Southwest Minnesota/Southeast South Dakota Electric Transmission Study
Phase 1:
Transmission Outlet Analysis
for
Southwest Minnesota (Buffalo Ridge Area) Generation Additions
(0 – 400 MW beyond initial 425 MW)
Volume 1
November 13, 2001
Prepared by:
Xcel Energy
Southwest Minnesota/Southeast South Dakota Electric Transmission Study
Phase 1:
Transmission Outlet Analysis
for
Southwest Minnesota (Buffalo Ridge Area) Generation Additions
(0 – 400 MW beyond initial 425 MW)
Volume 1
November 13, 2001
Prepared by:
Xcel Energy
Transmission Reliability & Assessment
Principal Contributors:
Angela Maiko
Richard Gonzalez
Assistant:
Bayardo Payan
Contents
Volume 1 Page
0.0 Certification 1
1.0 Background & Scope of Study 2
2.0 Conclusions & Recommended Plan 3
3.0 Study History & Participants 4
4.0 Analysis
4.1 Models employed 5
4.2 Conditions studied 5
4.3 Options evaluated 6
4.4 "First Cut" screening 7
4.5 Performance evaluation methods 8
5.0 Results of detailed analyses
5.1 Powerflow (system intact & contingency) 9
5.2 Constrained interface analysis 11
5.3 Reactive power requirements 13
5.4 Losses: technical evaluation 17
5.5 Losses: economic evaluation 19
6.0 Economic Analysis
6.1 Installed Cost 23
6.2 Evaluated Cost 25
7.0 Relevant Concerns
7.1 Load serving issues 28
7.2 Regional generation outlet (non-Buffalo Ridge developments) 29
7.3 Constructability & schedule considerations 31
Appendix A Maps
Appendix B TLTG Summaries & project cost data
Contents
Volume 2
Appendix C ACCC outputs
Appendix D TLTG outputs
Appendix E Powerflow diagrams & logsheets
Appendix F Interface PTDF analysis
Appendix G Input data for ACCC & TLTG
Appendix H Reactive requirements Q-V plots
Appendix I Power System Loss data
Appendix J Preliminary Construction Schedules
0.0 Certification
I hereby certify that this plan, specification, or report
was prepared by me or under my direct supervision
and that I am a duly Licensed Professional Engineer
under the Laws of the State of Minnesota
Richard Gonzalez
Registration Number 18938
November 13, 2001
1.0 Background & Scope of Study
This phase of the Southwest Minnesota/Southeast South Dakota Electric Transmission Study addresses the development of transmission outlet capacity for additional electric generation capacity which may be constructed on the Buffalo Ridge in Southwestern Minnesota or adjacent South Dakota and Iowa portions of the ‘Ridge.
The existing transmission system and several transmission system improvement options were evaluated to identify the steady-state (thermal and voltage) limitations which would be successively encountered if additional increments of generation capacity were installed on the Buffalo Ridge, subject to the following principal assumptions:
· a total of 425 MW of generation (nameplate rating) has already been installed prior to the period of interest;
· the pre-existing 425 MW of generation has been integrated into the power system by construction of the Chanarambie-Lk Yankton and Lk Yankton-Lyon Co (Marshall) 115 kV lines and associated substation facilities;
· it is desired to identify the limiters which would be incrementally encountered with additions ultimately aggregating to approximately 400 MW of additional nameplate generation capacity.
· under both system intact and first-contingency (n-1) conditions, facility loadings and bus voltage levels will be maintained within applicable established performance criteria, for both peak and off-peak load conditions, without resorting to tripping of generation or curtailment of deliveries to load.
· all new generation will have dynamic and steady-state reactive power control characteristics (power factor controllable in range of .90 lead to .90 lag) in conformance with the existing Xcel Energy reactive power/voltage control standard as referenced in the most recent generating capacity RFP issuances.
· Present MAPP standards and policies will continue to apply with respect to constrained interface impacts, non-degradation of existing transfer capabilities, and generation accreditation procedures.
The analysis does not address transient or dynamic stability, which--although not studied--is not anticipated to be a problem at the power levels examined, provided the transmission improvements embodied in each option studied are implemented. However, this topic would merit some examination prior to undertaking a transmission outlet development plan if one of the lower-voltage (no 230 or 345 kV addition) options were under consideration for adoption.
The technical and economic analyses were performed for the purpose of identifying a preferred plan to achieve the specific goal of providing generation outlet capacity for the 2nd 400 MW of generation development on the Buffalo Ridge. It is recognized that several other potential generation developments which may affect transmission requirements in this region are in preliminary stages of study by various entities. Since the timing, size, and number of such hypothetical generation projects which may actually be implemented--if any--cannot be determined at this time, this Buffalo Ridge generation outlet study was performed presuming that transmission requirements for any such additional projects will be addressed by other power system improvements, the characteristics of which would be determined through future transmission studies.
