defining NERC's working relationship with FERC. The MOU will clarify FERC's appropriate role in NERC oversight and the respective reliability responsibilities of both NERC and FERC.
18
FERC DOCKET No. PL04-5-000 Policy Statement on Matters Related to Power System Reliability http://www.ferc.gov/whats-new/comm-meet/041404/E-6.pdf
10
Regulatory Activities November 2004
2.1.1.2
FERC Order on Vegetation Management Practices
FERC also issued a companion vegetation management order.1 9 (issued April 19, 2004) FERC sought to minimize the risk of another regional blackout and ordered all entities that own, operate or control designated transmission facilities to report on their vegetation management practices by June 17, 2004. The Order, applicable to the lower 48 states, was directed to approximately 200 transmission providers, regardless of whether they are subject to FERC's jurisdiction as a public utility, in accordance with FERC's reporting authority. Designated transmission facilities are power lines of 230 kV or higher as well as tie -line interconnection facilities between control areas or balancing authority areas (regardless of voltage rating) and "critical" lines as previously designated by a regional reliability council. The Order directed the transmission providers to: Describe in detail the vegetation management practices and standards that the provider uses for vegetation control near designated transmission facilities; List those designated facilities under the provider's control; Indicate how often the facilities are inspected for vegetation management purposes and indicate when the most recent survey was completed; Indicate whether any necessary remediation has been completed as of June 14, 2004; and Describe any factors that prevent or unduly delay adequate vegetation management.
FERC directed that the reports also must be submitted to appropriate state regulatory commissions, NERC and the relevant reliability coordinators: "In order that this information be received before the summer peak load season, which typically has maximum transmission line loading and continued vegetation growth, this report should be submitted by June 17, 2004 to the Commission, the appropriate State commissions2 0 , the North American Electric Reliability Council ("NERC") and the relevant reliability authorities."2 1
19
FERC Docket No. EL04-52-000 Reporting by Transmission Providers on Vegetation Management Practices Related to Designated Transmission Facilities http://www.ferc.gov/whats-new/comm-meet/041404/E-7.pdf
20
Some transmission providers are not subject to the jurisdiction of a State Commission. We request, however, that they serve a copy of the report on all State Commissions for States in which their transmission facilities are located.
21
FERC Order Requiring Reporting by Transmission Providers on Vegetation Management Practices Related To Designated Transmission Facilities, 107 FERC 61,053, Page 1-2. A reliability authority is the entity responsible for the safe and reliable operation of the interconnected transmission system for its defined "reliability authority area." This term is replacing the term "reliability coordinator" which has the same meaning and is still in common use in many areas. The term reliability authority as used in this order refers to the corporate entity responsible for reliability, which may be called either the reliability authority or the reliability coordinator for its area.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
11
The ACC received the vegetation management reports from Arizona utilities as required2 2 . Arizona is commonly thought of as a desert that does not require vegetation management. This is incorrect. For example, Salt River Project ("SRP") alone has over eight million trees to maintain in and around its utility corridors. Vegetation management in Arizona is complicated by the involvement of federal agencies. In Arizona there are five National Forests, and 22 Forest Service districts, for which Federal authorities dictate to the utility how much clearance they can or cannot give around utility lines and when they can have right of way access for such activities. Numerous forest fires in Arizona and New Mexico have placed multiple transmission lines in operational jeopardy over the past five years due to inadequate vegetation management of transmission corridors. Therefore, the ACC, and other entities involved in requiring reliable service of transmission providers need to assure vegetation management receives proper and consistent attention irrespective of land ownership. FERC's September 7, 2004 report 2 3 to Congress summarizes its findings and recommendations. In this report, the FERC also recommended that Congress enact legislation providing for mandatory, enforceable reliability rules. The FERC recognized that, while the data filed in response to the Vegetation Management Order revealed each transmission owner's practice, it did not directly address how effective the practice has been in limiting preventable transmission line outages. The FERC did not ask for such data in the April request, because similar data are now being reported to the WECC and to NERC. Transmission owners reported that they were not able to acquire all necessary permits to maintain their rights-of-way from various federal and state agencies. The transmission owners reported that vegetation management approvals on federally managed rights-of-way are particula rly problematic in the Western United States. However, FERC stated that this problem could be alleviated, at least in part, if the acquisition of these permits is made a higher priority on the part of transmission owners. For instance, transmission owners could allow additional lead-time to acquire many needed permits. The agencies responsible for issuing permits, however, should ensure that they have clear rules and procedures for issuing permits in a timely manner. The FERC believes that better coordination among federal agencies and between the federal and state governments to develop clear, consistent policies and procedures for timely and effective vegetation management by transmission owners could help to alleviate many real and perceived obstacles to proper vegetation management.
22 23
These reports are available on FERC's website.
Utility Vegetation Management and Bulk Electric Reliability Report from the Federal Energy Regulatory Commission, September 7, 2004. FERC reported that Tucson Electric Power Co. did not perform all identified vegetation management remediation by the June 14, 2004 reporting date. Upon further review of the data submitted by TEP to FERC and the ACC and comments relative to the draft BTA Staff has determined that TEP had performed vegetation management remediation required for reliable operation of their system through the summer of 2004 and had delayed some additional vegetation management of a non-critical nature until the winter season..
12
Regulatory Activities November 2004
Summary of FERC's Recommendations
1. 2. The United States Congress should enact legislation to make reliability standards mandatory and enforceable under federal oversight. Effective transmission vegetation management requires clear, unambiguous, enforceable standards that adequately describe actions necessary by each responsible party. With respect to any jurisdictional issue that may arise involving vegetation management, it is important that state and federal regulators continue to coordinate so that jurisdictional considerations do not impede effective vegetation management. Federal and state regulators should allow reasonable recovery for the costs of vegetation management expenses. While permitting and environmental requirements properly protect public lands, the procedures implementing those protections may be inconsistent and timeconsuming and have the potential to significantly hinder transmission vegetation management. The FERC should work with the Council on Environmental Quality ("CEQ") and land management agencies to better coordinate these requirements. Federal, state and local land managers should develop "rush" procedures and emergency exemptions to allow utilities to correct "danger" trees2 4 that threaten transmission lines, from both on and off documented rights-of-way. Five-year vegetation management cycles should be shortened, and the FERC and states should look at the cost-effectiveness of more aggressive vegetation management practices. Transmission owners should fully exercise their easement rights for vegetation management and better anticipate and manage the permitting process for scheduled vegetation management. Variances in vegetation management practices may be resolved in the NERC vegetation management standard development process; if they are not, the FERC may seek to convene the industry, states and other stakeholders to address the remaining issues. State regulators and the utility industry should work through the National Association of Regulatory Utility Commissions ("NARUC"), the National
3.
4. 5.
6.
7.
8.
9.
10.
24
A danger tree is a tree that is dead or dying and has the potential to fall into a right-of-way close to a line.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
13
Conference of State Legislators, and other organizations to help state and local officials better understand and address transmission vegetation management.
2.1.2
FERC Large Generation Interconnection Standards
On July 24, 2003, FERC issued Order 2003, Standardization of Generator Interconnection Agreements and Procedures.2 5 The Final Rule became effective on October 20, 2003. The FERC adopted this rule to be used by Transmission Providers with Interconnection Customers proposing to interconnect a generator of more than 20 MW. The FERC initially required that all transmission providers amend their Open Access Transmission Tariffs ("OATT") with the new standards by the end of October 2003. However, the October deadline was extended until January 20, 2004.
Summary of Final Rule
The final rule is composed of two parts: 1. Standard Large Generator Interconnection Procedures ("Final Rule LGIP") sets forth the procedures that Interconnection Customers and Transmission Providers are required to follow during the interconnection process. The Final Rule LGIP sets forth the legal rights and obligations of each party, addresses cost responsibility issues, and establishes a process for resolving disputes; and 2. Standard Large Generator Interconnection Agreement ("Final Rule LGIA") applies to any new Interconnection Request to a Transmission Provider's Transmission System. New Interconnection Requests include those submitted after the effective date of this Final Rule and include requests to increase the capacity of, or modify the operating characteristics of, an existing Generating Facility that is interconnected with the Transmission Provider's Transmission System. The FERC is not requiring any retroactive changes to individual (versus generic) interconnection agreements filed with the FERC prior to the effective date of this Final Rule.2 6
In its March 3, 2004 Order No. 2003-A, FERC reaffirmed its July 2003 rule ("Order 2003").2 7 Responding to requests for clarification of its pricing policy for network upgrades, FERC made it clear that the transmission provider continues to have the option to charge the interconnected customer a transmission rate that is the higher of the incremental cost rate for the network upgrades required to
25
FERC Docket No. RM02-1-000; Order No. 2003, Standardization of Generator Interconnection Agreements and Procedures, (Issued July 24, 2003) http://www.ferc.gov/whats-new/comm-meet/072303/E-1.pdf
26 27
Docket No. RM02-1-000, Order 2003, July 24, 2003, Page 2
FERC Docket No. RM02-1-001; Order No. 2003-A, Standardization of Generator Interconnection Agreements and Procedures, (Issued March 3, 2004) http://www.ferc.gov/whats -new/comm- meet/030304/E- 1.pdf
14
Regulatory Activities November 2004
interconnect its generating facility or the average embedded cost rate for the entire transmission system (including the cost of the network upgrades). FERC emphasized that allowing transmission providers to charge the "higher of" rate ensures that other transmission customers, including the transmission providers' native load, will not subsidize network upgrades required to interconnect merchant generation. FERC granted rehearing on two aspects of Order 2003's method for reimbursing generators for the cost of financing network upgrades needed to complete the interconnection: 1. They will no longer require the transmission provider to provide credits to the interconnection customers for all of the transmission delivery services it takes on the system; instead credits are provided only for the transmission delivery service taken by the interconnecting generating facility. 2. They will allow the transmission provider to choose, five years from the commercial operation date of the generating facility, whether to reimburse the interconnection customer at that time for any remaining balance of the cost of financing network upgrades and accrued interest, or continue to provide credits beyond five years until no balance remains.
FERC also concluded, as it did in Order 2003, that it would allow additional flexibility to interconnection pricing proposals that are filed by an independent transmission provider. An independent transmission provider does not have an incentive to discourage new generation by competitors, and should be afforded more flexibility in manner of cost recovery. Consequently, an independent transmission provider has no obligation to reimburse generators for the financing of the network upgrades, but rather has an opportunity to offer transmission rights and financial products instead. The new Generation Interconnection Standards establishes two types of interconnection: Energy Resource Interconnection Service that allows the Interconnection Customer to connect the Large Generating Facility to the Transmission System and be eligible to deliver the Large Generating Facility's output using the existing firm or non-firm capacity of the Transmission System on an "as available" basis. The interconnecting generator must make a separate application for transmission service with the Transmission Provider for transmission service. Energy Resource Interconnection Service does not provide any rights for transmission service. This type of interconnection usually requires minimal network upgrades if any. Network Resource Interconnection Service requires the Transmission Provider to conduct the necessary studies and construct the Network Upgrades needed to integrate the Large Generating Facility: (1) in a manner comparable to that in which the Transmission Provider integrates its generating facilities to serve native load customers; or (2) in an Independent System Operator ("ISO") or Regional Transmission Organization ("RTO") with market based congestion management, in the same manner as all Network
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
15
Resources. Network Resource Interconnection Service does not provide any rights for transmission service; however, it does qualify the resource to serve network customer load using the transmission system. An Energy Resource type of interconnection adopts the "minimum interconnection standard" that FERC established via numerous precedents to Orders 2003 and 2003-A. This type of interconnection usually does not require any network upgrades. Interconnecting a new generator at a substation that does not have sufficient transmission capacity to deliver the generator's full output for all load conditions and transmission system topologies, creates a generation pocket. This could require reducing the generator's output or automatic unit tripping. The Arizona utilities' presentations at Workshop I provided useful information on generation interconnection requests in Arizona.2 8 Each transmission provider maintains its own generation interconnection queue, and keeps it publicly available at the utility page of the WesTTrans.net Open Access Same-time Information System ("OASIS") website.2 9 For jointly owned facilities the operating agent takes the lead in the study work and shares results with the other owners. The Palo Verde transmission system has an interconnection procedure explicitly describing the steps required for generation interconnection with the hub. In the Palo Verde Hub case, there is also an ad hoc group, which looks at those impacts. While this procedure complies with FERC Orders 2003 and 2003A, it would be valuable, from the Arizona resource planning perspective, that an organization such as SWAT maintains an integrated generation interconnection queue for the whole state. This integrated list would not have any legal implication on execution of the required studies or interconnection agreements, but would provide a quick insight on generators' overall interest to interconnect in Arizona. With regards to generation interconnection in Arizona, an additional problem is driven by the fact that many transmission lines are jointly owned by jurisdictional and non-jurisdictional entities. When this issue was raised before FERC, jurisdictional transmission providers, in cooperation with the nonjurisdictional entities, were instructed to propose changes to the ir joint participation agreements. Nonjurisdictional transmission entities may not pay transmission credits in the exact way jurisdictional entities must. Non-jurisdictional utilities with Safe Harbor Open Access Transmission Tariffs ("OATTs"), such as SRP, WAPA and SWTC, are required to charge rates for interconnections that are comparable to what such non-jurisdictional transmission entities charge their own or affilia ted generation for interconnection.
28 29
Workshop I Transcript, Page 167, Lines 17-25, and Page 168, line 1-6 The wesTTrans.net OASIS http://www.oatioasis.com/cwo_default.htm
16
Regulatory Activities November 2004
Western utilities, including Arizona's, filed proposed variations from the pro forma LGIP and LGIA. The utilities stated that the proposed variations were based on existing regional reliability standards applicable to WECC, the Northwest Power Pool ("NWPP"), and the Southwest Reserve Sharing Group ("SRSG"). In its June 4, 2004 Order, FERC accepted in part, rejected in part, and modified in part, the proposed regional reliability variations. 3 0 It appears that FERC approved all significant reliabilitystandard related requirements.
2.1.3
FERC Standard Market Design
As noted in the 2002 BTA Assessment, FERC proposed a Standard Market Design ("SMD"). The purpose of the SMD was to have all regions of the US implement standardized wholesale power markets. FERC originally anticipated that a final SMD rule would be approved in 2003. However, due to the objections of numerous stakeholders, state regulators and Congressional delegations, FERC has not acted to finalize the rule. FERC issued a White Paper entitled "Wholesale Power Market Platform" responding to the comments on FERC's SMD proposal and providing direction for the final rule.3 1 The White Paper focuses on the formation of RTOs, and on sound wholesale market rules for all independent transmission organizations. Additionally, the White Paper indicates that the final rule will allow variable implementation schedules, depending on local needs. According to the White Paper, the final ruling will focus on: The formation of RTOs; and Ensuring that all RTOs and ISOs have good wholesale market rules in place.
The final rule will require public utilities to join an RTO or ISO. The final rule will also allow for phased-in implementation customized to each region. FERC states that certain elements need to be in place for successful wholesale markets: Regional Transmission Planning Process FERC maintains that regional planning of the transmission grid is essential. The Final Rule will require technical assessments of the regional grid by the RTO or ISO. FERC expects the Final Rule to require the RTOs and ISOs to have a regional planning process in place as soon as possible. Fair Cost Allocation for Existing and New Transmission Costs associated with the existing grid (other than those directly assigned) will continue to be recovered though rates. The rates should be structured to allow customer access across multiple utility
30 31
http://www.ferc.gov/EventCalendar/Files/20040607074124-ER04-442-000.pdf
FERC White Paper: Wholesale Power Market Platform, (Issued April 28, 2003) http://www.ferc.gov/industries/electric/indus-act/smd/white_paper.pdf
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
17
grids in a region at a single rate. Regional state committees may agree on the form of access charge that will be filed by the RTO or ISO. Market Monitoring and Market Power Mitigation FERC intends to look closely at mitigation proposals to assure suitability for the RTO's or ISO's regional markets and for their compatibility with neighboring RTOs and ISOs. Spot Markets to Meet Customers' Real-Time Energy Needs Under the Final Rule, the RTO or ISO will be constrained to use a real-time market for energy to resolve imbalances. The RTO or ISO in each region will be required to develop detailed market rules that will be included in the tariffs filed with FERC. Additionally, the RTO or ISO will be required to introduce a day-ahead market and a market for various ancillary services. Transparency and Efficiency in Congestion Management Regions will be required to develop a congestion-management approach that will protect against manipulation, will use the grid efficiently, and will promote use of the lowest cost generation. Firm Transmission Rights ("FTRs") Those RTOs and ISOs that use location marginal pricing to manage congestion will be required to make firm physical transmission service available to customers. In the Final Rule, RTOs or ISOs that have not addressed FTRs will be required to do so. Resource Adequacy Approaches In the Final Rule, each region with an RTO or ISO will determine how it will ensure that there are adequate regional resources to meet customers' needs.
Regional Independent Grid Operation RTOs must meet the four minimum characteristics of independence, scope and regional configuration, operational authority, and short-term reliability. FERC notes that the lack of independence provides an incentive for those who own generation and operate transmission facilities to operate the system in ways that exclude competing suppliers and can allow the exercise of market power. This conflict of interest can be remedied through structural separation of transmission operation from other wholesale market activities. FERC states that regional operation is crucial to reliability and efficiency. The final rule will allow flexibility on the scope and configuration of RTOs and ISOs, and will not require ISOs to meet the scope and regional configuration requirement. However, interregional coordination between RTOs and ISOs must be actively pursued.
18
Regulatory Activities November 2004
2.1.4
Update on the FERC RTO Order 2000 and WestConnect RTO
FERC's Order 2000 presents FERC's desire for RTOs across the continental United States.3 2 ISOs and RTOs have in fact been implemented in the Northeast part of the country ("PJM", "NY-ISO", "ISO-NE"), the Midwest region ("MISO"), and in California ("CAISO"). FERC's April 28, 2003 FERC White Paper emphasized their strong commitment to customer-based, competitive wholesale power markets, while underscoring an increasingly flexible approach to regional needs and outlining step-by-step elaborations of its key market design proposal. In its final rule, the White Paper said FERC would focus on the formation of RTOs and on ensuring that all independent transmission organizations have sound wholesale market rules. The final rule would allow implementation schedules to vary depending on local needs, and would allow for regional differences. The White Paper notes that FERC's proposal has taken into consideration the experiences in this country and abroad in electric market design, including the effects of supply shortages, demand that does not respond to high prices, lack of price transparency in the marketplace, and the importance of market monitoring and market power mitigation. In September 2001, Arizona Public Service Company, El Paso Electric Company, Public Service Company of New Mexico and Tucson Electric Power Company filed with FERC a Request for Declaratory Order that the proposed WestConnect RTO, developed through an open, participatory process that included, among others, Salt River Project and Western Area Power Administration, met the requirements of Order 2000. FERC issued a Declaratory Order on WestConnect in October 2002, conditionally accepting the filing. However, in its Declaratory Order and subsequent Order on Rehearing, FERC removed some of the transmission owners' "must have" features and called into question the ultimate acceptability of others. In response to FERC's orders on the WestConnect RTO filing and the FERC SMD White Paper, issued April 2003, Southwest transmission owners, including investor-owned and non-jurisdictional utilities, decided to pursue development of a phased approach for the incremental and cost-effective implementation of wholesale transmission market improvements in the Southwest region that bring identified benefits to transmission customers. One of the significant steps in WestConnect's phasing was partnering with other western utilities, including a number of non-jurisdictional transmission owners, to implement WesTTrans.net. WesTTrans.net is a common OASIS platform operated by a third party that is open to participation by all transmission providers in the Western Interconnection. The wesTTrans.net OASIS platform went on-line in March 2004 and now has 20 participating transmission owners. WestConnect parties are working on steps to augment regional market interface and increase transmission market transparency. It will continue to work with stakeholders to identify additional cost-effective solutions to existing transmission market challenges that will benefit transmission customers.
