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20092010 Winter Reliability Assessment

VIEWS: 6 PAGES: 205

									2009/2010 Winter
Reliability Assessment


                                                    to ensure
                 reliability of the
                  the
            bulk power system
             November 2009
       116-390 Village Blvd., Princeton, NJ 08540
           609.452.8060 | 609.452.9550 fax
                     www.nerc.com
NERC’s Mission

The North American Electric Reliability Corporation (NERC) is an international regulatory
authority for reliability of the bulk power system in North America. NERC develops and
enforces Reliability Standards; assesses adequacy annually via a 10-year forecast and winter and
summer forecasts; monitors the bulk power system; and educates, trains, and certifies industry
personnel. NERC is a self-regulatory organization, subject to oversight by the U.S. Federal
Energy Regulatory Commission (FERC) and governmental authorities in Canada.1

NERC assesses and reports2 on the reliability and adequacy of the North American bulk power
system divided into the eight Regional Areas as shown on the map below (See Table A).3 The
users, owners, and operators of the bulk power system within these areas account for virtually all
the electricity supplied in the U.S., Canada, and a portion of Baja California Norte, México.

                                                                               Table A: NERC Regional Entities
                                                                     ERCOT                                RFC
                                                                     Electric Reliability                 ReliabilityFirst
                                                                     Council of Texas                     Corporation

                                                                     FRCC                                 SERC
                                                                     Florida Reliability                  SERC Reliability
                                                                     Coordinating Council                 Corporation

                                                                     MRO                                  SPP
                                                                     Midwest Reliability                  Southwest Power Pool,
                                                                     Organization                         Incorporated

 Note: The highlighted area between SPP and SERC                     NPCC                       WECC
denotes overlapping Regional area boundaries: For                    Northeast Power            Western Electricity
example, some load serving entities participate in                   Coordinating Council, Inc. Coordinating Council
one Region and their associated transmission
owner/operators in another.

1
    As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce Reliability
    Standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those standards mandatory
    and enforceable. In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New
    Brunswick, Nova Scotia, Québec and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory
    and enforceable in Ontario and New Brunswick as a matter of provincial law. NERC has an agreement with Manitoba Hydro, making
    reliability standards mandatory for that entity, and Manitoba has recently adopted legislation setting out a framework for standards to
    become mandatory for users, owners, and operators in the province. In addition, NERC has been designated as the “electric reliability
    organization” under Alberta’s Transportation Regulation, and certain reliability standards have been approved in that jurisdiction;
    others are pending. NERC and NPCC have been recognized as standards setting bodies by the Régie de l’énergie of Québec, and
    Québec has the framework in place for reliability standards to become mandatory. Nova Scotia and British Columbia also have a
    framework in place for reliability standards to become mandatory and enforceable. NERC is working with the other governmental
    authorities in Canada to achieve equivalent recognition.
2
  Readers may refer to the Reliability Concepts Used in this Report Section for more information on NERC’s reporting
  definitions and methods.
3
  Note ERCOT and SPP are tasked with performing reliability self-assessments as they are Regional planning and operating
  organizations. SPP-RE (SPP – Regional Entity) and TRE (Texas Regional Entity) are functional entities to whom NERC
  delegates certain compliance monitoring and enforcement authorities.


    Page i                                                                         2009/2010 Winter Reliability Assessment
Table of Contents
NERC’s Mission ...........................................................................................................................i
Summary Reliability Assessment of North America ...............................................................1
          Key Highlights ...................................................................................................................1
          Reliability Assessment ......................................................................................................2
          Demand.............................................................................................................................3
          Generation ........................................................................................................................5
          Transmission.....................................................................................................................7
          Operational Issues ............................................................................................................7
Adequate-Level of Reliability (ALR) Winter Metrics ..............................................................12
Estimated Demand, Resources, and Reserve Margins .........................................................15
Regional Reliability Assessment Highlights ..........................................................................20
Regional Reliability Self-Assessments...................................................................................25
          ERCOT............................................................................................................................26
          FRCC ..............................................................................................................................33
          MRO................................................................................................................................39
          NPCC ..............................................................................................................................52
          RFC.................................................................................................................................92
          SERC ............................................................................................................................113
          SPP ...............................................................................................................................154
          WECC ...........................................................................................................................159
About This Report...................................................................................................................177
Reliability Concepts Used in This Report.............................................................................180
Data Checking Methods Applied ...........................................................................................182
Capacity Margin to Reserve Margin Changes ......................................................................184
Terms Used in This Report ....................................................................................................185
Abbreviations Used in This Report .......................................................................................194
Reliability Assessment Subcommittee Roster.....................................................................198
North American Electric Reliability Corporation Staff Roster ............................................201




2009/2010 Winter Reliability Assessment                                                                                               Page ii
Summary Reliability Assessment of North America



Summary Reliability Assessment of North America

Winter Key Highlights


 Economic Recession Results in Increased Projected Reserve Margins

 Reduced economic activity and recession impacts have led to decreased peak
 demand projections and, as a result, higher Reserve Margins throughout North
 America are projected for the upcoming winter season. While some winter
 peaking subregions, including Québec and the Canadian portion of WECC, are
 projected to come close to NERC’s reference reserve levels, all Regions and
 subregions appear to have sufficient resources to maintain reliability this winter.


 Natural Gas and Wind Generation Resources Continue to Grow

 Natural gas-fired generation represents over half of the capacity added since last
 year, growing by approximately 11,000 MW. Regions with the highest growth
 include SERC, NPCC, and FRCC.

 Wind generation also continues to increase, with 8,000 MW of installed
 “nameplate” capacity added since last year (1,500 MW on-peak). Just under
 30,000 MW of installed wind capacity is currently interconnected to bulk power
 system, providing approximately 5,000 MW of on-peak capacity.


 Operational Challenges Are Manageable Through the Winter

 Overall, no operational conditions are expected to significantly impact bulk
 power system reliability this winter. All Regions have operational procedures
 and strategies to mitigate expected reliability issues that may arise.

 As wind resources continue to increase, new operational challenges begin to
 emerge. Challenges in managing the variability of wind resources as well as the
 need to provide additional ancillary services, such as operating reserves, remain
 critical to maintaining reliability. Nevertheless, accommodating the increase of
 wind resources appears manageable this winter.




Page 1                                                    2009/2010 Winter Reliability Assessment
                                                                                 Summary Reliability Assessment of North America


Reliability Assessment

Higher Reserve Margins are projected for this winter season, when compared to last year. The
differences in the projected winter planning Reserve Margin from last winter to this winter are
primarily the result of the economic recession, reducing peak demand projections in a majority
of the Regions. In terms of resource adequacy, all Regions and subregions appear to have
sufficient reserves for meeting winter peak demands and ensuring reliability.

Overall, North America’s projected Deliverable Reserve Margin4 is expected to rise from 29.3
percent forecast last year, to 32.5 percent.5 For the majority of the summer-peaking Regions
within the United States, higher Reserve Margins are expected this winter than the previous
winter (Figure 1a). For winter-peaking Regions and subregions in Canada, Reserve Margins
appear adequate and remain above the NERC Reference Margin Level (Figure 1b).6 Reserve
Margins for the Québec subregion of NPCC and the WECC-Canada subregion are 12.6 and 15.7
percent respectively, due to flat or slight increases in projected peak demands. Resources in both
subregions appear to be sufficient for meeting reliability and resource adequacy requirements.

             Figure 1a: U.S. Winter Peak Planning                                            Figure 1b: Canada Winter Peak
                 Reserve Margin Projections                                               Planning Reserve Margin Projections
             80%                                                                          60%
                                                                                          50%
             60%
                                                                                          40%
                                                                                 Margin
    Margin




             40%                                                                          30%
                                                                                          20%
             20%
                                                                                          10%
             0%                                                                            0%
                                                                        S




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                                            S




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                                                                                                                                     W
                            2008/2009 Net Reserve Margin                                             2008/2009 Net Reserve Margin
                            2009/2010 Deliverable Reserve Margin                                     2009/2010 Deliverable Reserve Margin
                            NERC Reference Margin Level                                              NERC Reference Margin Level


For subregions in the United States, Reserve Margins remain high for the winter season (Figure
1c). The New York subregion of NPCC and the Gateway subregion of SERC have decreased
margins when compared to last winter, but remain well above NERC Reference Margin Levels.7

                Figure 1c: U.S. Subregion Winter Peak Planning Reserve Margin Projections
              120%
              100%
               80%
    Margin




               60%
               40%
               20%
                0%
                       d       rk       SO        JM       al             l ta  y         rn      R          V      US     PP     PA
                    lan     Yo        MI       -P      ntr              De   wa       s te      CA        SN      X     NW     RM
                 Eng      w         C-      FC       Ce                   ate       ea       VA        M-       -M
               w        Ne       RF       R                             G       u th                -N       CA
             Ne                                                               So                 AZ
                       2008/2009 Net Reserve Margin            2009/2010 Deliverable Reserve Margin            NERC Reference Margin Level


4
  See Terms Used in this Report for the Deliverable Reserve Margin definition. “Deliverable” does not refer to deliverability.
5
  For the U.S., the projected 2009/2010 Deliverable Reserve Margin is 52.6 percent; for Canada, 22.2 percent.
6
  See Terms Used in this Report for the NERC Reference Margin Level definition.
7
  Decreases in margins for these subregions are attributed to market functions and enhancements to NERC supply definitions.

2009/2010 Winter Reliability Assessment                                                                                                   Page 2
Summary Reliability Assessment of North America


Demand

Winter forecast8 peak
demands across NERC                      Figure 2a: 2009/2010 Winter Peak Demand
Regions and subregions                  Comparisons for Winter Peaking Subregions
appear manageable for the       50,000
upcoming winter season,         40,000
with a majority of the



                                         MW
                                30,000
Regions showing slight
decreases when compared         20,000
to last year.     For the       10,000
system as a whole, winter
peak demand is projected             0
                                         NWPP US       MRO CA    Maritimes     Quebec     WECC CA
to reach 706,965 MW;
assuming approximately                     2008/2009 Forecast 2008/2009 Actual   2009/2010 Forecast
24,500 MW of Demand
Response       will     be
available on peak.9 A key driver for the overall improvement in Reserve Margins is the
substantial reduction in projected peak Net Internal Demand, representing more than a 2.5
percent decrease from last year’s projected winter peak demand. However, when comparing the
winter peaking subregions, winter peak demand is only slightly reduced, by less than one percent
(Figure 2a).10 Additionally, despite economic conditions affecting electricity use compared to
the past year, winter-peaking subregions, with the exception of the Maritimes subregion,
experienced all-time record-high peak demands last winter.

Decreases in peak demand are more prominent in the summer-peaking Regions and
subregions—as much as 12 percent in FRCC when compared to last winter (Figure 2b). Other
notable decreases are ERCOT (eight percent), CA-MX (seven percent), and RMPA (seven
percent), while NPCC-US and SPP show slight increases. While these reductions are consistent
with the continued effects of the economic recession, uncertainty still remains in the coming
season in terms of magnitude and duration of these reductions.

                   Figure 2b: 2009/2010 Winter Peak Demand Comparisons for Summer
                                      Peaking Regions/Subregions
         200,000

         150,000
    MW




         100,000

          50,000

              0
                   ERCOT    FRCC     MRO US NPCC US        RFC       SERC       SPP     AZ-NM-     CA-MX      RMPA      Ontario
                                                                                         SNV
                                   2008/2009 Forecast       2008/2009 Actual       2009/2010 Forecast


8
   A 50/50 forecast is defined as a forecast adjusted to reflect normal weather, and is expected on a 50 percent probability basis,
   i.e. a peak demand forecast level which has a 50 percent probably of being under or over achieved by the actual peak.
9
   This is a non-coincident value for all eight NERC Regions, generally occurring in the month of January 2010.
10
    Winter peaking subregions include NWPP-US, MRO-Canada, Maritimes, Quebec, and WECC-Canada.

Page 3                                                                          2009/2010 Winter Reliability Assessment
                                                                     Summary Reliability Assessment of North America


Weather and temperature are key drivers affecting peak electricity demand in North America.
For most of the United States, winter temperatures are projected to be either normal or warmer
than normal (see Figure 3a).11 Much of the Western Interconnection is projected to experience
warmer than normal weather patterns. Although temperatures may average warmer than usual,
periods of colder weather are still possible. In the southeast, temperatures are expected to be
colder than normal this winter. However, increased demand, as a result of colder than normal
temperatures, is not expected to affect reliability. While the FRCC Region has experienced
annual peak demands during some winter seasons, primarily due to residential electric heating,
current economic conditions has reduced the demand forecast in the region (12 percent lower
than last winter). Temperatures are forecast to be colder than normal this winter in eastern
Canada, specifically in the Ontario and Maritimes subregions, and southern British Columbia
(see Figure 3b). Normal temperatures are forecast in the south-central provinces of Canada. 12

              Figure 3a: U.S. Winter Mean                                  Figure 3b: Canadian Winter Mean
            Temperature Probability Outlook,                                Temperature Anomaly Outlook,
            December 2009 to February 2010                                 December 2009 to February 2010




       Source: Climate Prediction Center at NOAA, 10/15/09                  Source: Environment Canada, 11/1/09
          A (40) – 40% to 49% chance of temperatures                   Red –     Warmer than normal temperatures
                   being significantly warmer*                                   forecast when compared to the 30
          A (33) – 34% to 39% chance of temperatures                             seasons of the 1971-2000 period.
                   being significantly warmer*
                                                                       White – Normal temperatures forecast when
          B (33) – 34% to 39% chance of temperatures                           compared to the 30 seasons of the
                   being significantly colder *                                1971-2000 period.
          B (40) – 40% to 49% chance of temperatures
                   being significantly colder*                         Blue –    Colder than normal temperatures
                                                                                 forecast when compared to the 30
          EC – No significant shift is expected compared                         seasons of the 1971-2000 period.
               to normal temperatures*



Another variable affecting demand forecasts is the amount of Demand Response contributing to
peak demand reduction. Economic factors and regional, state, or provincial Demand Response
initiatives can greatly increase or decrease the amount (i.e., capacity) of demand resources
available to system operators to manage peak demand. With declining peak demand forecasts
and higher projected Reserve Margins, Demand Response is expected to contribute less to
meeting peak demands this winter, a reduction of about 300 MW. Demand Response programs
for this winter total approximately 27,500 MW for all NERC Regions. While some Regions
11
    http://www.cpc.ncep.noaa.gov/products/predictions/long_range/seasonal.php?lead=2 and
   http://www.noaanews.noaa.gov/stories2009/20091015_winteroutlook.html
12
    For more information on Canadian temperature forecasts, including the statistical significance of the areas in the figure above,
   see http://www.weatheroffice.gc.ca/saisons/index_e.html.
* Above normal temperatures are defined as being in the warmest 1/3 of the temperatures in the same season within the years
   1971—2000. Below normal temperatures are defined as being in the coldest 1/3 of the temperatures for the same time period.

2009/2010 Winter Reliability Assessment                                                                                 Page 4
Summary Reliability Assessment of North America
show continued growth in Demand Response (NPCC and MRO), others show a reduction (RFC,
SERC, and WECC) (Figure 4). The greatest rise in Demand Response resources is observed in
NPCC, where market mechanisms have encouraged significant development in Demand
Response programs within both ISO New England and the New York ISO. The Demand
Response program showing the highest growth is Load as a Capacity Resource.13 The reductions
in Demand Response are primarily due to current economic conditions resulting in a slow-down
of commercial and manufacturing sectors, thereby eliminating their demand resources and, thus,
no longer available to provide demand reductions. However, current economic conditions will
not affect the performance of Demand Response expected to be available this winter.

                            Figure 4: NERC Winter Peak Capacity Demand Response
                                        2008/2009-2009/2010 Comparison
           8,000
           6,000
      MW




           4,000
           2,000
               0
                     2008

                            2009

                                   2008

                                            2009

                                                   2008

                                                           2009

                                                                   2008

                                                                          2009

                                                                                 2008

                                                                                          2009

                                                                                                 2008

                                                                                                        2009

                                                                                                               2008

                                                                                                                      2009

                                                                                                                             2008

                                                                                                                                    2009
                     ERCOT          FRCC              MRO           NPCC            RFC           SERC            SPP         WECC

                        Direct Control Load Management                                  Contractually Interruptible (Curtailable)
                        Critical Peak-Pricing with Control                              Load as a Capacity Resource


Generation

The total Existing-Certain capacity for NERC this winter peak is approximately 1,043,000 MW,
an increase of about 19,000 MW when compared to last winter. While the 2009/2010 winter on-
peak fuel-mix remains relatively unchanged from last year, natural gas-fired generation
continues to be the primary fuel firing new on-peak capacity, with growth of approximately
11,000 MW since last year. Figure 5 shows the relative on-peak capacity by fuel for all of the
interconnected North American bulk power system.


                            Figure 5: 2009/2010 Winter On-Peak Capacity Fuel-Mix
                                                          Coal
                                                          29.4%                                         Pum ped Storage
                    Gas                                                                                      2.0%
                   27.8%

                                                                  4.1%           Other                            Geotherm al
                                                                                 0.7%                                0.2%

                                                                    Oil                                       Undeterm ined/
                                                                   3.8%                                         Unknow n
                                                                                    Biom ass
                                                                                                          Wind    0.3%
                    Hydro                                                             0.5%
                                                             Nuclear                                       0.4%
                    12.8%
                                          Dual Fuel           10.9%
                                           11.2%


13
     See http://www.nerc.com/docs/pc/drdtf/NERC_DSMTF_Report_040308.pdf .

Page 5                                                                                    2009/2010 Winter Reliability Assessment
                                                                    Summary Reliability Assessment of North America


Projected winter installed nameplate14 wind capacity increased by 8,000 MW since last winter to
29,416 MW. However, the total expected on-peak capacity from these resources is 5,000 MW
(Figure 6). On-peak capacity from wind plants, as a percentage of total installed capacity, ranges
from zero in two NERC Regions to over 30 percent in another NERC Region during the
2009/2010 winter.

Consistent methods to determine
                                                                    Figure 6: Projected 2009/2010 Winter
on-peak wind capacity are needed                                      Expected On-Peak Wind Capacity
to ensure uniform measurement of                     2,500                                                                        40%

its   contribution   to    Reserve                                                         31.2%                                  35%
                                                     2,000
Margins.16 On-peak capacity values                                                                                                30%




                                                    MW
shown by Region in Figure 6 are a                    1,500                         19.9%                                  17.7%
                                                                                                                                  25%
                                                                                                   17.6%
non-coincident consolidated sum of                                                                                15.4%           20%
                                                     1,000
subregional values, which may vary                              8.7%                                                              15%


widely. For example, WECC and                            500
                                                                                                                                  10%

                                                                                                                                  5%
NPCC subregions use diverse                                              0.0%                              0.0%
                                                           0                                                                      0%
policies and methods to calculate
                                                               ERCOT FRCC MRO NPCC RFC SERC SPP WECC
expected on-peak capacity of wind
generation (i.e., Effective Load                         Existing      Additions      % of Existing Capacity Expected On-Peak
Carrying Capability), with results
                                                     Table 1: Winter 2009/2010 Existing Wind Resources
ranging from 12.4 to 37.3 percent
                                                                                                                        % of
in WECC and 20.9 to 39.4 percent                                                      Nameplate        On-Peak       Nameplate
in NPCC (see Table 1).17                                                               Capacity        Capacity       Capacity
                                                   Region/Subregion                     (MW)            (MW)          On-Peak
Additionally, some subregions                      ERCOT                                   8,335            725        8.7%
                                                   FRCC                                         0             0         N/A
have modified their own methods
                                                   MRO                                     6,396          1,271        19.9%
for determining expected on-peak                   NPCC                                    3,686          1,161        31.2%
wind capacity this winter. For                       NPCC-Maritimes                          350            138        39.4%
example, in Québec, long-term                        NPCC-New England                        103             91          *
observations and overall increased                   NPCC-New York                         1,507            452        30.0%
installed wind capacity during the                   NPCC-Ontario                          1,084            347        32.0%
last year prompted the subregion to                  NPCC-Québec                             642            134        20.9%
review derating factors for wind                   RFC                                     1,700            300        17.6%
                                                   SERC                                         0             0         N/A
generation. Their simulations have
                                                   SPP                                       455             70        15.4%
determined 20—30 percent of the                    WECC15                                  8,844          1,568        17.7%
installed nameplate capacity can be                  WECC-AZ-NM-SNV                          410            153        37.3%
relied upon for meeting peak                         WECC-CA-MX-US                         3,089            499        16.2%
demand. Similar reevaluations are                    WECC-NWPP US                          3,714            680        18.3%
underway      in    MRO,      which                  WECC-RMPA                             1,109            137        12.4%
currently uses a 20 percent flat rule.               WECC-CANADA                             522             69        13.2%


14
   From EIA: Installed nameplate capacity “The maximum rated output of a generator under specific conditions designated by the
   manufacturer. Generator nameplate capacity is usually indicated in units of kilovolt-amperes (kVA) and in kilowatts (kW) on a
   nameplate physically attached to the generator.” http://www.eia.doe.gov/glossary/glossary_i.htm
15
   The WECC expected on-peak capacity value is a coincident value for all of WECC and is not the sum of the individual WECC
    subregions (which would be a non-coincident value).
16
   Currently, different methods are being used by Regions and subregions to determine expected on-peak values of wind capacity.
   The Integration of Variable Generation Task Force is addressing this issue. http://www.nerc.com/files/IVGTF_Report_041609.pdf

   Currently, differences exist in how existing wind capacity is seasonally rated versus how new wind will be rated under ISO-
    NE’s Forward Capacity Market (FCM). Existing wind capacity was self-determined and, as such, reporting was not
    consistent. This discrepancy is minor in magnitude and, therefore, does not significantly effect resulting ISO-NE conclusions.
2009/2010 Winter Reliability Assessment                                                                               Page 6
Summary Reliability Assessment of North America


Transmission

Based on the self-assessments provided by the Regions, transmission facilities across the NERC
Regions appear adequate for the upcoming winter season. Delays in meeting target in-service
dates for transmission additions are not expected. While some Regions have identified
transmission constraints, operating procedures are in place and no significant reliability impacts
are expected. Additionally, line outages during the winter season are expected to have minimal
impacts to the transmission system.

In some Regions, significant transmission enhancements have been made to meet reliability
needs since the previous winter.
            In ERCOT, dynamic reactive devices were installed in the Dallas area to improve
             voltage stability margins. Further, a new 345 kV line will reduce congestion in the area.
            In MRO, a number of transmission additions and upgrades are expected to be in-service
             by the winter, significantly enhancing reliability throughout the Region. These
             enhancements address both local reliability (i.e., loading issues, voltage support, and
             increased load serving capabilities) and the integration of new wind generation.
            In NPCC, the Québec subregion has commissioned two 625 MW back-to-back HVdc
             converters on its interconnection with Ontario, increasing import and export capability
             by 1,250 MW.
            In RFC, a Variable Frequency Transformer (VFT) was placed in-service, connecting the
             PJM and NYISO systems. The 300 MW VFT enables system operators to control power
             flows across this new tie-line between the two systems, providing enhanced stability
             with a high degree of reliability and flexibility, and improved controllability.18 The VFT
             will be the first merchant transmission project with multiple parties holding the
             entitlements to the new transmission capacity.

Operational Issues

Overall, no operational conditions are expected to significantly impact bulk system reliability.
All Regions have operational procedures and strategies to mitigate expected reliability issues that
may arise during the winter season. However, some issues must be continually monitored and
addressed, such as generator and transmission outage coordination, constrained flowgates, and,
specifically for winter seasons, reservoir water levels for hydroelectric generation. One notable
new ongoing operational challenge is the integration of variable generation.

Operating Reserves for Variable Generation

The continued increase in variable generation, predominately wind, can increase operational
challenges. As wind resources are less predictable and follow the availability of their fuel (i.e.,
wind) rather than demand, non-typical transmission loading can emerge. Further, some Regions
report specific challenges in managing the variability and magnitude of wind resources and the
need to provide additional ancillary services (such as operating reserves). Nevertheless,
operation of the increases in wind resources appears to be manageable for the 2009/2010 winter.
18
     For more detailed explanation of this new technology, refer to the RFC Self-Assessment: Transmission section.

Page 7                                                                          2009/2010 Winter Reliability Assessment
                                                                 Summary Reliability Assessment of North America


On an operational basis, a rapid increase or decrease of wind generation, often referred to as
“ramping,” can have a significant impact on the power flowing through the bulk power system.
Wind generation ramps can have an inverse correlation, or out-of-phase ramping, to daily load
profiles resulting in the need for additional operating reserves. Operators may need to closely
monitor the system and introduce operational resources (i.e., operating reserves) that support the
variability and ancillary services needed to maintain reliability. Additionally, enhanced
operational measures, in particular, redispatch of conventional generation and dynamic
curtailment/dispatch of wind resources can mitigate ramping impacts.

Many Regions and industry groups are actively studying wind integration needs such as accurate
wind forecasting, interconnection standards, new operator tools, and protection/control systems.
Some examples include:
        SPP – Wind Integration Task Force (WITF)19
        WECC – Variable Generation Subcommittee (VGS)20
        Eastern Interconnection – Eastern Wind Integration & Transmission Study (EWITS)21
        NREL – Wind Systems Integration22

Furthermore, tools are being implemented in ERCOT and IESO (the independent service
operator for the Ontario subregion) to improve the accuracy of wind generation forecasts. NERC
will continue to monitor the operational challenges of wind integration to ensure the reliability of
the bulk power system is maintained.

Minimum Demand/Minimum Generation Challenges

In Ontario, variable generation may present a challenge in managing the output from their
baseload23 generation fleet for the day-ahead unit commitment. For example, system demand
may be near the aggregate minimum output of existing conventional baseload generation.
Because existing contracts allow for all energy produced by wind generation to be injected into
the grid, if operators cannot find export opportunities, they may be required to shut down a
quantity of baseload generation to maintain bulk power system reliability. Variable generation,
however, can be curtailed for reliability reasons.