2.0 Conclusions & Recommended Plan
The Preferred Plan is Option 1, which adds a 345 kV Split Rock-Lakefield Jct line and related lower-voltage facilities. This option appears to offer the best overall results with respect to
power system performance (system intact & contingent loadings & voltages)
power and energy losses (MW and MWh)
practicality (logistics of construction and operation)
price (cumulative present worth cost)
Option 1 also appears to be highly compatible with other transmission improvements which may be undertaken to further address local and regional load-serving needs, enhance power system transfer capability, or provide outlet capacity for additional generation developments in the Dakotas, Minnesota, and Iowa.
The Study Group participants and the relevant MAPP Subregional Planning Groups further recommend that consideration be given to having the 345 kV line be constructed with double-circuit structures, to facilitate future installation of a second circuit. This recommendation arises from the observation that additional generation developments in the region (either on- or off-'Ridge) will likely produce further demand for transmission capability.
3.0 Study History & Participants
Following a kick-off meeting in October, 1999, progress review meetings were held periodically during 2000 and 2001.
Oct 6, 1999 Minneapolis, MN NSP Offices (kickoff meeting)
January 25, 2000 Sioux Falls, SD MRES Offices (adjacent to MB SPG meeting)
August 17, 2000 Sioux Falls, SD MRES Offices
April 19, 2001 Watertown, SD Country Inn & Suites
May 24, 2001 Sioux Falls, SD MRES Offices (adjacent to MB SPG meeting)
July 12, 2001 Watertown, SD WAPA Operations Center (adjacent to MB SPG meeting)
Sept 5, 2001 Sioux Falls, SD MRES Offices
In addition to the Study Group meetings, updates were also presented to the MAPP Missouri Basin (MB), Red River Valley (RRV), and Upper Mississippi Valley (UMV) Sub-regional Planning Groups (SPGs) during their regularly-scheduled meetings.
The Southwest Minnesota/Southeast South Dakota study group included technical staff of the following transmission entities:
ALT Alliant Energy Dubuque, IA
BEPC Basin Electric Power Coop Bismarck, ND
EREPC East River Electric Power Coop Madison, SD
GRE Great River Energy Elk River, MN
HCPD Heartland Consumers Power District Madison, SD
MRES Missouri River Energy Services Sioux Falls, SD
NWPS Northwestern Public Service Huron, SD
WAPA Western Area Power Administration Billings, MT
XEL Xcel Energy Minneapolis, MN
Participation was solicited and received from state (Minnesota and South Dakota) regulatory bodies and interested environmental and energy policy advocacy groups. Also in attendance at some meetings were representatives of generation development entities and representatives or consultants for transmission service customers.
Xcel Energy technical staff performed the powerflow simulations, economic analyses, and tabulation of results. These results were reviewed at the study group's meetings, at which comments, conclusions, and recommendations were developed to guide each successive stage of analysis.
A draft of this study report (dated August 17, 2001) was reviewed at the September 5, 2001 meeting; this final version reflects the comments received at that meeting and at the UMV, MB, and RRV Sub-Regional Planning Group meetings held on September 18 and 19, 2001.
4.0 Analysis
4.1 Models Employed
The powerflow models employed were developed by the SW MN/SE South Dakota transmission study group. The models are based on the 1999 Series MAPP models, updated by the study group to reflect any additional system improvements (primarily reconductors, shunt capacitors additions, and station equipment upgrades) which have either already been completed, or are planned to be in service by 2001 summer.
4.2 Conditions Studied
The technical analysis was performed based upon Year 2001 powerflow models. The base models were adjusted to represent the latest available forecast data for summer season peak (100%) and off-peak (70%) load conditions. The off-peak model simulates a high transfer condition corresponding to the presently-recognized simultaneous North Dakota/Manitoba transfer limits as established by the Northern MAPP Operating Review Working Group (NMORWG), while the on-peak model represents only identified firm power transactions.
Net generation, MW
load Path- Minn Lake-
Condition level NDEX1 MHEX2 MNEX3 MWSI4 Wind Anson finder Valley field Fibrominn
Peak 100 % 1350 1975 1292 883 260 232 63 47 550 50
Off-peak 70 % 1950 1975 1069 992 260 232 63 47 550 50
Powerflow diagrams for the base cases and relevant contingencies are provided in Appendix D.
1) NDEX = sum of flows on the 17 lines comprising the North Dakota Export Boundary;
2) MHEX = sum of flows on the 3 Manitoba Hydro-U.S. 230 & 500 kV tie lines;
3) MNEX = sum of flows on the 3 Twin Cities 345 kV tie lines (Eau Claire-Arpin, Byron-Adams, Wilmarth-Lakefield)
4) MWSI = sum of flows on the Minnesota-Wisconsin Stability Interface (Prairie Island-Byron, Eau Claire Arpin 345 kV)
4.3 Options Evaluated (Maps in Appendix A)
The following transmission improvement options were evaluated:
Option 1 “Split Rock-Lakefield 345 kV”
This option establishes a new Split Rock-Lakefield Jct 345 kV line, including an intermediate 345/115 kV station (Nobles County) and two 115 lines northward into the Southwest Minnesota windfarm area.