32
FERC Order 2000, http://www.ferc.gov/legal/ferc -regs/land-docs/RM99 - 2A.pdf
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
19
2.2
2.2.1
Arizona Corporation Commission Actions
Arizona Implementation of Special Reliability Requirements
In order to obtain ACC Staff support for approval of applications for Certificate of Environmental Compatibility ("CEC"), new generators in Arizona cannot rely on generator unit tripping for a single transmission facility outage.3 3 Staff's position is based on a principle that requires that adequate transmission is planned to assure reliable service of the full output of all interconnected generation without having to implement congestion management for single contingency transmission outages. In other words, Arizona wants energy from new generation to be firm rather than offered on an "as available basis." This would imply Arizona's preference for generation with Network Resource Interconnection Service as defined by FERC. The Commission has endorsed Staff's position that generators and load serving entities share the obligation to ensure adequate and reliable transmission service in Arizona.3 4 Consequently, new generators are required before commencing commercial operation to demonstrate adequate transmission delivery without relying on remedial action such as generator tripping, load shedding or remedial action schemes for single contingency transmission outages. Some of the new generation interconnections at the Palo Verde Hub have failed to adhere to this planning philosophy and therefore lack adequate near-term transmission capacity to deliver to some markets. By interconnecting via single transmission lines to the Palo Verde Hub these generation projects have also jeopardized the regional system reliability and supply for extreme outage contingencies. This practice also limits Arizona load serving entities' purchase of firm capacity from such units unless they are willing to raise their own system reserve requirements for loss of these units as their largest single hazard. The recent practice of electronic tagging ("E-tag") such merchants' unit contingent power as a firm transmission transaction has also just recently become an issue for the WECC Operating Committee. For the above reasons, Staff joined APS and SRP in sponsoring a new WECC planning guideline for consideration of extreme contingencies at large generation hubs. The guideline has gone through the WECC comment period and is not being pursued further due to lack of industry support. Nevertheless, Staff, APS and SRP have committed to implementing such guidelines in Arizona irrespective of WECC inaction. 3 5 In addition, Staff has been actively discussing with FERC Staff the need for a more balanced approach to considering reliability versus commercial practices both in a planning context and an operational context.
33
Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability See Appendix A, Generation, Under 1 34 Second BTA, Decision No. 65476. 35 Palo Verde to Southwest Valley (RUDD) 500 kV Line, Docket No. L-00000D-01-0115, Condition No. 23.
20
Regulatory Activities November 2004
2.2.2
Electric Re-Structuring Activities
The Commission issued a procedural order on January 22, 2002, which opened a generic docket on electric restructuring. 3 6 A subsequent procedural order issued on February 8, 2002, served the purpose of consolidating the generic docket with the following related cases already active before the Commission: Docket No. E-01345A-01-0822, APS variance request to A.A.C. R14-2-1606 Docket No. E-01933A-02-0069, TEP variance request to certain competition rule compliance dates Docket No. E-01933A-98-0471, TEP application for approval of its stranded cost recovery Docket No. E-00000A-01-0630, Proceedings concerning the Arizona Independent Scheduling Administrator ("AzISA") Docket No. E-00000A-02-0051-ETAL Decision No. 65154 Track A Proceedings Decision No. 65143 Track B Proceedings
The Track A proceeding concluded with a decision rendered by the Commission on September 10, 2002. 3 7 The opinion and order approved by the Commission was in general agreement with Staff's recommendations on transmission issues and encouraged an industry-wide planning process to resolve transmission constraints. 3 8 The Commission also believed that both transmission providers and merchant power plants should share the burden and obligation to resolve Arizona's transmission constraints. The FERC Order 2003 from July 2003 and 2003 A from March 2004 set up the clear rules on cost allocation and crediting policy related to the transmission upgrades now required for the new generators. At the Track A hearing, APS agreed that all generators designated as network resources, including both utility and merchant generators, would have access to transmission currently used by the utilities to serve their native load customers. There was also testimony establishing that existing transmission constraints in Arizona will limit APS' (and TEP's) ability to deliver competitively procured supply to less than the required 50% of Standard Offer Service load.
2.2.3
Commission Concern on Local Area Transmission Constraints and RMR
The transmission constraints limiting APS' and TEP's ability to comply with the aforementioned Commission rules result from their dependence upon local RMR generation to serve their peak load
36 37 38
ACC Staff Report on the Generic Electric Restructuring, Docket No. E-00000A-02-0051, March 22, 2002 Decision No. 65154, Docket No. E-00000A-02-0051, et al., September 10, 2002. Ibid, page 25 at line 23.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
21
during certain hours of the year. RMR needs result from an economic decision to balance local generation and transmission capabilities to serve loads in the most economical manner. The Track A order stipulates that APS and TEP are to work with Staff to develop a 2002 study process to resolve RMR generation concerns and that such study plan results are to be included in the 2004 Biennial Transmission Assessment.3 9 This includes studying and analyzing the merits of existing dependence on RMR generation instead of building transmission to resolve transmission import constraints, and the merits of any future contemplated utilization of RMR to defer transmission projects. Until the 2004 Biennial Transmission Assessment is issued with RMR study plan results resolved, APS and TEP are to file annual RMR study reports with the Commission in concert with their January 31 annual ten-year plan for review prior to implementing any new RMR generation strategies.4 0 The 2003 and 2004 RMR procedural overview, defined through the ACC Track A Decision No. 65154, required that RMR studies be filed by APS and TEP (with the cooperation of the industry) by January of 2003. These studies were to analyze the 2003 2005 time-period. By January of 2004, APS and TEP were to complete their study efforts extending the time frame out for the 10-year period. Results of both RMR study efforts have been incorporated into the 2004 BTA report.
2.2.4
2003 Competitive Resources Solicitation
The Commission's retail electric competition rules, in place since September 29, 1999, required that at least 50% of the power supply for Standard Offer Service by an investor owned utility distribution company ("UDC") will be purchased through a competitive bid process.4 1 That same UDC has the obligation to assure that adequate transmission import capability is available to meet the load requirements of all distribution customers within its service area. In its Track A order, the Commission stayed Rule 14-2-1606.B and required APS and TEP to competitively procure no less than all of Standard Offer Service requirements that they could not supply from utility-owned resources.4 2 Actions by the Commission and the utilities in 2002 and 2003 resulted in a competitive solicitation by APS and TEP for some generation requirements. That was referred to as Track B proceedings. The Track B proceedings decision 4 3 required that the results of the 2003 - 2005 RMR studies should be reflected in the contestable load requirements that those two utilities would be required to bid in their competitive solicitation. The industry responded very effectively in getting that RMR information in a very short period of time.
39 40
Decision No. 65154, Docket No. E-00000A-02-0051, et al., September 2002. Ibid, Finding of Fact 41. 41 A.A.C R14-2-1606.B, Decision No. 61969.
42 43
For this analysis, APS generation does not include the Redhawk and West Phoenix units owned by PWEC. Track B, Final Decision No. 65743, Docket No. E-00000A-02-0051
22
Regulatory Activities November 2004
2.2.5
Arizona Electric Utility Reorganizations
Two major utility reorganizations have occurred in Arizona since the Second BTA report was issued. The Arizona Electric Power Cooperative ("AEPCO") reorganized into three affiliate organizations to facilitate its participation in electric competition and direct access in Arizona. The resulting affiliates are the AEPCO generation affiliate, a transmission affiliate Southwest Transmission Cooperative ("SWTC"), and a marketing affiliate Sierra Southwest Cooperative Services. Secondly, UniSource Energy Corporation acquired the Citizens Utilities electric and gas facilities in Arizona and formed two new affiliates in 2003, UniSource Energy Services ("UES") and UES Gas. There is a UniSource Energy Corporation application currently pending before the Commission seeking approval for purchase by a private investor group. The Commission also has a third reorganization pending in the APS rate case. APS proposes to acquire and rate base its affiliate's, Pinnacle West Energy Corporation, Arizona generation assets. There are a number of economically stressed new merchant plants currently constructed in Arizona in search of a sufficiently robust market or new ownership. This may lead to other acquisitions and mergers in the local industry.
2.2.6
Arizona Independent Scheduling Administrator ("AzISA")
The AzISA is a non-profit corporation, created in 1998 under the laws of the state of Arizona, for the purpose of facilitating the development and function of competitive retail markets in Arizona. AzISA was created according to a Commission rule, which stipulates that the affected utilities that own and operate Arizona transmission facilities shall form an Arizona independent scheduling administrator.4 4 AzISA is focused on administrating Arizona retail transmission transactions according to protocols on file with FERC while WestConnect will be focused on all transmission transactions that occur within the RTO and with other RTOs. The following planning related functions are required of AzISA, under R14-2-1609 (D): The AzISA shall implement a transmission planning process that includes all AzISA participants and aids in identifying the timing and key characteristics of required reinforcements to Arizona transmission facilities to assure that the future load requirements of all participants will be met. The AzISA Board adopted a staged implementation of its functions based on the extent to which a robust retail market would develop, and the status of implementing a Desert Star or WestConnect RTO. As a result of this staged implementation, the planning functions were postponed to Phase II of AzISA's implementation plans. Important functions such
44
A.A.C. R14-2-1609.D.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
23
as dispute resolution for those serving the competitive load in Arizona, and monitoring of OASIS functions, are included in Phase I of AzISA's implementation. AzISA was also to participate in state transmission planning studies such as those of the Central Arizona Transmission System ("CATS") and Western Area Transmission System ("WATS") study groups. AzISA's role in such studies is to ensure that CATS satisfactorily addresses retail transmission needs and identifies transmission enhancements that would increase the load-serving capability in Arizona.
2.3
Western Governors Association Efforts
While it is not a regulatory body, the Western Governors Association ("WGA") is addressing inter-state bulk-power reliability coordination. Recent actions that took place in the West to advance the Governors' energy policies for the region include the following:4 5 The Seams Steering Group-Western Interconnection issued its first interconnection wide transmission plan, Framework for Expansion of the Western Interconnection Transmission System, in October of 2003. Sub-regional transmission planning has commenced on a grand scale in the Western Interconnection: The Rocky Mountain Area Transmission ("RMAT") study was launched in September of 2003, The Southwest Transmission Expansion Planning ("STEP") group completed its first annual report and continues to study transmission needs between Arizona, Southern California, Southern Nevada area and Northern Mexico, The CATS forum has concluded its third annual report and in 2004 morphed into a larger sub-regional study forum called Southwest Area Transmission ("SWAT") that is considering transmission needs for Arizona, New Mexico, Southern California , Nevada, Utah, and Colorado area and The Northwest Transmission Alternatives Committee ("NTAC").
45
Western Governors' Association 2003 Annual Report and Western Go vernor's Association 2004 Annual Report.
24
Regulatory Activities November 2004
Twelve Governors and four federal agencies have signed the WGA Transmission Permitting Protocol that provides for the collaborative review of proposed interstate transmission lines.
A project has been launched to develop an interconnection-wide market for Renewable Energy Certificates.
The value of a regional electricity body is currently being explored.
In April of 2004, the Western Governors' Association convened a North American Energy Summit. Summit participants discussed energy supply, demand and infrastructure issues facing the United States, Canada, and Mexico. Summit recommendations and action items were developed during breakout sessions in five general areas:4 6 Ensuring an efficient and reliable electricity system in the North American West. Financing infrastructure development and new technologies attracting capital, risk management and cross-border cooperation. Developing renewable energy and increasing energy efficiency. Seeking cooperative action on laws and policies across state, tribal, and international bor ders. Guiding the future of oil, natural gas, coal and nuclear energy clean technologies, supply and demand, emission and waste strategies, carbon sequestration, gasification and transportation. Specific Summit recommendations relevant to transmission included: 1. In regard to Providing a Reliable and Efficient Western Electricity Grid the Governors should: Support mandatory reliability standards. Create a formal inter-regional state entity. Work with FERC to address competitive western wholesale markets, while states retain decisions on retail access. Ensure regional coordination on transmission planning/expansion. Address financing of new transmission.
46
Western Governors' Association, North American Energy Summit, April 16, 2004 Breakout Group Recommendations
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
25
Support the review and reform, if needed, of state transmission certification and siting laws. Process should determine need first. WGA Protocol is a good start on interstate coordination. Support a phased approach to meeting the objectives of independent system operator/regional transmission organizations. Support the development of vibrant and secure regional electricity markets that include a diverse mix of supply (including renewables) and demand resources. Support efforts to stimulate the deployment of new transmission technologies. Support funding for corridor designation work on federal lands. Support expanded funding for training of electric system engineers (e.g., via universities) and thereby expand the supply of engineers. Recognize that Attorneys General need to be involved.
2. In regard to Fuel Choice and Transmission the Governors should: Advocate the formulation and adoption of Transmission Policy. Level the playing field between generation and power supply options. Full utilization of existing transmission capacity, before building new. Elimination of discriminatory practices: rate pancaking, renewables. Proper cost allocation: beneficiaries and grid reliability. Legitimize the regional transmission planning venues within the WGA footprint. Stakeholder Input: governmental, tribal, public, and industry. Consideration of power supply and generation options: remote and at load. Proactive: lead-time for transmission is longer than for generation. Incentives for renewables (PTC) and improved environmental performance.
26
Regulatory Activities November 2004
3.
Transmission Planning
Individual utilities within the state of Arizona plan and design their bulk transmission systems in accordance with the NERC, WECC regional Reliability Criteria for System Planning and Minimum Operating Reliability, guidelines established at the state level, and their own internal planning criteria, guidelines and methods. These planning practices are utilized to ensure that their respective systems are planned to provide reliable service to customers under various system conditions. In addition, they ensure that neighboring utilities and neighboring states plan their systems in a coordinated manner by following a consistent set of standards, guidelines and criteria in order to provide an economical and reliable supply of electricity. This chapter addresses the standards and processes used by the Arizona utilities in developing transmission.
3.1
3.1.1
Transmission Reliability Standards
NERC Reliability Standards
The interconnected bulk electric systems in the United States, Canada, and the northern portion of Baja California, Mexico are comprised of many individual systems. Each system has its own: electrical characteristics; set of customers; geographic, weather, and economic conditions; and regulatory and political climates. By their very nature, the bulk electric systems involve multiple parties. Since all electric systems within an integrated network are electrically connected, whatever one system does can affect the reliability of the other systems. Therefore, to maintain the reliability of the interconnected bulk electric systems, all electric industry participants are required to comply with the NERC Planning Standards. The NERC Planning Standards define the reliability of the interconnected bulk electric systems using the following two terms: Adequacy -- The ability of the electric systems to supply the aggregate electrical demand and energy requirements of their customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements. Security -- The ability of the electric systems to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. It is usually considered that adequacy is related to system planning and security is related to system operation.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
27
NERC requires that systems must be planned to withstand the more probable forced outage and maintenance outage system contingencies at projected customer demand and anticipated electricity transfer levels. Extreme but less probable contingencies measure the robustness of the electric systems and should be evaluated for risks and consequences. NERC has four basic planning standards:4 7 S1. The interconnected transmission systems shall be planned, designed, and constructed such that with all transmission facilities in service and with normal (precontingency) operating procedures in effect, the network can deliver generator unit output to meet projected customer demands and provide contracted firm (non-recallable reserved) transmission services, at all demand levels, under the conditions defined in Category A of Table 1. S2. The interconnected transmission systems shall be planned, designed, and constructed such that the network can be operated to supply projected customer demands and contracted firm (non-recallable reserved) transmission services, at all demand levels, under the conditions of the contingencies as defined in Category B of Table 1. The transmission systems also shall be capable of accommodating planned bulk electric equipment maintenance outages and continuing to operate within thermal, voltage, and stability limits under the conditions of the contingencies as defined in Category B of Table 1. S3. The interconnected transmission systems shall be planned, designed, and constructed such that the network can be operated to supply projected customer demands and contracted firm (non-recallable reserved) transmission services, at all demand levels, under the conditions of the contingencies as defined in Category C of Table 1. The controlled interruption of customer demand, the planned removal of generators, or the curtailment of firm (non-recallable reserved) power transfers may be necessary to meet this standard. The transmission systems also shall be capable of accommodating planned bulk electric equipment maintenance outages and continuing to operate within thermal, voltage, and stability limits under the conditions of the contingencies as defined in Category C of Table 1. S4. The interconnected transmission systems shall be evaluated for the risks and consequences of a number of each of the extreme contingencies that are listed under Category D of Table 1. (NERC Planning Standards, September 16, 1997, Page 9-10) In summary, NERC requires that transmission systems should be planned to withstand both single contingency (Category B), and double or multiple contingencies (Category C). In addition NERC requires that transmission systems should be planned to withstand the same set of contingencies with one bulk facility out of service for planned maintenance. The extreme contingencies (Category D) require that transmission systems be evaluated for the risks and consequences, but not for planning reinforcements.
47
NERC Planning Standards, September 16, 1997 ftp://www.nerc.com/pub/sys/all_updl/pc/pss/ps9709.pdf
28
Transmission Planning November 2004
Table 1: NERC Transmission System Standards-Normal and Contingency Conditions
Category Contingencies
Initiating Event(s) and Contingency Element(s) A - No Contingencies All Facilities in Service Elements Out of Service None Thermal Limits Applicable Rating a (A/R) A/R A/R A/R A/R Voltage Limits Applicable Rating a (A/R) A/R A/R A/R A/R
System Limits or Impacts
System Stable Yes Loss of Demand or Curtailed Firm Transfers No Cascading c Outages No
B - Event resulting in the loss of a single element.
Single Line Ground (SLG) or 3-Phase (3 Fault, with Normal Clearing: 1. Generator 2. Transmission Circuit 3. Transformer Loss of an Element without a Fault. Single Pole Block, Normal Clearingf: 4. Single Pole (dc) Line
Single Single Single Single
Yes Yes Yes Yes
No b No b No b No b
No No No No
Single
A/R
A/R
Yes
Nob
No
C - Event(s) resulting in the loss of two or more (multiple) elements.