During the projected peak month of December, Ontario may be susceptible to this over-
generation situation, where minimum baseload levels plus additional wind capacity can exceed
minimum demands (see Figure 7).24 Ontario assumes 34 percent of the installed nameplate as
baseload generation based, which is a historical median during minimum demand hours. Based
on weekly minimum demand projections, if wind generation exceeds 50 percent of the installed

19
   http://www.spp.org/committee_detail.asp?commID=78
20
   http://www.wecc.biz/committees/StandingCommittees/JGC/VGS/default.aspx
21
   http://wind.nrel.gov/public/EWITS/
22
   http://www.nrel.gov/wind/systemsintegration/
23
   All nuclear generation not scheduled to be on planned outage is considered to be baseload generation. Required minimum
   hydro output values provided by hydro generators are aggregated to represent baseload generation contribution from
   hydroelectric generation. Expected contribution from wind (34 percent of installed nameplate), cogeneration and other
   intermittent/self-scheduling generation is based on historical contributions during minimum demand hours and are included as
   baseload generation. The Baseload Other line also includes a 1,000 MW decrement to account for expected exports to occur
   during time of minimum demand. These exports are not Firm, but based on historical minimum exports during minimum
   demand.
24
   Figure 7 assumes both a 50 and 70 percent effective wind capacity during minimum demand periods for sensitivity purposes.

2009/2010 Winter Reliability Assessment                                                                            Page 8
Summary Reliability Assessment of North America
nameplate capacity during the minimum demand period, an over-generation situation is possible.
However, the risk of surplus baseload generation conditions is expected to be low. The NWPP
subregion in WECC has also identified this concern, but to a lesser extent. In both cases,
operating procedures have been developed to mitigate any reliability concerns that may occur in
real-time, including the curtailment of wind generation if excess power cannot be reliably
exported.

                           Figure 7: Ontario Minimum Baseload Generation with 50% and
                            70% Wind Capacity Compared to Minimum Weekly Demands
                 16,000
                 15,000
                 14,000
                 13,000
           MW




                 12,000
                 11,000
                 10,000
                  9,000
                  8,000




                                                                                         k1


                                                                                                  k2


                                                                                                           k3


                                                                                                                    k4
                    k1


                             k2


                                     k3


                                             k4


                                                     k1


                                                              k2


                                                                       k3


                                                                                k4

                                                                                       bW


                                                                                                bW


                                                                                                         bW


                                                                                                                  bW
                   W


                            W


                                    W


                                            W


                                                    W


                                                             W


                                                                      W


                                                                               W
                                                    n


                                                            n


                                                                     n


                                                                              n
                 ec


                           ec


                                   ec


                                           ec




                                                                                     Fe


                                                                                              Fe


                                                                                                       Fe


                                                                                                                Fe
                                                  Ja


                                                          Ja


                                                                   Ja


                                                                            Ja
                D


                          D


                                  D


                                          D




                70% of Installed Wind Capacity     50% of Installed Wind Capacity         Minimum Demand
                Minimum Baseload Other             Minimum Baseload Nuclear


Low Ambient Temperature Limits for Wind Generation

Operating wind generation in colder climates may also limit wind generation availability. The
typical minimum operating temperature of a utility-scale wind turbine generator without any
special cold-weather package is -20°C, with a standstill temperature of -30°C. These issues can
largely be mitigated through the addition of cold-weather packages, which include heaters, ice
detectors, and low-temperature lubricants. These measures can decrease ambient temperature
operating limits to -30°C, with a standstill temperature of -40°C. Colder-climate subregions are
considering these upgrades. Both MRO and the NWPP subregion of WECC have identified the
potential need for additional operating reserves during these extreme weather conditions.

Fuel Quality and Operational Challenges

Most Regions and subregions have indicated there are no reliability concerns about fuel quality
at this time. However, the increased reliance on natural gas as one of the leading fuels used for
both intermediate and peaking capacity has prompted NERC to evaluate and monitor reliability
issues associated with natural gas fuel quality and delivery. Because this issue is predominately
Region-specific, the reliability assessment of the impacts of gas composition focuses on those
areas with high reliance on gas-fired generation.

With an increase in Liquefied Natural Gas (LNG) imports and production of unconventional
natural gas, fuel quality is an important characteristic that must be monitored to ensure reliable
operation of some electric generators. Specifically, combined-cycle gas-fired units with low NOx
burners can be sensitive to unanticipated, transient changes in natural gas heat content25
(+/- 5 percent Btu/cu-ft) which could trigger automatic control-action to avoid unit shutdown and


25
     See http://www.beg.utexas.edu/energyecon/lng/documents/NGC_Interchangeability_Paper.pdf and
     http://www.ferc.gov/industries/lng/indus-act/issues/gas-qual/lng-interchangeability-rpt.pdf for more background.
Page 9                                                                            2009/2010 Winter Reliability Assessment
                                                                  Summary Reliability Assessment of North America
                         26
equipment damage. In cases where a number of these units obtain their fuel from the same
pipelines, changes in natural gas heat content can result in multiple unit trips at nearly the same
time, threatening bulk power system operating reliability.27 LNG presents the most notable
challenges due to its diverse origins and compositions; however, unconventional natural gas
production can also present similar fuel quality concerns. Furthermore, units are not only
susceptible to full outages, but may also experience the inability to modulate power output as one
mitigation strategy is to fix the output of units at constant power output until a fuel quality
disruption subsides. This strategy may affect both operational flexibility and resource adequacy.
While fuel quality and composition risks associated with the increased penetration of
unconventional and liquefied natural gas remain relatively low, the potential reliability impacts
should be studied further.

With a NERC-wide view, the number of units vulnerable to fuel quality issues and their capacity
is relatively low, 3.6 percent of all Existing capacity (see Table 2). However, for the New
England subregion of NPCC, over 35.3 percent of Existing capacity resources are potentially
vulnerable to fuel composition changes.

     Table 2: Gas-Fired Generation Identified as Vulnerable to Fuel Quality Issues
                                    # of            Total
                                 Existing          Winter            % of          # of Outages or             Total
                                   Units          Capability       Existing       Events Occurring           Duration of
     Region/Subregion            >100 MW            (MW)           Capacity       Within Last Year            Outages
     MRO                                 11            3,241          5.7%             Unknown                    -
     NPCC-Maritimes                       1              265          3.6%              1 Event               3 hours
     NPCC-New England                    39           12,771         35.3%            14 Outages             27.8 hours
     NPCC-Ontario                        12            1,992          6.5%                 0                      -
     SERC                                61           16,199          6.4%              1 Event               3 hours
     SPP                                  3            3,014          6.2%                 0                      -
                                                                                     14 Outages,
     Total                               127           37,482           3.6%        2 Other Events            33.8 hours

ISO New England continually assesses the impacts on the availability of electric power
generation due to constraints or contingencies within regional fuel supply chains. Due to the
high levels of gas-fired generation within New England’s power generation fleet, ISO New
England has been specifically studying the potential reliability impacts related to natural gas fuel
supplies. Over 25 studies have been performed by ISO New England to date due to a wide range
of events occurring on the regional natural gas supply and transmission systems.

Furthermore, over the last three years, ISO New England has been monitoring the developments
within the regional natural gas pipeline industry, as pipelines revise the gas quality sections of
their tariffs in response to an upcoming influx of LNG that is re-gasified into the northeastern
United States/Canadian natural gas pipelines. ISO New England has developed an operating
procedure, which works to maintain bulk power system reliability that specifically addresses the
seasonal impacts on regional gas-fired generation during periods of extreme winter weather.28



26
   FERC Docket RP08-374-000, June 11, 2008, page 5, item 12: “Casco Bay states that in 2006 it experienced a unit trip due to a
   “lean blow out” condition… attributed to backhauling gas from alternate supply during a Sable outage.”
27
   ISO-NE January 29, 2009 letter, “Summary of Events Related to the January 26, 2008 Sable Island Production Disturbance,
   1,470 MW lost in New England – (No OP4 declared) but shows loss of Sable can be disruptive.
28
   ISO-NE Market Rule 1 – Appendix H – Operation During Cold Weather Conditions.
2009/2010 Winter Reliability Assessment                                                                            Page 10
Summary Reliability Assessment of North America
ISO New England also has an operating procedure that deals with maintaining bulk power
system reliability during events that constrain or temporarily interrupt regional fuel supplies.29

Although ISO New England has not specifically studied the impacts of variations within the
natural gas stream on gas turbines equipped with low NOx burners, other studies were
performed, which simulate the loss of regional gas-fired generation. This “end-effect” – the
temporary loss of gas-fired generation, would be a similar by-product or result of any natural gas
fuel quality issue affecting regional gas-fired power generators.

Other Regions and subregions identified in Table 2 have a relatively low amount of vulnerable
gas-fired generation when compared to all Existing generation within the Regions or subregion.
Self-assessments to fuel quality issues are provided below.
            In FRCC, which has predominately gas-fired generation, the FERC Gas Tariff Gas
             Quality Provisions for natural gas in the Florida Market Area has strict specifications on
             gas composition, Wobbe Index, rate of change of the Wobbe Index, and the heat
             content.30 The FRCC has not experienced natural gas quality issues in the past year. This
             is attributed to compliance with the strict gas quality specifications outlined in the gas
             tariff and improved communication between Generator Operators and Natural Gas
             Transportation Service Providers (TSPs).
            The ERCOT Region is not generally reliant on any single natural gas supply paths that
             would impact significant amounts of generating capacity.
            In the Maritimes, within the last year, one event led to reduced output due to fuel quality
             issues. However, the Maritimes believes these events occur infrequently, and therefore,
             does not raise any major reliability concerns in their subregion.
            In SERC, any restrictions that may occur are continually managed in the daily operation
             of the systems while maintaining system reliability. Dual fuel units are tested to ensure
             their functionality and that back-up fuel supplies are adequately maintained and
             positioned for immediate availability and quality. Some generating units have made
             provisions to switch between two different natural gas pipeline systems, reducing the
             dependence on any single interstate or intrastate pipeline system. Moreover, the diversity
             of generating resources further reduces the Region’s risk.
            Generator operators within SPP continually monitor natural gas heat content and conduct
             regular communications with natural gas suppliers. Coordination with natural gas
             suppliers assures unannounced disruptions will not occur.

For this winter season, any reliability impacts due to fuel quality issues appear manageable for
all NERC Regions. However, NERC will continue to monitor fuel quality issues and other
impacts associated with the increased use of unconventional natural gas.


29
     ISO-NE Operating Procedure No. 21 – Action During an Energy Emergency.
30
     FERC Docket No. RP04-249 This proceeding addressed potential changes in gas quality resulting from introduction of LNG
     into the gas pipeline system. FERC Commission orders in this proceeding resulted in changes to the FERC Gas Tariff Gas
     Quality Provisions for gas in the Florida Market Area. The Commission order was based upon (a) warranty specifications for
     the combustion turbines, (b) the testimony of expert witnesses, (c) the characteristics of the Florida gas system, and (d) the
     NGC+ Interim Guidelines.




Page 11                                                                          2009/2010 Winter Reliability Assessment
                                                                       Adequate-Level of Reliability (ALR) Winter Metrics


Adequate-Level of Reliability (ALR) Winter Metrics

Introduction

Carefully selected and vetted metrics have the potential for indicating impending reliability
issues and performance. For the 2009/2010 Winter Reliability Assessment, two metrics were
selected, which are supported by available monthly data (December, January, and February)
They are:

             ALR 6-2          Energy Emergency Alert 3 (EEA 3)
                              Firm load interruption imminent or in progress.
                                  Balancing Authority or Load Serving Entity foresees or has implemented firm load
                                   obligation interruption. The available energy to the Energy Deficient Entity, as
                                   determined from Level 2, is only accessible with actions taken to increase
                                   transmission transfer capabilities.
             ALR 6-3          Energy Emergency Alert 2 (EEA 2)
                              Load management procedures in effect.
                                 Balancing Authority, Reserve Sharing Group, or Load Serving Entity is no longer able
                                  to provide its customers’ expected energy requirements, and is designated an Energy
                                  Deficient Entity.
                                 Energy Deficient Entity foresees or has implemented procedures up to, but excluding,
                                  interruption of firm load commitments. When time permits, these procedures may
                                  include, but are not limited to: Public appeals to reduce demand, voltage reduction,
                                  interruption of non-firm end use loads in accordance with applicable contracts, DSM,
                                  and load conservation measures.


NERC is reviewing these and other metrics to monitor reliability performance trends. No
conclusions as to the absolute value of these metrics can be drawn at this time. These metrics are
only in their early stages. Identifying benchmarks for performance is a separate and future
activity, which may aid the industry in quantifying its reliability performance. In some cases, the
database for a given metric does not yet contain enough historical information to reveal useful
information. While the metrics may show trends or variances from year-to-year, no
determination has been made as to what indicates an “acceptable” level of performance. Rather,
they show the annual performance and can be a basis for further root-cause analysis.

Further, the metrics should not be compared between Regions or subregions as their bulk power
system (BPS) characteristics and market structures differ significantly in terms of number of
facilities, miles of line, system expansion design approaches, and simple physical, geographic,
and climatic conditions. The metrics presented in this report have been vetted by the industry via
the Reliability Metrics Working Group (RMWG),31 along with the Planning and Operating
Committees.
31
      Through the creation of the RMWG the Planning and Operating Committees have promoted the development of performance
     metrics for the North American Bulk-Power System (BPS). (BPS is a defined term under Federal Power Act Section 215.)
     The intent of this metrics program is to fulfill the obligations of the ERO relative to benchmarking by providing a slate of
     agreed upon metrics, which can yield an overall assessment of reliability of the BPS. The RMWG’s charge is to do so within
     the context of the “Adequate Level of Reliability” (ALR) framework as set out in a December 2007 report Definition of
     “Adequate Level of Reliability” (http://www.nerc.com/docs/pc/Definition-of-ALR-approved-at-Dec-07-OC-PC-mtgs.pdf) and
     filed with the FERC for “information” in response to a FERC directive. The RMWG has developed and implemented a
     decision-making process and has begun to apply it to the myriad field of possible metrics in order to provide a single source for
     the decisional process.


2009/2010 Winter Reliability Assessment                                                                                  Page 12
Adequate-Level of Reliability (ALR) Winter Metrics

ALR 6-2. Energy Emergency Alert 3 (EEA 3)

Background
Energy Emergency Alert 3 (EEA 3) identifies the number of times EEA 3s are issued. EEA 3
events are firm-load interruptions due to capacity and energy deficiency. EEA 3 is currently
reported to NERC and a database is maintained of these events. EEA 3 is defined in NERC
Reliability Standard EOP-002-2.32

The frequency of EEA 3 over a timeframe provides an indication of performance measured at a
balancing authority (BA) or interconnection level. As historical data is gathered, trends in future
reports will provide an indication of either decreasing or increasing adequacy in the electric
supply system. This metric will also provide value in developing a correlation between EEA
events and Reserve Margins for future planning recommendation. Economic factors should not
be included in use of EEAs. However, in certain Regions, and under certain reserve sharing
agreements, the industry has adapted this metric in a way which requires EEA declarations in
order to implement certain commercial or tariff processes. In those Regions where EEA 3 events
are implemented under tariff or contract requirements for economic purposes, they have been
eliminated from the tabulations. These events are not valid as a reliability indicator. This was not
the intended purpose of the EEA process and unfortunately has the effect of making a reliability
indicator into an economic tool for operation of the system.

Limitations
The metric counts the number of EEA 3 declarations. The severity (e.g. load shedding
magnitude and duration) of the events is not presented at this time. The RMWG is presently
examining additional data reporting requirements for gathering information on event severity.

Assessment
Figure Metrics 2 shows the number of EEA 3 events for the winter seasons 2006/2007,
2007/2008, and 2008/2009 at a Regional level. Only four EEA 3s were called during the past
three winter seasons with zero occurring during the previous winter.
SERC contains a number of relatively small Balancing Authorities, which in general makes this
metric not comparable to other Regions.
                                                                                                    Figure Metrics 2
                                                                     EEA 3 Events by Region and Winter Season
              3

              2
      Count




              1

              0
                  2006/07

                             2007/08

                                       2008/09

                                                 2006/07

                                                           2007/08

                                                                     2008/09

                                                                               2006/07

                                                                                          2007/08

                                                                                                     2008/09

                                                                                                               2006/07

                                                                                                                          2007/08

                                                                                                                                    2008/09

                                                                                                                                              2006/07

                                                                                                                                                          2007/08

                                                                                                                                                                    2008/09

                                                                                                                                                                              2006/07

                                                                                                                                                                                         2007/08

                                                                                                                                                                                                   2008/09

                                                                                                                                                                                                             2006/07

                                                                                                                                                                                                                        2007/08

                                                                                                                                                                                                                                  2008/09




                            FRCC                           MRO                           NPCC                            SERC                            SPP                            ERCOT                          WECC




32
     EEA 3 definition is available at http://www.nerc.com/files/BAL-002-0.pdf


Page 13                                                                                                                                                 2009/2010 Winter Reliability Assessment
                                                                                                                                  Adequate-Level of Reliability (ALR) Winter Metrics
ALR 6-3. Energy Emergency Alert 2 (EEA 2)

Background
Energy Emergency Alert 2 (EEA 2) metric measures the number of events BAs declare for
deficient capacity and/or energy during peak load periods, which may serve as a leading
indicator of energy and/or capacity shortfall in the adequacy of the electric supply system. EEA
2 events precede the more severe EEA 3 events.

The number of EEA 2 events, and any trends in their reporting, indicates how well the system is
able to supply the aggregate load requirements. The historical record includes Demand-Side
Management (DSM) activations and non-firm load interruptions per applicable contracts within
the EEA alerts. These demand resources are called upon by BAs and are not of direct concern
regarding reliability. As data is gathered on a going-forward basis, future reports will provide an
indication of either decreasing or increasing adequacy in the electric supply system. EEA events
calling solely for activation of DSM (controllable or contractually prearranged demand-side
dispatch programs) or interruption of non-firm load per applicable contracts will be excluded
from the metric, as Demand Response is a legitimate resource. This metric may also provide
value in developing a correlation between EEA events and Reserve Margins for future planning
recommendations.

Limitations
Future data reporting will be modified to add additional information on what actions are being
taken in EEA 2 events to ensure DSM and non-firm load interruption are excluded from the
metric. Through the RMWG, the Planning Committee is proposing that data reporting processes
be modified to add additional information on what actions are being taken in EEA 2 events to
ensure DSM and non-firm load interruption are excluded from the metric.

Assessment
Figure Metrics 3 shows the number of EEA 2 events for the winter seasons 2006/2007,
2007/2008, and 2008/2009 at a Regional level, unadjusted for DSM activations.
SERC contains a number of relatively small Balancing Authorities, which in general makes this
metric not comparable to other Regions. An increasing number of EEA 2s were called over the
past three winter seasons.

                                                                                                   Figure Metrics 3
                                                                  EEA 2 Events by Region and Winter Season
           8
           6
   Count




           4
           2
           0
               2006/07

                          2007/08

                                    2008/09

                                              2006/07

                                                        2007/08

                                                                    2008/09

                                                                              2006/07

                                                                                         2007/08

                                                                                                   2008/09

                                                                                                             2006/07

                                                                                                                        2007/08

                                                                                                                                   2008/09

                                                                                                                                             2006/07

                                                                                                                                                       2007/08

                                                                                                                                                                 2008/09

                                                                                                                                                                           2006/07

                                                                                                                                                                                      2007/08

                                                                                                                                                                                                2008/09

                                                                                                                                                                                                          2006/07

                                                                                                                                                                                                                     2007/08

                                                                                                                                                                                                                               2008/09




                         FRCC                           MRO                             NPCC                           SERC                            SPP                           ERCOT                          WECC




2009/2010 Winter Reliability Assessment                                                                                                                                                                                             Page 14
Estimated Demand, Resources, and Reserve Margins


Estimated Demand, Resources, and Reserve Margins

To improve consistency and increase granularity                               Table 3: Demand, Capacity, and Margins
and transparency, the NERC Planning Committee
approved new categories33 for capacity resources,                              Total Internal Demand (MW) — The sum of the
                                                                               metered (net) outputs of all generators within the
purchases, and sales (see Table 3). The resource
                                                                               system and the metered line flows into the system, less
designations of “Existing-Certain”, “Existing,                                 the metered line flows out of the system. Total
Uncertain” and “Planned” have been replaced with:                              Internal Demand includes adjustments for indirect
                                                                               Demand-Side Management programs such as
1. Existing:                                                                   conservation programs, improvements in efficiency of
                                                                               electric energy use, and all non-dispatchable Demand
   a. Existing-Certain — Existing generation
                                                                               Response programs
      resources available to operate and deliver
      power within or into the Region during the                               Net Internal Demand (MW) — Total Internal
                                                                               Demand less Dispatchable, Controllable Capacity
      period of analysis in the assessment.
                                                                               Demand Response used to reduce load.
   b. Existing-Other — Existing generation
      resources that may be available to operate                               Existing-Certain and Net Firm Transactions (MW)
                                                                               — Existing-Certain capacity resources plus Firm
      and deliver power within or into the Region
                                                                               Imports, minus Firm Exports.
      during the period of analysis in the
      assessment, but may be curtailed or                                      Deliverable Capacity Resources (MW) —
                                                                               Existing-Certain and Net Firm Transactions plus
      interrupted at any time for various reasons.
                                                                               Future, Planned capacity resources plus Expected
   c. Existing, but Inoperable — Existing                                      Imports, minus Expected Exports
      portion of generation resources that are out-
                                                                               Prospective Capacity Resources (MW) —
      of-service and cannot be brought back into
                                                                               Deliverable Capacity Resources plus Existing, Other
      service to serve load during the period of                               capacity resources, minus all Existing, Other deratings
      analysis in the assessment.                                              (includes derates from variable resources, energy only
                                                                               resources, scheduled outages for maintenance, and
2. Future:                                                                     transmission-limited resources), plus Future-Other
   a. Future-Planned — Generation resources                                    capacity resources, minus all Future-Other deratings.
      anticipated to be available to operate and                               Existing-Certain and Net Firm Transactions (%)
      deliver power within or into the Region                                  — Existing-Certain, and Net Firm Transactions minus
      during the period of analysis in the                                     Net Internal Demand shown as a percent of Net
                                                                               Internal Demand.
      assessment.
   b. Future-Other — Future generating                                         Deliverable Reserve Margin (%) —
      resources that do not qualify in Future-                                 Deliverable Capacity Resources minus Net Internal
                                                                               Demand shown as a percent of Net Internal Demand.
      Planned and are not included in the
      Conceptual category.                                                     Prospective Reserve Margin (%) —
                                                                               Prospective Capacity Resources minus Net Internal
       The monthly estimates of peak-demand,                                   Demand shown as a percent of Net Internal Demand.
       resources and Reserve Margins for each Region                           NERC Reference Reserve Margin Level (%) –
       during the 2009/2010 winter season are in Table                         Either the Target Capacity Margin provided by the
       3a-3c.34                                                                Region/subregion or NERC assigned based on
                                                                               capacity mix (i.e. thermal/hydro).



33
     See the section entitled “Reliability Concepts Used in this Report” for definitions that are more detailed.
34
     For the Region of ERCOT, and the subregions of NPCC and RFC, coincident peaks are provided.



