Conference Call Summary by alicejenny

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									                             Conference Call Summary
            NorthWestern Energy Transmission Advisory Committee
                             January 29, 2009

Attendance
Those participating in the Transmission Advisory Committee (TRANSAC) conference call
included:

    Name                            Organization
Troy Dahlgren          Southern Montana Electric Generation & Transmission Cooperative, Inc.
Bryan Rogan            Oversight Resources
Donald Quander         Large Customer Group
LeRoy Patterson        Martinsdale Wind Developers
Bill Pascoe            Great Northern/Wind Hunter
Linda Palagi           Montana Department of Commerce, (MDOC) Energy Promotion and
                       Development Division
John Leland            NorthWestern Energy (NWE)
Kathleen Bauer         NWE
Don Bauer              NWE
Ryan Munson            NWE
James Hadley           NWE
Kim McClafferty        NWE
Ray Brush              NWE
Gerald Mueller         Consensus Associates

Standards of Conduct & Anti-Trust Policy
Kathleen Bauer began the call by reviewing the NWE TRANSAC Antitrust Policy and the
Standards of Conduct Policy and Safeguards posted on the OASIS at:
http://www.oatioasis.com/NWMT/NWMTdocs/NWE_Anti-Trust_and_SOC_Jul_11_07.doc.
When people joined the call after the initial review, they were reminded of the standards and
policy. John Leland noted that the Federal Energy Regulatory Commission (FERC) recently
authorized at NWE’s request unnoticed communication between NWE’s transmission and energy
supply long-term planning groups. Unnoticed communication between the NWE transmission
group and the energy supply operations staff continues to be prohibited. Mr. Leland stated that
the TRANSAC Standards of Conduct and Safeguards Policy will have to be amended in light of
the FERC decision.

Purpose of the Call
The purpose of the call was to review an example of the application of the local transmission
planning process decision rule to a transmission system problem. The decision rule was discussed at
the December 18, 2008 TRANSAC meeting. Prior to the call, the example had been posted in the
form of a spread sheet on the NWE OASIS at:
http://www.oatioasis.com/NWMT/NWMTdocs/Prioritizing_Mitigation_Decision_Rule_Transac_012909.xls .

Decision Rule Application Example
Don Bauer and John Leland led the review of the example which included two parts, a

January 29, 2009 NWE TRANSAC Conference Call Summary                                    Page 1
comparison of system problems/events to identify the highest priority system problems and an
analysis comparing alternative solutions to one system problem. All data listed in the spread
sheets are for purposes of illustration only. The data are not final values.

Highest Priority System Problems - The first tab of the spread sheet shows the comparison
between system problems/events. In the first section of this tab, “Consequences of Event”
(columns B through F), each system problem/event is rated in terms of its consequences and its
risk/probability. The consequence rating is the product of the peak load affected and the sum of
the stability, voltage, and thermal/load loss factors. The peak load affected is determined through
studies that identify the busses affected by the problem or event. The individual factors are
assigned a numerical value using the following table:

       Stability and               Voltage
         Thermal

    Extreme       10     Outage      10         Out
    Severe         5    Very Low      5        ≤ 80%
                         < 80%
    Moderate      2       Low         2        ≤ FERC
                                             (but greater
                                              80% p.u.)
     Minor        1       None        0           OK
     None         0


The 80% voltage value is a rule of thumb breakpoint where a motor will trip off and is measured
as the per unit (p.u.) transmission line voltage at transmission load buses. The FERC value is
NWE’s FERC 715 low voltage criteria limit (for 100 and 115 kV it is 95% p.u. voltage under
normal operating conditions). If the transmission line voltage is less than 80% (for a 161 kV
line, 80% is 128.8 kV), the voltage factor is assigned a value of 5. If the voltage is greater than
80%, but less than the FERC 715 limit, it is assigned a value of 2. For an outage of the 230 kV
bus at the Billings Steam Plant (row 5 on tab 1 of the spread sheet), the sum of the stability and
voltage problems and the thermal/load loss factors is 0 + 5 + 10 = 15. The consequence factor
for this outage is the product of this sum and the peak load affected (15 X 463 MW) = 6945.

The risk/probability factor is the product of the “system condition” factor, the “seasonal
condition” factor, and the “other condition” factor. The numerical value of the latter three factors
are determined from the following table:

         System              Seasonal                        Other

     Normal       1      S Peak     0.12       Major        1        Long Line > 30
                                                                          miles
    N-1 Out      0.1    W Peak      0.12     Moderate       0.5        Short Line
    N-2 Out     0.01    SWPeak      0.25      Minor         0.1      Sub Bus, XFMR
                         Light      0.25
                        Average     0.75
                          All        1




January 29, 2009 NWE TRANSAC Conference Call Summary                                        Page 2
The values assigned under “system” for system normal, a single contingency (N-1), and a double
contingency (N-2) are based on Western Electricity Coordinating Council standards which set
normal as ten times as likely as a single contingency and 100 times as likely as a double
contingency. “S Peak” and “W Peak” refer, respectively, to the several week period during the
summer and winter when the system is heavily loaded. Each peak period is assigned a 0.125
value (i.e., it lasts 12.5% of the year). “SW Peak” combines both peak periods and is assigned a
0.25 value. “Average” conditions are assumed to last one half of the year and are assigned the
value of 0.75. (The assigned “average” value combines both peak periods and the average
period). “All” refers to the entire year and is assigned a value of 1.0. A problem or event on a
transmission line longer than 30 miles is assigned a value of 1.0. A transmission line less than
30 miles in length receives a value of 0.5. A problem or event within a substation is assigned a
value of 0.1. The “risk factor” in column J of tab1 is calculated from the product of the system
condition, the seasonal condition, and the other condition factors. For an outage of the 230 KV
bus at the Billings Steam Plant (row 5 of tab1), the risk factor product of the single contingency
system condition (0.125), the summer peak seasonal condition (0.1), and the minor other
condition (0.1) factors: 0.125 X 0.1 X 0.1 = 0.00125.