SLG Fault, with Normal Clearing f: 1. Bus Section 2. Breaker (failure or internal fault) SLG or 3Fault, with Normal Clearingf, Manual System Adjustments, followed by another SLG or 3Fault, with Normal Clearingf: 3. Category B (B1, B2, B3, or B4) contingency, manual system adjustments, followed by another Category B (B1, B2, B3, or B4) contingency Bipolar Block, with Normal Clearingf: 4. Bipolar (dc) Line Fault (non 3, with Normal Clearingf: 5. Any two circuits of a multiple circuit towerlineg SLG Fault, with Delayed Clearing f (stuck breaker or protection system failure): 6. Generator 8. Transformer 7. Transmission Circuit 9. Bus Section
Multiple Multiple
A/R A/R
A/R A/R
Yes Yes
Planned/Controlled d Planned/Controlled d
No No
Multiple
A/R
A/R
Yes
Planned/Controlled d
No
Multiple Multiple
A/R A/R
A/R A/R
Yes Yes
Planned/Controlled d Planned/Controlled d
No No
Multiple Multiple
A/R A/R
A/R A/R
Yes Yes
Planned/Controlled d Planned/Controlled d
No No
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
29
D e - Extreme event resulting in two or more (multiple) elements removed or cascading out of service
3Fault, with Delayed Clearing f (stuck breaker or protection system failure): 1. Generator 3. Transformer 2. Transmission Circuit 4. Bus Section 3Fault, with Normal Clearingf: 5. Breaker (failure or internal fault) Other: 6. 7. 8. 9. 10. 11. 12. Loss of towerline with three or more circuits All transmission lines on a common right-of way Loss of a substation (one voltage level plus transformers) Loss of a switching station (one voltage level plus transformers) Loss of all generating units at a station Loss of a large load or major load center Failure of a fully redundant special protection system (or remedial action scheme) to operate when required 13. Operation, partial operation, or misoperation of a fully redundant special protection system (or remedial action scheme) in response to an event or abnormal system condition for which it was not intended to operate 14. Impact of sev ere power swings or oscillations from disturbances in another Regional Council.
Evaluate for risks and consequences. ay involve substantial loss of customer demand and generation in a widespread area or areas. ortions or all of the interconnected systems may or may not achieve a new, stable operating point. valuation of these events may require joint studies with neighboring systems.
a) b) c) d) e) f) g)
Applicable rating (A/R) refers to the applicable normal and emergency facility thermal rating or system voltage limit as determined and consistently applied by the system or facility owner. Applicable ratings may include emergency ratings applicable for short durations as required to permit operating steps necessary to maintain system control. All ratings must be established consistent with applicable NERC Planning Standards addressing facility ratings. Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or supplied by the faulted element or by the affected area, may occur in certain areas without impacting the overall security of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted firm (nonrecallable reserved) electric power transfers. Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread service interruption which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies. Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted firm (non-recallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems. A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated. Normal clearing is when the protection system operates as designed and the fault is cleared in the time normally expected with proper functioning of the installed protection systems. Delayed clearing of a fault is due to failure of any protection system component such as a relay, circuit breaker, or current transformer (CT), and not because of an intentional design delay. System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station entrance, river crossings) in accordance with Regional exemption criteria.
Source: NERC Planning Standards, June 15, 2001
30
Transmission Planning November 2004
3.1.2
WECC Reliability Standards
WECC provides the coordination that is essential for operating and planning a reliable and adequate electric power system for the western region of the continental USA, Canada, and Mexico. The WECC member systems' transmission facilities are planned in accordance with the NERC/WECC Reliability Criteria for Transmission System Planning. These criteria establish the performance levels intended to limit the adverse effects of each member's system operation on others, and recommend that each member system provide sufficient transmission capability to serve customers, to accommodate planned inter-area transfers, and to meet its transmission obligation to others. The WECC Reliability Criteria adopted all the NERC criteria mentioned in section 3.1.1 and asks its members to comply with several additional requirements, two of which are more stringent than those in some other NERC regions: WECC-S2 The NERC Category C.5 initiating event of a non-three phase fault with normal clearing shall also apply to the credible common mode contingency of two adjacent circuits on separate towers. The credibility of such an outage depends upon the credibility of the common mode failure. The credible outage of two circuits could result from a lightning storm or forest fire. Considerations in the determination of credibility should include line design; length; location, whether forested, agricultural, mountainous, etc.; outage history; operational guidelines; and separation between circuits. The common mode simultaneous outage of two generator units connected to the same switchyard, not addressed by the initiating events in NERC Category C, shall not result in cascading. (NERC/WECC Planning Standard, August 8-9, 2002, Page 11) In summary, WECC requires that the outage of two adjacent circuits on different towers or the outage of two units at the same plant meet Category C. This is in addition to the requirement that transmission systems should be capable of withstanding the same set of contingencies with one bulk facility out of service for planned maintenance. WECC also adds voltage dip and frequency deviation requirements for the effects of outages on neighboring systems. All except two WECC planning standards are at least as stringent as the NERC standards. The two exceptions are C2 and C9. 4 8 WECC currently has been granted a waiver for these standards and analysis is ongoing to determine whether NERC should grant a variance.4 9 This exception is not required by the Arizona utilities as they comply with NERC's C2 and C9 standards.
WECC-S3
48 49
C2-Breaker Failure, C9-Bus Section Failure Resource and Transmission Adequacy Recommendations, Prepared by the Resource and Transmission Adequacy Task Force of the NERC Planning Committee NERC Board of Trustees June 15, 2004, Table 2 Transmission Adequacy, (Revised 2/23/04) ftp://www.nerc.com/pub/sys/all_updl/pc/rtatf/RTATF_ReportBOTapprvd_061504.pdf
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
31
WECC's Reliability Management System ("RMS") agreement establishes a process to manage compliance with the established criteria. This process includes compliance monitoring, annual study reports, a project review and rating process, and an operating transfer capability policy group process. Compliance is ensured with regard to control performance, operating reserve and operating transfer capability, and disturbance control. While WECC members self-declare their compliance, WECC conducts compliance reviews through random audits. The RMS includes system operator requirements for managing transactions within major transmission path operating limits. WECC also addresses the unscheduled flow mitigation scheme approved by FERC. For reliable operation of the western interconnection, WECC requires all entities to comply with their Minimum Operating Reliability Criteria ("MORC")5 0 . MORC is applicable to system operation under all conditions even when facilities required for secure and reliable operation have been delayed or forced out of service. MORC principles applicable to the transmission system operation are: The interconnected power system shall be operated at all times so that system instability, uncontrolled separation, cascading outages, or voltage collapse will not occur as a result of single or multiple contingencies of sufficiently high likelihood. Continuity of service to load is the primary obje ctive of the MORC. Preservation of interconnections during disturbances is a secondary objective except when preservation of interconnections will minimize the magnitude of load interruption.
Since electric system reliability is so vital to Arizona, Staff contends that it is appropriate to apply the most specific and stringent criteria. Thus the Staff supports WECC's MORC. 3.1.2.1
Transmission Paths in the WECC
A grouping or set of transmission lines connecting two areas is often referred to as a transmission Path. Transmission paths consist of one or more lines emanating from a common location or between two regions. The performance of each transmission line within a transmission path is interdependent upon the performance of other lines in the same path. The adequacy and security of the whole transmission system is often determined by the performance of key and critical transmission paths. Transmission lines and paths are also rated in terms of their Total Transfer Capability ("TTC"). The TTC is the reliability limit of a transmission line or path. This rating is established by technical studies that consider the network topology and operational conditions affecting the adequacy and security of the transmission line or path. The thermal rating and the stability limit of transmission lines are both considered when establishing the TTC of transmission facilities.
50
http://www.wecc.biz/sdpp.html
32
Transmission Planning November 2004
WECC has an established process for determining the TTC of major transmission paths in the western interconnection. The transmission path consisting of lines between Arizona and California has the largest TTC of any established path in the Western Interconnection. The map in Figure 1 shows the nonsimultaneous TTC of the Arizona area for 2003. 5 1
Figure 1: Total Transfer Capabilities for Key WECC Transmission Paths (2003)
DC 160 1,400 160 DC 850 1,920 7,550 690 820 1,500 420 DC 420
2,990
814
800
408 352 312
The paths of interest to Arizona are shown in Figure 2, and are defined below in Table 2. A path of particular interest to Arizona is Path 49, East of Colorado River ("EOR") that connects Arizona and California. Paths 22, 23, 50 and 51 all lie between Four Corners/San Juan and the Phoenix area.
51
WECC Ten Year Coordinated Plan Summary, December 2003, Page 54
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
33
Figure 2: Western Interconnection Paths
Table 2: WECC Paths in Arizona
WECC Path # 22 WECC Path Name Southwest of Four Corners Four Corners Moenkopi Four Corners Cholla #1 Four Corners Cholla #2 Four Corners 345/500 kV Qualified Path New Mexico -Greenlee East of Colorado River Cholla - Pinnacle Peak Southern Navajo
23 47 49 50 51
3.1.3
Arizona Utilities Transmission Planning Standards
The utilities in Arizona plan their system facilities by following NERC and WECC reliability standards. In addition, each utility in the State develops its own internal reliability criteria and planning processes to assist in planning its EHV 345kV and above, HV transmission system, and local areas. Each utility plans
34
Transmission Planning November 2004
the transmission system to operate with no thermal overloads on lines and equipment, and voltages within defined limits under normal and emergency conditions. The Arizona transmission system is planned based on NERC and WECC single contingency criteria. 5 2 These criteria require that there should be no loss of load on the system for a single element contingency. There are credible disturbances, which are not probable, for which it is not economically feasible to protect against. These criteria recognize the need for direct load tripping for more severe disturbances, but the load tripping should be controlled to limit the adverse impact of the disturbance. Uncontrolled load shedding is unacceptable even under the most adverse, credible disturbance. The Arizona utilities have provided detailed information regarding the assumptions, studies performed and criteria used in their 10-year plans. The studies include power-flow, stability, and short-circuit analyses. While it is not explicitly stated, it appears that the plans are developed to only meet NERC category A and B criteria --normal and single contingency conditions. No evaluations appear to be made of NERC category C or D criteria --multiple and extreme contingencies. As is discussed later in chapter 6 of this report, the utilities perform companion studies of transmission and generation requirements for local load pockets. In some cases, these studies include evaluations of NERC category C & D contingencies. It is not unusual in the U.S.A. transmission planning practices that transmission systems supplying large urban areas (RMR areas) have more stringent criteria than used for the rest of the system. Staff recommends that Arizona utilities collaborate with the Staff to develop and effectively implement appropriate criteria for RMR areas in the 2006 BTA.
3.1.4
Transmission Ratings
Transmission facilities can be loaded up to their continuous or emergency ratings. The ratings may be set by thermal, stability, or voltage conditions. Thermal limits are set depending on the characteristics of the individual components, while stability and voltage limits depend on the topology and characteristics of the combined generation-transmission-load network. 3.1.4.1
Thermal Limits
Thermal limits relate to heating of equipment. High temperatures cause physical damage to the equipment and shorten the life of the equipment. In extreme heating conditions, the equipment can be damaged or destroyed. Utilities and manufacturers set temperature standards that are applied to different pieces of the transmission system to limit loss of life and avoid destroying equipment.
52
Workshop I Transcript, Page 165, Lines 9-17
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
35
Each transmission line has a utility-defined thermal rating based upon size and type of conductor, and its design and construction. The capability of the line will also be impacted by required spacing and clearances for trees, shrubs, buildings, animals and various human activities. Each transmission line has a thermal rating based on its current carrying capacity measured in amperes. Such ratings are dependent upon ambient weather, temperature, wind, and atmospheric conditions. Other devices connected to a circuit such as switches, connectors, and metering equipment may also thermally limit transmission lines. The most restrictive device rating in series with the transmission line establishes the thermal rating used for that transmission line. Circuit breakers and transformers are other major devices that have thermal ratings. These ratings are set by the manufacturers to prevent damage or destruction of the equipment. While thermal ratings are set based on ampere loading, they are usually converted to a megawatt rating assuming nominal voltage conditions. Thermal ratings are time dependent and may range from a short time emergency rating to a continuous rating. 3.1.4.2
Stability Limits
The limit of a group of transmission facilities may also be determined by stability or voltage limits. These represent limits on the system's ability to successfully respond to contingencies, even if no thermal limits are exceeded. For many system contingencies generators in different parts of the power system will "speed up" slightly while others will "slow down" slightly. The two areas will be briefly operating at very slightly different frequencies when this happens. In nearly all cases, the transmission system is strong enough to keep the two parts of the system connected so that they quickly return to normal speed (frequency). In these cases the system remains stable. For a few system configurations and contingencies, the transmission system is not strong enough to maintain the two areas' frequencies in balance. In these cases the two areas will separate from each other and operate isolated. This is an example of an unstable system condition. In most cases, however, one or more of the islands will experience partial or full loss of load. This occurs because one, or more, of the areas will be importing from the others. Thus, when the transmission connection is lost the importing area will be unbalanced, with more load than generation. When the imbalance is large, the only option for the importing area is to shed load; causing a partial blackout. If the imbalance is very large a complete blackout of the island will occur. It is also possible for the exporting area to experience problems when the islands form. There are situations in many systems, especially those in the western United States, where transfers are limited by stability problems before any thermal limits are reached. In these cases the transfer will be
36
Transmission Planning November 2004
stability limited. These stability (and voltage) limits are established via technical studies that determine the maximum power that can be transferred over a group of lines. 3.1.4.3
Voltage Limits
For nearly all system contingencies different parts of the power system will experience changes in voltages. In some areas voltages rise; while in others voltages will fall. Usually equipment and system operators are able to adjust the voltages to maintain acceptable levels. If voltages rise too much, however, equipment can be damaged due to insulation or other hardware failures. If the voltages fall too low it may not be possible to control, and voltage will continue to fall, resulting in a blackout. The greatest risk is usually to an importing area where the lowest voltages will usually be experienced.
3.2
Arizona Transmission Planning Processes
Planning methods and guidelines are used as the basis for the development of future transmission facilities. Transmission plans are updated on a continuous basis to determine the projected facilities needs for each year over a ten-year period. In addition to planning their transmission systems to meet their internal needs, the utilities in the State actively engage in a coordinated regional planning of transmission facilities in order to ensure that (a) there are no duplicate or redundant facility additions, and (b) the Extra High Voltage ("EHV") and High Voltage ("HV") transmission facilities are planned in the broader context of the needs of the State, and to take advantage of the diverse locations of load centers and generation complexes in the State. The nominal system voltages for EHV facilities are 345 kV and 500 kV. The nominal system voltage for HV facilities ranges from 115 kV to 230 kV. The utilities in the State are also coordinating the planning activities with the utilities in the neighboring states to identify and construct interstate transmission facilities in order to take advantage of the import and export of competitive energy that would benefit the customers. Since the 2002 BTA, with the encouragement of the ACC and its Staff, the planning process has become much more collaborative and regional. This is a significant improvement in the Arizona planning process. While individual transmission providers remain responsible for their individual transmission projects, the planning process has become so regional that plans are best presented on a regional basis, rather than by individual companies.
3.2.1
Regional Transmission Planning Affecting Arizona
Coordinated regional planning in Arizona dates back at least to the late 1960s when the NERC and its regional Councils were formed. The Arizona utilities were part of one of these regional Councils, the
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
37
Western Systems Coordinating Council ("WSCC"). In the years since that time many regional planning coordinating groups have formed and evolved. The WECC has succeeded the WSCC. There are now six regional transmission-planning groups active in the WECC as shown in Figure 3. As shown on the figure, the sub-regional groups that are directly involved with transmission planning in Arizona are STEP and SWAT.
Figure 3: Six Sub-Regional Planning Groups in the WECC
3.2.1.1
Southwest Transmission Expansion Planning ("STEP") Group
STEP was created as an ad-hoc group to coordinate transmission plans in the Arizona, Southern Nevada, Southern California, and Northern Mexico area. STEP first met in November 2002 and has met periodically since. Participants include representatives from utilit ies, independent power producers, state
38
Transmission Planning November 2004
agencies/regulators and other stakeholders with an interest in the transmission system in Southern Nevada, Arizona and Southern California. STEP's focus is on economically driven expansion projects that support the development of seamless west-wide markets while satisfying established reliability standards.
STEP goals and functions
The group adopted the following common goal: To provide a forum where all interested parties are encouraged to participate in the planning, coordination, and implementation of a robust transmission system between the Arizona, Southern Nevada, Mexico, and Southern California areas that is capable of supporting a competitive, efficient, and seamless west-wide wholesale electricity market while meeting established reliability standards. The wide participation envisioned in this process is intended to result in a plan that meets a variety of needs and has a broad basis of support. STEP performs 12 basic planning functions: 1. Produces a long-term bulk transmission expansion plan biennially. 2. Identifies current and future transmission congestion that is an impediment to the efficient operation of the western market. 3. Develops, through a collaborative process, strategic transmission options and specific alternative plans for reinforcing the transmission system and for reducing or eliminating congestion. 4. Reviews project-sponsored studies, if requested by the Project Sponsor. 5. Relies, as much as possible, on the technical studies conducted by Project Sponsors and studies conducted in other forums.
6.
Performs technical studies without duplicating work performed by others.
7. Shares the study work and will normally be documented in a report. 8. Provides a forum to facilitate stakeholder development of projects through the planning effort. 9. Facilitates the phased implementation of completed plans. 10. Works closely with regulatory and governmental agencies in developing facility plans. 11. Closely coordinates with the other regional planning and reliability groups. 12. Provides a forum for discussing different approaches for funding potential transmission projects.
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
39
In its first year, STEP conducted both technical and economic studies to develop transmission projects to mitigate inefficient congestion on the system. A large number of initial alternatives were narrowed down to one general expansion plan based on the studies and a consensus building process. The member systems began implementing several of the initial steps that can be implemented quickly and economically. These are discussed in section 5.2. A separate sub-group of STEP was formed to focus on these short-term upgrades. The initial steps primarily involve upgrades to the series capacitors in several existing 500 kV lines. During 2004, STEP expects to agree on some of the larger system upgrades and to initiate their implementation. Two other sub-groups were formed to make more detailed studies of specific areas. The first is developing a final plan for a new line between Arizona and California . The second is working on a new transmission line into San Diego. The planning and development of these two projects are taking place in parallel. These larger scale upgrades involve the construction of major new 500 kV lines. Altogether, the total cost of the economic transmission additions being developed by STEP is estimated to exceed one billion dollars.
40
Transmission Planning November 2004
STEP Arizona-California
STEP Arizona-California ("STEP-AC") covers the area on the east side of Path 49, as shown in Figure 4. The focus of the STEP-AC group is on the transmission transfer capability between Arizona and California. This means that there is some justified geographic overlap with other groups that are focused on the "internal" transmission needs of the areas within Arizona and California.