Page 15                                                                            2009/2010 Winter Reliability Assessment
                                                            Estimated Demand, Resources, and Reserve Margins


Table 3a: Estimated December 2009 Demand, Resources, and Reserve Margins

                                            Existing                            Existing                             NERC
                                           Certain &                           Certain &                           Reference
                    Total                  Net Firm    Deliverable Prospective Net Firm    Deliverable Prospective Reserve
                  Internal    Net Internal Trans-       Capacity    Capacity    Trans-      Reserve     Reserve     Margin
                  Demand       Demand       actions    Resources Resources      actions     Margin       Margin      Level
                   (MW)         (MW)         (MW)        (MW)        (MW)         (%)         (%)         (%)        (%)
United States
ERCOT               39,754        38,639      70,088      70,524      70,524       81.4%       82.5%       82.5%       12.5%
FRCC                35,980        32,807      54,572      55,907      55,907       66.3%       70.4%       70.4%       15.0%
MRO                 34,906        33,106      47,586      47,596      48,593       43.7%       43.8%       46.8%       15.0%
NPCC                46,302        44,348      73,523      73,767      72,067       65.8%       66.3%       62.5%       15.0%
  New England       21,304        21,304      35,700      35,813      35,813       67.6%       68.1%       68.1%       15.0%
  New York          24,998        23,044      37,823      37,954      36,254       64.1%       64.7%       57.3%       16.5%
RFC                143,500       138,600     215,800     215,800     217,200       55.7%       55.7%       56.7%       15.0%
  RFC-MISO          49,100        47,400      70,800      70,800      72,100       49.4%       49.4%       52.1%       15.0%
  RFC-PJM           94,300        91,100     142,800     142,800     142,900       56.8%       56.8%       56.9%       15.0%
SERC               168,574       163,757     245,990     246,489     256,394       50.2%       50.5%       56.6%       15.0%
  Central           39,124        38,337      53,331      53,331      53,451       39.1%       39.1%       39.4%       12.7%
  Delta             22,040        21,406      39,352      39,455      39,623       83.8%       84.3%       85.1%       15.0%
  Gateway           14,738        14,738      20,934      20,934      21,404       42.0%       42.0%       45.2%       15.0%
  Southeastern      39,193        37,482      58,344      58,694      66,709       55.7%       56.6%       78.0%       15.0%
  VACAR             53,479        51,794      74,029      74,075      75,207       42.9%       43.0%       45.2%       15.0%
SPP                 32,636        31,988      49,549      49,972      58,822       54.9%       56.2%       83.9%       13.6%
WECC               110,921       108,132     166,795     170,980     170,980       54.3%       58.1%       58.1%       16.7%
  AZ-NM-SNV         18,564        18,102      37,364      38,111      38,111      106.4%      110.5%      110.5%       15.5%
  CA-MX US          41,831        39,938      61,453      63,142      63,142       53.9%       58.1%       58.1%       15.9%
  NWPP              40,667        40,412      56,724      56,942      56,942       40.4%       40.9%       40.9%       18.4%
  RMPA               9,859         9,680      13,151      14,224      14,224       35.9%       46.9%       46.9%       15.4%

Total-U.S.         612,573       591,377     923,902     931,034     950,486       56.2%       57.4%       60.7%       15.0%

Canada
MRO                   7,390        7,102       8,839        8,947       8,947      24.5%       26.0%       26.0%       10.0%
NPCC                 60,323       58,434      75,171       74,205      73,583      28.6%       27.0%       25.9%       10.0%
  Maritimes           5,075        4,686       7,639        7,639       6,464      63.0%       63.0%       37.9%       15.0%
  Ontario            21,919       21,919      28,118       28,202      28,564      28.3%       28.7%       30.3%       17.5%
  Quebec             33,329       31,829      39,414       38,364      38,555      23.8%       20.5%       21.1%       10.0%
WECC                 21,548       21,548      24,751       24,929      24,929      14.9%       15.7%       15.7%       13.2%

Total-Canada         89,262       87,085     108,761     108,081     107,460       24.9%       24.1%       23.4%       10.0%

Mexico
WECC CA-MX Mex        1,395        1,395       2,454        2,454       2,454      75.9%       75.9%       75.9%       10.1%

Total-NERC         703,230       679,857   1,035,118    1,041,570   1,060,400      52.3%       53.2%       56.0%       15.0%




2009/2010 Winter Reliability Assessment                                                                            Page 16
Estimated Demand, Resources, and Reserve Margins


Table 3b: Estimated January 2010 Demand, Resources, and Reserve Margins

                                           Existing                            Existing                             NERC
                                          Certain &                           Certain &                           Reference
                   Total                  Net Firm    Deliverable Prospective Net Firm    Deliverable Prospective Reserve
                 Internal    Net Internal Trans-       Capacity    Capacity    Trans-      Reserve     Reserve     Margin
                 Demand       Demand       actions    Resources Resources      actions     Margin       Margin      Level
                  (MW)         (MW)         (MW)        (MW)        (MW)         (%)         (%)         (%)        (%)
United States
ERCOT              43,083        41,968      73,602      74,038      74,038       75.4%       76.4%       76.4%       12.5%
FRCC               44,446        40,846      55,881      57,216      57,216       36.8%       40.1%       40.1%       15.0%
MRO                34,977        33,075      47,661      47,765      48,936       44.1%       44.4%       48.0%       15.0%
NPCC               47,098        45,144      74,021      74,273      72,560       64.0%       64.5%       60.7%       15.0%
  New England      22,100        22,100      36,198      36,319      36,319       63.8%       64.3%       64.3%       15.0%
  New York         24,998        23,044      37,823      37,954      36,241       64.1%       64.7%       57.3%       16.5%
RFC               145,800       140,900     215,800     215,800     217,200       53.2%       53.2%       54.2%       15.0%
  RFC-MISO         49,100        47,400      70,800      70,800      72,100       49.4%       49.4%       52.1%       15.0%
  RFC-PJM          96,600        93,400     142,800     142,800     142,900       52.9%       52.9%       53.0%       15.0%
SERC              179,659       174,649     248,181     248,680     259,037       42.1%       42.4%       48.3%       15.0%
  Central          43,230        42,410      54,303      54,303      54,649       28.0%       28.0%       28.9%       12.7%
  Delta            21,839        21,183      39,506      39,609      39,776       86.5%       87.0%       87.8%       15.0%
  Gateway          15,640        15,640      21,868      21,868      22,338       39.8%       39.8%       42.8%       15.0%
  Southeastern     41,740        39,940      58,273      58,623      66,639       45.9%       46.8%       66.8%       15.0%
  VACAR            57,210        55,476      74,231      74,277      75,635       33.8%       33.9%       36.3%       15.0%
SPP                32,636        31,988      49,549      49,972      58,822       54.9%       56.2%       83.9%       13.6%
WECC              109,194       105,981     165,371     170,190     170,190       56.0%       60.6%       60.6%       16.7%
  AZ-NM-SNV        18,880        18,188      37,178      38,368      38,368      104.4%      111.0%      111.0%       15.5%
  CA-MX US         40,185        38,179      60,033      61,829      61,829       57.2%       61.9%       61.9%       15.9%
  NWPP             40,867        40,577      56,555      56,841      56,841       39.4%       40.1%       40.1%       18.4%
  RMPA              9,262         9,037      13,442      14,534      14,534       48.7%       60.8%       60.8%       15.4%

Total-U.S.        636,893       614,551     930,065     937,933     957,999       51.3%       52.6%       55.9%       15.0%

Canada
MRO                  7,504        7,216       8,823        9,022       9,022      22.3%       25.0%       25.0%       10.0%
NPCC                64,461       62,568      77,681       77,561      76,872      24.2%       24.0%       22.9%       10.0%
  Maritimes          5,497        5,104       7,697        7,697       6,458      50.8%       50.8%       26.5%       15.0%
  Ontario           22,848       22,848      30,659       30,889      31,398      34.2%       35.2%       37.4%       17.5%
  Quebec            36,116       34,616      39,325       38,975      39,016      13.6%       12.6%       12.7%       10.0%
WECC                21,271       21,271      24,509       24,687      24,687      15.2%       16.1%       16.1%       13.2%

Total-Canada        93,237       91,055     111,013     111,270     110,581       21.9%       22.2%       21.4%       10.0%

Mexico
WECC CA-MX Mex       1,359        1,359       2,265        2,265       2,265      66.7%       66.7%       66.7%       10.1%

Total-NERC        731,488       706,965   1,043,343    1,051,468   1,070,845      47.6%       48.7%       51.5%       15.0%




Page 17                                                                    2009/2010 Winter Reliability Assessment
                                                            Estimated Demand, Resources, and Reserve Margins


Table 3c: Estimated February 2010 Demand, Resources, and Reserve Margins

                                            Existing                            Existing                             NERC
                                           Certain &                           Certain &                           Reference
                    Total                  Net Firm    Deliverable Prospective Net Firm    Deliverable Prospective Reserve
                  Internal    Net Internal Trans-       Capacity    Capacity    Trans-      Reserve     Reserve     Margin
                  Demand       Demand       actions    Resources Resources      actions     Margin       Margin      Level
                   (MW)         (MW)         (MW)        (MW)        (MW)         (%)         (%)         (%)        (%)
United States
ERCOT               43,221        42,106      72,531      73,017      73,017       72.3%       73.4%       73.4%       12.5%
FRCC                36,765        33,352      55,881      57,528      57,679       67.5%       72.5%       72.9%       15.0%
MRO                 33,969        32,027      47,496      47,600      48,774       48.3%       48.6%       52.3%       15.0%
NPCC                46,612        44,658      73,099      73,351      71,786       63.7%       64.3%       60.7%       15.0%
  New England       21,614        21,614      36,098      36,219      36,219       67.0%       67.6%       67.6%       15.0%
  New York          24,998        23,044      37,001      37,132      35,567       60.6%       61.1%       54.3%       16.5%
RFC                140,700       135,800     215,800     215,800     217,200       58.9%       58.9%       59.9%       15.0%
  RFC-MISO          47,500        45,800      70,800      70,800      72,100       54.6%       54.6%       57.4%       15.0%
  RFC-PJM           93,100        89,900     142,800     142,800     142,900       58.8%       58.8%       59.0%       15.0%
SERC               172,901       167,807     247,467     247,966     256,558       47.5%       47.8%       52.9%       15.0%
  Central           40,964        40,161      53,946      53,946      54,112       34.3%       34.3%       34.7%       12.7%
  Delta             22,064        21,299      39,498      39,601      39,767       85.4%       85.9%       86.7%       15.0%
  Gateway           15,363        15,363      21,649      21,649      22,119       40.9%       40.9%       44.0%       15.0%
  Southeastern      40,075        38,273      58,198      58,548      66,563       52.1%       53.0%       73.9%       15.0%
  VACAR             54,435        52,711      74,176      74,222      73,997       40.7%       40.8%       40.4%       15.0%
SPP                 32,636        31,988      49,549      49,972      58,822       54.9%       56.2%       83.9%       13.6%
WECC               104,703       101,599     162,855     168,605     168,605       60.3%       66.0%       66.0%       16.7%
  AZ-NM-SNV         17,762        17,078      35,788      36,978      36,978      109.6%      116.5%      116.5%       15.5%
  CA-MX US          39,032        37,028      59,066      61,826      61,826       59.5%       67.0%       67.0%       15.9%
  NWPP              38,866        38,675      56,079      56,369      56,369       45.0%       45.8%       45.8%       18.4%
  RMPA               9,043         8,818      13,516      14,608      14,608       53.3%       65.7%       65.7%       15.4%

Total-U.S.         611,507       589,337     924,677     933,838     952,440       56.9%       58.5%       61.6%       15.0%

Canada
MRO                   7,337        7,049       8,736        8,935       8,935      23.9%       26.8%       26.8%       10.0%
NPCC                 62,588       60,701      75,303       74,883      74,300      24.1%       23.4%       22.4%       10.0%
  Maritimes           5,468        5,081       7,697        7,697       6,412      51.5%       51.5%       26.2%       15.0%
  Ontario            22,601       22,601      28,446       28,676      29,187      25.9%       26.9%       29.1%       17.5%
  Quebec             34,519       33,019      39,160       38,510      38,701      18.6%       16.6%       17.2%       10.0%
WECC                 20,604       20,604      24,828       25,107      25,107      20.5%       21.9%       21.9%       13.2%

Total-Canada         90,529       88,354     108,867     108,925     108,342       23.2%       23.3%       22.6%       10.0%

Mexico
WECC CA-MX Mex        1,357        1,357       2,264        2,264       2,264      66.8%       66.8%       66.8%       10.1%

Total-NERC         703,393       679,048   1,035,808    1,045,027   1,063,047      52.5%       53.9%       56.5%       15.0%




2009/2010 Winter Reliability Assessment                                                                            Page 18
Estimated Demand, Resources, and Reserve Margins


Notes for Table 3a through 3c

Note 1: Existing-Certain resources and Net Firm Transactions are reported to be deliverable by the Regions.

Note 2: The inoperable portion of Total Potential Resources may not be deliverable.

Note 3: The WECC-US peak demands or resources do not necessarily equal the sums of the non-coincident WECC-
US subregional peak demands or resources because of subregional monthly peak demand diversity. Similarly, the
Western Interconnection peak demands or resources do not necessarily equal the sums of the non-coincident
WECC-U.S., Canada, and Mexico peak demands or resources. In addition, the subregional resource numbers
include use of seasonal demand diversity between the winter-peaking northwest and the summer-peaking portions of
the Western Interconnection.

Note 4: The Demand-Side Management resources are not necessarily sharable between the WECC subregions and
are not necessarily sharable within subregions.

Note 5: WECC CA-MX represents only the northern portion of the Baja California Norte, Mexico electric system
interconnected with the United States.

Note 6: MISO and PJM information do not sum to the RFC total, as approximately 100 MW of Ohio Valley
Electric Corporation (OVEC)35 peak demand is also included in RFC. OVEC is not affiliated with either PJM or
MISO; however, OVEC’s Reliability Coordinator services are performed by PJM. RFC information is only for the
demand and capacity within its Region. Additionally, the RFC Region and the MISO and PJM subregion demand
values are coincident.

Note 7: These demand and supply forecasts were reported on September 30, 2009.

Note 8: Each Region/subregion may have their own specific Reserve Margin level based on load, generation, and
transmission characteristics as well as regulatory requirements. If provided in the data submittals, the
Regional/subregional Target Reserve Margin level is adopted as the NERC Reference Reserve Margin Level. If not,
NERC assigned a 15 percent Reserve Margin for predominately thermal systems and a 10 percent Reserve Margin
for predominately hydro systems.

Note 9: Based on Midwest ISO tariff requirements, individual LSE reserve levels in the SERC Gateway subregion
are 12.7 percent. Accordingly, the NERC Reference Margin Reserve Level for SERC Gateway subregion is 12.7
percent.36




35
  OVEC is a generation and transmission utility located in Indiana, Kentucky and Ohio.
36
  For more information, see the Midwest ISO 2009–2010 LOLE Study Report at:
  http://www.midwestmarket.org/publish/Document/62c6cd_120e7409639_-7f2a0a48324a



Page 19                                                                  2009/2010 Winter Reliability Assessment
                                                    Regional Reliability Assessment Highlights



Regional Reliability Assessment Highlights

                          ERCOT
                          The 2009/2010 winter peak demand forecast of 43,463 MW is 9.08
                          percent lower than the 2008/2009 winter actual demand of 47,806
                          MW. This expected reduction is largely due to the impact of the
                          economic recession. Market participants in the ERCOT Region have
                          added a net of 2,715 MW of Existing-Certain generation capacity
                          since last winter’s assessment. Of this amount, 214 MW was new
wind generation (which is 2,460 MW nameplate capacity with an effective load carrying
capability on-peak of 8.7 percent). With 72,531 MW of Net Capacity Resources, the ERCOT
Region Reserve Margin is 68 percent, well over the target annual Reserve Margin of 12.5
percent.

Several transmission improvements have been made throughout the ERCOT Region to meet
reliability needs. Approximately 27 miles of new 345 kV lines have been completed since the
2008/2009 winter and 20.5 miles of upgraded 345 kV lines are expected to be completed during
the 2009/2010 winter. Approximately 287 miles of new or upgraded 138 kV transmission lines
were completed since the 2008/2009 winter and an additional 108 miles of new or upgraded 138
kV lines are expected to be completed by the end of the 2009/2010 winter period.

There are no known transmission constraints expected to significantly impact reliability across
the ERCOT Region during the winter period. Integration of additional wind generation continues
to increasingly affect system operations. Several changes to requirements and processes have
already been made, or are planned for implementation, to mitigate these impacts.


                           FRCC
                           FRCC expects to have adequate generating reserves with transmission
                           system deliverability throughout the 2009/2010 winter peak demand.
                           In addition, Existing-Other merchant plant capability of 1,340 MW is
                           potentially available as future resources for FRCC members and
                           others.

The transmission capability within the FRCC Region is expected to be adequate to supply firm
customer demand and planned firm transmission service. Operational issues can develop due to
unplanned outages of generating units within the FRCC Region. However, it is anticipated that
existing operational procedures, pre-planning, and training will adequately manage and mitigate
these potential impacts to the bulk transmission system.




2009/2010 Winter Reliability Assessment                                               Page 20
Regional Reliability Assessment Highlights


                           MRO
                           The Midwest Reliability Organization’s (MRO) forecasted 2009/2010
                           Non-Coincident Winter Peak Total Internal Demand is 42,480 MW.
                           This forecast is 1.4 percent below last winter’s forecasted total
                           demand of 43,080 MW. The recession and nationwide economic
                           downturn are the main reasons for the slight decrease in forecast. The
                           Existing-Certain resources for 2009/2010 winter are 56,623 MW.
This is 1,036 MW higher than the Existing-Certain resources reported for the 2008/2009 winter.
303 MW of planned generation is expected to be placed in service prior to or during the
2009/2010 winter season. Approximately 700 MW of wind generation is expected to be placed
in service prior to or during the 2009/2010 winter season (since June 1, 2009). The projected
Reserve Margin is 41.3 percent, which is well above the various target Reserve Margins
established by the RTOs and Planning Authorities within the MRO Region.

Numerous transmission reinforcements will be completed by or during the upcoming winter
season. These reinforcements include several rebuilt/reconductored transmission circuits;
several new 115 kV, 138 kV and 161 kV circuits; two new 345 kV circuits in Nebraska and
Wisconsin; three new bulk power transformers; two new substations; and various substation
expansions and upgrades.

The MRO footprint will have about 6,400 MW of nameplate wind generation as of December 1,
2009. Most of this wind generation is managed by the Midwest ISO Reliability Coordinator. At
the present time ramp rates, output volatility, and the inverse nature of wind generation with
respect to load levels have been manageable. However, the Midwest ISO closely watches the
ramp-down rate of wind generation during the morning load pickup period. The simultaneous
output of wind generation within the MRO Region has historically reached 75 percent or more of
nameplate rating for extended periods of time which can occur during off-peak hours during
minimum load periods. The Midwest ISO is actively exploring new and better ways to manage
the wind generation within its footprint through stakeholder workshops. Extensive analysis is
being performed by the Midwest ISO regarding wind generation in areas such as regulation, load
following, ramp rates, managing minimum load periods, wind forecasting, equitable participation
during curtailments, and redispatch. These ongoing quarterly workshops also address future
aspects of wind such as establishing appropriate capacity credits, day-ahead participation in
market processes, and energy storage.


                          NPCC
                          Due to the realization of milder weather than that which was forecast,
                          the actual peak loads experienced during the winter of 2008/2009
                          were below forecasts in four of the five NPCC subregions; the
                          subregion of Québec exceeded its forecast peak demand for the
                          2008/2009 winter period by almost 700 MW due to a period of
                          extreme cold in January 2009. All NPCC subregions are currently
experiencing the impact of the economic downturn in its projected system demand. Demand
forecasts for the 2009/2010 Winter are lower than last winter’s forecasts for all five NPCC
subregions mainly due to the slowdown of economic activity.



Page 21                                                   2009/2010 Winter Reliability Assessment
                                                                       Regional Reliability Assessment Highlights


When compared with projections for the 2009/2010 winter, the New England, New York,
Ontario, and Québec subregions are projecting Reserve Margins similar to or higher than the
Reserve Margins projected for the 2008/2009 winter. The Maritimes subregion is projecting a
lower Reserve Margin due to the continuing outage of the Point Lepreau nuclear unit, however,
the Maritimes Reserve Margin is projected to be adequate with a forecast of 25 percent.

The NPCC transmission system is expected to perform adequately, and several enhancements to
the system have been made since the 2008/2009 Winter.


                         RFC
                         The projected Reserve Margin for the ReliabilityFirst (RFC) Region is
                         74,900 MW, which is 53.2 percent based on Net Internal Demand
                         (NID) and Deliverable Resources. Both Midwest ISO and PJM RTO
                         (PJM) have sufficient resources to satisfy their planning reserve
                         requirements. Therefore, the resulting Reserve Margin for this winter
                         in the ReliabilityFirst Region is adequate. This compares to a 49.8
percent Reserve Margin in last winter’s assessment.

Approximately 85 percent of the PJM RTO demand and approximately 60 percent of the
Midwest ISO market demand is within the RFC Region. Since Ohio Valley Electric Corporation
(OVEC) is not a member of either RTO market, its demand of approximately 100 MW was
added to that of the PJM and Midwest ISO areas within the RFC.37

The forecast winter 2009/2010 coincident peak demand for the RFC Region is 140,900 MW (Net
Internal Demand). This is unchanged when compared to the previous winter’s forecast, primarily
due to economic conditions. Both weather and economic conditions have significant influence on
electrical peak demand forecasts.

The amount of Existing-Certain OVEC, PJM and Midwest ISO capacity in RFC is 215,600 MW.
This is 4,600 MW more Existing-Certain capacity than the 211,000 MW that was reported within
the 2008/2009 winter assessment. Much of the increase in the Existing-Certain capacity for this
winter comes from capacity in the Midwest ISO area of RFC that was not committed in the
Midwest ISO market last winter. Capacity committed to the markets at the beginning of the
winter period is assumed constant throughout the winter. New capacity in-service after the start
of the planning year (June) is not included within the calculation of the winter Reserve Margins
for either PJM or Midwest ISO.

The projected reserves for the PJM RTO during the 2009/2010 winter peak are 58,000 MW,
which is 53.0 percent of the Net Internal Demand. The PJM capacity requirement is based upon
the summer peak demand and reflects a total capacity of 150,300 MW. The PJM net capacity
resources are 167,500 MW, which is 17,200 MW greater than the requirement. The PJM RTO
has adequate reserves to serve the 2009/2010 winter peak demand.

37
     Ohio Valley Electric Corporation (OVEC), a generation and transmission company located in Indiana, Kentucky and Ohio, is
     not a member of either RTO and is not affiliated with their markets; however, PJM performs OVEC’s Reliability Coordinator
     services.



2009/2010 Winter Reliability Assessment                                                                             Page 22
Regional Reliability Assessment Highlights


The projected reserves for the Midwest ISO for the 2009/2010 winter peak are 42,200 MW,
which is 53.1 percent, of the Net Internal Demand of its market area. The Midwest ISO reserve
requirement is 15.4 percent for each month of the planning year. The Midwest ISO winter
Reserve Margin is adequate for the Midwest ISO.

New transmission additions to the bulk power system, since last winter, that have been placed in-
service include a total of six miles of transmission line(s) at 230 kV and above, plus ten
transformers with a total capacity rating of about 6,100 MVA. An additional total of 32 miles of
transmission line(s) at 230 kV and above is expected to be placed in-service by this winter, plus
three transformers with a total capacity rating of about 4,500 MVA.

The transmission system within the RFC footprint is expected to perform well over a wide range
of operating conditions, provided new facilities go into service as scheduled, and that
transmission operators take appropriate action, as needed, to control power flows, reactive
reserves, and voltages.


                            SERC
                             SERC Reliability Corporation (SERC) reports all utilities within the
                            Region expect to meet all customer demand during the winter
                            2009/2010. The 2009/2010 winter demand forecast is 2.2 percent
                            lower than the forecast for the 2008/2009 winter Total Internal
                            Demand. This reduction in demand, as compared to last winter season
                            is primarily due to the economic recession. The majority of the
utilities in SERC are forecasting lower demand for the winter 2009/2010 period than was
forecasted for the prior winter season.

Utilities in the SERC Region expect to have adequate generating capacity and the reserves
necessary to meet all customer demand during the 2009/2010 winter period.

The transmission capability of the utilities within the SERC Region is expected to be adequate to
deliver supply to firm customer demand. Operational issues can develop due to unplanned
outages of generating units owned by the companies within the SERC Region; however, it is
anticipated that existing operational procedures, pre-planning, and training will allow the utilities
in the Region to adequately manage and mitigate the impacts of such events to the bulk
transmission system in the Region.




                           SPP
                           The SPP RTO Region’s forecasted demand for the 2009/2010 winter
                           operating season is 32,636 MW. Approximately 511 MW of Existing-
                           Certain resources were added to the SPP Region since the last
                           reporting year. Future resource growth is expected to total
                           approximately 423 MW over the assessment timeframe. The SPP



Page 23                                                      2009/2010 Winter Reliability Assessment
                                                    Regional Reliability Assessment Highlights


RTO’s Reserve Margin, based on Existing-Certain and net firm transactions, is forecasted to be
54.9 percent. With the addition of Deliverable resources, the Reserve Margin is forecasted to be
56.2 percent. The projected Reserve Margins exceed SPP’s target Reserve Margin of 13.6
percent.

On April 1, 2009, the SPP RTO acquired three new members for which SPP is performing
reliability coordination and tariff administration services: Nebraska Public Power District,
Omaha Public Power District, and Lincoln Electric System. However, Midwest Reliability
Organization (MRO) will continue to perform Reliability Assessments for these entities until the
NERC Regional Delegation Agreement is revised.

Because the SPP RTO is a summer-peaking Region, no known transmission issues are expected
during 2009/2010 winter. Because Level 3 Energy Emergency Alerts (EEA 3s) were issued in
the Acadiana area during this past summer, the SPP RTO will continue to monitor this area
closely as part of its reliability coordinator function.

The continued surge in wind development in the western part of the SPP system (especially in
Oklahoma, the Texas panhandle, and western Kansas) is the most challenging obstacle facing the
operation of SPP’s bulk power system. In the coming years SPP will develop additional criteria,
such as requiring voltage support, to handle issues native to variable wind farm operations. SPP
staff is expected to complete a Wind Integration Task Force study this winter which will suggest
implementing operational tools to manage wind penetration in the SPP footprint.

                              WECC
                              The WECC 2009/2010 winter Total Internal Demand is forecast to
                              be 133,864 MW, with a Reserve Margin of 50.9 percent. Due to
                              expected poor economic conditions, the forecast demand is 2.0
                              percent less than last winter’s actual peak demand of 136,592
                              MW.

                             All of WECC’s four subregions project sufficient margins to meet
their forecast peak demand and operating reserve obligations. Of the four subregions, the
Northwest Power Pool is typically winter peaking, but the Rocky Mountain Power subregion
could be either winter or summer peaking.

The projected hydro levels for the 2009/2010 winter season are below normal, but the hydro
generation and thermal generation are expected to be sufficient to meet the winter peak demands
and energy loads. While it is not expected that extremes of winter weather during peak load
conditions would have a significant impact on the fuel supply infrastructure, sudden and very
severe winter storms may adversely affect transmission, generating plant availability, and fuel
supplies in areas impacted by the storms.




2009/2010 Winter Reliability Assessment                                               Page 24
Regional Reliability Self-Assessments



Regional Reliability Self-Assessments

Introduction

Regional Resource and Demand Projections
The figures in the Regional self-assessment pages show the Regional historical demand,
projected demand growth, Reserve Margin projections, and generation expansion projections
reported by the Regions.

Capacity Fuel Mix
The Regional capacity fuel mix charts shown in each Region’s self-assessment presents the
relative reliance on specific fuels38 for its reported generating capacity. The charts for each
Region in the Regional self-assessments are based on the most recent data available in NERC’s
Electricity Supply and Demand (ES&D) database. Overall NERC fuel-mix is shown below.

                      2009/2010 Overall NERC Total Capacity Resources by Fuel-Type
            350,000
            300,000
            250,000
            200,000
       MW




            150,000
            100,000
             50,000
                  0
                          Coal          Gas         Hydro     Nuclear     Dual Fuel      Oil        Other       Pumped
                                                                                                                Storage
                                 Existing-Certain Capacity      Future-Planned Capacity (for the 2009/2010 Winter)




            NERC Interconnections                                                     NERC Subregions

38
     Note: The category “Other” may include capacity for which the total capacity of a specific fuel type is less than 1% of the total
     capacity or the fuel type has yet to be determined



Page 25                                                                           2009/2010 Winter Reliability Assessment
                                                        Regional Reliability Self-Assessments



ERCOT
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand MW                        On-Peak Capacity by Fuel Type
Total Internal Demand                       43,221
  Direct Control Load Management                 0
  Contractually Interruptible (Curtailable)      0
                                                                                    Dual
  Critical Peak-Pricing with Control             0
                                                                      Gas           Fuel
  Load as a Capacity Resource                1,115
                                                                      52%           20%
Net Internal Demand                         42,106                                              Other
                                                                                                 4%
2008/2009 Winter Comparison                    MW % Change                                    Nuclear
                                                                             Coal               7%
2008/2009 Winter Projected Peak Demand        45,658  -7.8%
                                                                             17%           Hydro
2008/2009 Winter Actual Peak Demand           47,806 -11.9%
                                                                                            1%
All-Time Winter Peak Demand                   50,408 -16.5%

2009/2010 Winter Projected Peak Capacity MW             Margin
Existing Certain and Net Firm Transactions 72,531       72.3%
Deliverable Capacity Resources             73,017       73.4%
Prospective Capacity Resources             73,017       73.4%
NERC Reference Margin Level                   -         12.5%




Demand
The 2009/2010 winter peak demand forecast of 43,463 MW, shown in Table ERCOT-1, is lower
than the 2008/2009 winter actual demand of 47,806 MW by 4,343 MW. This represents a 9.08
percent decrease from the 2008/2009 actual winter peak, largely due to the current economic
recession. The current forecast is also lower than last year’s forecast of 47,270 MW for the
2008/2009 winter peak demand.

