Meeting Minutes
Buffalo Ridge Incremental Generation Outlet Transmission Study
Study Group Meeting
November 23, 2004
2:00 pm
at Xcel Energy offices
414 Nicollet Mall, Minneapolis
Attendees:
In person
J Standing Xcel Energy
R Gonzalez Excel Engineering
G Stevenson Xcel Energy
P Rasmussen Xcel Energy
M Steckelberg Great River Energy
S Andiappan MISO
J Weiers Otter Tail Power Co
D Schiro Xcel Energy
W Raihala Xcel Energy
E Weber Western Area Power Admin.
Via telephone
T Torgerson Dairyland Power Coop
B Zavesky Missouri River Energy Services
R Dahl Missouri River Energy Services
D Duebner MISO
K Leier Alliant Energy
K Booze East River Electric Power Coop
B Roos Marshall Municipal Utilities
R Srivastava MISO (partial attendance)
Hand-outs:
 Yankee Voltage Stability Analysis (previously distributed via 11-yy-2004 e-mail)
 Yankee & Buffalo Ridge Q-V graphs (10 pages; larger version of those in Yankee report)
 Graph of “Installed Cost as function of Outlet” (distributed via 11-23-2004 e-mail)
 Set of powerflow diagrams (“automaps”) for the 11 transmission Options (system intact
conditions)
 Installed Cost Estimates (“Base Plan” Costs) for the transmission Options (2 pages)
 Set of TLTG summary tables for the 11 transmission Options under review (11 pages)
Meeting agenda is attached.
Following the introductions, the meeting progressed per the Agenda outline; this numbering is
used in the following sections.
1. Review of Study Purpose/Scope/Goals
R Gonzalez gave a review of the study goals, and the purpose of this particular Study Group
meeting. The principal goals of the Study are to

Determine how much additional Buffalo Ridge area generation outlet may be achievable
with modest-scale transmission upgrades or additions (presumably primarily 115 kV).
Ideally, a plan for securing an increment of at least 200 -300 MW would result.

Address Yankee “stability” limitations identified in the MISO Buffalo Ridge “Group II”
interconnection studies
Identify a Recommended Plan (if possible) of transmission improvements for addressing
the above goals.

This Study Group meeting was for the purpose of
 reviewing the technical analysis performed to date;
 making the “first cut” at the number of transmission Options to be further evaluated;
 provide direction for next stage of analysis
 schedule next study group meeting (date and location).
2. Review of transmission Options under evaluation
R Gonzalez and J Standing described the 11 transmission Options under evaluation. A handout was provided which lists the facilities (and conceptual installed costs) for each Option.
3. Hand-out of base case powerflow maps
A set of 11 powerflow maps was available as a hand-out. These maps show systemintact flows and voltages for each of the transmission Options, for the year 2007 offpeak condition studied. Participants suggested the following enhancements be made:



add generation symbols for total gen at Yankee and Fenton
add generation symbol for Lk Yankton SVS
add Lakefield Gen-Wilmarth 345 kV line
4. Discussion of Yankee/Buffalo Ridge Q-V Analysis (transmitted previously)
The “Yankee Voltage Stability Analysis” report draft distributed via e-mail on 11-17-2004
was reviewed. It was explained that Q-V analysis shows the “post-825 MW” system is
adequate for approximately 250 MW of Yankee generation, but is definitely not
adequate for 300 MW due to excessively high critical voltage (.96 pu on Graph B0-1).
At the 400 MW Yankee generation level, there is also the additional problem of “no
intersection of Q-V curve with horizontal axis (Graph Y0-1).
It was explained that these limitations are not a surprise, since the “825 MW” system
design was developed based on the assumption that half of the 400 MW Buffalo Ridge
area generation outlet increment (425-->825 MW) being achieved consisted of Yankeeconnected generation. Since half of 400 MW is 200 MW, any studies incorporating over
200 MW of Yankee generation are examining hypothetical operating conditions beyond
the “825 MW” system design level.
Since there is no steady-state post-contingent operating point available for Yankee
generation levels of 400 MW (problem actually begins around 350 MW), it was pointed
out that it is not surprising that the MISO Group II studies, which had up to 500 MW of
Yankee generation modeled, exhibit what at first appears to be dynamic instability.
However, since there is no steady-state operating point available, it is actually primarily
(if not exclusively) a voltage collapse situation rather than a dynamic stability problem.
The cause of the discontinuity (observed at approximately .95 - .97 pu voltage) in the
Buffalo Ridge post-contingent graphs (B0-1, BA-1, BB-1, BC-1) was discussed.
Gonzalez explained that it was initially suspected the discontinuity was due to the Lk
Yankton SVS hitting its reactive output limit; however, when the Lk Yankton SVS output
curves were added to the Q-V graphs, it was quickly determined this hypothesis was not
correct, as the Lk Yankton reactive capability is shown to be exhausted well before (at a
higher voltage than) the occurrence of the discontinuity. Consequently, it is exhaustion
of some other reactive source that causes this effect. It is most likely the Buffalo Ridge
or Chanarambie generation causing this “bend” in the Q-V curves.
Three transmission improvements were studied with respect to their effectiveness at
ameliorating the Yankee voltage collapse situation. All three options studied were
effective, each achieving 350 - 400 MW of Yankee outlet. A fourth option (not explicilty
discussed in the Yankee report) is to simply “double-up” on the Yankee-White 115 kV
line and install a second 345/115 kV transformer at NSP White. This neutralizes the
critical contingency (loss of Yankee-White 115 kV or White 345/115 tx) and therefore
yields performance as shown on the “Existing System, System Intact” Q-V graphs
(Graphs Y0-0 and B0-0); performance is satisfactory to Yankee generation levels
beyond 500 MW.
Some of the Buffalo Ridge outlet transmission Options under study include transmission
additions that adequately address the Yankee voltage stability concern, as confirmed in
Graphs YB-1, BB-1 (Yankee-Lyon Co 115 kV; Options 7 or 8), and YC-1, BC-1 (Option
6). Other Options, however, do not add any transmission directly connecting to Yankee,
and will therefore need to have a supplemental Yankee “fix” applied.
Several suggestions for revisions to the Yankee report were provided, including