Figure 4: Transmission Area of STEP-AC Planning Group
ad ev N a
HARRY ALLEN CRYSTAL
NAVAJO
da va n a N e r iz o A
ia rn ifo al C
MIDWAY McCULLOUGH MARKETPLAC E ELDORADO ADELANTO VICTORVILLE MOHAVE MEAD TO FOUR CORNERS MOENKOPI
YAVAPAI
LUGO RINALDI VINCENT
West of River
PERKINS
TOLUCA
MIRA LOMA DEVERS
East of River
PALO VERDE
WESTWING
RUDD HASSAYAMPA Ca lif o rni a SERRANO VALLEY LIBERTY TO KYRENE HARQUAHALA JOJOBA GILA RIVER
Arizo na
Phase Shifter MIGUEL IMPERIAL VALLEY NORTH GILA 500 kV line 345 kV line
Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047
4
Object Description
| Rating | |
| TITLE | Biennial transmission assessment / Arizona Corporation Commission. |
| CREATOR | Arizona Corporation Commission. |
| SUBJECT | Electric power-plants--Arizona; Electric power transmission--Arizona; Energy facilities--Arizona; |
| Browse Topic |
Business and industry Land and resources |
| DESCRIPTION | This title contains one or more publications. Published biennial. Report covers 10-year span. |
| Language | English |
| Publisher | Arizona Corporation Commission. |
| Material Collection |
State Documents |
| Acquisition Note | http://www.cc.state.az.us/utility/electric/Biennial.htm |
| Source Identifier | CC 1.3:B 43 |
| Location | 144682549 |
| REPOSITORY | Arizona State Library, Archives and Public Records--Law and Research Library. |
Description
| TITLE | Third biennial transmission assessment 2004-2013 |
| CREATOR | KEMA, Inc. |
| DESCRIPTION | 151 pages (PDF version). File size: 1628.66 KB. November 30, 2004. Docket No. E-00000D-03-0047. Prepared by Arizona Corporation Commission Staff and KEMA Inc. Fairfax, VA. |
| TYPE | Text |
| Acquisition Note | reports@lib.az.us; http://www.cc.state.az.us/utility/electric/Biennial.htm |
| RIGHTS MANAGEMENT | Copyright to this resource is held by the creating agency and is provided here for educational purposes only. It may not be downloaded, reproduced or distributed in any format without written permission of the creating agency. Any attempt to circumvent the access controls placed on this file is a violation of United States and international copyright laws, and is subject to criminal prosecution. |
| DATE ORIGINAL | 2004-11-30 |
| Time Period |
2000s (2000-2009) 2010s (2010-2019) |
| ORIGINAL FORMAT | Born Digital |
| DIGITAL IDENTIFIER | BTA-11-30-04.pdf |
| DIGITAL FORMAT | PDF (Portable Document Format) |
| REPOSITORY | Arizona State Library, Archives and Public Records--Law and Research Library. |
| Full Text | Arizona Corporation Commission Docket No. E-00000D-03-0047 Decision No. _______ THIRD BIENNIAL TRANSMISSION ASSESSMENT 2004-2013 November 30, 2004 Prepared by Arizona Corporation Commission Staff and KEMA Inc. 4400 Fair Lakes Court Fairfax, VA 22033 Executive Summary A.R.S. 40-360.02.E states "The (Ten-Year) plans shall be reviewed biennially by the commission and the commission shall issue a written decision regarding the adequacy of the existing and planned transmission facilities in this state to meet the present and future energy needs of this state in a reliable manner." This Third Biennial Transmission Assessment ("BTA") was undertaken by the Arizona Corporation Commission ("ACC" or "Commission") Staff ("Staff") to fulfill the above stated statutory obligation. The Ten-Year transmission plans filed in January 2003 and 2004 under Docket No. E-00000D-03-0047 are the subject of this assessment. Of particular interest are the many activities related to the collaborative regional planning process. Reliability Must Run ("RMR") studies were submitted in 2003 and 2004 by industry to address concerns identified in Staff's Second BTA and are also the topic of this assessment. Staff's approach in organizing the Third BTA remained the same as for the Second BTA. Staff relied on analyzing the Ten-Year studies, RMR Studies, and other technical reports and documents filed with the Commission by the various organizations rather than performing technical studies of their own. Staff hired a consulting organization, KEMA, to assist in this effort. Staff uses a set of guiding principles to determine whether the Arizona transmission system will be adequate during the next ten-year period. Staff's guiding principles are based upon best engineering practices established in Arizona, coupled with the use of regional and national reliability council criteria and standards, and related state and federal policies. The reliability of an existing or planned electric system under existing, alternative or future operating conditions can only be determined by technical simulation studies, including load flow, stability and short circuit analysis. Such studies require the application of a set of study criteria to measure the system's performance. In assessing the Arizona transmission system adequacy, Staff and KEMA critically reviewed and analyzed the transmission planning documents assembled by Staff and addressed the following questions: 1. Do the proposed Arizona transmission system plans meet the load serving requirements of the state during the 2004-2013 time period in a reliable manner 2. Was the transmission planning process conducted in accordance with the transmission planning principles and good utility practices accepted by the power industry 3. What steps were taken in the new transmission planning studies to effectively address the Commission's concerns raised in the First and Second BTA about the adequacy of the state's transmission system to reliably support the competitive wholesale market emerging in Arizona Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 i 4. Do the generation interconnection practices in Arizona adequately reflect technical aspects of the generation interconnection policies as defined in Federal Energy Regulatory Commission ("FERC") Orders 2003 and 2003-A 5. Do the transmission plans adequately reflect North America Electric Reliability Council's ("NERC") latest activities related to compliance with the transmission planning standards, as well as compliance with Western Electricity Coordinating Council ("WECC") reliability standards This transmission assessment represents the professional opinion of Commission Staff and its Consultant, KEMA. The BTA is not an evaluation of individual transmission provider's facilities or quality of service. This BTA report does not set Commission policy and d es not recommend specific action for o any individual Arizona transmission provider. It assesses the adequacy of Arizona's transmission system to reliably meet existing and future energy needs of the state. This transmission assessment will not become official unless and until it is adopted by Commission Decision. Staff offers the following conclusions for Commission consideration: 1. The electric industry in Arizona has been very responsive to concerns raised in the Commission's Second BTA. 2. Extensive regional studies addressing the interstate transmission needs have been conducted in a collaborative process. 3. Transmission providers have performed reliability-must-run studies for each local transmission import constrained area they serve and have complied with the Second BTA RMR requirements. 4. Numerous new transmission and generation projects have been announced and filed with the Commission since its First and Second BTAs and some of those projects have been constructed. 5. In general, the existing and proposed Arizona transmission system meets the load serving requirements of the state in a reliable manner: a. Many planned Extra High Voltage ("EHV") and High Voltage ("HV") projects will increase transmission system capability to support increased interstate power transfers, and to provide reliable transfers within the state of Arizona. b. The planned EHV system appears to be adequate throughout the study period. As is often the case, plans for the later years of the period are less well defined than those in the early years. Future reports should include more discussion of alternate additions considered for the final five years of the study period. This will allow the Commission and public to be better informed regarding future possibilities. ii Executive Summary November 2004 c. The RMR studies show that the RMR areas will have load-serving capacity sufficient to provide reliable supply during the next ten-year period. Problems are identified in the Yuma area in 2004 and Santa Cruz Country area in 2004-2008, but are addressed in the RMR study. The Phoenix area is determined as deficient in local operating reserves in 2013. The Arizona Public Service Company ("APS") and Salt River Project ("SRP") are currently investigating solutions to mitigate this Phoenix area deficiency. d. The RMR studies show no economic justification for additional transmission projects as an alternative to dispatch of local area generation. However, Staff is concerned with some inconsistent data among the utilities and would like increased transparency in energy production modeling, data and assumptions used in economic studies. Major disturbances in the Phoenix area are being addressed by the Commission in a separate proceeding. Utilities serving major Arizona urban areas should assess existing major facilities regarding such extreme multiple contingencies and describe the actions they have taken to address such contingencies. e. The planned Arizona transmission system meets the WECC and NERC single contingency criteria (N-1). f. Since interconnection of merchant plants commenced at the Palo Verde Hub, the Palo Verde east transmission system capability has increased from 3810 MW to 6970 MW as a result of several transmission upgrades. Two new 500 kV transmission line projects within Arizona are proposed as additional reinforcements in 2007 through 2011. The Palo Verde to TS5 to Raceway and Palo Verde to Browning projects will significantly increase the outlet capability of the Palo Verde Hub to Arizona. 6. No transmission improvements have been made to the pre-existing 2800 MW Palo Verde west transmission system capability to delivery power to California. Therefore, transmission from Palo Verde to California is inadequate to allow all new Palo Verde Hub generation full access to the California market. Three 500 kV transmission projects are being studied to remedy such market limitation between Arizona, California and Nevada. 7. There is very little existing long-term firm transmission capacity available to export or import energy over Arizona's transmission system. Studies investigating transmission additions required between Arizona and California and between New Mexico and Arizona continue to explore the scope, participation and timing of alternative projects. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 iii 8. Some new power plants have interconnected to Arizona's bulk transmission system via a single transmission line or tie rather than continuing Arizona's best engineering practices of multiple lines emanating from power plants. As interconnection of new transmission lines are considered for the Palo Verde Hub, they should be encouraged to terminate at these new power plant switchyards in order to mitigate this regional reliability concern. Concerns outlined by Staff in the above conclusions are not easily or quickly resolved. The public's best interest warrants effective and decisive remedies. Therefore, Staff offers the following recommendations for Commission consideration and action: Continue to support use of: a. "Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability" (attached as Appendix A) to aid Staff in its determination of adequacy and reliability of power plant and transmission line projects, b. NERC and WECC criteria and FERC policies for adequacy and reliability assessments of the transmission system, and c. Collaborative planning study forums of transmission providers, merchant plant developers, and other interested parties for the purpose of: 1. Ensuring consumer benefits of generation additions and costeffective transmission enhancements and interconnections. Endorse Staff's recommendation that: a. RMR studies continue to be performed and filed with ten year plans in even numbered years for inclusion in future BTA reports and that: 1. Future RMR studies provide more transparent information on input data and economic dispatch assumptions, and 2. Arizona utilities collaborate with the Staff to develop and effectively implement more stringent criteria as appropriate for RMR areas in the 2006 BTA. b. All future interconnections proposed at the Palo Verde Hub, either new generation or new transmission line, must perform a risk assessment of the Hub to ascertain to what degree the proposed project mitigates the pre-existing risks to extreme outage events. This assessment must precede a project's application for a CEC with the Commission. The recommendations of the Palo Verde Risk Assessment report should b followed if a e proposed project would otherwise exacerbate the existing risk at the Hub. iv Executive Summary November 2004 c. The Fourth BTA address and document: 1. Compliance with single contingency criteria overlapped with the bulk power system facilities maintenance (N-1-1) (for the first year of the BTA analysis) as required by WECC and NERC. 2. Extreme contingency outages studied for Arizona's major generation hubs and major transmission stations including identification of associated risks and consequences if mitigating infrastructure improvements are not planned. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 v Contents Executive Summary.............................................................................................................................i List of Figures ..................................................................................................................................ix List of Tables ....................................................................................................................................x 1. Overview .....................................................................................................................................1 1.1 Assessment Authority...........................................................................................................1 1.2 Previous Biennial Transmission Assessments - Conclusions and Recommendations ................. 1 1.2.1 First Biennial Transmission Assessment....................................................................1 1.2.2 Second Biennial Transmission Assessment................................................................2 1.3 Third Biennial Assessment - Purpose and Framework ............................................................ 4 1.3.1 Purpose ................................................................................................................... 4 1.3.2 Framework..............................................................................................................5 2. Related Regulatory Activities ........................................................................................................9 2.1 Relevant FERC Orders and Actions, and Arizona Industry Response.......................................9 2.1.1 FERC Activities Following the August 14, 2003 Blackout .......................................... 9 2.1.2 FERC Large Generation Interconnection Standards .................................................. 14 2.1.3 FERC Standard Market Design ............................................................................... 17 2.1.4 Update on the FERC RTO Order 2000 and WestConnect RTO ................................. 19 2.2 Arizona Corporation Commission Actions ........................................................................... 20 2.2.1 Arizona Implementation of Special Reliability Requirements.................................... 20 2.2.2 Electric Re-Structuring Activities............................................................................ 21 2.2.3 2003 Competitive Resources Solicitation ..................... Error! Bookmark not defined. 2.2.4 Commission Concern on Local Area Transmission Constraints and RMR.................. 21 2.2.5 Arizona Electric Utility Reorganizations .................................................................. 22 2.2.6 Arizona Independent Scheduling Administrator ....................................................... 23 2.3 Western Governors Association Efforts ............................................................................... 24 3. Transmission Planning ................................................................................................................ 27 3.1 Transmission Reliability Standards...................................................................................... 27 3.1.1 NERC Reliability Standards.................................................................................... 27 3.1.2 WECC Reliability Standards ................................................................................... 31 3.1.3 Arizona Utilities Transmission Planning Standards................................................... 34 3.1.4 Transmission Ratings ............................................................................................. 35 3.2 Arizona Transmission Planning Processes ........................................................................... 37 3.2.1 Regional Transmission Planning Affecting Arizona.................................................. 37 3.2.2 Arizona Planning Practices for Local Area Transmission Constraints ........................ 44 4. Adequacy of Existing System......................................................................................................47 4.1 System Description ............................................................................................................ 47 4.2 Local Area Transmission Constraints .................................................................................. 51 4.3 Palo Verde Hub Operational Issues ..................................................................................... 51 4.3.1 Palo Verde Hub Transmission Constraints ............................................................... 52 4.3.2 Palo Verde Risk Assessment................................................................................... 54 Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 vii Contents 5. Adequacy of the Future System...................................................................................................61 5.1 Phoenix-Tucson EHV System Assessment........................................................................... 61 5.2 Arizona-California EHV System Assessment....................................................................... 65 5.3 Arizona-New Mexico EHV System Adequacy..................................................................... 67 5.4 Navajo Transmission Project............................................................................................... 69 5.5 Phoenix-Tucson HV system adequacy................................................................................. 71 5.6 Western Arizona HV System Assessment............................................................................ 78 5.7 Conclusions on Adequacy of EHV and HV Arizona Transmission System............................. 78 6. Local-Area Transmission System.................................................................................................79 6.1 Arizona Reliability Must-Run Generation Requirements....................................................... 79 6.1.1 RMR Conditions and Study Methodology................................................................ 80 6.1.2 Summary of the 2003 and 2004 RMR Studies Process.............................................. 84 6.2 Transmission Import Constraint Areas................................................................................. 87 6.2.1 Phoenix Area RMR Conditions and Imports Assessment .......................................... 87 6.2.2 Yuma Area RMR Conditions and Import Assessment............................................... 97 6.2.3 Tucson Area RMR Conditions and Import Assessment........................................... 103 6.2.4 Mohave Area RMR Conditions and Import Assessment.......................................... 108 6.2.5 Santa Cruz County RMR Conditions and Import Assessment.................................. 110 7. Generation Update .................................................................................................................... 113 7.1 Merchant Plant Ten-Year Plans Reported for the Second BTA............................................ 113 7.2 Status of the Merchant Plant Ten-Year Plans Reported in the Second BTA.......................... 114 7.3 Status of Plants Scheduled for Future Years Operation Reported in the Second BTA............ 115 8. Future Generation ..................................................................................................................... 117 8.1.1 2003 and 2004 Generation Interconnection Requests.............................................. 117 9. Conclusions ............................................................................................................................. 121 10. Recommendations .................................................................................................................... 123 APPENDICES ............................................................................................................................... 125 Appendix A: Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability ................................................................................................................................ 127 Appendix B: 2004 BTA Workshop I and II List Attendees ........................................................ 129 Appendix C: Information Resources ......................................................................................... 133 Appendix D: List of new projects and project changes ............................................................... 135 viii Contents November 2004 Contents Figures Figure 1: Total Transfer Capabilities for Key WECC Transmission Paths (2003) ................................. 33 Figure 2: Western Interconnection Paths ........................................................................................... 34 Figure 3: Six Sub-Regional Planning Groups in the WECC................................................................38 Figure 4: Transmission Area of STEP -AC Planning Group.................................................................41 Figure 5 Areas Covered by SWAT Study Groups..............................................................................42 Figure 6: Arizona EHV Transmission System....................................................................................50 Figure 7 Local Area Transmission Constraints .................................................................................. 51 Figure 8: Palo Verde Transmission System........................................................................................52 Figure 9: Generic Model of Hub Concept .......................................................................................... 58 Figure 10: Arizona EHV Transmission Area System and Plans...........................................................62 Figure 11: Arizona-California Area Transmission System .................................................................. 65 Figure 12: Arizona-California Short-Term Transmission Improvements .............................................. 66 Figure 13: Major Arizona-New Mexico EHV Transmission ............................................................... 67 Figure 14: Navajo Transmission Project Concept...............................................................................69 Figure 15: Phoenix-Tucson Area EHV Transmission System..............................................................71 Figure 16: Phoenix Area HV Transmission System............................................................................72 Figure 17: Tucson Area HV Transmission System ............................................................................. 73 Figure 18: 2003 and 2004 RMR Study Framework ............................................................................ 80 Figure 19: RMR Conditions ............................................................................................................. 81 Figure 20: 2004 BTA Arizona Load Pocket Areas ............................................................................. 87 Figure 21: New Projects Strengthening the Phoenix-Area Transmission System .................................. 89 Figure 22: Phoenix Area Reserves .................................................................................................... 