                    Table ERCOT-1: ERCOT Winter Peaks
                    2008/2009 ACTUAL            2009/2010 FORECAST
                    December 2008 47,806        December 2009 39,996
                    January 2009  45,495        January 2010  43,325
                    February 2009 41,378        February 2010 43,463

The forecasted peak demands are produced by ERCOT ISO for the ERCOT Region, which is a
single Balancing Authority area, based on the Region-wide actual demands. The weather
assumptions on which the forecasts are based represent an average weather profile (50/50),
calculated for each of the eight weather zones in the ERCOT Region. These average profiles are
based on a Rank-Median method, because the calculation of the median temperatures is less
affected by outliers than a simple average.




2009/2010 Winter Reliability Assessment                                               Page 26
Regional Reliability Self-Assessments


To assess the impact of weather variability on the peak demand for ERCOT, alternative weather
scenarios are used to develop extreme weather load forecasts. One scenario is the one-in-ten-year
occurrence of a weather event. This scenario is calculated using the 90th percentile of the
temperatures in the database spanning the last fourteen years available. These extreme
temperatures are input into the load-shape and energy models to obtain the forecasts. The
extreme temperature assumptions consistently produce demand forecasts that are approximately
5.5 percent higher than the forecasts based on the average weather profile (50/50). Together, the
forecasts from these temperature scenarios are usually referred to as 90/10 scenario forecasts.

The economic factors that drive the 2009 ERCOT Long-Term Hourly Demand Forecast39
include per capita income, population, gross domestic product (GDP), and various employment
measures that include non-farm employment and total employment. The forecasts of these
economic indicators indicate the effects of the national recession on the Texas economy.

Based on Transmission and/or Distribution Service Provider (TDSP) filings to the Public
Utilities Commission of Texas, 242 MW of energy efficiency is assumed over the next winter.
This energy efficiency estimate is not reflected in the 43,463 MW peak demand forecast.

There are two categories of demand-response resources that can be dispatched by the ERCOT
ISO in all hours, and therefore are capable of reducing winter peak demand:
    Loads Acting as a Resource40 (LaaR) providing Responsive Reserve Service (RRS)
    Emergency Interruptible Load Service41 (EILS)

LaaRs are registered with ERCOT to provide ancillary services. ERCOT Staff measures and
verifies Load acting as a Resource performance in the Ancillary Services markets using
telemetry (updated every 2-10 seconds) that provides real-time visibility in the capability and
performance of the Resources and is integrated into the Operators’ performance monitoring
tools. The real-time data is stored using a Plant Information (PI) database that records key data
parameters that allows for more detailed analysis after-the-fact. ERCOT’s analysis of this
telemetry data is supported after-the-fact as necessary with 15-minute interval meter data. The
total contribution of LaaRs to RRS cannot exceed 1,150 MW in any hour; this amount is one-
half of the 2,300 MW of RRS procured for most winter hours. LaaRs providing RRS are
required to deploy automatically with under-frequency relays or to deploy within ten minutes by
a verbal dispatch instruction (VDI) from ERCOT. For the 2009/2010 winter season, 1115MW of
LaaRs is the only Demand Response counted toward planning Reserve Margin requirements,
which is 2.6 percent of the expected Net Internal Demand for the season.

EILS resources are loads that provide capacity services and are subject to deployment by VDIs
that can be executed prior to firm load shedding. EILS resources are procured for four-month
contracts, and the capacity available to ERCOT is dependent on the details from accepted bids,
which include time period, capacity, cost, location and performance. Measurement and
verification of EILS is accomplished entirely after-the-fact with 15-minute interval data applied

39
   See “2008 Long-Term Hourly Demand Energy Forecast” located on the following website:
   http://www.ercot.com/news/presentations/
40
   For additional information on LaaRs see: http://www.ercot.com/services/programs/load/laar/index
41
   For additional information on EILS see: http://www.ercot.com/services/programs/load/eils/index



Page 27                                                                     2009/2010 Winter Reliability Assessment
                                                                          Regional Reliability Self-Assessments


to multiple baseline types as assigned by ERCOT specific to the individual Load or aggregation.
EILS capacity is not included in Reserve Margin calculations.

Additionally, entities in the ERCOT Region may participate in market-based Demand Response
activities through the competitive retail market, including direct load control, real-time price
response, and critical peak price response. However, such resources are not dispatched by the
ERCOT ISO, and as this competitive market information is not available, there are no reliable
estimates of the aggregate capacity of these programs. Currently, this type of Demand Response
is not a reliability concern in the ERCOT Region. However, as Demand Response activities
continue to grow, ERCOT ISO is implementing efforts to improve Demand Response data
submittals.

Generation
ERCOT has 72,419 MW of Deliverable Internal Capacity (the sum of Existing Summer and
Future-Planned Generation) expected to be in service during the 2009/2010 winter period. The
Table below shows this broken out into the different reporting categories.

                               Table ERCOT-2: ERCOT Generation
                               Category                                         MW
                               Existing-Certain                                 71,933
                               Existing-Other                                   11,852
                               Existing-Inoperable                              4,782
                               Future-Planned                                   486
                               Future-Other                                     0


The amount of Existing-Other generation includes 6,154 MW of units undergoing maintenance
or repair during the first week of the reporting period (which is reduced to 3,711 MW at the time
of the expected Winter Peak Load in February) and 4,782 MW of units not readily available due
to their mothball status throughout the planning period. This first week reflects the largest
capacity outages that are planned for the period, and is not expected to adversely affect the
ability to meet demand.

Of the 8,335 MW of installed wind capacity, only 8.7 percent, or 725 MW, is used as Existing-
Certain generation based on the ERCOT Reserve Margin Analysis Report42. The remaining
7,610 MW of the existing wind capacity is included in the Existing-Other generation amount.
Similarly, the planned new wind generation expected to be online by the winter period totals 582
MW, however only 51 MW (8.7 percent) are considered to be available on-peak. In addition, 76
MW of biomass is included in the Existing-Certain generation amount. No solar generation is
assumed to be added prior to the winter period.

ERCOT has not performed a specific study of fuel supply vulnerability; generator owners and
operators are responsible for assessing their fuel supply. The ERCOT Region is not generally

42
     See “ERCOT Reserve Margin Analysis Report” located on the following website:
     http://www.ercot.com/calendar/2007/01/20070112-GATF



2009/2010 Winter Reliability Assessment                                                               Page 28
Regional Reliability Self-Assessments


reliant on single gas pipelines or import paths such that the long-term outage of one of these
types of lines or paths would lead to the loss of significant amounts of generating capacity.

ERCOT does not expect significant capacity reduction implications due to water levels. While
reservoir levels43 are currently below average, less than 1 percent of the ERCOT generation
capacity is hydro. These facilities are typically operated as run-of-river or planned release due to
downstream needs, and not operated specifically to produce electricity. Water necessary for
cooling resources is not expected to be an issue during this period. If the drought-like weather
continues over the longer period, then lack of water may become an issue. There are no other
conditions expected within the ERCOT Region during the winter period that are expected to
create capacity reductions. There are also no environmental or regulatory restrictions known at
this time that would potentially impact capacity or reliability.

Capacity Transactions on Peak
ERCOT is a separate interconnection with only asynchronous ties to SPP and Mexico’s
Comisión Federal de Electricidad (CFE) and does not share reserves with other Regions. There
are two asynchronous (DC) ties between ERCOT and SPP with a total of 820 MW of transfer
capability and three asynchronous ties between ERCOT and Mexico with a total of 280 MW of
transfer capability. ERCOT does not rely on external resources to meet demand under normal
operating conditions; however, under emergency support agreements with CFE and AEP, it may
request external resources for emergency services over the asynchronous ties or by transferring
block loads.

One long-term contract for purchase of 48 MW of firm power from specific generation is an
import from SPP. One-half of the asynchronous tie transfer capability is also included as an
import (410 MW from SPP and 140 MW from CFE) due to emergency support arrangements.
As a result, for the winter 2009/2010 season, ERCOT includes 458 MW as imports from SPP
and 140 MW from CFE. Ownership by members of SPP of 247 MW of a power plant located in
the ERCOT Region results in a firm export from ERCOT to SPP. There are no non-Firm
contracts signed or pending. There are also no other known contracts under negotiation or under
study.

Transmission
Several significant transmission improvements have been made throughout the ERCOT Region
to meet reliability needs44. Dynamic reactive devices were installed in the Dallas area to
improve voltage stability margins. A new 345/138 kV substation was constructed in the Tyler
area. In the Dallas-Fort Worth area a new 345/138 kV autotransformer was installed and another
one was replaced with a larger capacity autotransformer to meet load growth.

North of Houston, a new 345 kV-switching station was constructed in order to allow for the
reliable import of additional power into the Houston area. A 138 kV line was also upgraded to
decrease Houston import congestion. A new 345 kV line, planned to be in-service in November,
is being built through the city of Dallas in order to relieve congestion in the area. If this project

43
     Reservoir levels can be found at: http://wiid.twdb.state.tx.us/ims/resinfo/bushbutton/lakestatus.asp
44
     Additional details on transmission projects can be found in the “Transmission Constraints and Needs Report 2008” located on
     the following website: http://www.ercot.com/news/presentations/



Page 29                                                                        2009/2010 Winter Reliability Assessment
                                                                                  Regional Reliability Self-Assessments


is delayed, reliability will continue to be ensured using existing congestion management
techniques.

Approximately 27 miles of new 345 kV lines have been completed since the 2008/2009 winter
and 20.5 miles of upgraded 345 kV lines are expected to be completed during the 2009/2010
winter. Approximately 287 miles of new or upgraded 138 kV transmission lines were completed
since the 2008/2009 winter and an additional 108 miles of new or upgraded 138 kV lines are
expected to be completed by the end of the 2009/2010 winter period45.

                                     Table ERCOT-3: ERCOT Transmission
                                     Additions/Rebuilds
                                     Voltage       New     Upgraded
                                     345kV         27.3    20.5
                                     138kV         106.8   287.9

There are no known transmission constraints that are expected to significantly impact reliability
across the ERCOT Region. The outage coordination process described in the Operational Issues
section addresses many potential constraints. If transmission constraints are identified in the
operations planning horizon, remedial action plans or mitigation plans are developed to provide
for preemptive or planned response to maintain reliability of a localized area. Interregional
transfers can provide support over the asynchronous ties or through block load transfers, but
emergency support arrangements are not generally relied upon to resolve transmission reliability
planning.

Operational Issues
ERCOT does not expect any unit or transmission outages, environmental or other unusual system
conditions during this winter period that would impact reliability. Transmission outage plans are
reviewed twice each year through discussions with the ERCOT transmission owners/operators,
taking into account the known resource outages. Outage coordination begins approximately
ninety days prior to real-time, when ERCOT Outage Coordination begins steady-state analysis of
the ERCOT grid incorporating known stability limits. ERCOT continually studies outages,
ensuring they are evaluated and coordinated; transmission outages are ultimately approved or
rejected based on reliability until three days before the operating day. Several Special Protection
Systems (SPS) have been implemented to resolve congestion more efficiently.

The continued increase of installed wind generation has the potential to lead to operating
challenges during the winter period. ERCOT has recently implemented a wind power forecasting
system to allow ERCOT ISO system operators to identify and take appropriate action when wind
resource schedules may not track expected changes in wind production. In addition, congestion
management associated with the increased wind generation requires increased attention. As a
result of transmission limitations, ERCOT does not expect issues this winter associated with base
load unit commitment during minimum net load conditions. Finally, ERCOT evaluates the
impact of increased wind generation on ancillary services requirements on an ongoing basis.


45
     Details can be found on the following secure website: http://planning.ercot.com/reports/tpit/. Please note that registration is
     required to access this site.



2009/2010 Winter Reliability Assessment                                                                                    Page 30
Regional Reliability Self-Assessments


Reliability Assessment Analysis
The projected Reserve Margin for winter 2009/2010 is 67.8 percent, slightly higher than the
2008/2009 margin of 62 percent. This is well over the ERCOT Region minimum annual Reserve
Margin of 12.5 percent. The ERCOT Reserve Margin is based on a loss-of-load expectation
(LOLE) analysis of no more than one day in ten years loss of load. The LOLE study that was
used to assess the adequacy of the 12.5 percent Reserve Margin criteria was completed in 200746.
This Reserve Margin should be sufficient to cover, among other uncertainties, the potentially
higher peak demand associated with the 10th percentile temperatures.

In the planning horizon, ERCOT performs a security-constrained unit commitment and economic
dispatch analysis for the upcoming year. This analysis is performed on an hourly basis for a
variety of conditions to ensure deliverability of sufficient resources to meet a load level that is
approximately 10 percent higher than the expected summer coincident system peak demand plus
operating reserves. In the operations horizon, resource adequacy is maintained by ERCOT ISO
through market-based procurement processes47. Transmission operating limits are adhered to
through market-based generation redispatch directed by ERCOT ISO as the balancing authority
and reliability coordinator.

As the winter period approaches, ERCOT will perform off-line transient stability studies for
specific areas of the Region as needed. The results of these studies are used in real-time and near
real-time monitoring of the grid. In addition, day-ahead studies are run to screen for possible
resource deficiencies as well as potential delivery problems.            Furthermore, ERCOT is
increasingly using voltage and transient stability analysis to establish transfer limits and
recommend transmission improvements.

Generation capacity in ERCOT is fueled primarily by natural gas (69 percent) and coal (21
percent). ERCOT ISO does not coordinate directly with the fuel suppliers; ERCOT does perform
a Regional survey to determine dual-fuel capabilities of generating units and reviews fuel studies
completed by the Energy Information Administration48 (EIA) to determine if fuel availability
issues are expected.

As in past years, while ERCOT does not anticipate extreme winter weather to have an impact on
fuel supply or fuel delivery, in extreme weather conditions, natural gas fuel supply becomes a
primary concern due to heating demands. Fuel supply issues are typically reported to ERCOT by
the affected generation entity as a resource de-rating or a forced outage. In the event of
forecasted extreme weather and possible fuel curtailments, ERCOT may request fuel capability
information from the scheduling entities that represent generation to better prepare operationally
for potential curtailments49




46
   See “ERCOT Reserve Margin Analysis Report” located on the following website:
   http://www.ercot.com/calendar/2007/01/20070112-GATF
47
   See Sections 6 and 7 of the ERCOT Protocols found at http://www.ercot.com/mktrules/protocols/current
48
   See the Short Term Energy Outlook from EIA at: http://www.eia.doe.gov/steo
49
   See ERCOT Protocols Section 5.6.5 found at: http://www.ercot.com/mktrules/protocols/current. See also the ERCOT
   Operating Guides found at: http://www.ercot.com/mktrules/guides/operating/current



Page 31                                                                   2009/2010 Winter Reliability Assessment
                                                                                Regional Reliability Self-Assessments


By maintaining appropriate voltage profiles50 at generating units and coordinating voltage-
control equipment, it is possible to maintain transmission grid voltages at all points in ERCOT
within acceptable operating voltage limits. Steady-state data sets are used to run a voltage profile
study for the winter period. Specific dynamic reactive studies were not performed for the
2009/2010 winter network models.

Region Description
The ERCOT Region51 is a separate electric interconnection located entirely within the state of
Texas. ERCOT is a summer-peaking Region covering 75 percent of the land area of Texas.
ERCOT ISO serves over 21 million people, representing approximately 85 percent of the electric
load in Texas, with an all-time peak demand of 63,400 MW52 set in July, 2009. The Texas
Regional Entity (Texas RE)53, a functionally independent division of ERCOT, performs the
Regional entity functions described in the Energy Policy Act of 2005 for the ERCOT Region.
ERCOT ISO is the only Balancing Authority in the ERCOT Region.




50
   Voltage profiles can be found at: http://www.ercot.com/gridinfo/generation/voltprof/
51
   For additional information, see “ERCOT Quick Facts May 2009” found in the key documents section of the following website:
   http://www.ercot.com/about/profile/
52
   This is a preliminary value; the value is not final until completion of the market’s financial settlement process six months after
   the operating day.
53
   For additional information, see Texas RE website at: http://www.texasre.org



2009/2010 Winter Reliability Assessment                                                                                 Page 32
Regional Reliability Self-Assessments



FRCC
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand MW                               On-Peak Capacity by Fuel Type
Total Internal Demand                       44,446
  Direct Control Load Management             2,905                                          Dual
  Contractually Interruptible (Curtailable)    692                             Gas          Fuel
                                                                                                             Other
  Critical Peak-Pricing with Control             0                             33%
                                                                                                              3%
                                                                                             22%
  Load as a Capacity Resource                    0
Net Internal Demand                         40,846                                                 Nuclear
                                                                                                     8%
2008/2009 Winter Comparison                          MW % Change                  Oil      Coal
2008/2009 Winter Projected Peak Demand              46,362 -11.9%                16%       18%
2008/2009 Winter Actual Peak Demand                 45,604 -10.4%
All-Time Winter Peak Demand                         45,604 -10.4%

2009/2010 Winter Projected Peak Capacity MW                    Margin
Existing Certain and Net Firm Transactions 55,881              67.5%
Deliverable Capacity Resources             57,216              72.5%
Prospective Capacity Resources             57,216              72.9%
NERC Reference Margin Level                   -                15.0%




Demand
The Florida Reliability Coordinating Council (FRCC) is forecasted to reach its 2009/2010 winter
peak demand of 44,446 MW in January, which represents a projected demand decrease of 2.6
percent over the actual 2008/2009 winter demand of 45,604 MW. This projection is consistent
with historical weather-normalized FRCC demand growth and is 11.6 percent lower than last
year’s winter forecast of 49,601 MW. The decrease in the 2009/2010 winter peak demand is
attributed to a sluggish economy primarily driven by a declining housing market and higher
energy prices as well as a modification to the winter demand forecast method aimed at reducing
forecast                                                                               errors.54

Each individual Load Serving Entity (LSE) forecast takes into account historical temperatures to
determine the normal temperature at the time of peak demand. The demand forecast for this
winter takes into consideration the overall economy in Florida with emphasis on the price of
electricity. Each individual LSE within the FRCC Region develops a forecast that accounts for
their actual peak demand. The individual peak demand forecasts are then aggregated by
summing these forecasts to develop the FRCC Region forecast. These individual peak demand
forecasts are coincident for each LSE but there is some diversity at the Region level. The entities
within the FRCC Region plan their systems to meet the Reserve Margin criteria under both
summer and winter peak demand conditions. There are a variety of energy efficiency programs
implemented by entities throughout the FRCC Region. These programs can include commercial
54
  https://www.frcc.com/Planning/Shared%20Documents/Load%20and%20Resource%20Plans/FRCC%202009%20Load%20and
  %20Resource%20Reliability%20Assessment.pdf



Page 33                                                         2009/2010 Winter Reliability Assessment
                                                                     Regional Reliability Self-Assessments


and residential audits (surveys) with incentives for duct testing and repair, high efficiency
appliances (air conditioning, water heater, heat pumps, refrigeration, etc.) rebates and high
efficiency lighting rebates.55 The 2009/2010 net internal FRCC peak demand forecast includes
the effects of 3,600 MW (8 percent of Total Internal Demand) of potential demand reductions
from the use of direct control load management and interruptible load management programs
composed of residential, commercial and industrial demand. Entities within the FRCC use
different methods to test and verify Direct Load programs such as actual load response to
periodic testing, use of a time and temperature matrix and the number of customers participating.
Projections also incorporate demand impacts of new energy efficiency programs. There
currently is no critical peak pricing with control incorporated into the FRCC projection. Each
LSE within the FRCC treats every Demand-Side Management load control program as “demand
reduction” and not as a capacity resource.

FRCC assesses the peak demand uncertainty and variability by developing Regional bandwidths
or 80 percent confidence intervals on the projected or most likely load (90/10). The 80 percent
confidence intervals on peak demand can be interpreted to mean that there is a 10 percent
probability that in any year of the forecast horizon that actual observed load could exceed the
high band. Likewise, there is a 10 percent probability that actual observed load in any year could
be less than the low band in the confidence interval. The purpose of developing bandwidths on
peak demand loads is to quantify uncertainties of demand at the Regional level. This would
include weather and non-weather load variability such as demographics, economics and price of
fuel and electricity. Factors that dampened the growth outlook for this winter’s forecast include
a weaker Florida economy and projected higher fuel prices.

Generation
FRCC supply-side resources considered for the winter assessment are categorized as Existing-
Certain, Existing-Other, and Existing Inoperable. The total Existing generation in the FRCC
Region for this winter is 58,439 MW of which 53,343 MW (479 MW of biomass) are Existing-
Certain, 908 MW are Existing Inoperable, and 4,188 MW (318 MW of biomass) are Existing-
Other. The Region is expected to add 1,647 MW of Future-Planned generation for the winter
season. The FRCC Region has a negligible amount of variable generation.

The FRCC Region does not rely on hydro generation, therefore hydro conditions and reservoir
levels will not impact the ability to meet the peak demand and the daily energy demand.

For the 2009/2010 winter period, no load serving concerns are anticipated due to fuel supply
vulnerabilities. For extreme weather conditions such as hurricanes affecting natural gas supply
points, extreme temperatures or impacts to pipeline infrastructure, alternate short-term fuel
supply availability continues to be adequate for the Region. There are no additional fuel
availability or supply issues identified at this time and existing mitigation strategies continue to
be refined. Based on recent studies, current fuel diversity, alternate fuel capability and fuel study
results, the FRCC does not anticipate any fuel transportation issues affecting resource capability
during peak periods and/or extreme weather conditions this winter.

55
     Additional details can be found in the 10-Year Site Plan filing for each entity at the following link
     https://www.frcc.com/Planning/default.aspx?RootFolder=%2fPlanning%2fShared%20Documents%2fTen%20Year%20Site%2
     0Plans%2f2009&FolderCTID=&View=%7bFBDE89E4%2dE66F%2d40EE%2d999D%2dCFF06CF2A726%7d



2009/2010 Winter Reliability Assessment                                                                Page 34
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The FRCC Region has not identified any unit retirements that could have a significant impact on
reliability. Progress Energy Florida’s 870 MW Crystal River Unit #3 (CR3) in Citrus County is
presently in maintenance outage. Work is on schedule with the unit’s return to service expected
before the winter peak season. While the unavailability of CR3 has minimal reliability impact to
the Bulk Power System, in the unlikely event that the unit is not returned to service by the winter
peak season, a mitigation plan has been developed as part of the FRCC Winter Assessment.

Capacity Transactions on Peak
Currently, there are 2,538 MW of generation under Firm contract that are available to be
imported into the Region on a firm basis from the Southeastern Subregion of SERC. No portion
of these contracts are from Liquidated Damages or “make whole” contracts. These purchases
have firm transmission service to ensure deliverability into the FRCC Region. No Non-Firm or
Expected transactions are included in the assessment. The FRCC Region does not rely on
external resources for emergency imports and reserve sharing. However, there are emergency
power contracts (as available) in place between SERC and FRCC members.

Presently, the FRCC Region has no Firm winter contract exports into the Southeastern Subregion
of SERC. The FRCC does not consider Non-Firm or Expected sales to other Regions as capacity
resource reductions.

Transmission
Major additions to the FRCC bulk power system are mostly related to expansion in order to
maintain the reliability of the transmission system. The most notable transmission additions
placed in-service over the recent summer are the rebuild of two existing 230kV transmission
lines in the Central Florida area. For the upcoming winter 2009/2010 there are no concerns in
meeting targeted in-service dates for any new transmission line additions or upgrades.

No significant substation equipment (i.e. SVC, FACTS controllers, HVdc, etc.) additions are
expected. Presently there are no significant transmission lines expected to be out of service for
the winter period.

Transmission constraints in the Central Florida area may require remedial actions depending on
system conditions creating increased west-to-east flow levels across the Central Florida
metropolitan load areas. Permanent solutions such as the addition of new transmission lines and
the rebuild of existing 230kV transmission lines are planned and implementation of these
solutions is underway. In the interim, remedial operating strategies have been developed to
mitigate thermal loadings and will continue to be evaluated to ensure system reliability.

An interregional transfer study is performed annually to evaluate the total transfer capability
between FRCC and the Southeastern Subregion of SERC. Joint studies of the
Florida/Southeastern transmission interface indicate a winter seasonal import capability of 3,800
MW into the Region, and an export capability of 1,900 MW. These joint studies account for
constraints within the FRCC and/or the Southeastern Subregion of SERC.




Page 35                                                    2009/2010 Winter Reliability Assessment
                                                               Regional Reliability Self-Assessments


Operational Issues
FRCC expects the bulk transmission system to perform adequately over various system operating
conditions with the ability to deliver the resources to meet the load requirements at the time of
the winter peak demand. The results of the 2009/2010 Winter Transmission Assessment, which
evaluated the steady-state winter peak load conditions under different operating scenarios,
indicates that any concerns with thermal overloads or voltage conditions can be managed
successfully by operator intervention. Such interventions may include generation redispatch,
system sectionalizing, reactive device control, and transformer tap adjustments. The operating
scenarios analyzed included the unavailability of major generating units within the FRCC.
Therefore, various dispatch scenarios were evaluated to ensure generating resources within the
FRCC are deliverable by meeting NERC Reliability Standards under these operating scenarios.

The amount of variable resources within the FRCC Region is negligible having no potential to
cause over generation. Therefore, no operational changes are needed due to the integration of
small amounts of variable resources.

In addition, there are no foreseen environmental and/or regulatory restrictions or unusual
operating conditions that can potentially impact reliability in the FRCC Region during the
2009/2010 winter period.

Demand-Side Management load control programs within the FRCC are treated as “demand
reduction” and not as a capacity resource. Therefore, high levels of demand reduction programs
are considered to benefit reliability throughout the FRCC Region.

No unusual operating conditions are expected that could impact reliability for the upcoming
2009/2010 winter season. The FRCC has a Reliability Coordinator agent that monitors real-time
system conditions and evaluates near-term operating conditions of the bulk electric grid. The
Reliability Coordinator uses a Region-wide state estimator and contingency analysis program to
evaluate current system conditions. These programs are provided with new input data from
operating members every ten seconds. These tools enable the FRCC Reliability Coordinator to
implement operational procedures such as generation redispatch, sectionalizing, planned load
shedding, reactive device control, and transformer tap adjustments to successfully mitigate line
loading and voltage concerns that may occur in real time.