The expected consequence is the product of the consequence factor and the risk/probability
factor. For the Billings Steam Plant example, this value is 6945 X 0.00125 = 8.68.

Comment - Risk is usually the product of the consequence and the likelihood that it will occur.
You might, therefore, consider changing the labels in tab 1 columns G through J to “likelihood”
and to column K to “risk”.
Response - We will make this suggested change.

Comment - For the risk rank in column M, low values are good, while for cost rank, column N,
low values are bad.
Response - We agree and will make note of this.

Comment - Another way to display the results that are easily understood is to graph the risk
values, column K or M, on one axis the cost values, and columns L or N on the other axis.
Response - This is a good idea, and we will include such a graph.

Comment - This analysis is very thoughtful and takes us in the right direction.

Comment - The written comments may be even more important than the numerical values in
helping people understand the prioritization.

Question - Some of your loads have different implications for safety or environmental protection.
For example, loss of electricity service to hospitals or the Billings area petroleum refineries
would be more significant than the loss of residential load. To what extent are you comfortable
that this analysis captures the priority of your service to different loads?
Answer - We are aware of the special significance of some loads and should try to capture this
through the comments. While we agree that the loss of some loads would be unacceptable, we
try to plan to serve all loads.

Comparison of Mitigation Alternatives - The second and third tabs in the spread sheet show a

January 29, 2009 NWE TRANSAC Conference Call Summary                                       Page 3
comparison of the mitigation alternatives to address the Helena-Three Forks 100 kV System
problem/event. The first alternative involves the addition of capacitors at various locations. The
second includes the capacitors and reconductoring 66 miles of the Trident-Helena 100 kV
transmission line. While the risk and consequence factors for both alternatives are the same, the
cost and duration of the mitigation of the alternatives are not. The cost divided by the duration
for the two alternatives are $2.1M/15 years = $0.14M/year for the capacitor alternative and
$18.4M/30 years = $0.61M/year for the transmission line plus capacitor alternative.

Question - Where would you factor in additional benefits for solutions that address more than
the specific problem/event under study such as an expansion of capacity that would allow
meeting additional load growth?
Answer - We examine the alternatives using load flow studies. These studies will show how
specific additions provide advantages or disadvantages to other portions of the transmission
system. Evaluating the alternatives is both an art and a science. By art, we mean that
professional judgment is applied as well as quantitative studies. We could note the advantages or
disadvantages and explain professional judgment in the comment box.

Comment - While I don’t want to create more paper work, documentation helps third parties
understand how and why NWE has made a decision. Compiling the spread sheets such as the
examples you provided us today in a binder will aid transparency for planning and rate case
decisions.
Response - We agree. Transparency is one of our key planning objectives.

Comment by Don Bauer - In tab 1 of the spread sheet, lines 11 and 12 show the same system
element/event, the Columbus Area 50 and 100 kV System. Line 11 analyzes this element under
normal operating conditions and line 12 considers the single contingency or N-1 condition. The
results show that problems affecting normal system conditions will have a higher priority than
under the N-1 conditions.

New Oasis Postings
Kathy Bauer stated that a new action item listing and 2009 calendar are posted on the OASIS.
Please see: http://www.oatioasis.com/NWMT/NWMTdocs/Action_Items_01-21-09.xls and
http://www.oatioasis.com/NWMT/NWMTdocs/2009_Calendar_of_Events_and_Study_Cycle_01-20-09.doc.

Also, NWE will accept new economic study requests through the end of February 2009. The
Economic Study Request Form is posted at:
http://www.oatioasis.com/NWMT/NWMTdocs/Economic_Study_Request_Form.xls.

Finally, Ms. Bauer stated that revised versions of the two documents have been posted for a 30-day
comment period, the 01-20-09 draft of Attachment K Business Practice and the 01-20-09 draft of the
ETP Methodology, Criteria and Process. These documents can be found, respectively. at:
http://www.oatioasis.com/NWMT/NWMTdocs/Attachment_K_Business_Practice_Draft_01-20-09.doc; and
http://www.oatioasis.com/NWMT/NWMTdocs/ETP_Method_Criteria_and_Process_BP_Draft_01-20-09.doc.

Next Meeting
The next TRANSAC meeting is scheduled for Thursday, March 19, 2009.


January 29, 2009 NWE TRANSAC Conference Call Summary                                       Page 4
Disclaimer
Committee members provide advice to NWE as individual professionals; the advice they provide
does not bind the agencies or organizations that the members serve.




January 29, 2009 NWE TRANSAC Conference Call Summary                                 Page 5

								
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