November 19, 2002
PI transmission study Comments
As the owner of the Transmission System on which the Prairie Island units are
interconnected and after a cursory review of the MISO Preliminary Screening
Study, we have the following observations and views concerning the power
system impacts which would likely arise from removal of the Prairie Island units:
Of necessity, the MISO screening study is a very high level and cursory review of
the potential transmission impacts of replacing the Prairie Island Generating
Plant. The evaluation however, only looked at thermal issues and one basic
operating condition. In the MAPP region, system stability cannot be ignored or
evaluated with simple screening studies. Accumulated operating experience and
preliminary assessments confirm that removing Prairie Island generating plant
from the system will have major dynamic stability consequences.
General issue: Removal of Base load generation at PI
This issue applies to all the plant options proposed in the screening analysis.
Impact of a Prairie Island retirement on the transmission system will be highly
dependent on where the generation to replace it is located and its dispatch merit,
based on operating cost. Prairie Island is a base load generating station with at
least one unit expected to be running almost all the time. Preliminary testing
indicates that without the plant, under a system normal state, there would be a
15-30 % reduction in the Minnesota- Wisconsin transfer interface limit (MWSI).
Also, Sherco will be limited to about 2340 MW, which is approximately 100 MW
below its present capability.
With outage of an additional large Twin Cities generator such as King or certain
345 kV circuit outages, the MWSI and Sherco both will have major operating
restrictions. (A more detailed study is required to establish these restriction
levels). This would mean almost constant Transmission Loading Relief (TLR’s)
calls, severely restricting the use of the transmission system. The situation is
potentially further aggravated by the anticipated outage of approximately 1 - 2
years of the King generator for the MERP-related modernization. The planned
King outage’s significance depends on whether the plant outage occurs before or
after the hypothetical Prairie Island retirement). There will also be a few
underlying 115 kV overloads.
The magnitude of the significance of the Prairie Island retirement on the region
depends on how close the replacement generation is to the Prairie Island site,
and how close to base load operation the replacement generators run.
Assuming the generation that will replace the Prairie Island units is remote from
the Prairie Island site or has an economic cost such that it would not be run as a
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base load generation resource, there will need to be transmission facility
additions to resolve the dynamic stability issue. The preliminary testing indicates
the nature of the dynamic stability problem is voltage collapse both in the vicinity
of Eau Claire, Wisconsin and the Twin Cities. Removal of the Prairie Island
generation causes a large dynamic reactive power (VAR) requirement in both of
these regions. An initial assessment indicates adding large dynamic VAR
sources--such as Static Var Compensators (SVCs)--similar in size to the existing
Forbes SVC, in the vicinity of Eau Claire and Prairie Island will resolve the
dynamic stability issue. Although much more detailed study work would be
required to choose the appropriate technology and size of these dynamic VAR
sources, a rough estimate of cost can be derived by noting that the installed cost
of the Forbes SVC (in 1994) was approximately $24 million. Presuming 2%/yr
cost escalation for a period of approximately 14 years (to 2008) yields a total cost
of $63 million for a pair of “Forbes” style SVCs.
From the screening study it was also noted that some scenarios include a
smaller replacement generating plant in the vicinity of Prairie Island. It has been
noted in operating studies that with one Prairie Island unit out of service there are
stability restrictions on use of the transmission system. Even in an ideal location
for the smaller plant such restriction will become permanent. Again, dynamic
VAR sources would be required to mitigate this issue. This will likely require
smaller dynamic VAR capability than in the above scenario where no
replacement generation was located at or near Prairie Island. Again, the actual
magnitude of resultant cost to alleviate resultant performance deficiencies will be
highly dependant on the characteristics of the new plant, how it is integrated into
the transmission system and how closely it is dispatched as a base load unit.
1 Scenario1. 1100 MW at Rosemount
The MISO analysis found about $26 million in upgrades to the underlying system
required with this proposal. It assumed a 345 kV interconnection (I think Inver
Hills). This result seems reasonable except that there are no costs for
interconnecting. No Constrained Interface issues were identified; this would be
reasonable as this site is electrically close to PI.
Issue: there are generation additions ahead of this in the queue that will likely
raise the cost significantly to this project. It will need to be 345 kV and need to
get the power away from this part of the 345 kV loop. This cost is very site
specific but being close to the Twin Cities metro 345 kV system and urban load
centers, one could expect an additional $20-30 Million.
2. Scenario 2. 998 MW at PI
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This is trivial as found in the screening study. Cost would be dependent on
exactly how the new generation interconnected and how much of the existing PI
connection equipment could be re-used.
3. Scenario 3. 1100 MW in Illinois
The screening study found only thermal issues around the site in Illinois. The
estimate was for $47 million in system upgrade costs. Power flows from this
location would be counter to all the normal flows on the Xcel Energy system and
far away so no thermal issues would be expected on the Xcel Energy system.