Reliability Assessment Analysis
The FRCC Region is required by the State of Florida to maintain a 15 percent Reserve Margin
(20 percent for Investor Owned Utilities). Based on the expected load and generation capacity,
the calculated Reserve Margin for the winter of 2009/2010 is 40 percent. This year’s calculated
Reserve Margin is significantly higher than last year’s Reserve Margin calculation of 25 percent
for the winter of 2008/2009 primarily related to a calibration of the winter forecast model.56

The expected Reserve Margin for this winter includes a total of 2,538 MW import from the
Southeastern Subregion of SERC to the FRCC. The total import into the FRCC Region consists
of 836 MW of generation residing in the Southeastern Subregion of SERC owned by FRCC

56
  https://www.frcc.com/Planning/Shared%20Documents/Load%20and%20Resource%20Plans/FRCC%202009%20Load%20and
  %20Resource%20Reliability%20Assessment.pdf



2009/2010 Winter Reliability Assessment                                                        Page 36
Regional Reliability Self-Assessments


entities and the remaining 1,702 MW are firm purchases. These imports account for 6.2 percent
of the total Reserve Margin, and have firm transmission service to ensure deliverability into the
FRCC Region.

The FRCC has historically used the Loss Of Load Probability (LOLP) analysis to confirm the
adequacy of reserve levels for peninsular Florida. The LOLP analysis incorporates system
generating unit information (e.g., Availability Factors and Forced Outage Rates) to determine the
probability that existing and planned resource additions will not be sufficient to serve forecasted
loads. The objective of this study is to establish resource levels such that the specific resource
adequacy criterion of a maximum LOLP of 0.1 day in a given year is not exceeded. The results
of the most recent LOLP analysis conducted in 2009 indicated that for the “most likely” and
extreme scenarios (e.g., extreme seasonal demands; no availability of firm and non-firm imports
into the Region; and the non-availability of load control programs), the peninsular Florida
electric system maintains a LOLP below the 0.1 day per year criterion.

Reactive power-limited areas are typically localized pockets that do not affect the bulk power
system. The FRCC 2009/2010 Winter Transmission Assessment did not identify any reactive
power-limited areas that would impact the bulk electric system during the upcoming winter
season.

The FRCC Operating Committee has developed the procedure, FRCC Communications
Protocols – Reliability Coordinator, Generator Operators and Natural Gas Transportation Service
Providers, to enhance the existing coordination between the FRCC Reliability Coordinator and
the natural gas pipeline operators and in response to FERC Order 698. 57

For capacity constraints due to inadequate fuel supply, the FRCC State Capacity Emergency
Coordinator (SCEC) along with the Reliability Coordinator (RC) have been provided with an
enhanced ability to assess Regional fuel supply status by initiating Fuel Data Status reporting by
Regional utilities. This process relies on utilities to report their actual and projected fuel
availability along with alternate fuel capabilities, to serve their projected system loads. This is
typically provided by type of fuel and expressed in terms relative to forecast loads or generic
terms of unit output, depending on the event initiating the reporting process. Data is aggregated
at the FRCC and is provided, from a Regional perspective, to the RC, SCEC and governing
agencies as requested. Fuel Data Status reporting is typically performed when threats to Regional
fuel availability have been identified and is quickly integrated into an enhanced Regional Daily
Capacity Assessment Process along with various other coordination protocols to ensure accurate
reliability assessments of the Region and also ensure optimal coordination to minimize impacts
of Regional fuel supply issues and/or disruptions.

Fuel supplies continue to be adequate for the Region and these supplies are not expected to be
impacted by extreme weather during peak load conditions. There are no identified fuel
availability or supply issues at this time. Based on current fuel diversity, alternate fuel capability
and preliminary study results, the FRCC does not anticipate any fuel transportation issues
affecting capability during peak periods and/or extreme weather conditions.

57
     https://www.frcc.com/handbook/Shared%20Documents/EOP%20-
     %20Emergency%20Preparedness%20and%20Operations/FRCC%20Communications%20Protocols%20102207.pdf



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Region Description
FRCC’s membership includes 27 Regional Entity Division members and 25 Member Services
Division members, which is composed of investor-owned utilities, cooperative systems,
municipal utilities, power marketers, and independent power producers. The FRCC Region is
divided into 11 Balancing Authorities. As part of the transition to the ERO, FRCC has registered
70 entities (both members and non-members) performing the functions identified in the NERC
Reliability Functional Model and defined in the NERC Reliability Standards glossary. The
Region contains a population of more than 16 million people, and has a geographic coverage of
about 50,000 square miles over peninsular Florida. Additional details are available on the
FRCC website (https://www.frcc.com/default.aspx).




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MRO
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand MW                                            On-Peak Capacity by Fuel Type
Total Internal Demand                       42,481                                                                    Nuclear
  Direct Control Load Management               810                                                                      8%
                                                                                                Coal
  Contractually Interruptible (Curtailable)  1,380
                                                                                                46%
  Critical Peak-Pricing with Control             0
  Load as a Capacity Resource*                   0
                                                                                                                Gas
Net Internal Demand                         40,291
                                                                                                                15%
                                                                                                                       Dual
                                                                                               Hydro
2008/2009 Winter Comparison                                   MW % Change                                              Fuel
                                                                                                10%
2008/2009 Winter Projected Peak Demand                       41,539 -3.0%             Wind
                                                                                                                  Other 7%
2008/2009 Winter Actual Peak Demand                          43,317 -7.0%              2%                 Oil
                                                                                                                      2%
All-Time Winter Peak Demand                                  43,317 -7.0%                                 4%

2009/2010 Winter Projected Peak Capacity MW                                Margin
Existing Certain and Net Firm Transactions 56,643                          40.6%
Deliverable Capacity Resources             56,946                          41.3%
Prospective Capacity Resources             58,118                          44.2%
NERC Reference Margin Level                   -                            15.0%
*Note: MRO has classified an additional 44 MW of Demand Response as a
supply resource which does not reduce Total Internal Demand.




Demand
The MRO’s forecasted 2009/2010 Winter Non-Coincident Peak Total Internal Demand in the
combined MRO US and MRO Canada is 42,480 MW, assuming normal weather conditions.
This forecast is 1.4 percent below last winter’s forecasted total demand of 43,080 MW and 1.9
percent lower than last year’s actual winter peak demand of 43,317 MW. Any interruptible
demand or DSM implemented during last year’s peak load is unknown. The MRO 2009/2010
winter forecast Net Internal Demand is 40,291 MW, which is 3.0 percent lower than the
2008/2009 winter forecasted Net Internal Demand of 41,539 MW. The recession and nation-
wide economic downturn are the main reasons for the slight decrease in forecast.

Peak demand uncertainty and variability due to extreme weather and/or other conditions are
accounted for within the determination of adequate generation Reserve Margin levels. Both the
MAPP Generation Reserve Sharing Pool (GRSP) members and the former MAIN members
within MRO use a Load Forecast Uncertainty (LFU) factor within the calculation for the Loss of
Load Expectation (LOLE) and/or the percentage Reserve Margin necessary to obtain a LOLE of
0.1 day per year or 1 day in 10 years.58 The load forecast uncertainty considers uncertainties
attributable to weather and economic conditions. Forecasts are developed for Saskatchewan to
cover possible ranges in economic variations and other uncertainties such as weather using a
Monte Carlo simulation model to reflect those uncertainties.

58
     The former MAIN members are Alliant Energy, Wisconsin Public Service Corp., Upper Peninsula Power Co., Wisconsin
     Public Power Inc., and Madison Gas and Electric



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Each MRO member uses its own forecasting method, meaning some may use a 50/50 forecast
and some may use a 90/10 forecast. In general, the peak demand forecast includes factors
involving recent economic trends (industrial, commercial, agricultural, residential) and normal
weather patterns. From a Regional perspective, there were no changes in this year’s forecast
assumptions in comparison to last year.

MRO staff distributed the NERC Winter 2009/2010 data request spreadsheet to each LSE
member within the MRO in the format it was received from NERC. The members populated
these spreadsheets based on NERC and MRO instructions and submitted them back to the MRO
for processing by a predetermined due date. Internally, MRO staff compiled the individual
spreadsheet submissions into a set of Regional spreadsheets representing the MRO Region as a
whole as well as MRO U.S. and MRO Canada.

When the spreadsheet was initially distributed, MRO instructions emphasized to the LSEs that
each MW of demand must be counted once and only once and that LSEs should carefully
coordinate with their neighboring LSEs to ensure that double-counting would not occur in the
Regional compilations.

Interruptible Demand (1,380 MW, 3.3 percent) and Direct Controlled Load Management
(DCLM) (810 MW, 1.9 percent) programs, amounting to 5.2 percent of the MRO’s Projected
Total Internal Peak Demand of 42,481 MW are used by a number of MRO members. A wide
variety of programs, including direct load control (such as electric appliance cycling) and
interruptible load may be used to reduce peak demand during the winter season.

Reductions in demand due to energy efficiency are not known at this time.

Saskatchewan

Being an MRO member and one of the six Planning Authorities registered within the MRO
footprint, Saskatchewan Power Corporation (SaskPower) develops annual energy and peak
demand forecasts based on a provincial econometric model and forecasted industrial load data.
Weather can have a significant impact on the amount of electricity consumed by non-industrial
customers. Due to this weather sensitivity, average daily weather conditions for the last thirty
years are assumed to develop the energy forecast.

The winter peak load is forecasted on a heating season basis and represents the highest level of
demand placed on the supply system. The winter forecast is normalized to account for cold
weather based on a 30-year average weather pattern. The factors that contribute to the peak load
include time of day, seasonal variations, industrial load and weather conditions. Seasonal
variations include Christmas lighting, increased lighting load due to shorter daylight hours and
increased shopping hours. The peak load forecast assumes that sustained cold weather will occur
during the month of December.

Forecasts are developed for Saskatchewan to cover possible ranges in economic variations and
other uncertainties such as weather using a Monte Carlo simulation model to reflect those
uncertainties. This model considers each variable to be independent from other variables and



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assumes the distribution curve of a probability of occurrence of a given result to be normal.
Results are based on an 80 percent confidence interval. This means that a probability of 80
percent is attached to the likelihood of the load falling within the bounds created by the high and
low forecasts.

Saskatchewan has energy efficiency programs designed to help customers save power, save
money and help the environment. These programs include energy-efficiency, conservation,
education, and load management programs. Residential programs focus on consumer education
on energy efficiency and market transformation of lighting, appliances and furnace motors
including retailer/ manufacturer partnerships and end-user incentives. Commercial and industrial
programs include energy performance contracting, energy audits, and information services for
facility operators. Saskatchewan is currently establishing an evaluation framework for this
program, which includes measurement and verification for programs based on industry standard
protocols.

Generation
The Existing-Certain resources for the MRO US and Canada 2009/2010 winter are 56,623 MW.
The Existing-Other and Inoperable resources for the MRO US and Canada 2009/2010 winter are
6,719 MW. Planned resources expected to be in service this winter are 478 MW. These values
do not include firm or non-firm purchases and sales. The month of January was used in all cases
to be consistent.

The nameplate capacity of the wind generation for the MRO is 6,396 MW. The wind resources
for the MRO expected to be available at peak times is 1,271 MW, based on 20 percent of
nameplate capacity. The Midwest ISO is using the 20 percent of nameplate capacity rule in
determining capacity of wind generation.

The biomass portion of resources for the MRO expected to be available at peak times is 242
MW.

Reservoir water levels have improved over the past few years, but continue to remain below
normal in Montana, North Dakota, and South Dakota, and will likely continue to reduce the
magnitude and duration of power transfers (on an energy basis) out of northern MRO. This will
continue to contribute to the imports of power into the MRO Region during peak load periods.

The Manitoba water condition is normal and normal Manitoba-US transfers are expected.
Manitoba Hydro manages its reservoir levels in preparation for the winter season such that there
is adequate energy to meet daily energy demand throughout the winter.

SaskPower reservoirs are at normal conditions and regular operating regimes are expected.
Reservoir levels are sufficient to meet both peak demand and the daily energy demand
throughout the upcoming system. SaskPower reservoirs are sufficiently large enough to meet
daily requirements, and current hydrological conditions are expected to be normal during the
upcoming season.




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Environmental and regulatory requirements prevent continued operations of the Manitoba Hydro
Brandon #5 generating unit (100 MW). This, however, will not impact the reliability of the
interconnected system since there are two gas turbine generating units (140 MW each) at the
station.

Capacity Transactions on Peak
For the 2009/2010 winter season, the MRO is projecting total firm purchases of 1,501 MW.
These purchases are from sources external to the MRO Region. The MRO has approximately
1,481 MW of total projected sales to load outside of the MRO Region. The net import/export of
the MRO Region can vary at peak load, depending on system conditions and market conditions.

Transfer capability from MRO Canada (Saskatchewan and Manitoba) into the MRO US is
limited to 2,415 MW due to the operating security limits of the two interfaces between these two
provinces and the U.S. The forecasted firm transfers from Manitoba to the U.S. are 630 MW for
the 2009/2010 winter. Saskatchewan has a firm import of 50 MW scheduled for the December
2009 to February 2010 reporting period. All of the energy contracts is firm and has firm
transmission reserved.

Throughout the MRO Region, firm transmission service is required for all generation resources
that provide firm capacity; also meaning that these firm generation resources are fully
deliverable to the load. The MRO is forecast to meet the various Reserve Margin targets without
needing to include energy-only, uncertain, or transmission-limited resources.

Different transmission providers within the MRO Region treat Liquidated Damage Contracts
(LDC) according to their tariff policies. Most MRO members are within non-retail access
jurisdictions (except for Upper Michigan) and therefore liquidated damages products are not
typically used.

Transmission Reliability Margins (TRM) are calculated and reserved by the Transmission
Providers within the MRO Region to assure that operating reserves can adequately be delivered.
TRM includes a contingency component and an uncertainty component on a flowgate such that
operating reserves for the worst single contingency can be reliably delivered from the operating
reserve sharing group. 
 
Most MRO members participate in the Midwest Contingency Reserve Sharing Group (CRSG)
and will be able to call for resources as operating reserves from the members of the Midwest
CRSG outside of the MRO Region in case of emergency.

Transmission
The following reinforcements include projects that have expected service dates from June 1,
2009 through December 2009. Several projects went in service prior to June 1, 2009, and are
also listed in the 2009 summer assessment.




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Iowa

New wind farm generation, Whispering Willows and Crane Creek wind farms, is planned to be
in service prior to (or during) this winter season.

The Whispering Willows facility affects the Iowa transmission system. Several transmission
enhancement projects are expected to be completed by the end of 2009:
    The Arnold-Vinton-Dysart-Washburn 161kV rebuild/reconductoring project
    The Fernald-Story County line rebuild, the Adams-Barton rebuild
    The Ground Mound 161 kV upgrades
    The Butler-Union Tap 161 kV line reconductoring

The Crane Creek wind farm ties to the transmission system at Rice 161 kV in Northern Iowa and
mainly affects the southern Minnesota areas. The transmission upgrades needed to
accommodate the facility is described under the Northern MRO area discussions below.

Nebraska

Phase 2 of Nebraska Public Power District’s (NPPD) Electric Transmission Reliability (ETR)
Project for East-Central Nebraska is expected to be energized in October of 2009. Phase 2 of the
ETR Project includes the construction of 12 miles of new 345 kV transmission line from Shell
Creek to Columbus East and expansion of the Columbus East 345/230/115 kV Substation.
Completion of this phase of the project will improve local area voltage support.

Phase 3 of the ETR Project includes the construction of 67 miles of new 345 kV transmission
line from Columbus East to Lincoln Electric System’s (LES) NW 68th & Holdrege and the
expansion of the NW 68th & Holdrege 345 kV Substation. This final project phase is currently
expected to be completed in January 2010. The completion of this project will address peak load
voltage issues and enhance the reliability of the eastern Nebraska Regional transmission system.

A new third Grand Island 345/230 kV transformer was placed in-service in July 2009. This
transformer was installed to address the contingency loading issues associated with the existing
two 250 MVA 345/230 kV transformers at the Grand Island Substation.

A 115 kV interconnection line between the LES 20th & Pioneers Substation and NPPD Sheldon
Substation will be out of service from October 2009 to May 2010. This line is being rebuilt and
will have a higher thermal capacity when completed. This is expected to reduce contingent
overload issues in the local transmission area. The line outage during this time period is expected
to have minimal impact on local power flows. Temporary operating guides will be issued for this
outage if actions or limitations are required to protect system operating limits.




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Northern MRO59

Dairyland Power Cooperative (DPC) has scheduled an outage to its Rochester-Adams and
Beaver Creek-Harmony 161 kV lines for upgrades during the 2009/2010 winter season. The
Rochester-Adams 161 kV outage is scheduled for this winter season. During this outage, final
structure upgrades will be completed to accommodate reconductoring of this line with a 795
MCM ACSS conductor. Prior to this outage, phase raisers were installed under a live line permit
to facilitate the new conductor. Likewise, the Beaver Creek-Harmony 161 kV line is schedule
for a similar upgrade early in 2010. This line will also be reconductored with a 795 MCM ACSS
conductor, and phase raisers will be used for the bulk of the structure improvements required to
accommodate the new conductor. Note that Midwest ISO prior outage guides will be developed
for these outages, and no operating problems are expected.

The Integrated System of Basin Electric Power Cooperative-Western subregion Power
Administration-Heartland Consumers Power District will energize a substation at Neset, North
Dakota. This is a new 230/115 kV substation with a 125 MVA transformer that will sit in
parallel to the nearby existing Tioga 230 kV substation. The Tioga 230 kV substation 100 MVA
transformer will be replaced by a new 125 MVA 230/115 kV transformer. The additional
transformer capacity in the area will be used to support load growth in the Region and
imports/exports with Saskatchewan. The additions are anticipated to be in service October 2009.
A new substation on the Little Missouri-Bowman 230 kV line called Rhame substation and
230kV transmission line from Rhame to Belfield substation are anticipated to be in service mid-
January. This line will help with load and voltage support in the Region.

In the Otter Tail Power Company system, the existing transmission can support 150 MW of new
wind generation, which will be coming on line before the winter season at Rugby, North Dakota.
No additional transmission facilities will be added.

In the Minnkota Power Cooperative system, 358 MW of wind generation development near
Fargo, ND will be installed at the Maple River 230 kV bus by December 2009. Constraints may
occur on the 230 kV network lines in the Fargo area, for which upgrades are still pending. These
constraints are addressed by a Special Protection System and operating guides which specify
conditions requiring generation curtailment.

Great River Energy (GRE) projects that have been added since 2008/2009 winter include:

           Elk River 14 Substation: A new 230 kV ring bus was installed in support of the new Elk
            River Generation Station, a 175 MW simple cycle gas turbine put in service in July 2009.
            There are now ring positions for the Bunker Lake and Monticello 230 kV lines, both 187
            MVA 230/69 kV autotransformers, and the generation connection.
           Long Lake – Badoura 115 kV Line: A new 115 kV line connection between GRE’s Long
            Lake Substation and Minnesota Power’s (MP) Badoura Substation is expected to be
            completed by October 2009.

59
     Northern MRO consists of the electric systems in eastern Montana, North Dakota, South Dakota, Minnesota, and Manitoba.




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         Tamarac Substation: 115 kV breakers were installed at Tamarac dividing the 115 kV line
          between Fergus Falls and Frazee. A 20 MVAr capacitor bank was installed on the 115
          kV bus for voltage support.

GRE has a scheduled outage on the 230 kV Line between Ramsey and Prairie scheduled for
early 2010. There are no other anticipated outages or transmission additions that could impact
reliability during the winter.

Minnesota Power will commission the new Embarrass 115 kV substation in the fall of 2009. The
new substation will have lines connecting to existing Virginia, Babbitt, and Laskin 115 kV
substations. There will also be a new line built to connect to GRE's new Tower 115 kV sub. The
new ring bus configuration will provide greater reliability for the area than the line tap that it
replaces. Minnesota Power will also commission the new Pine River 115 kV substation in its
Western Division this winter. The Pine River Substation will be connected to Badoura via a new
line. Additionally, the Badoura bus will be changed to a ring bus configuration with a new line to
GRE's Long Lake Substation. These upgrades will primarily provide more load serving
capability in the area. Boswell unit 3 will be coming online at the end of October 2009 after an
extended outage for environmental retrofits. Although the Bulk Electric System reliability will
not be compromised, it will likely take most of the winter to adjust the new equipment at the unit
for optimum performance.

Wisconsin-Upper Michigan Systems (WUMS)

Major transmission additions expected to be in-service between July and December 2009 are
listed in the following. There are no concerns in meeting the targeted in-service dates of these
projects.

         Construct an Iron Grove-Aspen 138 kV line. In-service in August 2009.
         Construct a Highway 22-Morgan 345 kV line. In-service in October 2009.
         Construct a Jefferson-Lake Mills-Stony Brook 138 kV line. In-service in October 2009.

Inter-Regional Transfers

The following information is based on the MRO/RFC/SPP/SERC-W 2008/2009 Winter Inter-
regional Assessment, from which the total transfer capabilities listed below may be used for the
purposes of this assessment.

Non-simultaneous Total Import Capabilities into MRO from RFC-W, SERC-W, and SPP
Regions:

                                                     TIC
                         Transfer Direction
                                                    (MW)
                         RFC_W TO MRO                3,064
                         SERC_W TO MRO               3,764
                         SPP TO MRO                  3,164




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The Total Import Capability (TIC) is equal to the net import into MRO (1,964 MW) in the base
case plus the First Contingency Incremental Transfer Capability (FCITC) obtained in the transfer
analysis. The Inter-regional Assessment recognized constraints internal and external to the
MRO.

Operational Issues
The Midwest ISO as a Reliability Coordinator and Balancing Authority does not expect any
reliability concerns resulting from wind generation during minimum demand and over generation
conditions for the 2009/2010 Winter Assessment period. At the present levels of nameplate wind
generation, the Midwest ISO is able to manage ramp rates and volatility without any reliability
concerns. The Midwest ISO’s Public Emergency Procedure RTO-EOP-003 Supply Surplus
Procedure steps the Reliability Coordinator and Balancing Authority through necessary steps to
continuously balance load and generation during minimum generation events, and this procedure
includes variable resources as necessary. The maximum ramp down per hour in the MRO Region
has been approximately 1,200 MW thus far and is managed though Region-wide forecasting that
has proven to be routinely accurate to +/-10 percent out to 24 hrs.

The MRO does not expect any reliability concerns resulting from high-levels of Demand
Response resources.

There are no known environmental or regulatory restrictions that could impact reliability during
the 2009/2010 winter season.

The MRO Region has approximately 6,400 MW of nameplate wind generation. There is a
potential ambient temperature restriction (e.g., some wind turbines can be restricted to operating
in ambient temperatures between -20 degrees F and 104 degrees F) with wind turbines and there
may be a potential increase in operating reserves that could be required for this wind generation
during ambient temperature limitations. Accurate forecasting will help to identify any near-term
concerns regarding ambient temperature limits.

Iowa

MidAmerican Energy Company has joined the Midwest ISO as a transmission-owning member.
MidAmerican Energy turned over functional control of its transmission system to Midwest ISO
on September 1, 2009. Two other Iowa utilities, Muscatine Power and Water and the Municipal
Electric Utility of Cedar Falls, also joined the Midwest ISO.

A strong south-to-north system bias across the transmission system in Iowa is again expected
during winter 2009/2010. This bias may cause NERC TLR/LMP binding processes to be
implemented to maintain the system operating parameters within system operating limits.
However, reliable operation of the transmission system is expected in Iowa during winter
2009/2010.

A significant number of generator and line outages have been scheduled to be completed during
period from September 2009 to April 2010. These outages might cause congestion management
mechanisms to be implemented and occasional limitations on wind generation outputs.



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Temporary operating guides will be developed and issued whenever outage-scheduling studies or
operational studies indicate a potential post-contingency overload or voltage limit violation.

Nebraska

No significant operational concerns are expected in Nebraska during winter 2009/2010.

In the past, the eastern Nebraska transmission system has experienced heavy south-to-north
transfers due to low water conditions and winter peak load conditions in northern MRO. These
south-to-north transfers across the MRO system have a more profound impact on the eastern
Nebraska system than on the western Nebraska system. All of the Nebraska area flowgates have
approved operating guides that have proven effective in dealing with system conditions
throughout the year.

Winter season load distributions are considered worst case for western Nebraska area stability.
Operating guides have been developed which adequately protect the western Nebraska Region
for winter season load levels and maximum transfer conditions.

Northern MRO

No significant operational issues are expected this winter for the Northern MRO Region.
Reservoir water levels have improved but continue to remain low throughout the northern U.S.
MRO Region (Montana, North Dakota, and South Dakota). Hydro unit limitations continue in
the winter due to requirements for endangered species and limitation due to flow of river
restrictions. These issues coupled with maintenance outages will likely continue to reduce the
magnitude and duration of exports out of northern MRO, and also continue to contribute to the
recent significant imports of power into the MRO Region. The Manitoba water condition is
normal. Therefore, normal Manitoba-US exports are likely.

A number of bulk transmission outages are scheduled in the northern US MRO Region for
construction and maintenance; however, no operating problems are expected. Temporary
operating guides will be developed as necessary. Several large wind generation additions to the
northern US MRO area are expected this winter.

In conclusion, a typical winter flow pattern characterized by a south-to-north system bias is
expected to re-occur this winter season. These heavy south-to-north power transfers will likely
cause some TLR/Congestion Management activities. Overall, the northern MRO system is
expected to operate under all load and firm exchange levels while meeting the Regional
reliability criteria.

Wisconsin-Upper Michigan Systems (WUMS)

Significant increases in wind generation have occurred within the MRO-US Region.
Approximately 5,000 MW of nameplate wind generation existed on December 1, 2008. This will
increase to about 6,400 MW of nameplate by December 1, 2009.




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It has been observed that the rapid increase or decrease of the overall high or low levels of wind
generation in Iowa and Minnesota can have a significant impact on the flows through the WUMS
western and southern interfaces, namely MWEX and SOUTH TIE interfaces, respectively.
American Transmission Company LLC (ATCLLC) and the Midwest ISO are monitoring this
operational issue closely. An operational study performed hourly by the Midwest ISO anticipates
the impacts of the sudden change in wind generation in Iowa and Minnesota on a number of
selected flowgates. Operators will be alerted when the study results show the loading of any
monitored flowgate comes within 95 percent of its rating. ATCLLC also analyzes the data and
trends related to this operational issue monthly to be better prepared for managing the potentially
impacted flowgates, particularly the MWEX and SOUTH TIE interfaces, looking forward.