94 Figure 23: Phoenix Area Load Serving Capability..............................................................................96 Figure 24: New Projects Strengthening the Yuma Area Transmission System......................................98 Figure 25: Yuma Area Load Serving Capability............................................................................... 103 Figure 26: Addition of New Projects in TEP.................................................................................... 104 Figure 27: Study System for Mohave County .................................................................................. 109 Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 ix Contents List of Tables Table 1: NERC Transmission System Standards-Normal and Contingency Conditions ......................... 29 Table 2: WECC Paths in Arizona ...................................................................................................... 34 Table 3: Existing Arizona Power Plants Owned by Arizona Utilities ................................................... 48 Table 4 Merchant Plant Additions in Arizona Since the First Biennial Transmission Assessment.........49 Table 5: New Transmission Lines and Stations Added Since the Second BTA.....................................50 Table 6: Gross Generation Interconnected to the Hub.........................................................................53 Table 7: Palo Verde transmission and generation capability ................................................................ 53 Table 8: Arizona Planned EHV Transmission Additions ..................................................................... 63 Table 9: Long-Range Transmission "Needs" of Parties in the AZ-NM Region ..................................... 68 Table 10: Arizona Planned HV Transmission Additions ..................................................................... 74 Table 11: Summary 2004 RMR Studies Results.................................................................................85 Table 12: Phoenix Area Facilities Additions ...................................................................................... 91 Table 13: Phoenix Area Critical Outages...........................................................................................92 Table 14: Phoenix Area Maximum Load Serving Capability...............................................................93 Table 15: Generating Unit Operational Characteristics ....................................................................... 95 Table 16: Yuma Area Facility Additions ......................................................................................... 100 Table 17: Yuma Area Critical Outages............................................................................................ 101 Table 18: Yuma Area Maximum Load Serving Capability................................................................ 101 Table 19: TEP Area Facility Additions ............................................................................................ 105 Table 20: TEP Area Critical Outages .............................................................................................. 105 Table 21: SIL, MLSC, and Annual Costs for Dispatch to Mitigate RMR Conditions .......................... 107 Table 22: SIL, MLSC, and Annual Costs for Dispatch to Mitigate RMR Conditions .......................... 110 Table 23: SIL, MLSC, and Annual Costs for Dispatch to Mitigate RMR Conditions .......................... 111 Table 24: Generation Projects Proposed for Interconnection in Arizona............................................. 114 Table 25: Status of Generation Plants Scheduled for Future Years .................................................... 115 x Contents November 2004 1. 1.1 Overview Assessment Authority Arizona statutes require every organization contemplating construction of any transmission line within Arizona during a ten-year period to file a ten-year plan with the Arizona Corporation Commission ("ACC or Commission") on or before January 31 of each year.1 In 1999, the Arizona state legislature placed a statutory obligation with the ACC to biennially review the plans filed with the Commission and "issue a written decision regarding the adequacy of the existing and planned transmission facilities in Arizona to meet the present and future energy needs of the state in a reliable manner."2 In 2001, the Arizona legislature further modified the Arizona Power Plant and Transmission Line Siting statutes resulting in two new statutory requirements related to filing of plans with the Commission. Every organization contemplating construction of a new power plant within Arizona is now required to file a plan with the Commission 90 days before filing an application for a Certificate of Environmental Compatibility ("CEC").3 Additionally, all plans filed with the Commission are to be accompanied by power flow and stability analysis reports showing the effect of plant interconnections on the current (and future) Arizona electric transmission system. 4 1.2 1.2.1 Previous Biennial Transmission Assessments - Conclusions and Recommendations First Biennial Transmission Assessment The Utilities Division Staff ("Staff") of the ACC initiated its First Biennial Transmission Assessment ("BTA") in 2000, under Docket No. E-00000A-01-0120. The Commission's decision was rendered in July 2001. In its First BTA, the Commission determined that the State of Arizona ("State") transmission system was not adequate5 to provide reliable supply to the State electrical load, neither for the present nor for the future conditions. These conclusions were based upon the following findings 6 : 1 2 A.R.S. 40-360.02.A A.R.S. 40-360.02.G 3 A.R.S. 40-360.02.B 4 A.R.S. 40-360.02.C.7 5 BTA 2002-2011, Page 2 6 BTA 2002-2011, Page 2 Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 1 There was very little additional long-term firm regional transmission capacity available to export or import energy over Arizona's transmission system. Southeastern Arizona utilities relied upon restoration of service, rather than continuity of service, following transmission outages due to service via radial transmission lines. There were transmission import constraints for three geographical load zones in Arizona: the Phoenix metropolitan area, Tucson, and Yuma. Planned transmission enhancements failed to resolve this situation in a timely manner. The existing and planned additions to the Palo Verde t ansmission system failed to r accommodate the full output of all new power plants proposing to interconnect at Palo Verde, requiring procedures to be developed for curtailment and scheduling restriction. Some proposed power plants were being interconnected to Arizona's bulk transmission system via a single transmission line or tie rather than continuing Arizona's best engineering practice of multiple lines emanating from power plants. The Commission adopted the following two concepts for Staff's measurement of Arizona's transmission system adequacy and security: 1. There should be sufficient transmission import capability to reliably serve all loads in a utility's service area without limiting access to more economical or a less polluting remote generation. 2. New power plants must have sufficient interconnected transmission capacity to reliably deliver their full output without use of remedial action schemes or displacing existing generation at the same interconnection for single contingency (N-1) outages. 1.2.2 Second Biennial Transmission Assessment The Staff initiated its Second BTA in 2002, under Docket No. E-00000A-02-0065. Written decision No. 65476 of that assessment was rendered on December 19, 2002. In its Second BTA, the Commission concluded that the electric i dustry had been very responsive 7 to n concerns raised in its First BTA. The BTA process was built upon an extensive collaborative transmission planning process open to all stakeholders. In addition, some merchant power plant developers had begun proposing transmission system reinforcements to resolve transmission barriers to the wholesale market. Transmission providers had agreed to participate in Reliability-Must-Run ("RMR") study processes for transmission-constrained areas with which they are interconnected. Most 7 BTA 2002-2011, Executive Summary, Page ii 2 Overview November 2004 importantly, numerous new transmission projects had been announced and filed with the Commission since its First BTA. The Commission concluded that the existing and planned Arizona transmission system generally met the load serving requirements of the state in a reliable manner. However, the Commission had several concerns about the adequacy of the state's transmission system to reliably support the competitive wholesale market emerging in Arizona. These concerns included: Limited access by competitive wholesale generators' to local Arizona markets, due to local transmission import constraints, that results in local RMR generation requirements. Failure of planned Palo Verde transmission system additions to accommodate the full output of all new power plants connected at the Palo Verde Hub. Limited additional long-term firm transmission capacity available to export or import energy over Arizona's transmission system. A single transmission line or tie being used to connect some new power plants to Arizona's bulk transmission system rather than continuing Arizona's best engineering practices of multiple connections from power plants. The above concerns are not easy to resolve. Nevertheless, the Commission approved and ordered in its Decision No. 65476 the following actions: 1. Continue to support use of the "Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability" to aid Staff in its determination of adequacy and reliability of power plant and transmission line projects. 2. Request Staff to commence rule making proceedings to determine how: a. Utility distribution companies ("UDCs") should ensure sufficient transmission import capacity to reliably serve all loads in its service area without limiting access to more economic al or less polluting remote generation 8 , and b. New power plants should demonstrate sufficient transmission capacity exists to reliably and economically deliver their full output without use of remedial action schemes for single contingency (N-1) outages or displacing existing generation at the interconnection. 8 Each utility distribution company also has an obligation to assure that adequate transmission import capability is available to meet the load requirements of all distribution customers in its service area. This requirement is also coupled with a requirement that Arizona utilities competitively procure 100% of their standard offer requirements, with at least 50% procured through competitive bidding. This later requirement was stayed by the Commission in Decision No. 61969, for Staff to determine the proper level of competitive solicitation. Staff used these guiding principles, criteria, standards and rules for this biennial transmission assessment. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 3 3. Encourage transmission providers to continue to investigate and study, in a collaborative fashion, local area import constraints in accordance with the RMR Study Plan outlined in Section 7.2 of the 2002 BTA. 4. Continue to encourage collaborative study activities between transmission providers and merchant plant developers for the purpose of: a. Ensuring consumer benefits of generation additions and costeffective transmission enhancements and interconnections, and b. Facilitating restructuring of the electric utility industry to reliably serve Arizona consumers at just and reasonable rates via a competitive wholesale market. 1.3 1.3.1 Third Biennial Assessment - Purpose and Framework Purpose The Commission undertook the Third BTA, which evaluates the Ten-Year transmission plans filed in January 2003 and 2004, under Docket No. E-00000D-03-0047. This report fulfills the Commission's statutory obligation to review these transmission plans and assess whether the Arizona transmission system is adequate. The 2003 and 2004 RMR Studies are also the subject of this 2004 assessment. Of particular interest are the adjustments made by the industry to address the concerns identified in the Commission's First and Second BTAs. Staff hired a consulting organization, KEMA Inc. ("KEMA") to assist Staff in this effort. The adequacy of an existing or planned electric system is determined by technical simulation studies. Such studies require the use of: databases, software and transmissio n planning reliability standards, and planning assumptions. The process assumes that the Arizona transmission utilities conduct their own studies, participate in the collaborative regional planning process, and present the study results in the TenYear Plan reports and at public workshops. Staff and KEMA reviewed and analyzed all these study reports assembled by Staff, and organized two workshops. Staff relied on the technical reports and documents filed with the Commission by the various organizations, rather than performing technical studies of their own. Staff used a set of guiding principles to aid it in determining the adequacy and reliability of both transmission and generation systems.9 Staff's guiding principles are based upon best engineering practices established in Arizona coupled with the use of Western Electricity Coordinating Council 9 Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability: Appendix A Arizona's Best Engineering Practices, Jerry D. Smith, ACC, pre -filed comments for the Gila Bend Power Plant Hearing, Docket No. E-00000V-00-0106, November 9, 2000 4 Overview November 2004 ("WECC")1 0 and North American Electric Reliability Council ("NERC")1 1 planning standards. Staff and KEMA critically reviewed and analyzed the transmission planning documents assembled by Staff and addressed the following questions: 1. Do the proposed Arizona transmission system plans meet the load serving requirements of the state during the 2004-2013 period, in a reliable manner 2. Was the transmission planning process conducted in accordance with the transmission planning principles and good utility practices accepted by the power industry 3. What steps were taken in the new transmission planning studies to effectively address the Commission's concerns raised in the First and Second BTA about the adequacy of the state's transmission system to reliably support the competitive wholesale market emerging in Arizona 4. Do the generation interconnection practices in Arizona adequately reflect technical aspects of the generation interconnection policies as defined in the Federal Energy Regulatory Commission ("FERC") Orders 2003 and 2003-A 5. Do the transmission plans adequately reflect NERC's latest activities related to compliance with the transmission planning standards, as well as compliance with WECC reliability standards 1.3.2 Framework Staff and KEMA made use of a three-stage process to facilitate the electric industry's participation in the third BTA: 1. Workshop I: Industry Presentation; 2. Preparation of Initial Draft Report and Industry Comments on Draft; and 3. Workshop II: Staff/KEMA Presentation and Final Report. An overview of each stage is described below. Stage 1. Workshop I: Industry Presentation Staff and KEMA organized and facilitated a one-day public Workshop on June 30, 2004. Transmission Providers and Regional Planning Groups presented information regarding their transmission expansion plans and related activities to supply native load customers for the next ten years. In addition, merchant transmission and wind generator d velopers reported on their development plans.1 2 The Workshop e 10 11 http://www.wecc.biz/documents/standards/for_approval/2002JulyBODStandards.htm http://www.nerc.com/~filez/pss-psg.html 12 The Workshop presentation materials are located on the ACC website: http://www.cc.state.az.us Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 5 provided an informal setting to promote effective discussions of the presentations from transmission providers and merchant plant developers. The Workshop I participants 1 3 included: Arizona Transmission Providers Merchant Transmission and Generation Developers Arizona Power Plant and Transmission Line Siting Committee ("Siting Committee) Members Consumer Advocates Individual Interested Parties.1 4 The workshop was organized in to four panels--one for each topic. An open period of discussion and audience questions followed each panel presentation. To facilitate focused and meaningful presentations and discussions at the Workshop, Staff requested the participants to discuss four topics. 1. Regional planning updates provided by: Seams Steering Group-Western Interconnection("SSG-WI") Planning Group Southwest Transmission Expansion Plan ("STEP") Southwest Area Transmission ("SWAT") Planning Group 2. Utilities' Updates concerning Ten-Year Transmission Plans, providing details on transmission additions/upgrades/revisions since the Second Biennial Transmission Assessment: Arizona Public Service Company ("APS") Salt River Project ("SRP") Southwest Transmission Cooperative ("SWTC") Tucson Electric Power ("TEP") / UniSource Energy Services ("UES") Western Area Power Administration ("WAPA") Interstate Transmission Projects Located in Arizona 3. Developments at the Palo Verde Hub: Risk Assessment and WECC Catastrophic Outage Guide, presented by Staff Disturbances that occurred on July 28, 2003 and June 14, 2004 Experience of Palo Verde Hub interconnected generation plants 13 14 The list of Workshop I participants is included in Appendix B. The Workshop presentation materials are located on the ACC website: http://www.cc.state.az.us 6 Overview November 2004 4. National and Regional Transmission Issues including: WestConnect/WesTTrans update August 14, 2003 Eastern U.S. blackout implications for Arizona utilities Right of way ("ROW") vegetation management and bark beetle infestation mitigation Federal reliability legislation FERC large generator interconnection rule impacts Technical transmission challenges re: interconnection of renewable generation In addition to the four panels, the Staff presented their response to the 2004 RMR Study Results. Staff's opinion is that the Transmission Providers presented enough information to allow a suitable assessment of the status of Arizona's transmission system reliability. Stage 2. Preparation of initial draft report and industry comments on draft Staff and KEMA provided the first draft of the 2004 BTA report for industry review and comment. The first draft of the report was based on the utilities' filed plans and the participants' responses to questions raised at Workshop I. 1 5 The draft report and industry comments were placed on the Commission website to expedite the review process. Stage 3. Workshop II: Staff/KEMA presentation and final report Workshop II, organized on September 24, 2004, presented the Staff's response to industry comments on the first draft of the 2004 BTA Report and allowed for discussion and questions. The Workshop again provided an informal setting to promote effective discussions of the p esentations from transmission r providers and merchant plant developers. The Workshop II participants included: 16 Arizona Transmission Providers Merchant Transmission and Generation Developers Siting Committee Members Consumer Advocates Service List Members.1 7 15 16 Transcripts of June 30, 2004 Workshop I The lis t of Workshop II participants is included in Appendix B. 17 The Workshop presentation materials are located on the ACC website: http://www.cc.state.az.us Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 7 The workshop was organized in one main session followed by an open period of discussion and audience questions. To facilitate focused and meaningful presentations and discussions at the Workshop, Staff provided a copy of the draft report several weeks before the Workshop. The Staff and their consultant presented 5 major issues and 6 less significant issues for discussion. The 5 major issues were: 1. Near-term Palo Verde transmission's ability to handle full generation output as discussed on draft BTA, page 3; 2. A similar issue discussed on draft BTA, page 57; 3. How the Arizona system meets the "n-1" criteria and relationship to RMR studies as discussed on draft BTA, page 3; 4. The economic viability of generators at the Palo Verde Hub as discussed on draft BTA, page 57; and 5. The responsibility of generators in regard to transmission expansion as discussed on draft BTA, page 3. The 6 less significant issues were: 1. Specific wording regarding the RMR studies discussed on draft BTA, page 3; 2. Consistency in data used in the RMR studies as discussed on draft BTA, page 49; 3. What party should maintain a study database as discussed on draft BTA, page 19; 4. Inconsistent and inaccurate generation data in Table 15 as discussed on draft BTA, page 96; 5. The need for new capacity in the Phoenix area by 2012 in regard to RMR studies as discussed on draft BTA, page 97; and 6. The treatment of the costs assigned to un-served energy in the RMR studies as discussed on draft BTA, page 97. In addition, there was a presentation by SRP regarding the installed generation and transmission capacity at the Palo Verde Hub during the 2000-2010 period. All the issues presented were resolved successfully as a result of the Workshop discussions and are reflected in this final report. 8 Overview November 2004 2. Related Regulatory Activities This section describes selected regulatory and industry activities since the 2002 BTA. Only those activities related to transmission infrastructure, transmission grid expansion at regional and sub-regional levels, transmission congestion, transmission reliability, and transmission rights and pricing are described. This section considers how such activities relate to the transmission expansion, siting and analysis in Arizona. 2.1 2.1.1 Relevant FERC Orders and Actions, and Arizona Industry Response FERC Activities Following the August 14, 2003 Blackout On August 14, 2003, an electric power blackout occurred that affected large portions of the Northeast and Midwest United States and Ontario, Canada. The following day, a U.S.-Canada Power System Outage Task Force ("Task Force") was established to investigate the causes of the blackout and recommend measures to reduce the possibility of future outages. The Final Report of this Task Force (April 5, 2004) identified four categories of causes: 1. Inadequate system understanding; 2. Inadequate situational awareness; 3. Inadequate tree trimming; and 4. Inadequate reliability coordinator diagnostic support Although none of the categories related to transmission planning issues, the Final Report found that several entities violated NERC operating policies and planning standards, directly contributing to the blackout. The Final Report found that many of NERC's policies are unclear and ambiguous. In addition the task force report found that tree contact with transmission lines was a precipitating factor in the blackout. The FERC took prompt action in response to recommendations issued by the Task Force by clarifying its power grid reliability policies and objectives. In a related order, FERC directed transmission-operating utilities to report on vegetation management practices in transmission corridors. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 9 2.1.1.1 FERC Policy Statement on Bulk Power System Reliability FERC issued a Policy Statement on Matters Related to Bulk Power System Reliability. 1 8 (Issued April 19, 2004). This policy statement responded to recommendations in the U.S.