Issues: This will impact the east to west flow constraints in Iowa as found in the
screening study. Although the screening study did not find any limits exceeded
this may be due to the limited dispatch scenarios reviewed. A much more
detailed analysis would need to be done to determine if mitigation of the Iowa
constraints will be needed. Also there are a number of Generation projects in the
queue in Iowa that could aggravate the situation.
The major power import capability for the MAPP system is from the south and
south east (SPP and MAIN regions). Looking at the NERC 2002 summer
assessment, there is in theory about 1000 MW of import capability from MAIN
and from SPP. However, these are not independent and use many of the same
transmission paths. A long-term purchase of this magnitude would greatly reduce
the import capability available to the MAPP region for pool emergencies. From a
regional reliability standpoint, it is doubtful that this will be acceptable. A major
transmission addition will likely be required just to maintain reasonable import
capability; otherwise, generation reserve requirements would need to be
increased MAPP-wide to maintain established power system adequacy levels.
This option also is the worst case scenario for the general system stability issues
described above.
4, Scenario 4. 586 MW in Missouri and 565 MW at Wilmarth
The screening study only found problems at the Missouri site with an estimate
about $9 million. However, there where a number of issues not addressed that
would likely result in upgrades required around Wilmarth. These include the
study being done only at system peak, high transfers not assumed, and not
reviewing the 69 kV system which is already heavily loaded at Wilmarth.
Issues: As in many of the other scenarios, there are a number of generation
additions nearby listed in the MISO queue which would absorb much of the
transmission capacity that this study assumes is available for outlet by the
Wilmarth unit.
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Once stability and transfer issues are addressed, it is more likely that a new 345
kV line to the metro area will still be required.
This would be about 50 miles.
Assuming similar construction costs with the Sioux Falls- Lakefield line of $450k/
mile, an estimate for this would add:
Wilmarth interconnect $5 Milllion
Approx. 50 Mile Line $25 Milllion
TC interconnection
$10 Million (new sub assumption)
Total
similar size plant)
$ 40 Milllion (Chisago Site Is about $40 million with a
5. Scenario 5. 586 MW in Missouri and 550 MW at Rosemount
Again the study only found significant impacts with the Missouri site. However,
this time only about $3.5 Million. The only difference is a $5 million upgrade of a
line in southern Iowa. This may be due to the line being just on the edge of being
an issue. If so, a more detailed analysis with more system conditions studied
would also likely result in the need for this line to be upgraded.
It is also a bit surprising that the smaller generation addition at Rosemount
(assumed to be Inver Hills) would reduce the 115 kV upgrades from the $26
million found with the 1100 MW plant to $ 0. A more detailed review would be
expected to find it reduced but not zero cost.
Issue: this has the same issue as the 1100 MW scenario at Rosemount. There
are generators ahead in the queue that will use up much of the transmission
capacity assumed available to this plant in the Dakota Co area.
6. Scenario 6. 550 MW at Rosemount and 565 MW at Wilmarth
The screening study found no upgrades required for this scenario. However, This
scenario suffers the combined study limitations described for Scenarios 4 and 5.
Under the assumption identified in Scenario 4 for the Wilmarth plant location. It is
likely that a $40 million 345 kV project will also be required.
All scenarios Issues
In all scenarios, no costs were added for the direct interconnection of these
plants to the system. Depending on how close the units are to an existing 345 kV
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sub these could be low to about $20 million for just integrating the plant into the
system.
There are many large generators ahead of these proposed replacement plants in
the MISO queue in Minnesota and northern Iowa. These will have significant
impact on most of these scenarios as they utilize capacity assumed available in
this study.
The study was run only at peak and not under all the conditions that will be
imposed on the analysis when these plant request interconnections. Being a
stability-limited region, the stability performance of each scenario could add
significant cost. Also, only one generation dispatch pattern was assumed.
Different generation dispatch patterns are likely to result in identification of
additional costs.
With respect to the MWSI interface, proper division of loading between the KingEau Claire-Arpin and the Prairie Island-Byron-Adams paths has also been
identified as a limiting factor. Generation reductions at Prairie Island cause
increased loading on the King-Eau Claire-Arpin path. Consequently, although
preliminary analyses such as conducted by MISO may not indicate exceedance
of the existing MWSI total boundary limit, loading constraints can be encountered
at MWSI levels below the present 1480 MW limit due to excessive King-Eau
Claire-Arpin loading. Addressing this load-sharing issue would require addition
of series compensation, phase shifting transformer(s) or equivalent devices such
as a UPFC (Unified Power Flow Controller). Depending on the ratings required
and technology selected, such options would likely have installed costs in the
range of $ 8 – 40 million, plus additional operating costs from additional electrical
losses which would likely arise.
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