The eastern portion of the Upper Peninsula of Michigan (UP) experiences flows in both west to
east and east to west directions. Heavy flows in either direction can cause potential thermal and
voltage violations in the eastern UP. These constraints are managed by opening the 69 kV lines
between the eastern UP and the rest of the WUMS system, using procedures defined in an
operating guide.

Reliability Assessment Analysis
The MRO Reliability Assessment Committee is responsible for the seasonal assessments. The
MRO Transmission Assessment Subcommittee, MRO Resource Assessment Subcommittee, the
MAPP Transmission Operations Subcommittee, the ATCLLC and Saskatchewan Power
Corporation all contribute to this MRO seasonal Reliability Assessment. To prepare this MRO
Regional self-assessment, MRO staff sent the NERC spreadsheets to the registered entities
within the MRO and collected individual entity’s load forecast, generation, and Demand-Side
Management data. The staff then combined the individual inputs from these spreadsheets to
calculate the MRO Regional totals. The staff also sought responses to the questions included in
the NERC seasonal request letter, from Planning Authorities within the MRO Region – MAPP,
ATCLLC, and SaskPower. The MAPP Transmission Operations Subcommittee provided detail
from the various MAPP operating groups. Using the information gathered from this process, the
MRO Resource Assessment Subcommittee prepared the resource assessment portions, while the
Transmission Assessment Subcommittee prepared the transmission assessment and operational
issues portions. Finally, the MRO Reliability Assessment Committee, which is ultimately
responsible for the long-term reliability assessments, reviewed and approved the final draft
before it was submitted to NERC.

The MRO’s projected 2009/2010 Winter Reserve Margin is 41.3 percent without existing
uncertain resources. The projected MRO Reserve Margin of 41.3 percent for the upcoming
winter season, compared with last winter’s projected Reserve Margin of 35.2 percent, is in
excess of the target Reserve Margins.

For the MAPP GRSP, resource adequacy is measured through its accreditation rules and
procedures.60 The MAPP GRSP requires a 15 percent Reserve Capacity Obligation for
predominantly thermal systems, and 10 percent Reserve Capacity Obligation for predominantly

60
     MAPP Generation Reserve Sharing Pool Handbook; Revision May 27, 2009:
     http://www.mapp.org/ReturnBinary.aspx?Params=584e5b5f405b5072400a0d0a253b2c1518270c0754410e4413525c48421749
     0e0b10002025053b0a0323



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hydro systems, based on previously conducted LOLE studies. Approximately 8,850 MW of
generation in the MAPP GRSP (15.7 percent of MRO net capacity) is associated with
predominantly hydro systems and only requires a 10 percent Reserve Obligation. The projected
MRO Reserve Margin of 41.3 percent for the 2009/2010 winter season is in excess of the target
margin.

The Midwest ISO has conducted a Loss of Load study establishing a 12.69 percent Reserve
Margin requirement for all Midwest ISO load serving entities. Saskatchewan's reliability
criterion is based on annual expected un-served energy (EUE) analysis and equates to an
approximate 13 percent Reserve Margin. The projected MRO Reserve Margin of 41.3 percent
for the 2009/2010 winter season is in excess of these target Reserve Margins.

As in last year’s winter assessment, MRO staff attempted to include all IPP megawatts as an
internal resource, not as a purchase. Most large IPPs that are registered as Generator Owners
within the MRO were properly captured. However, there are smaller IPPs within the MRO that
fall below registration criteria that have not been entirely captured. These additional IPPs would
likely increase the projected capacity and Reserve Margins by a minimal amount.

Throughout the MRO Region, firm transmission service is required for all generation resources
that are used to provide firm capacity; also meaning that these firm generation resources are fully
deliverable to the load. The MRO expects to meet the various Reserve Margin targets without
needing to include energy-only, uncertain, or transmission-limited resources.

No specific analysis is performed to ensure external resources are available and deliverable.
However, to be counted as firm capacity the MAPP GRSP, former MAIN utilities, and
Saskatchewan require external purchases to have a firm contract and firm transmission service.

The MRO Region considers known and anticipated fuel supply or delivery issues in its
assessment. Because the Region has a large diversity in fuel supply, inventory management, and
delivery methods, the MRO does not have a specific mitigation procedure in place should fuel
delivery problems occur. The MRO members do not foresee any significant fuel supply and/or
fuel delivery issues for the upcoming 2009/2010 winter season. However, if problems occur,
they will be addressed on a case by case basis. Therefore, there should be no apparent impacts to
the reliability of meeting peak electrical demand.

Fuel-supply coordination or interruption in Saskatchewan is generally not considered an issue
due to system design and operating practices for the following reasons:

         Coal resources have firm contracts, are mine-to-mouth, and stockpiles are maintained at
          each facility in the event that mine operations are unable to meet the required demand of
          the generating facility. Typically there are 20 days of on-site stockpile for each of the
          coal facilities which in total represent approximately 47 percent of total provincial
          installed capacity. Strip coal reserves are also available and only need to be loaded and
          hauled from the mine. These reserves range from 30 to 65 days depending on the plant.
         Natural gas resources have firm on-peak transportation contracts with large natural gas
          storage facilities located within the province to back the contracts.



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      Hydro facilities/reservoirs are fully controlled by SaskPower.
      Typically, Saskatchewan does not rely on external generation resources.

Transient, voltage and small signal stability studies are performed as part of the near-term/long-
term transmission assessments. Voltage stability is also evaluated in the Midwest ISO’s seasonal
assessment. The results of the Midwest ISO winter assessment were not available prior to the due
date of this Regional assessment. Reactive power resources are considered in on-going
operational planning studies. No transient, voltage, or small signal stability issues are expected
that impact reliability during the 2009/2010 winter season.

Dynamic reactive margin is part of the ATCLLC Planning Criteria, which is determined using a
reduction to the reported reactive capability of synchronous machines. A 10 percent dynamic
reactive margin is required in the intact system and a 5 percent dynamic reactive margin is
required under NERC Category B contingencies. This criterion is applied in the ATCLLC
planning 10-year assessment studies.


Region Description
The MRO has 116 registered entities. There are seven Balancing Authorities: NPPD, OPPD,
LES, SPC, MH, WAPA and Midwest ISO, which assumes all tariff members under Midwest ISO
operate as one Balancing Authority. The MRO Region as a whole is a summer peaking Region.
The MRO Region covers all or portions of Iowa, Illinois, Minnesota, Nebraska, North and South
Dakota, Michigan, Montana, Wisconsin, and the provinces of Manitoba and Saskatchewan. The
total geographic area is approximately 1,000,000 square miles with an approximate population
of 20 million.

The MRO has six Planning Authorities registered within the footprint: the Midwest ISO, MAPP,
American Transmission Company, Southwest Power Pool, Manitoba Hydro, and SaskPower.
The Midwest ISO also spans into the RFC and SERC Regions. There are three Reliability
Coordinators within the MRO footprint, the Midwest ISO, Southwest Power Pool, and
SaskPower. The majority of Registered Entities within MRO are Midwest ISO tariff members
and therefore participate in the Midwest ISO market operations. The Nebraska utilities fall
under the Southwest Power Pool tariff and Reliability Coordinator.




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Reference Documents

2008 – ATCLLC 10-Year Transmission System Assessment Update,
http://www.atc10yearplan.com

Midwest ISO Winter 2009/2010 Coordinated Seasonal Transmission Assessment (in progress),
http://www.midwestiso.org/home

Reliability First Corporation (RFC) Winter 2009/2010 Transmission Assessment Study (on-
going), http://www.maininc.org/

Eastern Interconnection Reliability Assessment Group (ERAG) Winter 2008/2009 Inter-regional
Transmission Assessment, MRO-RFC-SERC West-SPP (MRSWS) sub-group study (on-going)

Fall, Winter and Spring Peak Operational Studies performed by NPPD Transmission Planning
Department, 2009

MEC-Operational and Outage Studies conducted by System Operations Department, June-
September 2009

2008 Baseline Reliability Study-Steady State Analysis, MidAmerican Energy Company,
December 9, 2008

NMORWG Winter Peak sensitivity reviews and voltage stability analysis, pre-winter 2008/2009.

2009 MAPP System Performance Assessment

MAPP Small Signal Stability Analysis Project Report, June 2007

MAPP Members Reliability Criteria and Study Procedures Manual, April, 2009.

SaskPower 2009 Supply Development Plan

SaskPower 2009 Load Forecast Report

Manitoba Hydro - Saskatchewan Power Seasonal Operating Guideline on Manitoba-
Saskatchewan Transfer Capability




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NPCC
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand        MW                               On-Peak Capacity by Fuel Type
Total Internal Demand                       111,559
  Direct Control Load Management                250                                        Gas
                                                                                                   Dual
  Contractually Interruptible (Curtailable)   1,643                                        14%
                                                                                                   Fuel       Other
  Critical Peak-Pricing with Control              0                              Nuclear
                                                                                  14%              17%         6%
  Load as a Capacity Resource*                1,954
                                                                                Coal
Net Internal Demand                         107,712
                                                                                 8%

2008/2009 Winter Comparison                              MW    % Change                    Hydro
2008/2009 Winter Projected Peak Demand                 106,874     0.8%                     34%
                                                                                                              Oil
2008/2009 Winter Actual Peak Demand                    110,764    -2.8%                                       8%
All-Time Winter Peak Demand                            116,284    -7.4%

2009/2010 Winter Projected Peak Capacity MW                          Margin
Existing Certain and Net Firm Transactions 151,702                   40.8%
Deliverable Capacity Resources             151,834                   41.0%
Prospective Capacity Resources             149,432                   38.7%
NERC Reference Margin Level**                 -                      15.0%
*Note: NPCC has classified an additional 3,343 MW of Demand Response as a
supply resource which does not reduce Total Internal Demand.
**Refer to the NPCC LOLE criterion imposed on each subregion as presented in
the NPCC Resource Adequacy Assessment Section
The five NPCC subregions, or subregions, are defined by the following footprints:

                the Maritimes subregion (the New Brunswick System Operator, Nova Scotia
                 Power Inc., the Maritime Electric Company Ltd. and the Northern Maine
                 Independent System Administrator, Inc);
                New England (the ISO New England Inc.);
                New York (New York ISO);
                Ontario (Independent Electricity System Operator); and
                Québec (Hydro-Québec TransÉnergie).

Demand
The NPCC Region includes both summer peaking and winter peaking systems. The Maritimes
subregion and the Québec subregion are winter peaking systems; Ontario, New York and New
England are summer peaking systems.

Due to milder than forecasted weather, the actual peak loads experienced during the winter of
2008/2009 were below forecasts in four of the five NPCC subregions; the subregion of Québec
exceeded its forecast peak load for the 2008/2009 winter period by almost 700 MW due to a
period of extreme cold in January. All NPCC subregions are currently experiencing the impact
of the economic downturn in its projected system load. Demand forecasts for the 2009/2010
winter are lower than last winter’s forecasts for all five NPCC subregions, mainly due to the
slowdown of economic activity.


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When compared with projections for the 2009/2010 winter in the following table, the New
England, New York, Ontario and Québec subregions are projecting Reserve Margins similar to
or higher than the Reserve Margins projected for the 2008/2009 winter: The Maritimes
subregion is projecting a lower Reserve Margin due to the continuing outage of the Point
Lepreau nuclear unit, however, the Maritimes Reserve Margin is projected to be adequate with a
forecast of 25 percent.

                 Table NPCC-1: NPCC Demands and Reserve Margins
           NPCC          2008/2009    2008/2009  2009/2010   2009/2010
         Balancing      Forecasted   Actual Peak Forecasted  Forecasted
         Authority      Peak (MW)       (MW)        Peak      Reserve
         subregion                                 (MW)     Margin (%)
       Maritimes           5,547         5,504      5,514       25.0
       New England         23,030       21,022     22,100       64.3
       New York            25,293       24,673     24,998       54.3
       Ontario             23,710       22,983     22,848       29.1
       Québec              36,533       37,230     36,116       12.7


Transmission
The NPCC transmission system is expected to perform adequately, and several enhancements to
the NPCC transmission system have been made since the 2008/2009 Winter. The significant
additions include:

         In New England, the Middletown–Norwalk phase of the Southwest Connecticut
          Reliability Project (SWCTRP) installed several new 345 kV overhead and underground
          circuits, approximately 70 miles in length, along with several 345/115 kV
          autotransformers within the area. The overhead portion extends from the Beseck
          substation in Middletown to the East Devon substation. Cables extend from East Devon
          to the Singer substation in Bridgeport and on to the Norwalk substation.
         In northern New York, two substations have been added on the Willis – Plattsburg 230kV
          circuits for connecting wind farms, and three substations around Stolle Rd – Meyer
          230kV also for wind farm connections.
         The forced outage to the 230 kV circuit BP76 on the Ontario-New York interconnection
          at Niagara reduces the total Ontario-New York import and export capability until its
          scheduled return to service in the third quarter of 2010. The Millwood 345 kV 240 MVar
          capacitor bank was added in summer 2009 for added voltage support in the lower Hudson
          Valley.
         On July 2, 2009, TransÉnergie commissioned the first HVdc converter of the new
          Outaouais substation and its interconnection with IESO in the Ottawa-Gatineau area
          across the Ottawa River. The interconnection consists of two 625-MW back-to-back
          HVdc converters in Québec and a double-circuit 240 kV line to Hawthorne substation in
          Ottawa. On the Québec side of the converters, a 315 kV switchyard integrates the
          interconnection into the existing system. The Chénier 735/315 kV substation, north of
          Montréal is the source station feeding this interconnection. The second converter is


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            scheduled for commissioning in November 2009 and both converters will be available for
            the 2009/2010 Winter Operating Period.

Resource Adequacy Assessment
Through numerous studies and reviews, the NPCC Task Force on Coordination of Planning
(TFCP) ensures that the proposed resources of each NPCC subregion will comply with NPCC
Document A-02, “Basic Criteria for Design and Operation of Interconnected Power Systems.”61
Section 3.0 of Document A-02 defines the criterion for resource adequacy for each subregion as
follows:

            Resource Adequacy - Design Criteria

            Each Area’s [subregion] probability (or risk) of disconnecting any firm load due to
            resource deficiencies shall be, on average, not more than once in ten years. Compliance
            with this criterion shall be evaluated probabilistically, such that the loss of load
            expectation [LOLE] of disconnecting firm load due to resource deficiencies shall be, on
            average, no more than 0.1 day per year. This evaluation shall make due allowance for
            demand uncertainty, scheduled outages and de-ratings, forced outages and de-ratings,
            assistance over interconnections with neighboring subregions and Regions, transmission
            transfer capabilities, and capacity and/or load relief from available operating
            procedures.

The Northeast Power Coordinating Council has in place a comprehensive resource assessment
program directed through NPCC Document B-08, “Guidelines for subregion Review of Resource
Adequacy.”62 This document charges the TFCP to assess periodic reviews of resource adequacy
for the five NPCC subregions.

The primary objective of the NPCC subregion resource review is to ensure that plans are in place
within the subregion for the timely acquisition of resources sufficient to meet this resource
adequacy criterion and to identify those instances in which a failure to comply with the NPCC
“Basic Criteria for Design and Operation of Interconnected Power Systems,” or other NPCC
criteria, could result in adverse consequences to another NPCC subregion or subregions. If, in
the course of the study, such problems of an inter-subregion nature are determined, NPCC
informs the affected systems and subregions, works with the subregion to develop mechanisms
to mitigate potential reliability impacts and monitors the resolution of the concern.

Document B-08 requires each subregion resource assessment to include an evaluation and/or
discussion of the:

           load model and critical assumptions on which the review is based;
           procedures used by the subregion for verifying generator ratings and identifying de-
            ratings and forced outages;
           ability of the subregion to reliably meet projected electricity demand, assuming the most
            likely load forecast for the subregion and the proposed resource scenario;

61
     http://www.npcc.org/documents/regStandards/Criteria.aspx
62
     http://www.npcc.org/documents/regStandards/Guide.aspx



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         ability of the subregion to reliably meet projected electricity demand, assuming a high
          growth load forecast for the subregion and the proposed resource scenario;
         impact of load and resource uncertainties on projected subregion reliability, discussing
          any available mechanisms to mitigate potential reliability impacts;
         proposed resource capacity mix and the potential for reliability impacts due to the
          transportation infrastructure to supply the fuel;
         internal transmission limitations; and
         the impact of any possible environmental restrictions.

The resource adequacy review must describe the basic load model on which the review is based
together with its inherent assumptions, and variations on the model must consider load forecast
uncertainty. The anticipated impact on load and energy of Demand-Side Management programs
must also be addressed. If the subregion load model includes pockets of demand for entities
which are not members of NPCC, the subregion must discuss how it incorporates the electricity
demand and energy projections of such entities.

Each area’s resource adequacy review will be conducted for a window of five years and a
detailed “Comprehensive Review” is conducted triennially. For those years when the
Comprehensive Review is not required, the subregion is charged to continue to evaluate its
resource projections on an annual or interim basis. The subregion will conduct an “Annual
Interim Review” that will reassess the remaining years studied in its most recent Comprehensive
Review. Based on the results of the Annual Interim Review, the subregion may be asked to
advance its next regularly scheduled Comprehensive Review.

These resource assessments are complemented by the efforts of the Working Group on the
Review of Resource and Transmission Adequacy (Working Group CP-08), which assesses the
interconnection benefits assumed by each NPCC subregion in demonstrating compliance with
the NPCC resource reliability. The Working Group conducts such studies at least triennially for
a window of five years, and the Working Group judges if the outside assistance assumed by each
subregion is reasonable.

Wind Energy Development
Energy produced by wind will continue to increase in NPCC. For the winter of 2009/2010, the
following contribution from wind generation is projected:

                    Table 2: 2009/2010 Projected Wind Resources
                 Sub-Region             Nameplate Capacity    Capacity After
                                                            Applied De-Rating
Maritimes                                           350 MW                   138 MW
New England                                         103 MW                    91 MW
New York                                           1,507 MW                  452 MW
Ontario                                            1,084 MW                  347 MW
Québec                                              642 MW                   134 MW
TOTAL                                              3,686 MW                 1,162 MW




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For the winter of 2008/2009, wind generation estimates were as follows:

                       Table 3: 2008/2009 Projected Wind Resources
                    Sub-Region             Nameplate Capacity    Capacity After
                                                               Applied De-Rating
 Maritimes                                                    335 MW               217 MW
 New England                                                   5 MW                  0 MW
 New York                                                     706 MW               212 MW
 Ontario                                                      494 MW                50 MW
 Québec                                                       471 MW                 0 MW
 TOTAL                                                       2,011 MW              479 MW


Transmission Assessment Process
In parallel with the NPCC subregion resource review, the NPCC Task Force on System Studies
(TFSS) is charged with conducting periodic reviews of the reliability of the planned bulk power
transmission systems of each subregion of NPCC, the conduct of which is directed through
NPCC Document B-04, “Guidelines for NPCC subregion Transmission Reviews.”63 Each
subregion is required to present an annual transmission review to the TFSS, assessing its planned
transmission network four to six years in the future. Depending on the extent of the expected
changes to the system studied, the review presented each year by the subregion may be one of
the following three types:

           Comprehensive Review

            A detailed analysis of the complete bulk power system of the subregion is presented
            every five years at a minimum. The TFSS will charge the subregion to conduct such a
            review more frequently as changes may dictate.

           Intermediate Review

            An Intermediate Review is conducted with the same level of detail as a Comprehensive
            Review, but, in those instances in which the significant transmission enhancements are
            confined to a segment of the subregion, the review will focus only on that portion of the
            system. Or, if the changes to the overall system are intermediate in nature, the analysis
            will focus only on the newly planned facilities.

           Interim Review

            If the changes in the planned transmission system are minimal, the subregion will
            summarize these changes, assess the impact of the changes on the bulk power system of
            the subregion and reference the most recently conducted Intermediate Review or
            Comprehensive Review.


63
     http://www.npcc.org/documents/regStandards/Guide.aspx



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          In the years between Comprehensive Reviews, an subregion will annually conduct either
          an Interim Review, or an Intermediate Review, depending on the extent of the system
          changes projected for the subregion since its last Comprehensive Review. The TFSS will
          judge the significance of the proposed system changes planned by the subregion and
          direct an Intermediate Review or an Interim Review. If the TFSS agrees that revisions to
          the planned system are major, it will charge a Comprehensive Review in advance of the
          normal five-year schedule.

          Both the Comprehensive Review and the Intermediate Review analyze:

                the steady state performance of the system;
                the dynamic performance of the system;
                the response of the system to selected extreme contingencies; and
                the response of the system to extreme system conditions.

          Each review will also discuss special protection systems and/or dynamic control systems
          within the subregion, the failure or misoperation of which could impact neighboring
          subregions or Regions.

          The depth of the analysis required in the NPCC transmission review fully complies with,
          or exceeds, the obligations of NERC Reliability Standards TPL-001 through TPL-004:

                TPL-001-0, “System Performance Under Normal Conditions”
                TPL-002-0, “System Performance Following Loss of a Single BES Element”
                TPL-003-0, “System Performance Following Loss of Two or More BES Elements”
                TPL-004-0, “System Performance Following Extreme BES Events”

          NPCC-specific criteria requires system operation and system design to the following
          contingencies, which exceed what is required in the TPL standards.

                Simultaneous permanent phase to ground faults on different phases of each of two
                 adjacent transmission circuits on a multiple circuit tower, with normal fault
                 clearing.
                A permanent phase to ground fault on any transmission circuit, transformer, or
                 bus section with delayed fault clearing.

The following information is the specific discussions by each NPCC subregion.




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Maritimes

Demand
The Maritimes subregion is a winter peaking system. The Maritimes subregion load is the
mathematical sum of the forecasted weekly peak loads of the sub-areas (New Brunswick, Nova
Scotia, Prince Edward Island, and the area served by the Northern Maine Independent System
Operator). As such, it does not take the effect of load coincidence within the week into account.
Economic assumptions are not made when determining load forecasts.

Based on the Maritimes subregion 2009/2010 demand forecast, a peak of 5514 MW is predicted
to occur for the winter period, December through February. The actual peak for Winter
2008/2009 was 5,504 MW on January 16, 2009, which was 43 MW (< 1 percent) lower than last
year’s forecast of 5,547 MW.

       For the New Brunswick System Operator (NBSO), the load forecast is based on an End-
       use Model (sum of forecasted loads by use e.g. water heating, space heating, lighting etc.)
       for residential loads and an Econometric Model for general service and industrial loads,
       correlating forecasted economic growth and historical loads. Each of these models is
       weather adjusted using a 30-year historical average.

       For Nova Scotia, the load forecast is based on a 10-year average measured at the major
       load center, along with analyses of sales history, economic indicators,
       customer surveys, technological, demographic changes in the market, and the price and
       availability of other energy sources.

       For Prince Edward Island, the load forecast uses average long-term weather for the peak
       period (typically December) and a time-based regression model to determine the
       forecasted annual peak. The remaining months are prorated on the previous year.

       The Northern Maine Independent System Administrator performs a trend analysis on
       historic data in order to develop an estimate of future loads.

Load Management is not included in the resource adequacy assessment for the Maritimes
subregion; it is assumed that all forecasted load is served in determining compliance with the
NPCC Criterion of loss of load expectation [LOLE] of disconnecting firm load due to resource
deficiencies shall be, on average, no more than 0.1 day per year. In the Maritimes subregion
there is between 389 and 406 MW of interruptible demand available during the assessment
period; there is 389 MW (7 percent of projected peak demand) forecasted to be available at the
time of the seasonal peak.

The Maritimes subregion is broken up into sub-areas and each area has its own energy efficiency
programs. These programs are primarily aimed at the residential consumer to help reduce their
heating costs. It is usually geared towards heat as the Maritimes subregion is a winter peaking
system.

For further information on the energy efficiency programs please review the following links:



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          www.maritimeelectric.com
          www.nbpower.com
          www.mainepublicservice.com
          www.emec.com
          www.nspower.ca/energy_efficiency/programs/

The Maritimes subregion does not address quantitative analyses to assessing the variability in
projected demand due to weather, the economy, or other factors. In addition the Maritimes does
not develop an extreme (e.g. 90/10) winter forecast in its seasonal assessment.

Generation
The Maritimes subregion resources will vary between 7,280 MW and 7,338 MW of existing
capacity plus between 176.6 and 179.6 MW (nameplate rating) of planned wind generation
scheduled to come on line. The Maritimes subregion does not consider conceptual, future or
inoperable resources when doing its seasonal assessment.

During this time period there is 138.1 MW of existing wind with a nameplate rating of 350.02
MW. Each sub-area in the Maritimes subregion use its own winter capacity factor. In New
Brunswick it is 40 percent, Northern Maine 30 percent, Prince Edward Island 40 percent and
Nova Scotia uses history for each individual wind farm giving an average for Nova Scotia of
around 35 percent. Nova Scotia does not use any wind capacity towards their installed capacity.

Wind project capacity is de-rated to its demonstrated or projected average output for each winter
or winter capability period. This de-ration of wind capacity in the Maritimes subregion is based
upon results from the Sept. 21, 2005 NBSO report Maritimes Wind Integration Study.64 This
wind study showed that the effective capacity from wind projects, and their contribution to
LOLE, was equal to or better than their seasonal capacity factors. Coincidence of high winter
wind generation with the peak winter loads results in the Maritimes subregion receiving a higher
capacity benefit from wind projects versus a summer peaking area. The effective wind capacity
calculation also assumes a good geographic dispersion of the wind projects in order to mitigate
the occurrences of having zero wind production. Wind is the only variable resource currently
considered in the Maritimes subregion resource adequacy assessment.

During this time period there is 130 MW of existing Biomass with a nameplate rating of 133
MW.

The Maritimes subregion is forecasting normal hydro conditions for the Winter 2009/2010
assessment period. The Maritimes subregion hydro resources are run of the river facilities with
limited reservoir storage facilities. These facilities are primarily used as peaking units or
providing operating reserve.