Option 1A “Split Rock-Franklin-LeSueur Co 345 kV”
This option establishes a new 345 kV line from Split Rock to a new switching station ("LeSueur County") on the existing Blue Lake-Wilmarth 345 kV line. This configuration was motivated by a desire to keep incremental loading of the Ft Calhoun-S ("Omaha") constrained interface to under the 5% PTDF threshold value presently used in evaluation of acceptable impact to identified MAPP constrained interfaces. 345/115 kV transformations would be established along this line at or near the existing Chanarambie and Franklin substations.
Option 2 “White-Lyon Co-Franklin-LeSueur Co 345 kV
This option establishes a new 345 kV line from the existing WAPA White 345/115 kV substation to a new substation (LeSueur Co) on the existing Blue Lake-Wilmarth 345 kV line. Connection to the 115 kV system would be made near Marshall (Lyon Co) and Redwood Falls/New Ulm (Franklin) via new 345/115 kV transformations.
Option 3 “115 & 161 kV Only”
This option establishes three new 115 or 161 kV outlet lines from the ‘Ridge:
· Buffalo Ridge-White 115 kV
· Lyon Co-Franklin 115 kV
· Chanarambie-Heron Lk 161 kV
Option 4 “Lyon Co-Franklin-Ft Ridgely 115 kV”
This option establishes a new outlet line from the Marshall area eastward to the Redwood Falls/New Ulm vicinity by constructing a new Lyon Co-Franklin-Ft Ridgley 115 kV circuit.
Option 5 “Reconductors only”
This option upgrades all existing facilities as necessary to alleviate overload conditions. This tactic consists of reconductoring any overloaded lines and replacing overloaded transformers with higher-capacity units.
For Options 1 – 4, any overloads still observed following addition of the new facilities are generally addressed by upgrading the affected lines or transformers as required. In a few cases, additional 115 kV circuits are added where such an addition would economically eliminate the need for multiple other projects. For Option 5, all overload conditions are addressed by reconductoring the affected lines and replacing overloaded transformers with larger units.
The above transmission Options were designed to be representative of a broad range of theoretically possible power system improvement strategies. Although a large number of other combinations of improvements could be concocted, their individual performance characteristics would not differ substantially from that of one of the of the above representative options.
4.4 "First Cut" Screening
To keep the amount of technical analysis required at a manageable level, a "first cut" screening analysis was undertaken in an attempt to identify any facility addition Options which were technically or economically significantly weaker than the others, and for which further detailed analysis would not be warranted. Specifically, it was desired to determine whether the 345 kV options should all be carried forward in the analysis. Table 1 shows the results of the initial screening analysis.
Table 1
Initial Estimated Comparison of Options' Economic Viability
(all values in $1,000,000's):
Installed Cost Losses
Base Omaha Other Total Equivalent Evaluated
Option Description Plan Mitigation fixes Capital value Cost
1 Split Rock-Lakefield Jct 345 78 8 0 86 0 86
1A Split Rock-Franklin-LeSueur Co 345 112 0 0 112 3 115
2 White-Franklin-LeSueur Co 345 104 0 6 110 9 119
3 115 & 161 kV 65 4 1 70 13 83
Considering the above information, Option 2 was dropped from further analysis because of its high installed cost relative to Option 1, the other 345 kV option. The higher cost is primarily due to the miles of new 345 kV line required being approximately 50% higher than Option 1. Although it is suspected Option 2 may have considerable merit with respect to other regional goals, such as generation outlet for possible future developments in western Minnesota or the Dakotas, it does not appear to be competitive with respect to the presently-identified wind generation transmission outlet goals and anticipated load-serving requirements in the SW MN/SE SD area.
A particular drawback of Option 2 relative to Option 1 (Split Rock-Lakefield Jct) which is not indicated in Table 1 is that Option 2 does not provide a new EHV source to the Sioux Falls load center. Consequently, although Option 2 appears to be capable of providing adequate generation outlet for the 825 MW wind goal, it does so only at significantly higher cost, and does not provide any Sioux Falls load serving benefit. For these reasons it was concluded Option 2 does not appear competitive relative to addressing the identified power system requirements within the scope of this study.
Option 1A was dropped for similar reasons. The significantly higher cost of Option 1A relative to Option 1 does not appear to be balanced by corresponding benefits. The specific advantage of avoiding improvements to the Omaha area EHV system does not merit the higher installed cost of Option 1A. Accordingly, Option 1A was dropped from further consideration.