-Canada Power System Outage Task Force's Interim and Final Blackout Reports on initiatives FERC should undertake. It also responded to comments submitted after FERC's December 1, 2003 public conference on actions it should take to promote reliable transmission service in interstate commerce. The Policy Statement clarified FERC's policy with regard to: The need to promptly modify existing bulk power system reliability standards, to translate them into clear and enforceable requirements. Public utility compliance with industry reliability standards and possible FERC action to address specific bulk power system reliability issues. Cost recovery of prudent bulk power system reliability expenditures. The need for communication and cooperation between FERC and the States. The need for communication and cooperation among FERC, Canada and Mexico regarding reliability issues. Consideration of reliability in FERC's decision-making. Limitations on utility liability. The Policy Statement immediately took the following steps: No new Independent System Operator (ISO) or Regional Transmission Operator (RTO) will be allowed to begin operations until its reliability capabilities are functional. FERC will consider the reliability implications of its decisions, as appropriate. FERC will appoint a staff task force to report on potential funding mechanisms for NERC and the regional reliability councils to ensure their independence from the utilities they monitor. The staff task force will work closely with FERC's Canadian counterparts, state regulatory authorities, NERC, regional reliability councils and the industry. FERC staff was directed to draft a memorandum of understanding ("MOU") defining NERC's working relationship with FERC. The MOU will clarify FERC's appropriate role in NERC oversight and the respective reliability responsibilities of both NERC and FERC. 18 FERC DOCKET No. PL04-5-000 Policy Statement on Matters Related to Power System Reliability http://www.ferc.gov/whats-new/comm-meet/041404/E-6.pdf 10 Regulatory Activities November 2004 2.1.1.2 FERC Order on Vegetation Management Practices FERC also issued a companion vegetation management order.1 9 (issued April 19, 2004) FERC sought to minimize the risk of another regional blackout and ordered all entities that own, operate or control designated transmission facilities to report on their vegetation management practices by June 17, 2004. The Order, applicable to the lower 48 states, was directed to approximately 200 transmission providers, regardless of whether they are subject to FERC's jurisdiction as a public utility, in accordance with FERC's reporting authority. Designated transmission facilities are power lines of 230 kV or higher as well as tie -line interconnection facilities between control areas or balancing authority areas (regardless of voltage rating) and "critical" lines as previously designated by a regional reliability council. The Order directed the transmission providers to: Describe in detail the vegetation management practices and standards that the provider uses for vegetation control near designated transmission facilities; List those designated facilities under the provider's control; Indicate how often the facilities are inspected for vegetation management purposes and indicate when the most recent survey was completed; Indicate whether any necessary remediation has been completed as of June 14, 2004; and Describe any factors that prevent or unduly delay adequate vegetation management. FERC directed that the reports also must be submitted to appropriate state regulatory commissions, NERC and the relevant reliability coordinators: "In order that this information be received before the summer peak load season, which typically has maximum transmission line loading and continued vegetation growth, this report should be submitted by June 17, 2004 to the Commission, the appropriate State commissions2 0 , the North American Electric Reliability Council ("NERC") and the relevant reliability authorities."2 1 19 FERC Docket No. EL04-52-000 Reporting by Transmission Providers on Vegetation Management Practices Related to Designated Transmission Facilities http://www.ferc.gov/whats-new/comm-meet/041404/E-7.pdf 20 Some transmission providers are not subject to the jurisdiction of a State Commission. We request, however, that they serve a copy of the report on all State Commissions for States in which their transmission facilities are located. 21 FERC Order Requiring Reporting by Transmission Providers on Vegetation Management Practices Related To Designated Transmission Facilities, 107 FERC 61,053, Page 1-2. A reliability authority is the entity responsible for the safe and reliable operation of the interconnected transmission system for its defined "reliability authority area." This term is replacing the term "reliability coordinator" which has the same meaning and is still in common use in many areas. The term reliability authority as used in this order refers to the corporate entity responsible for reliability, which may be called either the reliability authority or the reliability coordinator for its area. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 11 The ACC received the vegetation management reports from Arizona utilities as required2 2 . Arizona is commonly thought of as a desert that does not require vegetation management. This is incorrect. For example, Salt River Project ("SRP") alone has over eight million trees to maintain in and around its utility corridors. Vegetation management in Arizona is complicated by the involvement of federal agencies. In Arizona there are five National Forests, and 22 Forest Service districts, for which Federal authorities dictate to the utility how much clearance they can or cannot give around utility lines and when they can have right of way access for such activities. Numerous forest fires in Arizona and New Mexico have placed multiple transmission lines in operational jeopardy over the past five years due to inadequate vegetation management of transmission corridors. Therefore, the ACC, and other entities involved in requiring reliable service of transmission providers need to assure vegetation management receives proper and consistent attention irrespective of land ownership. FERC's September 7, 2004 report 2 3 to Congress summarizes its findings and recommendations. In this report, the FERC also recommended that Congress enact legislation providing for mandatory, enforceable reliability rules. The FERC recognized that, while the data filed in response to the Vegetation Management Order revealed each transmission owner's practice, it did not directly address how effective the practice has been in limiting preventable transmission line outages. The FERC did not ask for such data in the April request, because similar data are now being reported to the WECC and to NERC. Transmission owners reported that they were not able to acquire all necessary permits to maintain their rights-of-way from various federal and state agencies. The transmission owners reported that vegetation management approvals on federally managed rights-of-way are particula rly problematic in the Western United States. However, FERC stated that this problem could be alleviated, at least in part, if the acquisition of these permits is made a higher priority on the part of transmission owners. For instance, transmission owners could allow additional lead-time to acquire many needed permits. The agencies responsible for issuing permits, however, should ensure that they have clear rules and procedures for issuing permits in a timely manner. The FERC believes that better coordination among federal agencies and between the federal and state governments to develop clear, consistent policies and procedures for timely and effective vegetation management by transmission owners could help to alleviate many real and perceived obstacles to proper vegetation management. 22 23 These reports are available on FERC's website. Utility Vegetation Management and Bulk Electric Reliability Report from the Federal Energy Regulatory Commission, September 7, 2004. FERC reported that Tucson Electric Power Co. did not perform all identified vegetation management remediation by the June 14, 2004 reporting date. Upon further review of the data submitted by TEP to FERC and the ACC and comments relative to the draft BTA Staff has determined that TEP had performed vegetation management remediation required for reliable operation of their system through the summer of 2004 and had delayed some additional vegetation management of a non-critical nature until the winter season.. 12 Regulatory Activities November 2004 Summary of FERC's Recommendations 1. 2. The United States Congress should enact legislation to make reliability standards mandatory and enforceable under federal oversight. Effective transmission vegetation management requires clear, unambiguous, enforceable standards that adequately describe actions necessary by each responsible party. With respect to any jurisdictional issue that may arise involving vegetation management, it is important that state and federal regulators continue to coordinate so that jurisdictional considerations do not impede effective vegetation management. Federal and state regulators should allow reasonable recovery for the costs of vegetation management expenses. While permitting and environmental requirements properly protect public lands, the procedures implementing those protections may be inconsistent and timeconsuming and have the potential to significantly hinder transmission vegetation management. The FERC should work with the Council on Environmental Quality ("CEQ") and land management agencies to better coordinate these requirements. Federal, state and local land managers should develop "rush" procedures and emergency exemptions to allow utilities to correct "danger" trees2 4 that threaten transmission lines, from both on and off documented rights-of-way. Five-year vegetation management cycles should be shortened, and the FERC and states should look at the cost-effectiveness of more aggressive vegetation management practices. Transmission owners should fully exercise their easement rights for vegetation management and better anticipate and manage the permitting process for scheduled vegetation management. Variances in vegetation management practices may be resolved in the NERC vegetation management standard development process; if they are not, the FERC may seek to convene the industry, states and other stakeholders to address the remaining issues. State regulators and the utility industry should work through the National Association of Regulatory Utility Commissions ("NARUC"), the National 3. 4. 5. 6. 7. 8. 9. 10. 24 A danger tree is a tree that is dead or dying and has the potential to fall into a right-of-way close to a line. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 13 Conference of State Legislators, and other organizations to help state and local officials better understand and address transmission vegetation management. 2.1.2 FERC Large Generation Interconnection Standards On July 24, 2003, FERC issued Order 2003, Standardization of Generator Interconnection Agreements and Procedures.2 5 The Final Rule became effective on October 20, 2003. The FERC adopted this rule to be used by Transmission Providers with Interconnection Customers proposing to interconnect a generator of more than 20 MW. The FERC initially required that all transmission providers amend their Open Access Transmission Tariffs ("OATT") with the new standards by the end of October 2003. However, the October deadline was extended until January 20, 2004. Summary of Final Rule The final rule is composed of two parts: 1. Standard Large Generator Interconnection Procedures ("Final Rule LGIP") sets forth the procedures that Interconnection Customers and Transmission Providers are required to follow during the interconnection process. The Final Rule LGIP sets forth the legal rights and obligations of each party, addresses cost responsibility issues, and establishes a process for resolving disputes; and 2. Standard Large Generator Interconnection Agreement ("Final Rule LGIA") applies to any new Interconnection Request to a Transmission Provider's Transmission System. New Interconnection Requests include those submitted after the effective date of this Final Rule and include requests to increase the capacity of, or modify the operating characteristics of, an existing Generating Facility that is interconnected with the Transmission Provider's Transmission System. The FERC is not requiring any retroactive changes to individual (versus generic) interconnection agreements filed with the FERC prior to the effective date of this Final Rule.2 6 In its March 3, 2004 Order No. 2003-A, FERC reaffirmed its July 2003 rule ("Order 2003").2 7 Responding to requests for clarification of its pricing policy for network upgrades, FERC made it clear that the transmission provider continues to have the option to charge the interconnected customer a transmission rate that is the higher of the incremental cost rate for the network upgrades required to 25 FERC Docket No. RM02-1-000; Order No. 2003, Standardization of Generator Interconnection Agreements and Procedures, (Issued July 24, 2003) http://www.ferc.gov/whats-new/comm-meet/072303/E-1.pdf 26 27 Docket No. RM02-1-000, Order 2003, July 24, 2003, Page 2 FERC Docket No. RM02-1-001; Order No. 2003-A, Standardization of Generator Interconnection Agreements and Procedures, (Issued March 3, 2004) http://www.ferc.gov/whats -new/comm- meet/030304/E- 1.pdf 14 Regulatory Activities November 2004 interconnect its generating facility or the average embedded cost rate for the entire transmission system (including the cost of the network upgrades). FERC emphasized that allowing transmission providers to charge the "higher of" rate ensures that other transmission customers, including the transmission providers' native load, will not subsidize network upgrades required to interconnect merchant generation. FERC granted rehearing on two aspects of Order 2003's method for reimbursing generators for the cost of financing network upgrades needed to complete the interconnection: 1. They will no longer require the transmission provider to provide credits to the interconnection customers for all of the transmission delivery services it takes on the system; instead credits are provided only for the transmission delivery service taken by the interconnecting generating facility. 2. They will allow the transmission provider to choose, five years from the commercial operation date of the generating facility, whether to reimburse the interconnection customer at that time for any remaining balance of the cost of financing network upgrades and accrued interest, or continue to provide credits beyond five years until no balance remains. FERC also concluded, as it did in Order 2003, that it would allow additional flexibility to interconnection pricing proposals that are filed by an independent transmission provider. An independent transmission provider does not have an incentive to discourage new generation by competitors, and should be afforded more flexibility in manner of cost recovery. Consequently, an independent transmission provider has no obligation to reimburse generators for the financing of the network upgrades, but rather has an opportunity to offer transmission rights and financial products instead. The new Generation Interconnection Standards establishes two types of interconnection: Energy Resource Interconnection Service that allows the Interconnection Customer to connect the Large Generating Facility to the Transmission System and be eligible to deliver the Large Generating Facility's output using the existing firm or non-firm capacity of the Transmission System on an "as available" basis. The interconnecting generator must make a separate application for transmission service with the Transmission Provider for transmission service. Energy Resource Interconnection Service does not provide any rights for transmission service. This type of interconnection usually requires minimal network upgrades if any. Network Resource Interconnection Service requires the Transmission Provider to conduct the necessary studies and construct the Network Upgrades needed to integrate the Large Generating Facility: (1) in a manner comparable to that in which the Transmission Provider integrates its generating facilities to serve native load customers; or (2) in an Independent System Operator ("ISO") or Regional Transmission Organization ("RTO") with market based congestion management, in the same manner as all Network Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 15 Resources. Network Resource Interconnection Service does not provide any rights for transmission service; however, it does qualify the resource to serve network customer load using the transmission system. An Energy Resource type of interconnection adopts the "minimum interconnection standard" that FERC established via numerous precedents to Orders 2003 and 2003-A. This type of interconnection usually does not require any network upgrades. Interconnecting a new generator at a substation that does not have sufficient transmission capacity to deliver the generator's full output for all load conditions and transmission system topologies, creates a generation pocket. This could require reducing the generator's output or automatic unit tripping. The Arizona utilities' presentations at Workshop I provided useful information on generation interconnection requests in Arizona.2 8 Each transmission provider maintains its own generation interconnection queue, and keeps it publicly available at the utility page of the WesTTrans.net Open Access Same-time Information System ("OASIS") website.2 9 For jointly owned facilities the operating agent takes the lead in the study work and shares results with the other owners. The Palo Verde transmission system has an interconnection procedure explicitly describing the steps required for generation interconnection with the hub. In the Palo Verde Hub case, there is also an ad hoc group, which looks at those impacts. While this procedure complies with FERC Orders 2003 and 2003A, it would be valuable, from the Arizona resource planning perspective, that an organization such as SWAT maintains an integrated generation interconnection queue for the whole state. This integrated list would not have any legal implication on execution of the required studies or interconnection agreements, but would provide a quick insight on generators' overall interest to interconnect in Arizona. With regards to generation interconnection in Arizona, an additional problem is driven by the fact that many transmission lines are jointly owned by jurisdictional and non-jurisdictional entities. When this issue was raised before FERC, jurisdictional transmission providers, in cooperation with the nonjurisdictional entities, were instructed to propose changes to the ir joint participation agreements. Nonjurisdictional transmission entities may not pay transmission credits in the exact way jurisdictional entities must. Non-jurisdictional utilities with Safe Harbor Open Access Transmission Tariffs ("OATTs"), such as SRP, WAPA and SWTC, are required to charge rates for interconnections that are comparable to what such non-jurisdictional transmission entities charge their own or affilia ted generation for interconnection. 28 29 Workshop I Transcript, Page 167, Lines 17-25, and Page 168, line 1-6 The wesTTrans.net OASIS http://www.oatioasis.com/cwo_default.htm 16 Regulatory Activities November 2004 Western utilities, including Arizona's, filed proposed variations from the pro forma LGIP and LGIA. The utilities stated that the proposed variations were based on existing regional reliability standards applicable to WECC, the Northwest Power Pool ("NWPP"), and the Southwest Reserve Sharing Group ("SRSG"). In its June 4, 2004 Order, FERC accepted in part, rejected in part, and modified in part, the proposed regional reliability variations. 3 0 It appears that FERC approved all significant reliabilitystandard related requirements. 2.1.3 FERC Standard Market Design As noted in the 2002 BTA Assessment, FERC proposed a Standard Market Design ("SMD"). The purpose of the SMD was to have all regions of the US implement standardized wholesale power markets. FERC originally anticipated that a final SMD rule would be approved in 2003. However, due to the objections of numerous stakeholders, state regulators and Congressional delegations, FERC has not acted to finalize the rule. FERC issued a White Paper entitled "Wholesale Power Market Platform" responding to the comments on FERC's SMD proposal and providing direction for the final rule.3 1 The White Paper focuses on the formation of RTOs, and on sound wholesale market rules for all independent transmission organizations. Additionally, the White Paper indicates that the final rule will allow variable implementation schedules, depending on local needs. According to the White Paper, the final ruling will focus on: The formation of RTOs; and Ensuring that all RTOs and ISOs have good wholesale market rules in place. The final rule will require public utilities to join an RTO or ISO. The final rule will also allow for phased-in implementation customized to each region. FERC states that certain elements need to be in place for successful wholesale markets: Regional Transmission Planning Process FERC maintains that regional planning of the transmission grid is essential. The Final Rule will require technical assessments of the regional grid by the RTO or ISO. FERC expects the Final Rule to require the RTOs and ISOs to have a regional planning process in place as soon as possible. Fair Cost Allocation for Existing and New Transmission Costs associated with the existing grid (other than those directly assigned) will continue to be recovered though rates. The rates should be structured to allow customer access across multiple utility 30 31 http://www.ferc.gov/EventCalendar/Files/20040607074124-ER04-442-000.pdf FERC White Paper: Wholesale Power Market Platform, (Issued April 28, 2003) http://www.ferc.gov/industries/electric/indus-act/smd/white_paper.pdf Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 17 grids in a region at a single rate. Regional state committees may agree on the form of access charge that will be filed by the RTO or ISO. Market Monitoring and Market Power Mitigation FERC intends to look closely at mitigation proposals to assure suitability for the RTO's or ISO's regional markets and for their compatibility with neighboring RTOs and ISOs. Spot Markets to Meet Customers' Real-Time Energy Needs Under the Final Rule, the RTO or ISO will be constrained to use a real-time market for energy to resolve imbalances. The RTO or ISO in each region will be required to develop detailed market rules that will be included in the tariffs filed with FERC. Additionally, the RTO or ISO will be required to introduce a day-ahead market and a market for various ancillary services. Transparency and Efficiency in Congestion Management Regions will be required to develop a congestion-management approach that will protect against manipulation, will use the grid efficiently, and will promote use of the lowest cost generation. Firm Transmission Rights ("FTRs") Those RTOs and ISOs that use location marginal pricing to manage congestion will be required to make firm physical transmission service available to customers. In the Final Rule, RTOs or ISOs that have not addressed FTRs will be required to do so. Resource Adequacy Approaches In the Final Rule, each region with an RTO or ISO will determine how it will ensure that there are adequate regional resources to meet customers' needs. Regional Independent Grid Operation RTOs must meet the four minimum characteristics of independence, scope and regional configuration, operational authority, and short-term reliability. FERC notes that the lack of independence provides an incentive for those who own generation and operate transmission facilities to operate the system in ways that exclude competing suppliers and can allow the exercise of market power. This conflict of interest can be remedied through structural separation of transmission operation from other wholesale market activities. FERC states that regional operation is crucial to reliability and efficiency. The final rule will allow flexibility on the scope and configuration of RTOs and ISOs, and will not require ISOs to meet the scope and regional configuration requirement. However, interregional coordination between RTOs and ISOs must be actively pursued. 18 Regulatory Activities November 2004 2.1.4 Update on the FERC RTO Order 2000 and WestConnect RTO FERC's Order 2000 presents FERC's desire for RTOs across the continental United States.3 2 ISOs and RTOs have in fact been implemented in the Northeast part of the country ("PJM", "NY-ISO", "ISO-NE"), the Midwest region ("MISO"), and in California ("CAISO"). FERC's April 28, 2003 FERC White Paper emphasized their strong commitment to customer-based, competitive wholesale power markets, while underscoring an increasingly flexible approach to regional needs and outlining step-by-step elaborations of its key market design proposal. In its final rule, the White Paper said FERC would focus on the formation of RTOs and on ensuring that all independent transmission organizations have sound wholesale market rules. The final rule would allow implementation schedules to vary depending on local needs, and would allow for regional differences. The White Paper notes that FERC's proposal has taken into consideration the experiences in this country and abroad in electric market design, including the effects of supply shortages, demand that does not respond to high prices, lack of price transparency in the marketplace, and the importance of market monitoring and market power mitigation. In September 2001, Arizona Public Service Company, El Paso Electric Company, Public Service Company of New Mexico and Tucson Electric Power Company filed with FERC a Request for Declaratory Order that the proposed WestConnect RTO, developed through an open, participatory process that included, among others, Salt River Project and Western Area Power Administration, met the requirements of Order 2000. FERC issued a Declaratory Order on WestConnect in October 2002, conditionally accepting the filing. However, in its Declaratory Order and subsequent Order on Rehearing, FERC removed some of the transmission owners' "must have" features and called into question the ultimate acceptability of others. In response to FERC's orders on the WestConnect RTO filing and the FERC SMD White Paper, issued April 2003, Southwest transmission owners, including investor-owned and non-jurisdictional utilities, decided to pursue development of a phased approach for the incremental and cost-effective implementation of wholesale transmission market improvements in the Southwest region that bring identified benefits to transmission customers. One of the significant steps in WestConnect's phasing was partnering with other western utilities, including a number of non-jurisdictional transmission owners, to implement WesTTrans.net. WesTTrans.net is a common OASIS platform operated by a third party that is open to participation by all transmission providers in the Western Interconnection. The wesTTrans.net OASIS platform went on-line in March 2004 and now has 20 participating transmission owners. WestConnect parties are working on steps to augment regional market interface and increase transmission market transparency. It will continue to work with stakeholders to identify additional cost-effective solutions to existing transmission market challenges that will benefit transmission customers. 