The Point Lepreau nuclear generating station (635 MW) will continue be out of service during
the whole Winter Assessment period; the plant was removed from service in the spring of 2008
to begin a major refurbishment. With firm purchases from outside the Maritimes subregion in

64
  http://www.nbso.ca/Public/_private/2005percent20Maritimepercent20Windpercent20Integrationpercent20Studypercent20_Fina
  l_.pdf



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place, and all scheduled maintenance completed prior to the winter period, there are no
anticipated shortfalls in capacity. Other than the continuing Pt. Lepreau outage, the Maritimes
subregion does not expect to experience any conditions that would cause any further
unanticipated capacity reductions during the winter period.

Capacity Transactions on Peak
There are firm capacity agreements in place between New Brunswick - H.Q and New Brunswick
- Newfoundland and Labrador and are as follows:

                         Table Maritimes 1: Firm Purchases
             Firm Purchases     Dec-08        Jan-09       Feb-09
             LD Energy          330 MW        330 MW       330 MW

There is a firm sale of 207 MW to H.Q. which is tied to specific generators within New
Brunswick.

The Maritimes subregion does have agreements in place for the purchase of emergency energy
with other sub Regions as well as a reserve sharing agreement within NPCC. But the Maritime
subregion does not rely on this assistance when doing its winter assessment, and no portion of
any transaction includes a provision for a Liquidated Damage Contract (LDC)

Transmission
There has been no significant new bulk power transmission addition since the last reporting
winter period. Furthermore, there are no bulk transmission additions expected this winter.

All existing significant transmission facilities are expected to be in service during the winter
reporting period.

The Maritimes inter-regional transfer capabilities are:

            NB – MEPCO: 1000 MW

            MEPCO – NB: 550 MW (presently a presidential order in the U.S.A. limiting the
             interface to 400 MW).

            HQ – NB: HVdc + Radial Load = Between 985 MW and 1017 MW. (The reason
             for the range is due to the varying radial load during the winter reporting period).

            NB – HQ: 770 MW

The latest study would be the IPL/NRI studies on the NB / ISO-NE interface. The Regions
import capabilities are based on real time values based on transmission and generation being in /
out of service. NBSO has rules based on study results for simultaneous transfer capability with
our interconnections. Transmission or generation constraints are recognized that are external to
the Maritimes subregion.


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No other significant substation equipment has recently been added.

Operational Issues
The Maritimes subregion assesses its seasonal resource adequacy in accordance with NPCC C-
13 Operational Planning Coordination procedure. As such, the assessment considers the
Regional Operating Reserve criteria; 100-percent of the largest single contingency and 50-
percent of the second largest contingency.

The amount of wind presently operating does not require any operational changes.

The Maritimes subregion is a winter is winter peaking system. Minimum demand and over
generation will not be a concern.

The only Demand Response considered in resource adequacy assessment for the Maritimes
subregion is interruptible load. The Maritimes subregion uses a 20 percent reserve criterion for
planning purposes, equal to 20 percent x (Forecast Peak Load MW – Interruptible Load MW).

There are no environmental or regulatory restrictions which could impact reliability in the
Maritimes subregion during the assessment period.

Reliability Assessment Analysis
When allowances for unplanned outages (based on a discreet MW value representing an
historical assessment of the total forced outages in MW typically realized at the time of peak for
the given operating season) are considered, the Maritimes subregion is projecting more than
adequate surplus capacity margins above its operating reserve requirements for the Winter
2009/2010 assessment period.

The projected capacity margin for winter 2009/2010 period is 8 percent to 30 percent as
compared to the projected capacity margin for the winter 2008/2009 of 6 percent to 16 percent.

The Maritime subregion does not consider potential fuel-supply interruptions in the Regional
assessment. The fuel supply in the Maritimes subregion is very diverse and it includes natural
gas, coal, oil (both light and residual), hydro, tidal, municipal waste, and wood.

The NB transmission system is robust, comprised of a 345 kV transmission ring with additional
supporting 230 kV transmissions. For those areas that may suffer low voltage post contingency,
there are specific “must run” procedures that require generation online to meet necessary reactive
reserves for contingencies. This requirement is applied for generation assessments as well as the
day ahead review to ensure that there are sufficient reactive reserves.




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New England

Demand
ISO New England Inc. (ISO-NE) serves as the NERC Balancing Authority (BA) for the six-state
New England region. ISO-NE’s reference case winter peak demand forecast is the 50/50
forecast (50 percent chance of being exceeded), corresponding to a New England weighted dry-
bulb temperature of 6.8º F. The 6.8º F dry-bulb temperature corresponds to the 50th percentile of
the extreme weather distribution and is consistent with the average temperature at the hour of the
ISO-NE winter peak demand for the previous 20 years. The reference case load forecast is for
New England’s coincident peak demand and is based on the most recent reference economic
forecast, which reflects the regional economic conditions that are most likely to occur.

ISO-NE’s actual metered 2008/2009 winter peak demand was 21,022 MW, which occurred at
hour ending 18:00 on Monday, December 8, 2008. The weather normalized 2008/2009 winter
peak demand was 22,190 MW, which is 1,168 MW greater than the actual metered demand. The
reconstituted65 2008/2009 winter peak demand was 21,581 MW, which is 559 MW greater than
the actual metered demand.

The 2009/2010 winter peak demand forecast is 22,100 MW, which is 930 MW (4.21 percent)
lower than the 2008/2009 winter peak demand forecast of 23,030 MW. The current economic
conditions have lowered this year’s forecast for peak demand (and also energy) when compared
to last year’s forecast. The lower forecast for this winter is also due to modeling improvements
within the energy and peak demand forecast methodologies, which resulted in a lower forecast
for winter peaks. The change in the forecast methodology reflects the elimination of the growth
trend on the weather sensitive portion of the winter peak demand. This methodology change
subsequently results in even lower winter peak demand forecasts when compared with the 2008
long-term (10-year) forecast for both summer and winter peak demands.

ISO-NE develops an independent demand forecast for the Balancing Authority area as a whole
and each of the six states within it. ISO-NE uses historical hourly demand data from individual
member utilities, which is based upon revenue quality metering, to develop historical demand
data from which the regional peak demand and energy forecasts are based upon. From this, ISO-
NE develops a forecast of monthly energies and peak demands, by state. Therefore, the peak
demand forecast for the region and the states is a coincident66 peak demand forecast.

A total of 2,520 MW of demand resources (DR) could be interrupted, during times of capacity
shortages, during the winter of 2009/2010. As done in past seasonal reliability assessments, ISO-
NE treats these demand-side resources like supply-side capacity. These resources, which are in
ISO-NE’s Real-Time 30-Minute (1,767 MW), Real-Time 2-Hour (193 MW), and Profiled
Demand Response (18 MW) programs, are instructed to interrupt their consumption67 during
specific actions of ISO-NE Operating Procedure No. 4 - Action During a Capacity Deficiency


65
   Reconstituted for the load reducing actions of demand resources.
66
   The first two years of ISO-NE’s annual 10-year, long-range load forecast, for both peak demand and energy, is developed at
   the system or regional level with the remaining eight years of that same forecast being developed as the sum of the six-state’s
   forecasts.
67
   May also include the starting of “on-site” generation.



2009/2010 Winter Reliability Assessment                                                                                Page 62
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(OP 4).68 Demand reductions from existing Demand-Side Management (DSM) programs are
accounted for in the historical data that is used within ISO-NE’s load forecast model. In addition
to demand response resources, ISO-NE also considers energy efficiency (EE) to be a supply-side
capacity resource. New energy efficiency programs are projected to be 542 MW during the
winter 2009/2010. Demand that will interrupt voluntarily based on the current price of energy is
not included in this amount. As of July 31, 2009, there were approximately 77 MW enrolled
within the Demand Resource price response program.

Total demand response resources of 2,520 MW represent approximately 11.4 percent of the
projected 2009/2010 winter peak demand, which is forecast to be 22,100 MW.

ISO-NE Demand Response Measurement & Verification (M&V) Plans describe the methods,
assumptions and measurements that will be used to determine actual demand reductions under
ISO-NE’s Forward Capacity Market (FCM) Commitment Periods.69 All M&V Plans must
comply with the requirements set forth within ISO-NE’s Manual for Measurement and
Verification of Demand Reduction Value from Demand Resources (M-MVDR).70

As mentioned earlier, ISO-NE has always considered energy efficiency (EE) to be a supply-side
capacity resource, and as such, new energy efficiency programs are projected to be 542 MW,
during the winter 2009/2010. New England’s measurement and verification programs used for
energy efficiency are also documented in ISO-NE’s M-MVDR.

ISO New England addresses seasonal peak demand uncertainty in two ways:

         Weather — Peak demand distribution forecasts are made based on 35 years of historical
          weather, which includes the reference forecast (50 percent chance of being exceeded) and
          the extreme forecast (10 percent chance of being exceeded);

         Economics — Alternative forecasts are also made using high and low economic
          scenarios. The 2009/2010 winter peak demand forecasts for the various weather and
          economic scenarios are shown in Table New England-1.

              New England Table 1: Economic and Weather Assumptions
     Economic Assumptions                        Weather Assumptions
                                           Reference             Extreme
                                          50/50 (MW)           90/10 (MW)
     Reference Economic Forecast             22,100               22,850
     Alternative High Economic Forecast      22,180               22,925
     Alternative Low Economic Forecast       22,025               22,775



68
   Operating Procedure No. 4 may be found on ISO-NE’s web site at:
   http://www.isone.com/rules_proceds/operating/isone/op4/index.html
69
   A FCM Commitment Period runs from June 1 of one year to May 31 of the next year.
70
   This ISO-NE Manual can be located at: http://www.iso-ne.com/rules_proceds/isone_mnls/index.html



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Generation
For the winter of 2009/2010, ISO-NE has 36,140 MW of Existing-Certain capacity, 141 MW of
Existing-Other capacity and 525 MW of existing inoperable capacity. Included within the
Existing-Certain capacity is 2,520 MW of demand resources, which are treated as capacity in
New England. ISO-NE is also reporting 121 MW of Future-Planned capacity additions and 36
MW of Future-Other capacity.

Approximately 91 MW of the Existing-Certain capacity is on-peak wind generation. The total
nameplate capability of those wind facilities is 103 MW. Of the 121 MW of Future-Planned
capacity projected to be in-service for the 2009/2010 winter, 55 MW (91 MW nameplate) is new
wind capacity.71 Also included in the Existing-Certain capacity is 1,929 MW of hydro-electric
capacity and 1 MW of solar capacity.

Seasonal wind capacity ratings for existing resources is determined from either the sustained
maximum net output averaged over a four (4) consecutive hour period (measured for the summer
and winter capability periods each year); or the unit’s nameplate rating adjusted for engineering
data that projects unit output at time of peak demand. The expected on-peak capacity values of
new variable resources are determined based on engineering analyses performed by those
resources in support of their qualified capacity within the Forward Capacity Market.

For the 2009/2010 winter, biomass capacity within the Existing-Certain capacity category totals
986 MW. There are no biomass facilities planned for commercialization during the three-month
winter period of 2009/2010.

Hydrological conditions are anticipated to be sufficient during the winter of 2009/2010. Within
New England, the seasonal variation of hydrological conditions traditionally peaks during the
spring timeframe, are lowest during the summer, and range somewhat in between these seasonal
variations (minimums and maximums) during the fall and winter. Small non-dispatchable and/or
run-of-river hydro-electric facilities are seasonally rated against historical stream flow data, and
as such, their monthly capacity ratings already reflect the dynamic variations of regional
hydraulic conditions. Conventional weekly-cycle hydro-electric facilities, with significant
pondage or storage capability, are seasonally de-rated based on demonstrated capacity, can also
become energy limited. However, within New England, these conditions traditionally occur only
during the dry, summer months. If and when these conditions do occur, these energy limitations
are accounted for within the daily dispatch.

However, the total hydro-electric capacity only contributes approximately 5 percent to New
England’s overall installed generating capacity and that historical hydro-electric energy
production has only accounted for approximately 6-8 percent of the annual (native generation)
energy production within New England.

New England is not currently experiencing or expecting any fuels supply constraints that would
create temporary capacity reductions on regional power generators.

71
     Currently, there is a significant difference between how existing wind capacity is seasonally rated versus how new wind
     capacity will be seasonally rated under ISO-NE’s Forward Capacity Market (FCM). These differences will no longer exist
     after June 1, 2010, when the FCM begins.



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A large portion of generation in New England is fueled by natural gas (40.9 percent), followed
by nuclear (28.5 percent), coal (14.9 percent), non-hydro renewables (6.0 percent), hydro (6.8
percent), oil (1.5 percent) and pumped storage (1.3 percent)72. Fuel supply vulnerability has
historically not been a concern for any of the power plant fuels, other than natural gas.

In the past, winter has traditionally brought concern over the availability and deliverability of
natural gas to regional gas-fired generators. This situation was primarily due to two factors; 1) a
seasonally (winter) constrained natural gas delivery system both into and within the region, and,
2) the overall characteristic of most regional gas-fired generators of having subordinate
entitlements for contracting for both natural gas supply and transportation. However, the first
factor has been eliminated due to the recent influx of new LNG projects73 within and around the
region, in combination with several new pipeline expansion projects to deliver these new gas
supplies to area markets. Several other recent regional pipeline projects have worked to eliminate
seasonal bottlenecks and constraints as well as improve bidirectional flow capability. The second
factor (#2 - lack of firm contracting) is still an ongoing issue, however, with the region now
having access to more natural gas supplies (as a result of the initiatives from factor #1), the
concern over the unavailability of regional gas-fired generating units during the winter peak
season has now diminished.

In addition, to minimize concerns over real-time reliability brought about by historical gas
supply availability or short-term deliverability constraints, increased communication and
coordination efforts have been implemented between ISO-NE and the regional natural gas
industry, with help from the Northeast Gas Association (NGA).74 These communications
improvements have increased the response-time for situational awareness of emerging gas
supply constraints that could potentially impact regional gas-fired generators. ISO-NE and NGA
co-chair the Electric/Gas Operations Committee (EGOC), which was formed in 2004 to address
the operational issues that resulted from the Cold Snap75 of January 2004. The EGOC works on a
variety of issues common to both industries and has recently been working on coordination of
maintenance schedules, reviewing communications protocols and conducting cross-industry
education and training sessions. ISO-NE recently held an EGOC Training Session on September
18, 2009.

The only time when significant amounts of generating capacity are expected to be out of service
is during the first two weeks in December 2009, when generators will be in the process of
wrapping-up their late fall annual maintenance inspections.76 However, with the reduced
projections for this winter’s peak demand and the natural surplus of generating capacity during
the overall winter season, there are no major concerns with respect to serving potential winter
peak loads that may occur in early December 2009 or for all winter for that matter. If, however,
due to some unexpected situation where real-time capacity conditions deteriorate, to rebalance
72
   Values represent 2008 actual energy generation.
73
   These LNG projects include: 1) The Northeast Gateway Deepwater Port Project, 2) The Canaport LNG Facility, and the nearly
   complete Neptune LNG Deepwater Port Project.
74
   The Northeast Gas Association (NGA) is a regional trade association that focuses on education and training, technology
   research and development, operations, planning, and increasing public awareness of natural gas in the Northeast U.S. The
   NGA web site is located at: http://www.northeastgas.org
75
   Which occurred over a three-day period, January 14-16, 2004.
76
   Includes 1,700 MW of planned maintenance during the first week in December and 1,300 MW of planned maintenance during
   the second week in December.



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demand with supply, ISO-NE would invoke the load and capacity relief actions as available
within ISO-NE Operating Procedure No. 4 – Action During a Capacity Deficiency (OP 4).

Capacity Transactions on Peak
For the 2009/2010 winter, ISO-NE expects firm external capacity imports of 401 MW. This
includes 310 MW from Hydro-Québec and 91 MW from New York. Only firm, Installed
Capacity (ICAP) imports that are known in advance are included as capacity transactions. While
the entire 401 MW of ICAP imports are backed by firm contracts for generation, there is no
requirement for those purchases to have firm transmission service. However, it is specified that
deliverability of ICAP purchases must meet the New England delivery requirement and should
be consistent with the deliverability requirements of internal generators. The market participant
is free to choose the type of transmission service necessary for the delivery of energy associated
with ICAP, but the market participant also bears the associated risk of ICAP market (non-
delivery) penalties if it chooses to use non-firm transmission service. The 310 MW purchase
from Hydro-Québec is a Liquidated Damage Contract (LDC), but the 91 MW purchase from
New York is not.

Based on studies and past experience, ISO-NE assumes approximately 2,000 MW of emergency
assistance, also referred to as tie-line benefits, available from other areas within the NPCC
Region. This tie benefit value represents about 50 percent of New England’s total import
capability. ISO-NE also participates in a regional reserve sharing group with NPCC, and has a
shared activation of reserves agreement with New York for up to 300 MW.

For the 2009/2010 winter, ISO-NE expects firm external capacity exports to New York (Long
Island) of 343 MW via the Cross-Sound Cable. Although this export capacity transaction is
backed by a firm contract for generation, the energy and capacity may be considered recallable
by ISO-NE, depending on whether the transaction clears the New York market. In the event of a
transmission import-constraint into Connecticut, if the capacity export transaction does not clear
in the New York market, it is recallable and can be cut earlier than other non-recallable exports.
The capacity export across the Cross-Sound Cable is based on a make-whole contract.

Transmission
Within the New England Balancing Authority area, the following new bulk power transmission
facilities have either been placed in-service since the 2008/2009 winter period or are expected to
be placed in-service during the 2009/20010 winter period:

New Hampshire
The northern and central New Hampshire voltage and thermal performance concerns were
addressed by closing the Y-138 115 kV tie with Maine. This included the installation of a Phase
Angle Regulator (PAR) at the Saco Valley Substation, located in New Hampshire. A new
substation located in Fitzwilliam, NH consisting of one 345/115 kV autotransformer has also
been energized.

Vermont
A set of transmission reinforcements, the Northwest Vermont Reliability Project (NWVTRP),
which was designed to address thermal and voltage violation issues in the broad northwestern


2009/2010 Winter Reliability Assessment                                                 Page 66
Regional Reliability Self-Assessments


portion of Vermont, has been completed. The remaining components, four +25/-12.5 MVAr
synchronous condensers at the Granite Substation, were placed in-service in April 2009. The 28-
mile 115 kV circuit from New Haven to Vergennes to Queen City was completed in December
2008.

Massachusetts
The final 345 kV cable from the Stoughton substation to the K Street substation in downtown
Boston was placed in-service, along with an associated autotransformer and two reactors.

Improvements have been made to provide additional line-out protection in lower Southeast
Massachusetts (SEMA). The new facilities installed include a new 115 kV line between the
Brook Street and Auburn Street substations, a new 115 kV line between the Carver and Tremont
substations, and a 115 kV Static Var Compensator (SVC) at Barnstable. Additionally, the
Bridgewater to Pilgrim 345 kV line has been looped into the Carver 345 kV substation.

Connecticut
The Middletown–Norwalk phase of the Southwest Connecticut Reliability Project (SWCTRP)
installed several new 345 kV overhead and underground circuits, approximately 70 miles in
length, along with several 345/115 kV autotransformers within the area. The overhead portion
extends from the Beseck substation in Middletown to the East Devon substation. Cables extend
from East Devon to the Singer substation in Bridgeport and on to the Norwalk substation. The
planned Norwalk–Glenbrook 115 kV cable project has also been placed in-service. The project
includes the installation of two 9-mile 115 kV underground circuits between the Norwalk and
Glenbrook substations.

There are no reliability concerns in meeting the in-service dates for the aforementioned facilities
and there are no specific transmission additions deemed necessary to meet the demand forecast
for the 2009/2010 winter period.

ISO-NE does not expect any major transmission lines or facilities to be out-of-service (OOS)
during the 2009/2010 winter period. However, if major transmission outages were to occur,
system reliability would be maintained through adherence to ISO-NE Operating Procedure No.
19 - Transmission Operations (OP19)77 criteria, during real-time operations.

No significant transmission constraints are anticipated for the upcoming winter.

Table New England-2 summarizes the nominal interregional transmission transfer capabilities,
which also reflects transmission and generation constraints in systems external to ISO-NE. In
addition, these interregional transfer capabilities are also reviewed and (re)calculated78 on a day-
to-day basis within real-time.




77
   ISO-NE’s OP19 may be found on ISO New England’s web site at:
   http://www.isone.com/rules_proceds/operating/isone/op19/index.html
78
   These “nominal” interregional transmission transfer capabilities are dynamic in nature and subject to a increase or decrease in
   value on a real-time basis, which is based upon ever changing system topology.



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                      New England Table 2: Transfer Capability
 Transmission Interface           Nominal Transfer            Basis or Study for
                                   Capability (MW)             Interface Limit
 New Brunswick – New England                                 1,000                     Second New Brunswick Tie
                                                                                       Study
 Phase II                                                    1,400                     PJM & NYISO Loss of
                                                                                       Source Studies
 Highgate                                                     200                      Various Transmission
                                                                                       Studies
 New York – New England                                      1,600                     NYISO Operating Study,
                                                                                       Winter 2005/2006
 Cross-Sound Cable                                            330                      Cross-Sound Cable System
                                                                                       Impact Study

As stated earlier, a new SVC has been installed at the Barnstable substation on Cape Cod and
four +25/-12.5 MVAr synchronous condensers have been installed at the Granite substation in
Vermont.

Operational Issues
ISO-NE is not projecting any major operational constraints or issues for the winter of 2009/2010,
ISO-NE has not performed any special operating studies for the 2009/2010 winter period.

As of October 2009, no special operating procedures have been developed as a result of the
recent integration of approximately 100 MW of wind generation into New England’s bulk power
system.

ISO-NE is not projecting any reliability concerns resulting from minimum demand periods or
over-generation. If this was to occur in real-time, ISO-NE can invoke System Operating
Procedure(s) (SOPs)79 that work to mitigate such situations.

ISO-NE is not projecting any reliability concerns resulting from high levels of demand response
resources. If this was to occur in real-time, ISO-NE can invoke Operating Procedures (OPs)80
that work to mitigate such situations.

No environmental or regulatory restrictions are anticipated to impact system or sub-area
reliability during the 2009/2010 winter period. Furthermore, ISO-NE is not anticipating any unusual
operating conditions during the winter of 2009/2010.


79
   ISO-NE System Operating Procedure entitled SOP-RTMKTS.0120.0015 - Implement Minimum Generation Emergency
   Remedial Action, which can be located on the ISO-NE web site at: http://www.iso-
   ne.com/rules_proceds/operating/sysop/rt_mkts/sop_rtmkts_0120_0015.pdf.
80
   ISO-NE Operating Procedure No. 4 – Action During a Capacity Deficiency, which can be located on the ISO-NE web site at:
   http://www.iso-ne.com/rules_proceds/operating/isone/op4/index.html.


2009/2010 Winter Reliability Assessment                                                                         Page 68
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Reliability Assessment Analysis
ISO-NE does not have a Reserve Margin criterion. ISO-NE bases its capacity requirements on
probabilistic loss-of-load expectation (LOLE) analysis that calculates the total amount of
installed capacity needed to meet NPCC’s once-in-10-year resource adequacy requirement for
preventing the disconnection of firm load due to a capacity deficiency. This value, known as the
Installed Capacity Requirement (ICR),81 was calculated for the 2009/2010 capability year, which
runs from June 1, 2009 to May 31, 2010. The annual ICR of 31,823 MW (in terms of summer
ratings) for the 2009/2010 capability period translates to approximately 34,000 MW in terms of
winter ratings. This results in a projected Reserve Margin of 54 percent.

For this winter’s reliability assessment, ISO-NE projects deliverable capacity resources of
36,319 MW against a peak demand forecast of 22,100 MW, which results in a Reserve Margin
of 14,219 MW or 64.3 percent under the 50/50 winter peak demand forecast. For the 90/10
winter peak demand forecast of 22,850 MW, the Reserve Margin is 13,469 MW, or 58.9 percent.
The capacity margins are based on anticipated generation additions and retirements, planned
generator outages, projected firm capacity imports and exports, and the expected impact of
demand response programs.

Table New England-3 shows New England’s projected winter Reserve Margins for winter
2008/2009 and 2009/2010 under both the 50/50 and 90/10 winter peak demand forecasts. The
2009/2010 winter Reserve Margins of 64 percent and 59 percent are higher than last year’s
margins of 54 percent and 47 percent.

                       Table 3: New England Reserve Margins
                                         Winter 2008/2009   Winter 2009/2010
                                       Reserve Margin and Reserve Margin and
                                            Percent (%)        Percent (%)
     Reference Winter Peak Demand
     (50/50 Forecast)                   12,432 MW (54.0%)  14,219 MW (64.3%)
     Extreme Winter Peak Demand
     (90/10 Forecast)                   11,287 MW (46.7%)  13,469 MW (58.9%)


ISO-NE continuously monitors regional fuel supplies serving the power generation sector. In
addition, ISO-NE attends regional fuels conferences82 which usually include seasonal
assessments of all fuel supply chains serving the northeast U.S./CA corridor. However, because
of the regional fuel mix, ISO-NE primarily focuses on both the liquid fuel and natural gas
sectors. Early communications of potential supply-chain problems ensures timely development
of remedial actions. Situational awareness in real-time is benefitted by increased
communications with the gas control divisions of the regional pipelines.




81
   The 2009/2010 ICR Report is located on the ISO New England web site at: http://www.iso-
ne.com/genrtion_resrcs/reports/nepool_oc_review/index.html.
82
   Includes market and regulatory based fuel supply and delivery assessments, seminars, conferences, briefings and meetings.



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Communication is Key:
During the winter season in New England, regional natural gas pipelines usually run full with
LDC gas supplies targeted to serve the core space heating demands of the residential,
commercial and industrial sectors. These LDC gas supplies typically have superior deliverability
entitlements over those of the gas-fired electric generation sector. After contingency events
within the natural gas sector (i.e. unplanned compressor station outages, regional production
outages, etc.) or when other abnormal conditions exist, natural gas supplies to the electric power
sector may be the first to be temporarily curtailed. It is under these types of situations that ISO-
NE encourages increased coordination and communication with the gas control divisions of both
pipelines and LDCs, to ensure that any gas sector problem is readily known and the resulting
impacts on the electric generation sector can be understood and assessed. Within New England,
enhanced communication between the electric and natural gas sectors contributes to maintaining
system reliability during all seasons.