Determine whether an SVC is a feasible option for addressing the Yankee voltage
collapse situation which appears at high Yankee gen levels. Looking at Graph Y0-1 of
the report, it appears that a VAR source at Yankee would not work, because of the
flatness of the Q-V curve trough (SVC can provide the VARS, but won't change the
shape of the Q-V curve). However, it's not clear whether adding an SVC at Buffalo
Ridge might fix the Yankee situation; additional Q-V analysis should be run on that
scenario (showing Yankee Q-V curve shape with Buffalo Ridge SVC).
It may be desirable to first introduce the Q-V curves using graphs that do not have the Lk
Yankton SVS output shown; seeing these “extra” curves on the graphs causes some
initial puzzlement.
5. Discussion of transmission Options’ TLTG results
A hand-out (11 pages) was provided which summarizes for each Option the outlet
limiters encountered at progressively-higher levels of Buffalo Ridge area generation. It
was explained that these summaries were derived from powerflow program (PSS/E)
Activity TLTG (“Transfer Limit Table Generator”) incremental transfer simulations. The
incremental generation was presumed to be 50% at Yankee (represents northern
portion of the ‘Ridge) and 50% at Fenton (represents southern portion of the ‘Ridge).
These TLTG tabulations show the steady-state “system intact” and “first contingency”
(“n-1”) thermal limits only; later analyses will be needed to address
 voltage adequacy (reactive power requirements)
 dynamic stability performance
 Losses (MW and MWh)
Referring to the 1-page handout graph showing the Options’ “Installed Cost as Function
of Outlet” the following observations were made:





Reconductors (Option 9) has the lowest installed cost, up to approximately 1250
MW (825 + 425 MW).
Option 8 is significantly more costly than all other options.
Option 1A is consistently $4 - 5 million lower in cost than Option 1, to at least
1400 MW
All Options have a “cost plateau” which begins at or before approximately 925
MW (825 + 100). This plateau extends to at least 1175 MW (825 + 350), except
in the case of Option 9, where the step occurs at 1145 (825 + 320). For several
Options (1A, 2, 4, 5) the plateau extends to at least 1325 MW (825 + 500)
In the “plateau region, all options have an installed cost of approximately $13 - 22
million, except for Option 9 (cheaper) and Option 8 (much costlier).
At this stage of the analysis, all Options except Option 8 are competitive with each other
($12 - 22 million), out to approximately the 825 + 350 = 1175 MW) level. This may
change with upcoming adjustments for losses, reactive requirements, and "Yankee fix".
General discussion on the Options:
The TLTG graph is helpful in comparing the Options’ performance with respect to
Buffalo Ridge outlet. However, it was noted the Options differ as to the degree to which
they address other relevant transmission planning concerns for this geographic area:
 Yankee voltage stability
 Marshall load serving capability
 Franklin area load serving capability(Redwood Falls/Sleepy Eye/New Ulm area)
 Demand (MW) and Energy (MWh) Losses
The cost curve for Option 3 takes a large step at approximately 1180 MW. The TLTG
summaries show three line overloads are encountered in the range 1180 - 1250 MW.
The step represents the cost of implementing at that point the “Option 1A”
improvements, as they would address the overloads at a cost less than that of the
individual fixes. Consequently, the Option 3 curve actually represents implementation
of a staged hybrid “Option 3 + Option 1A” plan.
It was noted that implementation of Option 1A does not preclude later extension to
Chanarambie, which would then complete implementation of Option 1 in a staged
fashion.
It was agreed the next steps in the analysis will need to include
 Addition of a “Yankee fix” cost for Options that don’t already address Yankee
(expected to be $8 -10 million, depending on results of finalized Yankee analysis).
This will be significant, since most of the Options have an installed cost of $13 - 22
million. The “Yankee fix” penalty will apply to all Options except 6, 7, and 8.
 Economic evaluation of losses (an “Equivalent Installed Cost” credit to apply to
options with losses lower than those of Option 9, which is to be the reference).
Addition of this loss credit may cause “cross-over” of the cost curves since Option
9 (the cheapest) is only approximately $2 - 6 million lower in cost than Options 1A
and 3 in the “plateau” region.
6. Discussion: What Options should be kept at this “first cut” point?
It was agreed that Option 8 (Yankee-Lyon Co-Franklin) should be dropped from further
consideration, due to its extreme cost compared to the other Options. Option 8 fared
poorly because the number of line miles is high, resulting in a high installed cost, while
the length also resulted in considerable circuit impedance at 115 kV, thereby
constraining its electrical performance. It was noted that this east-west concept would
likely have more merit as a 345 kV development.
It was also decided to drop Option 1 (Nobles Co-Chanarambie 115 kV). It was
observed that Option 1 was never more economical than Option 1A (Nobles Co-Fenton
115 kV), and that if “internal to the Ridge” transmission considerations were to merit the
line’s later extension further north to Chanarambie, a staged development of Option 1
could still occur. Rasmussen also noted that from a routing perspective, avoidance of
Chanarambie is a plus (due to some physical congestion beginning to develop there)
although this does not rise to the level of a critical consideration.
Consequently, it was decided to drop Options 8 and 1 from further consideration. All
remaining Options will be carried forward to the next stages of analysis.
7. Discussion of next steps
The following is to be undertaken for the remaining Options (survivors of the “first cut”):
 Perform ACCC “n-1” analysis at 1175 MW outlet level (confirm TLTG thermal
results, check voltage performance & determine reactive needs).
 Perform losses analysis (determine MW loss differences & compute equivalent
installed cost credit based on Present Worth considerations).
 Revise “installed cost” graph to include effects of Yankee fix, reactive
requirements, losses.

Perform “constrained interface” analysis; are there any significant differences
among Options as to degree of incremental loading impressed upon the defined
MAPP and MISO constrained interfaces (“flowgates”). In addition to the traditional
defined interfaces, this analysis should also monitor Buffalo Ridge outlet corridors
(White 345/115 tx, Marshall-->Granite Falls/Minn Valley 115 kV, PipestonePathfinder 115 kV, Nobles Co 345/115 kV tx(s)) to enable comparison of how the
incremental flows leave the ‘Ridge.
There was also some discussion regarding Anson generation level. All analysis to date
has been performed with Anson at 2 x 116 = 232 MW. It was recommended some
comparison work be done with the new 170 MW Anson Unit 4 on line. Although
scenarios of all Anson on-line should be rare during the off-peak load condition of
interest, this is a concern with respect to any generation accreditation in the reserve
sharing pool. W Raihala or D Schiro will provide written comments on this concern.
Grant Stevenson will provide updated line lengths for Chanarambie-Fenton-Nobles Co
115 kV. Due to Nobles Co Sub site having moved eastward from the originallyconceived location, total 115 kV line length is now approximately 38 mi rather than the
26 miles presumed to date. This will affect pricing of Options 1 and 1A, and will affect to
a lesser degree their electrical performance.
Pam Rasmussen volunteered to get HDR (consultant to Xcel Energy) working on
producing some good area maps showing the Options' transmission components. This
will be needed for the final study report, and for any subsequent permitting activities.
8. Arrangements for next Study Group Meeting
The next Study Group meeting is tentatively scheduled for 9:00 am on Tuesday
December 21. We anticipate to be meeting at the Marshall Municipal offices in
Marshall, MN. Arrangements will be finalized and notification sent to the group during
the next week.
Prepared by:
Richard Gonzalez, PE
Transmission Planning
Excel Engineering, Inc.
(Consultant to Xcel Energy Transmission Asset Management)
desk: 612-330-6312 (414 Nicollet)
desk: 763-571-5008 x 234 (Fridley)
cell: 612-790-WIRE (9473)
rick@exceleng.net
richard.gonzalez@xcelenergy.com
Minutes 11-23-2004.doc
----------------------Note: The above minutes were distributed 11-29-2004 to the meeting participants and
the MB and NM SPG exploders, with comments requested by 12-7-2004. No
comments were received which affected the above text.
Comments received
1. E. Weber, WAPA: provided a list of additional detail recommended to be added to
the powerflow maps
2. D Schiro, Xcel Energy: confirmed Xcel Energy interest in sensitivity analysis with all
Anson generation (including the 2005 addition) on line at full capability.
3. M Steckelberg, GRE: accepted minutes as submitted
R Gonzalez, PE
Xcel Engineering, Inc
12-9-2004