32 FERC Order 2000, http://www.ferc.gov/legal/ferc -regs/land-docs/RM99 - 2A.pdf Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 19 2.2 2.2.1 Arizona Corporation Commission Actions Arizona Implementation of Special Reliability Requirements In order to obtain ACC Staff support for approval of applications for Certificate of Environmental Compatibility ("CEC"), new generators in Arizona cannot rely on generator unit tripping for a single transmission facility outage.3 3 Staff's position is based on a principle that requires that adequate transmission is planned to assure reliable service of the full output of all interconnected generation without having to implement congestion management for single contingency transmission outages. In other words, Arizona wants energy from new generation to be firm rather than offered on an "as available basis." This would imply Arizona's preference for generation with Network Resource Interconnection Service as defined by FERC. The Commission has endorsed Staff's position that generators and load serving entities share the obligation to ensure adequate and reliable transmission service in Arizona.3 4 Consequently, new generators are required before commencing commercial operation to demonstrate adequate transmission delivery without relying on remedial action such as generator tripping, load shedding or remedial action schemes for single contingency transmission outages. Some of the new generation interconnections at the Palo Verde Hub have failed to adhere to this planning philosophy and therefore lack adequate near-term transmission capacity to deliver to some markets. By interconnecting via single transmission lines to the Palo Verde Hub these generation projects have also jeopardized the regional system reliability and supply for extreme outage contingencies. This practice also limits Arizona load serving entities' purchase of firm capacity from such units unless they are willing to raise their own system reserve requirements for loss of these units as their largest single hazard. The recent practice of electronic tagging ("E-tag") such merchants' unit contingent power as a firm transmission transaction has also just recently become an issue for the WECC Operating Committee. For the above reasons, Staff joined APS and SRP in sponsoring a new WECC planning guideline for consideration of extreme contingencies at large generation hubs. The guideline has gone through the WECC comment period and is not being pursued further due to lack of industry support. Nevertheless, Staff, APS and SRP have committed to implementing such guidelines in Arizona irrespective of WECC inaction. 3 5 In addition, Staff has been actively discussing with FERC Staff the need for a more balanced approach to considering reliability versus commercial practices both in a planning context and an operational context. 33 Guiding Principles for ACC Staff Determination of Electric System Adequacy and Reliability See Appendix A, Generation, Under 1 34 Second BTA, Decision No. 65476. 35 Palo Verde to Southwest Valley (RUDD) 500 kV Line, Docket No. L-00000D-01-0115, Condition No. 23. 20 Regulatory Activities November 2004 2.2.2 Electric Re-Structuring Activities The Commission issued a procedural order on January 22, 2002, which opened a generic docket on electric restructuring. 3 6 A subsequent procedural order issued on February 8, 2002, served the purpose of consolidating the generic docket with the following related cases already active before the Commission: Docket No. E-01345A-01-0822, APS variance request to A.A.C. R14-2-1606 Docket No. E-01933A-02-0069, TEP variance request to certain competition rule compliance dates Docket No. E-01933A-98-0471, TEP application for approval of its stranded cost recovery Docket No. E-00000A-01-0630, Proceedings concerning the Arizona Independent Scheduling Administrator ("AzISA") Docket No. E-00000A-02-0051-ETAL Decision No. 65154 Track A Proceedings Decision No. 65143 Track B Proceedings The Track A proceeding concluded with a decision rendered by the Commission on September 10, 2002. 3 7 The opinion and order approved by the Commission was in general agreement with Staff's recommendations on transmission issues and encouraged an industry-wide planning process to resolve transmission constraints. 3 8 The Commission also believed that both transmission providers and merchant power plants should share the burden and obligation to resolve Arizona's transmission constraints. The FERC Order 2003 from July 2003 and 2003 A from March 2004 set up the clear rules on cost allocation and crediting policy related to the transmission upgrades now required for the new generators. At the Track A hearing, APS agreed that all generators designated as network resources, including both utility and merchant generators, would have access to transmission currently used by the utilities to serve their native load customers. There was also testimony establishing that existing transmission constraints in Arizona will limit APS' (and TEP's) ability to deliver competitively procured supply to less than the required 50% of Standard Offer Service load. 2.2.3 Commission Concern on Local Area Transmission Constraints and RMR The transmission constraints limiting APS' and TEP's ability to comply with the aforementioned Commission rules result from their dependence upon local RMR generation to serve their peak load 36 37 38 ACC Staff Report on the Generic Electric Restructuring, Docket No. E-00000A-02-0051, March 22, 2002 Decision No. 65154, Docket No. E-00000A-02-0051, et al., September 10, 2002. Ibid, page 25 at line 23. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 21 during certain hours of the year. RMR needs result from an economic decision to balance local generation and transmission capabilities to serve loads in the most economical manner. The Track A order stipulates that APS and TEP are to work with Staff to develop a 2002 study process to resolve RMR generation concerns and that such study plan results are to be included in the 2004 Biennial Transmission Assessment.3 9 This includes studying and analyzing the merits of existing dependence on RMR generation instead of building transmission to resolve transmission import constraints, and the merits of any future contemplated utilization of RMR to defer transmission projects. Until the 2004 Biennial Transmission Assessment is issued with RMR study plan results resolved, APS and TEP are to file annual RMR study reports with the Commission in concert with their January 31 annual ten-year plan for review prior to implementing any new RMR generation strategies.4 0 The 2003 and 2004 RMR procedural overview, defined through the ACC Track A Decision No. 65154, required that RMR studies be filed by APS and TEP (with the cooperation of the industry) by January of 2003. These studies were to analyze the 2003 2005 time-period. By January of 2004, APS and TEP were to complete their study efforts extending the time frame out for the 10-year period. Results of both RMR study efforts have been incorporated into the 2004 BTA report. 2.2.4 2003 Competitive Resources Solicitation The Commission's retail electric competition rules, in place since September 29, 1999, required that at least 50% of the power supply for Standard Offer Service by an investor owned utility distribution company ("UDC") will be purchased through a competitive bid process.4 1 That same UDC has the obligation to assure that adequate transmission import capability is available to meet the load requirements of all distribution customers within its service area. In its Track A order, the Commission stayed Rule 14-2-1606.B and required APS and TEP to competitively procure no less than all of Standard Offer Service requirements that they could not supply from utility-owned resources.4 2 Actions by the Commission and the utilities in 2002 and 2003 resulted in a competitive solicitation by APS and TEP for some generation requirements. That was referred to as Track B proceedings. The Track B proceedings decision 4 3 required that the results of the 2003 - 2005 RMR studies should be reflected in the contestable load requirements that those two utilities would be required to bid in their competitive solicitation. The industry responded very effectively in getting that RMR information in a very short period of time. 39 40 Decision No. 65154, Docket No. E-00000A-02-0051, et al., September 2002. Ibid, Finding of Fact 41. 41 A.A.C R14-2-1606.B, Decision No. 61969. 42 43 For this analysis, APS generation does not include the Redhawk and West Phoenix units owned by PWEC. Track B, Final Decision No. 65743, Docket No. E-00000A-02-0051 22 Regulatory Activities November 2004 2.2.5 Arizona Electric Utility Reorganizations Two major utility reorganizations have occurred in Arizona since the Second BTA report was issued. The Arizona Electric Power Cooperative ("AEPCO") reorganized into three affiliate organizations to facilitate its participation in electric competition and direct access in Arizona. The resulting affiliates are the AEPCO generation affiliate, a transmission affiliate Southwest Transmission Cooperative ("SWTC"), and a marketing affiliate Sierra Southwest Cooperative Services. Secondly, UniSource Energy Corporation acquired the Citizens Utilities electric and gas facilities in Arizona and formed two new affiliates in 2003, UniSource Energy Services ("UES") and UES Gas. There is a UniSource Energy Corporation application currently pending before the Commission seeking approval for purchase by a private investor group. The Commission also has a third reorganization pending in the APS rate case. APS proposes to acquire and rate base its affiliate's, Pinnacle West Energy Corporation, Arizona generation assets. There are a number of economically stressed new merchant plants currently constructed in Arizona in search of a sufficiently robust market or new ownership. This may lead to other acquisitions and mergers in the local industry. 2.2.6 Arizona Independent Scheduling Administrator ("AzISA") The AzISA is a non-profit corporation, created in 1998 under the laws of the state of Arizona, for the purpose of facilitating the development and function of competitive retail markets in Arizona. AzISA was created according to a Commission rule, which stipulates that the affected utilities that own and operate Arizona transmission facilities shall form an Arizona independent scheduling administrator.4 4 AzISA is focused on administrating Arizona retail transmission transactions according to protocols on file with FERC while WestConnect will be focused on all transmission transactions that occur within the RTO and with other RTOs. The following planning related functions are required of AzISA, under R14-2-1609 (D): The AzISA shall implement a transmission planning process that includes all AzISA participants and aids in identifying the timing and key characteristics of required reinforcements to Arizona transmission facilities to assure that the future load requirements of all participants will be met. The AzISA Board adopted a staged implementation of its functions based on the extent to which a robust retail market would develop, and the status of implementing a Desert Star or WestConnect RTO. As a result of this staged implementation, the planning functions were postponed to Phase II of AzISA's implementation plans. Important functions such 44 A.A.C. R14-2-1609.D. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 23 as dispute resolution for those serving the competitive load in Arizona, and monitoring of OASIS functions, are included in Phase I of AzISA's implementation. AzISA was also to participate in state transmission planning studies such as those of the Central Arizona Transmission System ("CATS") and Western Area Transmission System ("WATS") study groups. AzISA's role in such studies is to ensure that CATS satisfactorily addresses retail transmission needs and identifies transmission enhancements that would increase the load-serving capability in Arizona. 2.3 Western Governors Association Efforts While it is not a regulatory body, the Western Governors Association ("WGA") is addressing inter-state bulk-power reliability coordination. Recent actions that took place in the West to advance the Governors' energy policies for the region include the following:4 5 The Seams Steering Group-Western Interconnection issued its first interconnection wide transmission plan, Framework for Expansion of the Western Interconnection Transmission System, in October of 2003. Sub-regional transmission planning has commenced on a grand scale in the Western Interconnection: The Rocky Mountain Area Transmission ("RMAT") study was launched in September of 2003, The Southwest Transmission Expansion Planning ("STEP") group completed its first annual report and continues to study transmission needs between Arizona, Southern California, Southern Nevada area and Northern Mexico, The CATS forum has concluded its third annual report and in 2004 morphed into a larger sub-regional study forum called Southwest Area Transmission ("SWAT") that is considering transmission needs for Arizona, New Mexico, Southern California , Nevada, Utah, and Colorado area and The Northwest Transmission Alternatives Committee ("NTAC"). 45 Western Governors' Association 2003 Annual Report and Western Go vernor's Association 2004 Annual Report. 24 Regulatory Activities November 2004 Twelve Governors and four federal agencies have signed the WGA Transmission Permitting Protocol that provides for the collaborative review of proposed interstate transmission lines. A project has been launched to develop an interconnection-wide market for Renewable Energy Certificates. The value of a regional electricity body is currently being explored. In April of 2004, the Western Governors' Association convened a North American Energy Summit. Summit participants discussed energy supply, demand and infrastructure issues facing the United States, Canada, and Mexico. Summit recommendations and action items were developed during breakout sessions in five general areas:4 6 Ensuring an efficient and reliable electricity system in the North American West. Financing infrastructure development and new technologies attracting capital, risk management and cross-border cooperation. Developing renewable energy and increasing energy efficiency. Seeking cooperative action on laws and policies across state, tribal, and international bor ders. Guiding the future of oil, natural gas, coal and nuclear energy clean technologies, supply and demand, emission and waste strategies, carbon sequestration, gasification and transportation. Specific Summit recommendations relevant to transmission included: 1. In regard to Providing a Reliable and Efficient Western Electricity Grid the Governors should: Support mandatory reliability standards. Create a formal inter-regional state entity. Work with FERC to address competitive western wholesale markets, while states retain decisions on retail access. Ensure regional coordination on transmission planning/expansion. Address financing of new transmission. 46 Western Governors' Association, North American Energy Summit, April 16, 2004 Breakout Group Recommendations Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 25 Support the review and reform, if needed, of state transmission certification and siting laws. Process should determine need first. WGA Protocol is a good start on interstate coordination. Support a phased approach to meeting the objectives of independent system operator/regional transmission organizations. Support the development of vibrant and secure regional electricity markets that include a diverse mix of supply (including renewables) and demand resources. Support efforts to stimulate the deployment of new transmission technologies. Support funding for corridor designation work on federal lands. Support expanded funding for training of electric system engineers (e.g., via universities) and thereby expand the supply of engineers. Recognize that Attorneys General need to be involved. 2. In regard to Fuel Choice and Transmission the Governors should: Advocate the formulation and adoption of Transmission Policy. Level the playing field between generation and power supply options. Full utilization of existing transmission capacity, before building new. Elimination of discriminatory practices: rate pancaking, renewables. Proper cost allocation: beneficiaries and grid reliability. Legitimize the regional transmission planning venues within the WGA footprint. Stakeholder Input: governmental, tribal, public, and industry. Consideration of power supply and generation options: remote and at load. Proactive: lead-time for transmission is longer than for generation. Incentives for renewables (PTC) and improved environmental performance. 26 Regulatory Activities November 2004 3. Transmission Planning Individual utilities within the state of Arizona plan and design their bulk transmission systems in accordance with the NERC, WECC regional Reliability Criteria for System Planning and Minimum Operating Reliability, guidelines established at the state level, and their own internal planning criteria, guidelines and methods. These planning practices are utilized to ensure that their respective systems are planned to provide reliable service to customers under various system conditions. In addition, they ensure that neighboring utilities and neighboring states plan their systems in a coordinated manner by following a consistent set of standards, guidelines and criteria in order to provide an economical and reliable supply of electricity. This chapter addresses the standards and processes used by the Arizona utilities in developing transmission. 3.1 3.1.1 Transmission Reliability Standards NERC Reliability Standards The interconnected bulk electric systems in the United States, Canada, and the northern portion of Baja California, Mexico are comprised of many individual systems. Each system has its own: electrical characteristics; set of customers; geographic, weather, and economic conditions; and regulatory and political climates. By their very nature, the bulk electric systems involve multiple parties. Since all electric systems within an integrated network are electrically connected, whatever one system does can affect the reliability of the other systems. Therefore, to maintain the reliability of the interconnected bulk electric systems, all electric industry participants are required to comply with the NERC Planning Standards. The NERC Planning Standards define the reliability of the interconnected bulk electric systems using the following two terms: Adequacy -- The ability of the electric systems to supply the aggregate electrical demand and energy requirements of their customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements. Security -- The ability of the electric systems to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. It is usually considered that adequacy is related to system planning and security is related to system operation. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 27 NERC requires that systems must be planned to withstand the more probable forced outage and maintenance outage system contingencies at projected customer demand and anticipated electricity transfer levels. Extreme but less probable contingencies measure the robustness of the electric systems and should be evaluated for risks and consequences. NERC has four basic planning standards:4 7 S1. The interconnected transmission systems shall be planned, designed, and constructed such that with all transmission facilities in service and with normal (precontingency) operating procedures in effect, the network can deliver generator unit output to meet projected customer demands and provide contracted firm (non-recallable reserved) transmission services, at all demand levels, under the conditions defined in Category A of Table 1. S2. The interconnected transmission systems shall be planned, designed, and constructed such that the network can be operated to supply projected customer demands and contracted firm (non-recallable reserved) transmission services, at all demand levels, under the conditions of the contingencies as defined in Category B of Table 1. The transmission systems also shall be capable of accommodating planned bulk electric equipment maintenance outages and continuing to operate within thermal, voltage, and stability limits under the conditions of the contingencies as defined in Category B of Table 1. S3. The interconnected transmission systems shall be planned, designed, and constructed such that the network can be operated to supply projected customer demands and contracted firm (non-recallable reserved) transmission services, at all demand levels, under the conditions of the contingencies as defined in Category C of Table 1. The controlled interruption of customer demand, the planned removal of generators, or the curtailment of firm (non-recallable reserved) power transfers may be necessary to meet this standard. The transmission systems also shall be capable of accommodating planned bulk electric equipment maintenance outages and continuing to operate within thermal, voltage, and stability limits under the conditions of the contingencies as defined in Category C of Table 1. S4. The interconnected transmission systems shall be evaluated for the risks and consequences of a number of each of the extreme contingencies that are listed under Category D of Table 1. (NERC Planning Standards, September 16, 1997, Page 9-10) In summary, NERC requires that transmission systems should be planned to withstand both single contingency (Category B), and double or multiple contingencies (Category C). In addition NERC requires that transmission systems should be planned to withstand the same set of contingencies with one bulk facility out of service for planned maintenance. The extreme contingencies (Category D) require that transmission systems be evaluated for the risks and consequences, but not for planning reinforcements. 47 NERC Planning Standards, September 16, 1997 ftp://www.nerc.com/pub/sys/all_updl/pc/pss/ps9709.pdf 28 Transmission Planning November 2004 Table 1: NERC Transmission System Standards-Normal and Contingency Conditions Category Contingencies Initiating Event(s) and Contingency Element(s) A - No Contingencies All Facilities in Service Elements Out of Service None Thermal Limits Applicable Rating a (A/R) A/R A/R A/R A/R Voltage Limits Applicable Rating a (A/R) A/R A/R A/R A/R System Limits or Impacts System Stable Yes Loss of Demand or Curtailed Firm Transfers No Cascading c Outages No B - Event resulting in the loss of a single element. Single Line Ground (SLG) or 3-Phase (3 Fault, with Normal Clearing: 1. Generator 2. Transmission Circuit 3. Transformer Loss of an Element without a Fault. Single Pole Block, Normal Clearingf: 4. Single Pole (dc) Line Single Single Single Single Yes Yes Yes Yes No b No b No b No b No No No No Single A/R A/R Yes Nob No C - Event(s) resulting in the loss of two or more (multiple) elements. SLG Fault, with Normal Clearing f: 1. Bus Section 2. Breaker (failure or internal fault) SLG or 3Fault, with Normal Clearingf, Manual System Adjustments, followed by another SLG or 3Fault, with Normal Clearingf: 3. Category B (B1, B2, B3, or B4) contingency, manual system adjustments, followed by another Category B (B1, B2, B3, or B4) contingency Bipolar Block, with Normal Clearingf: 4. Bipolar (dc) Line Fault (non 3, with Normal Clearingf: 5. Any two circuits of a multiple circuit towerlineg SLG Fault, with Delayed Clearing f (stuck breaker or protection system failure): 6. Generator 8. Transformer 7. Transmission Circuit 9. Bus Section Multiple Multiple A/R A/R A/R A/R Yes Yes Planned/Controlled d Planned/Controlled d No No Multiple A/R A/R Yes Planned/Controlled d No Multiple Multiple A/R A/R A/R A/R Yes Yes Planned/Controlled d Planned/Controlled d No No Multiple Multiple A/R A/R A/R A/R Yes Yes Planned/Controlled d Planned/Controlled d No No Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 29 D e - Extreme event resulting in two or more (multiple) elements removed or cascading out of service 3Fault, with Delayed Clearing f (stuck breaker or protection system failure): 1. Generator 3. Transformer 2. Transmission Circuit 4. Bus Section 3Fault, with Normal Clearingf: 5. Breaker (failure or internal fault) Other: 6. 7. 8. 9. 10. 11. 12. Loss of towerline with three or more circuits All transmission lines on a common right-of way Loss of a substation (one voltage level plus transformers) Loss of a switching station (one voltage level plus transformers) Loss of all generating units at a station Loss of a large load or major load center Failure of a fully redundant special protection system (or remedial action scheme) to operate when required 13. Operation, partial operation, or misoperation of a fully redundant special protection system (or remedial action scheme) in response to an event or abnormal system condition for which it was not intended to operate 14. Impact of sev ere power swings or oscillations from disturbances in another Regional Council. Evaluate for risks and consequences. ay involve substantial loss of customer demand and generation in a widespread area or areas. ortions or all of the interconnected systems may or may not achieve a new, stable operating point. valuation of these events may require joint studies with neighboring systems. a) b) c) d) e) f) g) Applicable rating (A/R) refers to the applicable normal and emergency facility thermal rating or system voltage limit as determined and consistently applied by the system or facility owner. Applicable ratings may include emergency ratings applicable for short durations as required to permit operating steps necessary to maintain system control. All ratings must be established consistent with applicable NERC Planning Standards addressing facility ratings. Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or supplied by the faulted element or by the affected area, may occur in certain areas without impacting the overall security of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted firm (nonrecallable reserved) electric power transfers. Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread service interruption which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies. Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted firm (non-recallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems. A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated. Normal clearing is when the protection system operates as designed and the fault is cleared in the time normally expected with proper functioning of the installed protection systems. Delayed clearing of a fault is due to failure of any protection system component such as a relay, circuit breaker, or current transformer (CT), and not because of an intentional design delay. System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station entrance, river crossings) in accordance with Regional exemption criteria. Source: NERC Planning Standards, June 15, 2001 30 Transmission Planning November 2004 3.1.2 WECC Reliability Standards WECC provides the coordination that is essential for operating and planning a reliable and adequate electric power system for the western region of the continental USA, Canada, and Mexico. The WECC member systems' transmission facilities are planned in accordance with the NERC/WECC Reliability Criteria for Transmission System Planning. These criteria establish the performance levels intended to limit the adverse effects of each member's system operation on others, and recommend that each member system provide sufficient transmission capability to serve customers, to accommodate planned inter-area transfers, and to meet its transmission obligation to others. The WECC Reliability Criteria adopted all the NERC criteria mentioned in section 3.1.1 and asks its members to comply with several additional requirements, two of which are more stringent than those in some other NERC regions: WECC-S2 The NERC Category C.5 initiating event of a non-three phase fault with normal clearing shall also apply to the credible common mode contingency of two adjacent circuits on separate towers. The credibility of such an outage depends upon the credibility of the common mode failure. The credible outage of two circuits could result from a lightning storm or forest fire. Considerations in the determination of credibility should include line design; length; location, whether forested, agricultural, mountainous, etc.; outage history; operational guidelines; and separation between circuits. The common mode simultaneous outage of two generator units connected to the same switchyard, not addressed by the initiating events in NERC Category C, shall not result in cascading. (NERC/WECC Planning Standard, August 8-9, 2002, Page 11) In summary, WECC requires that the outage of two adjacent circuits on different towers or the outage of two units at the same plant meet Category C. This is in addition to the requirement that transmission systems should be capable of withstanding the same set of contingencies with one bulk facility out of service for planned maintenance. WECC also adds voltage dip and frequency deviation requirements for the effects of outages on neighboring systems. All except two WECC planning standards are at least as stringent as the NERC standards. The two exceptions are C2 and C9. 4 8 WECC currently has been granted a waiver for these standards and analysis is ongoing to determine whether NERC should grant a variance.4 9 This exception is not required by the Arizona utilities as they comply with NERC's C2 and C9 standards. WECC-S3 48 49 C2-Breaker Failure, C9-Bus Section Failure Resource and Transmission Adequacy Recommendations, Prepared by the Resource and Transmission Adequacy Task Force of the NERC Planning Committee NERC Board of Trustees June 15, 2004, Table 2 Transmission Adequacy, (Revised 2/23/04) ftp://www.nerc.com/pub/sys/all_updl/pc/rtatf/RTATF_ReportBOTapprvd_061504.pdf Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 31 WECC's Reliability Management System ("RMS") agreement establishes a process to manage compliance with the established criteria. This process includes compliance monitoring, annual study reports, a project review and rating process, and an operating transfer capability policy group process. Compliance is ensured with regard to control performance, operating reserve and operating transfer capability, and disturbance control. While WECC members self-declare their compliance, WECC conducts compliance reviews through random audits. The RMS includes system operator requirements for managing transactions within major transmission path operating limits. WECC also addresses the unscheduled flow mitigation scheme approved by FERC. For reliable operation of the western interconnection, WECC requires all entities to comply with their Minimum Operating Reliability Criteria ("MORC")5 0 . MORC is applicable to system operation under all conditions even when facilities required for secure and reliable operation have been delayed or forced out of service. MORC principles applicable to the transmission system operation are: The interconnected power system shall be operated at all times so that system instability, uncontrolled separation, cascading outages, or voltage collapse will not occur as a result of single or multiple contingencies of sufficiently high likelihood. Continuity of service to load is the primary obje ctive of the MORC. Preservation of interconnections during disturbances is a secondary objective except when preservation of interconnections will minimize the magnitude of load interruption. Since electric system reliability is so vital to Arizona, Staff contends that it is appropriate to apply the most specific and stringent criteria. Thus the Staff supports WECC's MORC. 3.1.2.1 Transmission Paths in the WECC A grouping or set of transmission lines connecting two areas is often referred to as a transmission Path. Transmission paths consist of one or more lines emanating from a common location or between two regions. The performance of each transmission line within a transmission path is interdependent upon the performance of other lines in the same path. The adequacy and security of the whole transmission system is often determined by the performance of key and critical transmission paths. Transmission lines and paths are also rated in terms of their Total Transfer Capability ("TTC"). The TTC is the reliability limit of a transmission line or path. This rating is established by technical studies that consider the network topology and operational conditions affecting the adequacy and security of the transmission line or path. The thermal rating and the stability limit of transmission lines are both considered when establishing the TTC of transmission facilities. 50 http://www.wecc.biz/sdpp.html 32 Transmission Planning November 2004 WECC has an established process for determining the TTC of major transmission paths in the western interconnection. The transmission path consisting of lines between Arizona and California has the largest TTC of any established path in the Western Interconnection. The map in Figure 1 shows the nonsimultaneous TTC of the Arizona area for 2003. 5 1 Figure 1: Total Transfer Capabilities for Key WECC Transmission Paths (2003) DC 160 1,400 160 DC 850 1,920 7,550 690 820 1,500 420 DC 420 2,990 814 800 408 352 312 The paths of interest to Arizona are shown in Figure 2, and are defined below in Table 2. A path of particular interest to Arizona is Path 49, East of Colorado River ("EOR") that connects Arizona and California. Paths 22, 23, 50 and 51 all lie between Four Corners/San Juan and the Phoenix area. 51 WECC Ten Year Coordinated Plan Summary, December 2003, Page 54 Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 33 Figure 2: Western Interconnection Paths Table 2: WECC Paths in Arizona WECC Path # 22 WECC Path Name Southwest of Four Corners Four Corners Moenkopi Four Corners Cholla #1 Four Corners Cholla #2 Four Corners 345/500 kV Qualified Path New Mexico -Greenlee East of Colorado River Cholla - Pinnacle Peak Southern Navajo 23 47 49 50 51 3.1.3 Arizona Utilities Transmission Planning Standards The utilities in Arizona plan their system facilities by following NERC and WECC reliability standards. In addition, each utility in the State develops its own internal reliability criteria and planning processes to assist in planning its EHV 345kV and above, HV transmission system, and local areas. Each utility plans 34 Transmission Planning November 2004 the transmission system to operate with no thermal overloads on lines and equipment, and voltages within defined limits under normal and emergency conditions. The Arizona transmission system is planned based on NERC and WECC single contingency criteria. 5 2 These criteria require that there should be no loss of load on the system for a single element contingency. There are credible disturbances, which are not probable, for which it is not economically feasible to protect against. These criteria recognize the need for direct load tripping for more severe disturbances, but the load tripping should be controlled to limit the adverse impact of the disturbance. Uncontrolled load shedding is unacceptable even under the most adverse, credible disturbance. The Arizona utilities have provided detailed information regarding the assumptions, studies performed and criteria used in their 10-year plans. The studies include power-flow, stability, and short-circuit analyses. While it is not explicitly stated, it appears that the plans are developed to only meet NERC category A and B criteria --normal and single contingency conditions. No evaluations appear to be made of NERC category C or D criteria --multiple and extreme contingencies. As is discussed later in chapter 6 of this report, the utilities perform companion studies of transmission and generation requirements for local load pockets. In some cases, these studies include evaluations of NERC category C & D contingencies. It is not unusual in the U.S.A. transmission planning practices that transmission systems supplying large urban areas (RMR areas) have more stringent criteria than used for the rest of the system. Staff recommends that Arizona utilities collaborate with the Staff to develop and effectively implement appropriate criteria for RMR areas in the 2006 BTA. 3.1.4 Transmission Ratings Transmission facilities can be loaded up to their continuous or emergency ratings. The ratings may be set by thermal, stability, or voltage conditions. Thermal limits are set depending on the characteristics of the individual components, while stability and voltage limits depend on the topology and characteristics of the combined generation-transmission-load network. 3.1.4.1 Thermal Limits Thermal limits relate to heating of equipment. High temperatures cause physical damage to the equipment and shorten the life of the equipment. In extreme heating conditions, the equipment can be damaged or destroyed. Utilities and manufacturers set temperature standards that are applied to different pieces of the transmission system to limit loss of life and avoid destroying equipment. 52 Workshop I Transcript, Page 165, Lines 9-17 Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 35 Each transmission line has a utility-defined thermal rating based upon size and type of conductor, and its design and construction. The capability of the line will also be impacted by required spacing and clearances for trees, shrubs, buildings, animals and various human activities. Each transmission line has a thermal rating based on its current carrying capacity measured in amperes. Such ratings are dependent upon ambient weather, temperature, wind, and atmospheric conditions. Other devices connected to a circuit such as switches, connectors, and metering equipment may also thermally limit transmission lines. The most restrictive device rating in series with the transmission line establishes the thermal rating used for that transmission line. Circuit breakers and transformers are other major devices that have thermal ratings. These ratings are set by the manufacturers to prevent damage or destruction of the equipment. While thermal ratings are set based on ampere loading, they are usually converted to a megawatt rating assuming nominal voltage conditions. Thermal ratings are time dependent and may range from a short time emergency rating to a continuous rating. 3.1.4.2 Stability Limits The limit of a group of transmission facilities may also be determined by stability or voltage limits. These represent limits on the system's ability to successfully respond to contingencies, even if no thermal limits are exceeded. For many system contingencies generators in different parts of the power system will "speed up" slightly while others will "slow down" slightly. The two areas will be briefly operating at very slightly different frequencies when this happens. In nearly all cases, the transmission system is strong enough to keep the two parts of the system connected so that they quickly return to normal speed (frequency). In these cases the system remains stable. For a few system configurations and contingencies, the transmission system is not strong enough to maintain the two areas' frequencies in balance. In these cases the two areas will separate from each other and operate isolated. This is an example of an unstable system condition. In most cases, however, one or more of the islands will experience partial or full loss of load. This occurs because one, or more, of the areas will be importing from the others. Thus, when the transmission connection is lost the importing area will be unbalanced, with more load than generation. When the imbalance is large, the only option for the importing area is to shed load; causing a partial blackout. If the imbalance is very large a complete blackout of the island will occur. It is also possible for the exporting area to experience problems when the islands form. There are situations in many systems, especially those in the western United States, where transfers are limited by stability problems before any thermal limits are reached. In these cases the transfer will be 36 Transmission Planning November 2004 stability limited. These stability (and voltage) limits are established via technical studies that determine the maximum power that can be transferred over a group of lines. 3.1.4.3 Voltage Limits For nearly all system contingencies different parts of the power system will experience changes in voltages. In some areas voltages rise; while in others voltages will fall. Usually equipment and system operators are able to adjust the voltages to maintain acceptable levels. If voltages rise too much, however, equipment can be damaged due to insulation or other hardware failures. If the voltages fall too low it may not be possible to control, and voltage will continue to fall, resulting in a blackout. The greatest risk is usually to an importing area where the lowest voltages will usually be experienced. 3.2 Arizona Transmission Planning Processes Planning methods and guidelines are used as the basis for the development of future transmission facilities. Transmission plans are updated on a continuous basis to determine the projected facilities needs for each year over a ten-year period. In addition to planning their transmission systems to meet their internal needs, the utilities in the State actively engage in a coordinated regional planning of transmission facilities in order to ensure that (a) there are no duplicate or redundant facility additions, and (b) the Extra High Voltage ("EHV") and High Voltage ("HV") transmission facilities are planned in the broader context of the needs of the State, and to take advantage of the diverse locations of load centers and generation complexes in the State. The nominal system voltages for EHV facilities are 345 kV and 500 kV. The nominal system voltage for HV facilities ranges from 115 kV to 230 kV. The utilities in the State are also coordinating the planning activities with the utilities in the neighboring states to identify and construct interstate transmission facilities in order to take advantage of the import and export of competitive energy that would benefit the customers. Since the 2002 BTA, with the encouragement of the ACC and its Staff, the planning process has become much more collaborative and regional. This is a significant improvement in the Arizona planning process. While individual transmission providers remain responsible for their individual transmission projects, the planning process has become so regional that plans are best presented on a regional basis, rather than by individual companies. 3.2.1 Regional Transmission Planning Affecting Arizona Coordinated regional planning in Arizona dates back at least to the late 1960s when the NERC and its regional Councils were formed. The Arizona utilities were part of one of these regional Councils, the Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 37 Western Systems Coordinating Council ("WSCC"). In the years since that time many regional planning coordinating groups have formed and evolved. The WECC has succeeded the WSCC. There are now six regional transmission-planning groups active in the WECC as shown in Figure 3. As shown on the figure, the sub-regional groups that are directly involved with transmission planning in Arizona are STEP and SWAT. Figure 3: Six Sub-Regional Planning Groups in the WECC 3.2.1.1 Southwest Transmission Expansion Planning ("STEP") Group STEP was created as an ad-hoc group to coordinate transmission plans in the Arizona, Southern Nevada, Southern California, and Northern Mexico area. STEP first met in November 2002 and has met periodically since. Participants include representatives from utilit ies, independent power producers, state 38 Transmission Planning November 2004 agencies/regulators and other stakeholders with an interest in the transmission system in Southern Nevada, Arizona and Southern California. STEP's focus is on economically driven expansion projects that support the development of seamless west-wide markets while satisfying established reliability standards. STEP goals and functions The group adopted the following common goal: To provide a forum where all interested parties are encouraged to participate in the planning, coordination, and implementation of a robust transmission system between the Arizona, Southern Nevada, Mexico, and Southern California areas that is capable of supporting a competitive, efficient, and seamless west-wide wholesale electricity market while meeting established reliability standards. The wide participation envisioned in this process is intended to result in a plan that meets a variety of needs and has a broad basis of support. STEP performs 12 basic planning functions: 1. Produces a long-term bulk transmission expansion plan biennially. 2. Identifies current and future transmission congestion that is an impediment to the efficient operation of the western market. 3. Develops, through a collaborative process, strategic transmission options and specific alternative plans for reinforcing the transmission system and for reducing or eliminating congestion. 4. Reviews project-sponsored studies, if requested by the Project Sponsor. 5. Relies, as much as possible, on the technical studies conducted by Project Sponsors and studies conducted in other forums. 6. Performs technical studies without duplicating work performed by others. 7. Shares the study work and will normally be documented in a report. 8. Provides a forum to facilitate stakeholder development of projects through the planning effort. 9. Facilitates the phased implementation of completed plans. 10. Works closely with regulatory and governmental agencies in developing facility plans. 11. Closely coordinates with the other regional planning and reliability groups. 12. Provides a forum for discussing different approaches for funding potential transmission projects. Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 39 In its first year, STEP conducted both technical and economic studies to develop transmission projects to mitigate inefficient congestion on the system. A large number of initial alternatives were narrowed down to one general expansion plan based on the studies and a consensus building process. The member systems began implementing several of the initial steps that can be implemented quickly and economically. These are discussed in section 5.2. A separate sub-group of STEP was formed to focus on these short-term upgrades. The initial steps primarily involve upgrades to the series capacitors in several existing 500 kV lines. During 2004, STEP expects to agree on some of the larger system upgrades and to initiate their implementation. Two other sub-groups were formed to make more detailed studies of specific areas. The first is developing a final plan for a new line between Arizona and California . The second is working on a new transmission line into San Diego. The planning and development of these two projects are taking place in parallel. These larger scale upgrades involve the construction of major new 500 kV lines. Altogether, the total cost of the economic transmission additions being developed by STEP is estimated to exceed one billion dollars. 40 Transmission Planning November 2004 STEP Arizona-California STEP Arizona-California ("STEP-AC") covers the area on the east side of Path 49, as shown in Figure 4. The focus of the STEP-AC group is on the transmission transfer capability between Arizona and California. This means that there is some justified geographic overlap with other groups that are focused on the "internal" transmission needs of the areas within Arizona and California. Figure 4: Transmission Area of STEP-AC Planning Group ad ev N a HARRY ALLEN CRYSTAL NAVAJO da va n a N e r iz o A ia rn ifo al C MIDWAY McCULLOUGH MARKETPLAC E ELDORADO ADELANTO VICTORVILLE MOHAVE MEAD TO FOUR CORNERS MOENKOPI YAVAPAI LUGO RINALDI VINCENT West of River PERKINS TOLUCA MIRA LOMA DEVERS East of River PALO VERDE WESTWING RUDD HASSAYAMPA Ca lif o rni a SERRANO VALLEY LIBERTY TO KYRENE HARQUAHALA JOJOBA GILA RIVER Arizo na Phase Shifter MIGUEL IMPERIAL VALLEY NORTH GILA 500 kV line 345 kV line Third Biennial Transmission Assessment 2004-2013 Docket No. E-00000D-03-0047 4 |