However, if the aforementioned inter-industry communication fails to provide the advance notice
necessary to develop and implement a remedial action plan, other solutions available to help
mitigate the effects from gas-fired unit outages or reductions may include invocation of special
market rules and/or operating procedures. Appendix H of Market Rule 1- Operations During
Cold Weather Events83 is a market rule that works to optimize the synchronization of electric
market bidding timelines with the regional natural gas nomination deadlines. Appendix H of
Market Rule 1 can also request voluntary fuel switching from dual-fuel units and can trigger
requests for regional electric conservation. In addition, ISO-NE can also invoke Operating
Procedure No. 21, Action During an Energy Emergency,84 (OP 21) which was developed to
mitigate reliability impacts resulting from all types of fuel supply constraints, shortages or other
abnormal system conditions impacting the regional generation sector, during any time of the
year.

Since no major transmission or operational constraints that would significantly impact regional
reliability are anticipated during the winter of 2009/2010, and also because New England is a
summer peaking system, ISO-NE has not performed any dynamic or static reactive power studies
for the 2009/2010 winter period.

Subregion Description
ISO New England Inc. is a Regional Transmission Organization (RTO), serving Connecticut,
Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. It is responsible for the
reliable day-to-day operation of New England’s bulk power generation and transmission system,
and also administers the region’s wholesale electricity markets and manages the comprehensive
planning of the regional bulk power system. The New England regional electric power system
serves 14 million people living in a 68,000 square-mile area. New England is a summer-peaking
electric system, which recorded its all-time record electrical peak demand of 28,130 MW on
August 2, 2006.


83
   Appendix H of Market Rule 1 may be found on the ISO New England web site at:
    http://www.iso-ne.com/regulatory/tariff/sect_3/index.html.
84
   OP 21 is located on the ISO New England web site at:
   http://www.iso-ne.com/rules_proceds/operating/isone/op21/index.html.


2009/2010 Winter Reliability Assessment                                                      Page 70
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New York

The New York Balancing Authority 2009 winter peak load forecast is 24,998 MW, which is 295
MW lower than the forecast of 25,293 MW for the 2008 Winter and 325 MW more than the
24,673 MW 2008 actual winter peak. This forecast load is 0.98 percent lower than the all-time
winter peak load of 25,541 MW that occurred on December 20, 2004. The 2009 forecast is
lower due to the impact of the current economic recession on electric energy consumption. The
existing, Certain Capacity in the New York Control Area (NYCA) for the upcoming winter
operating period is 37,823 MW. 511 MW of Certain Capacity has been added since winter ‘08-
‘09. There is 46 MW of capacity expected to be added during this period and is largely due to
several new wind farms and a Hydro plant rerating. An 890 MW Fuel Oil and Natural Gas
Generating station is scheduled to retire in February 2010. The Prospective Capacity Resource
Reserve Margin is 54.3 percent. This exceeds the 16.5 percent annual Reserve Margin set by the
New York State Reliability Council.

Since the previous winter, stations splitting the Willis – Plattsburg 230kV circuits have been
added, as well as stations splitting the Stolle Rd – Meyer 230kV circuit. These additions have
been added to connect new wind farms. Two 120 MVar capacitor banks have been added to
Millwood 345. A Variable Frequency Transformer with three 100 MW channels connecting
between PJM and New York City is expected to be in-service before the time frame of this
assessment.

There is no single outstanding challenge aside from the typical challenges in operating the Bulk
Power System. There are no special assessments or studies performed through the assessment
timeframe that are detailed in our Regional Assessment.

Demand
The 2009 winter forecast assumes normal weather conditions for both energy use and peak
demand. The economic outlook is derived from the New York forecast provided to the NYISO
by Moody's Economy.com. Econometric models are used to obtain energy forecasts for each of
the eleven zones in New York. A winter load factor is used to derive the winter peak from the
annual energy forecast.

The New York Balancing Authority 2009 winter peak load forecast is 24,998 MW, which is 295
MW lower than the forecast of 25,293 MW for the 2008 winter and 325 MW more than the
24,673 MW 2008 actual winter peak. This forecast load is 0.98 percent lower than the all-time
winter peak load of 25,541 MW that occurred on December 20, 2004. The 2009 forecast is
lower due to the impact of the current economic recession on electric energy consumption.

Peak load forecasts are provided by Consolidated Edison for its service territory, and by the
Long Island Power Authority for Long Island. Con-Ed's service territory includes New York
City and nearby Westchester, and is contained within the NYISO Zones H, I and J. The LIPA
service territory is contained within the NYISO Zone K. Con-Ed and LIPA provide the NYISO
with both coincident and non-coincident peak demands. The NYISO aggregates the utility
forecasts with the remaining zones A through G that comprise the New York Control Area.




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 NEW YORK CONTROL AREA LOAD ZONES

                                                          D
                                                                           A - WEST
                                                                           B - GENESSE
                                                                           C - CENTRAL
                                          E                                D - NORTH
                            B                                              E – MHK VL
                                                      F                    F - CAPITL
                                                                           G – HUD VL
                                                                           H - MILLWD
                                C                                          I - DUNWOD
              A
                                                                           J – N.Y.C.
                                                                           K - LONGIL
                    B                                 G
                                                                 H

                                                  I
                                                                       K
                                                          J

The daily peak demand observed by New York during the Winter Operating Period occurs in the
late afternoon to early evening. For daily forecasting purposes, the NYISO uses a weather index
that relates dry bulb air temperature and wind speed to the load response in the determination of
the forecast. At the peak load conditions, a one-degree decrease in this index will result in
approximately 100 MW of additional load. The expected temperature at which the New York
load could reach the forecast peak is 12.9 °F (-11 °C).

The NYISO has two Demand Response programs: the Emergency Demand Response Program
(EDRP) and ICAP Special Case Resources (SCR) program. Both programs can be deployed in
energy shortage situations to maintain the reliability of the bulk power grid.

The Emergency Demand Response Program is designed to reduce power use through the
voluntary shutting down of businesses and large power users. Companies, mostly industrial and
commercial, sign up to take part in the EDRP. The companies are paid by the NYISO for
reducing energy consumption when asked to do so by the NYISO.

Special Case Resources is a program designed to reduce power use through the shutting down of
businesses and large power users. Companies, mostly industrial and commercial, sign up to
become SCRs. The companies must, as part of their agreement, curtail power use, usually by
shutting down when asked by the NYISO. In exchange, they are paid in advance for agreeing to
cut power use upon request.




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The NYISO's Day-Ahead Demand Response Program (DADRP) allows energy users to bid their
load reductions, into the Day-Ahead energy market as generators do. Offers determined to be
economic are paid at the market clearing price. DADRP allows flexible loads to effectively
increase the amount of supply in the market and moderate prices.

SCR participants represent 1,954 MW and DRP participants represent 219 MW. Combined, this
can reduce the peak demand of 24,998 MW by 8.7 percent. All SCR and EDRP program
participants submit hourly interval data to the NYISO so that actual performance indexes may be
calculated. The NYISO files reports to the FERC on a period basis regarding the performance of
these programs.

The Public Service Commission of New York (NYPSC) issued an order in June 2008 that
directed state organizations to begin implementation of its Energy Efficiency Portfolio Standard
(EEPS), whose goal is to reduce the projected energy consumption in the year 2015 by 15
percent of forecasted demand levels (approximately 27,500 GWh). The estimated reduction in
peak demand, if the full impact of these programs were achieved, would reduce summer peak
demand by about 5,600 MW. The full impact for winter peak demand would total about 2,800
MW.

The NYPSC made provisions for the funding of measurement and verification of the EEPS. The
NYISO is a member of the Evaluation Advisory Group, which provides input to the Public
Service Commission on methods and standards used to verify the level of savings the EEPS
achieves in practice. The New York State Energy Research and Development Agency
(NYSERDA) also implements state-funded energy efficiency programs as authorized by the
Public Service Commission. NYSERDA publishes annual reports on the measurement and
verification of the programs it implements.

The NYISO conducts a load forecast uncertainty analysis based on the combined effects of both
weather and the economy. This analysis is conducted for annual energy, summer peak demand
and winter peak demand. The results of this analysis are used to make projections of upper and
lower bounds of each of these forecasts. The upper bounds are at the 90th percentile and the
lower bounds at the 10th percentile.

Generation
For 2009 the New York Balancing Area expects 40,935 MW of existing capacity. Capacity
classified as “Existing-Certain” total 37,823 MW. Of that, 452 MW is from wind generation and
333 MW is from biomass generation. Based on historical performance, a 7.6 percent de-rate
factor is applied for the majority of generators. This includes biomass, but excludes wind. For
wind generation the NYISO de-rates all wind generators to 30 percent of rated capacity, a 70
percent de-rate factor, in the winter operating period.

Hydro conditions are anticipated to be sufficient to meet the expected demand this winter. The
New York area is not experiencing continued effects of a drought or any conditions that would
create capacity reductions. Reservoir levels are expected to be normal for the upcoming winter.
NYISO is not experiencing or expecting conditions that would reduce capacity. An 890 MW fuel




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oil and natural gas generating station is scheduled to retire in February 2010, however this is not
expected to cause any reliability issues due to sufficient capacity in the local area.

Capacity Transactions on Peak
The NYISO projects net imports into the New York Balancing Authority area of 85 MW. Due to
NYISO market rules the specific projected sales and purchases are considered confidential non-
public information and cannot be explicitly indicated in this report.

Capacity purchases are not required to have accompanying firm transmission but adequate
transmission rights must be available to assure delivery to New York when scheduled. External
capacity is also subject to external availability rights. Availability on the import interface is
available on a first-come first-serve basis. The total capacity purchased for this winter operating
period may increase since there remains both time and external rights availability.

Due to NYISO market rules, information on specific import and export transactions is considered
confidential. Information on the aggregated or net expected capacity imports and exports during
peak summer conditions is not yet known. Capacity is traded in the NYISO market as a monthly
product, and total imports and exports are not finalized until shortly before the month begins.
NYISO does not rely on external resources for emergency assistance.

Transmission
Two substations have been added on the Willis – Plattsburg 230kV circuits for connecting wind
farms, and three substations around Stolle Rd – Meyer 230kV also for wind farm connections. A
Variable Frequency Transformer has been added between PJM and New York City consisting of
three 100 MW channels. Any delays in meeting in-service dates for new transmission facilities
would not be expected to impact reliability.

The forced outage to the 230 kV circuit BP76 on the Ontario-New York interconnection at
Niagara continues to reduce the total Ontario-New York import and export capability until its
scheduled return to service in the third quarter of 2010. The Millwood 345 kV 240 MVar
capacitor bank was added in summer 2009 for added voltage support in the lower Hudson
Valley. The NYISO does not have any transmission constraints that could significantly impact
reliability. New York Balancing Authority area import capability is summarized in the table
below. These values are derived by joint studies with adjoining Regions and recognize
transmission and generation constraints.
                      New York Table 1: 2009/2010 Winter Transfer
                                      Capability
                Import Area                                   Transfer Capability
                PJM                                                      2,500 MW
                Linden VFT                                                 300 MW
                Neptune Cable                                              660 MW
                Québec                                                   1,500 MW
                Cedars-Dennison                                            200 MW
                New England                                              2,100 MW
                Cross Sound Cable                                          340 MW
                1385 Cable                                                 100 MW
                Ontario                                                  1,900 MW



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The NYISO participates in the seasonal and future ERAG RFC-NPCC inter-regional assessment
studies.

Operational Issues
There have been no significant special operating studies performed. NYISO has put in a protocol
with ISO New England to manage a Phase Angle Regulator controlled tie line as a means to
integrate wind resources. NYISO does not have any reliability concerns resulting from minimum
demand and over generation due to variable resources. Wind is integrated into the security
constrained dispatch (SCD). As a result, wind can be curtailed to address transmission
constraints based on their shift factors and economic offers. Through November 1, 2009 the
System Operators will call the Transmission Owner (TO) to request wind to back down if
needed. After this date, it is expected that wind resources be able to receive basepoints from the
TO and financial penalties will be assessed for non-response. Because wind is managed through
SCD the need for special operating procedures has been limited. There have not been any
operating issues associated with wind generation.

The NYISO does not expect any reliability concerns resulting from its’ Demand Response
Program.

The Regional Greenhouse Gas Initiative (RGGI) became effective January 1, 2009. The
program is an agreement among ten northeast states designed to reduce the emissions of carbon
dioxide from power plants greater than 25 MW. The RGGI program caps carbon dioxide
emissions at existing levels initially, and then, beginning in 2015, requires a 2.5 percent
reduction per year through 2018. The RGGI system is administered through the use of permits
known as allowances. One allowance is required for each ton of CO2 that has been emitted by
an affected facility. RGGI established an annual emissions cap for each of the member states that
approximates recent emission patterns. The allowances are mostly distributed through a series of
auctions.

Program compliance is measured over a three year period with the first compliance period
running between 2009 through 2011. If the market price of allowances increases above
threshold prices then the compliance period is extended one more year. If the new RGGI
Allowance market operates as set forth by the modeling conducted by the State, bulk power
system reliability is not expected to be negatively impacted in the near term. If a gas pipeline
failure were to cause dual fueled plants to convert to oil resulting in increase emissions of carbon
dioxide and allowances were not available to cover the increased emissions, then some states
have provided for the suspension of the RGGI program. New York State Department of
Environmental Conservation administers the program in New York. The NYSDEC
Commissioner has stated in the rule making process, that in such a situation, he would act to
maintain electric system reliability.

Furthermore, there are no anticipated unusual operating conditions that could significantly
impact reliability for the upcoming winter.




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Reliability Assessment Analysis
The Prospective Capacity Resource Reserve Margin is 54.3 percent.. This exceeds the 16.5
percent annual Reserve Margin set by the New York State Reliability Council.

NYISO complies with NPCC and NYSRC resource adequacy criteria of no more than one
occurrence of loss of load per ten years due to a resource deficiency, as measured by 0.10
days/year LOLE. The assumptions take into account demand uncertainty, scheduled outages and
deratings, forced outages and deratings, assistance over interconnections with neighboring
control areas, NYS Transmission System emergency transfer capability, and capacity and/or load
relief from available operating procedures.

The NYSRC establishes the IRM85 based on a technical study conducted by the NYISO and the
Installed Capacity Subcommittee (of the NYSRC). This study find the required amount of
installed capacity needed to meet the 0.1 days/year LOLE criterion. Following this study, the
NYISO conducts the Locational installed Capacity Requirements (LCR) study86. This study
determines the amount of Unforced Capacity (UCAP) that load serving entities must procure to
reliably meet demand in New York’s high load Areas.

NYISO has the New York State Gas-Electric Coordination Protocol as Appendix BB 87in the
Open Access Transmission Tariff (OATT). This Coordination Protocol applies to circumstances
in which the NYISO has determined (for the bulk power system) or a Transmission Owner has
determined (for the local power system) that the loss of a Generator due to a Gas System Event
would likely lead to the loss of firm electric load. This Coordination Protocol also applies to
communications following the declaration of an Operational Flow Order or an Emergency
Energy Alert. There are no anticipated fuel delivery problems for this winter operating period.

Dynamic and static reactive power studies are performed based on anticipation of issues. No
reactive power issues are anticipated for this winter.

Subregion Description
NYISO is the only Balancing Authority in the New York Control Area. The NYCA is over 48,000
sq miles serving a total population of about 18.5 million people and peaks annually in the
summer.




85
   NYSRC Report titled New York Control Area Installed Capacity Requirements for the Period May 2009 Through April 2010
   (December 5, 2008).
86
   NYISO Report titled “LOCATIONAL MINIMUM INSTALLED CAPACITY REQUIREMENTS STUDY COVERING THE
   NEW YORK CONTROL AREA For the 2008 – 2009 Capability, February 28, 2009.
87
   New York State Gas-Electric Coordination Protocol, Attachment BB of the NYISO Open Access Tariff (OATT), September
   30, 2008. 



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Ontario

Demand
Ontario’s forecast winter peak demand is 22,848 MW based on Monthly Normal weather and
taking into consideration the impacts of planned conservation, growth in embedded generation
and the economic retrenchment. The forecast peak for winter 2009/2010 is 0.6 percent lower
than the 22,983 MW actual peak demand for this past winter, which occurred on January 15,
2009. Also, the 2009/2010 winter forecast is 0.2 percent lower than last winter’s weather-
corrected peak demand of 22,901 MW. Last winter, the relatively high forecasted peak of
23,710 MW had not yet captured the impact of the economic recession. The current forecast’s
declining peak is the result of reductions due to economic forecast and conservation initiatives
offsetting the demand growth from an increasing building stock. Despite a growth in the number
of customers – i.e. building stock – overall demand will decrease, as savings from existing
customers will be greater than the increase due to the growth in new customers.

Ontario demand is the aggregation of generator injections (and net exports). Since there is no
market or sectoral segmentation of load the forecast is generated at the aggregated level.
However, it is recognized that the demand is made up of these various sectors. As such, these
are model drivers that would represent different market segments. Households are used as a
driver for residential demand. Employment is used as a d river for the commercial sector and
manufacturing employment is used as a driver for the industrial sector.

The Ontario Power Authority (OPA) is responsible for promoting conservation and demand
management within Ontario. The OPA provides the IESO with projected conservation based on
their programs. Validation and verification of these savings are the purview of the OPA. A
sizeable number of loads within the province bid their load into the market and are responsive to
price and to dispatch instructions. Other loads have been contracted by the OPA to provide
Demand Response under tight supply conditions. The forecast amount of these demand
measures has been steadily increasing and now amounts to approximately 1,441 MW in total of
which 1,027 MW is included for seasonal capacity planning purposes, with 593 MW of the
included amount categorized as interruptible.

The IESO quantifies the uncertainty in peak demand due to weather variation through the use of
Load Forecast Uncertainty (LFU), which represents the impact on demand of one standard
deviation in the underlying weather parameters. For the upcoming winter peak of 22,848 MW,
the LFU is 581 MW. Economic factors do not have a significant impact in seasonal assessments.

Since Ontario is a large geographic area, the IESO uses six weather stations to capture the
weather variability across the province. Although the analysis is driven from the system’s
perspective the individual zones reflect their weather and economic diversity. The IESO
addresses winter extreme weather conditions by using the most severe weather experienced since
1970 for each time period of the analysis.

Generation
The total capacity of existing installed generation resources (35,370 MW) and loads as a capacity
resource (823 MW) connected to the IESO controlled grid is 36,193 MW, of which the amount


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of ‘Certain’ capacity is 28,118 MW for December 2009. The remainder, 8,075 MW, is ‘Other’
capacity for December 2009 which includes the on-peak resource deratings, planned outages,
and transmission-limited resources. The certain capacities for January and February are
30,659 MW, and 28,446 MW respectively.

East Windsor Cogeneration project with an on-peak value of 84 MW is scheduled to come into
service before December 2009. By January peak, it is expected that the natural gas fired Fort
Frances Cogeneration plant (105 MW) will be converted to biomass to produce 47 MW and an
additional 204 MW of demand measures will be added.

Capacity contribution from wind for winter months, December, January and February, is
assumed at 31 percent of the installed capacity. Wind capacity contribution values (percent of
installed capacity) are determined by picking the lower value between the actual historic median
wind generator contribution and the simulated 10 year wind historic median value at the top 5
demand hours of the day for each month. No other variable resources (solar etc) are connected
to the IESO controlled grid or are expected to be connected between now and February 2010.
For wind, the ‘Certain’ capacity is 336 MW and ‘Other’ capacity is 748 MW.

For biomass, the ‘Certain’ capacity is 47 MW and ‘Other’ capacity is 28 MW for December
2009. These values are 94 MW and 28 MW for January and February.

IESO resource adequacy assessments include hydroelectric generation capacity contributions
based on median historical values of hydroelectric production plus operating reserve provided
during weekday peak demand hours. The capacity assumptions are updated annually, in the
second quarter of each year. Energy capability is provided by market participants’ forecasts.
The amount of available hydroelectric generation is greatly influenced both by water-flow
conditions on the respective river systems and by the way in which water is used by the
generation owner. Material deviations from median conditions are not anticipated at this time.
In the operating timeframe, water resources are managed by market participants through market
offers to meet the hourly demands of the day. Since most hydro storages are energy limited,
hydroelectric operators identify weekly and daily limitations for near-term planning in advance
of real-time operations.

The province does not anticipate any weather or fuel related constraints that would reduce
generating capacity.

No generators are expected to be retired ahead of or during the upcoming winter.

Capacity Transactions on Peak
In its determination of resource adequacy, the IESO plans for Ontario to meet NPCC criteria
without reliance on external resources to satisfy normal weather peak demands under planned
supply conditions. Day to day, external resources are normally procured on an economic basis
through the IESO-administered markets. No firm exports are projected during peak demand.

For use during daily operation, the IESO has agreements in place with neighbouring jurisdictions
in NPCC, RFC and MRO for emergency imports and reserve sharing.



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Transmission
Since last winter, a new interconnection between Hawthorne transformer station (TS) in Ontario
and Outaouais station in Québec went in service. The new interconnection is designed for an
ultimate capacity of 1,250 MW; however, the import and export capability could be
limited to less than the nominal capacity, depending on level of load and generation in the
Outaouais Region. After the completion of transmission reinforcement work in Québec,
anticipated for May 2010, the interconnection will be able to operate up to its nominal capacity.

The following bulk power system transmission projects are planned before the upcoming winter.

                     Ontario Table 1: New Transmission Facilities
          Description                                    Proposed I/S Date
          Nanticoke TS: new 2x250 Mvar shunt capacitors         2009-Q3
          Middleport TS: new 4x250 Mvar shunt capacitors        2009-Q4
          Buchanan TS: new 200 Mvar shunt capacitors            2009-Q4

The transmission facilities listed in the table above are currently on schedule for their expected
in-service dates. None are critical to the reliability of the bulk system for the winter.

The forced outage to the 230 kV circuit BP76 on the Ontario-New York interconnection at
Niagara continues to reduces the total Ontario-New York import and export capability until its
scheduled return to service in the third quarter of 2010. Phase angle regulators are installed on
three of the four Michigan to Ontario interconnections. One phase angle regulator, on the Keith
to Waterman 230 kV circuit J5D, is in service and regulating. The other two available phase
angle regulators, on circuits L51D and L4D at Lambton TS, are currently bypassed during
normal operations, but are available for use during emergency operations. The fourth phase
angle regulator, on the 230 kV circuit B3N, is scheduled for replacement in 2010. They will
become operational once agreements between the IESO, the Midwest ISO, Hydro One and the
International Transmission Company, are finalized. The operation of the phase angle regulators
will assist in the control of circulating flows. However, Ontario meets all reliability criteria
without dependence on any external resources.

Ontario has many operating limits and instructions that could limit transfers under specific
conditions, but for the forecast conditions including design-criteria contingencies, sufficient
resources and bulk system transfer capability is expected to be available to manage potential
congestion and supply forecast demand.

In the winter, Ontario’s theoretical maximum capability for coincident exports could be up to
5,750 MW and coincident imports up to 6,200 MW. These values represent theoretical levels
that could be achieved only with a substantial reduction in generation dispatch in the West and
Niagara transmission zones. In practice, the generation dispatch required for this high transfer
levels would rarely, if ever materialize. Therefore, at best, due to internal constraints in the
Ontario transmission network, Ontario has an expected coincident import capability of
approximately 4, 600 MW. This amount does not recognize transmission or generation
constraints external to the area.



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No significant substation equipments such as SVC, FACTS devices, etc. were added since the
last winter.

Operational Issues
IESO addresses winter extreme weather conditions by doing planning studies using the most
severe weather experienced since 1970. Studies show that Ontario will have sufficient reserve
over the winter period under extreme weather conditions.

Ontario experienced surplus baseload generation under minimum demand conditions over the
spring and summer months of 2009. However, the risk of surplus baseload generation conditions
is expected to be low over the upcoming winter period.

Intermittent variable generators are not economically dispatched to assist with surplus generation
management; their contracts permit them to inject energy when they chose. They can, however
be curtailed for reliability reasons. Future renewable project contracts are expected to provide
incentives to self-curtail production during minimum demand conditions.

IESO will start a centralized wind forecasting service in 2010 to improve the accuracy of wind
generation forecast. This will assist with the management of wind variability and its influence
on load-generation balance.

Demand measures, currently, comprise only less than 4 percent of total resources and is about
6.3 percent of projected peak demand. It does not pose any significant concern to reliability.
Demand measures are grouped into two categories, price sensitive and voluntary. IESO
considers only price sensitive demand for adequacy assessment purposes and to be dispatched,
they have to bid into the market, like other resources.

There are no unusual operating conditions, environmental, or regulatory restrictions that are
expected to impact reliability for this winter. The Ontario program to reduce emissions from
coal-fired generation is achievable without impacting on reliability.

Reliability Assessment Analysis
The IESO uses a multi-area resource adequacy model, in conjunction with power flow analyses,
to determine the deliverability of resources to load. This process is described in the document,
“Methodology to Perform Long-Term Assessments”.88

The Reserve Margin target used for Ontario is 17.5 percent based on the NPCC criteria.
Planning reserves, determined on the basis of the IESO’s requirements for Ontario self-
sufficiency, are above target levels for all weeks over this period. On average, the projected
Reserve Margins for the upcoming winter are 2.9 percent higher than the projected margin for
the winter of 2008/2009.

Reserve requirements are established in conformance with the NPCC Regional criteria. The
latest study results are published in the 18-Month Outlook.89

88
     http://www.ieso.ca/imoweb/monthsYears/monthsAhead.asp
89
     http://www.ieso.ca/imoweb/pubs/marketReports/18MonthOutlook_2009aug.pdf



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Due to the convergence of the natural gas and electricity sectors, the IESO continues to work
with the Ontario gas transportation industry to identify and address issues. There are
communication protocols in effect between the IESO and the gas pipe lines to manage and share
information under tight supply conditions in either sector (gas or electricity).

The IESO regularly conducts transmission studies that include results of stability, voltage and
thermal and short-circuit analyses in conformance with NPCC criteria. The IESO’s interim
transmission studies in 2008 were conducted to comply with the NERC TPL standards, in
addition to NPCC criteria.

The IESO has market rules and connection requirements that establish minimum dynamic
reactive requirements, and the requirement to operate in voltage control mode for all resources
connected to the IESO-controlled grid. In addition, the IESO’s transmission assessment criteria
includes requirements for absolute voltage ranges, and permissible voltage changes, transient
voltage-dip criteria, steady-state voltage stability and requirements for adequate margin
demonstrated via pre and post-contingency P-V curve analysis. These requirements are applied
in facility planning studies. Seasonal operating limit studies review and confirm the limiting
phenomenon identified in planning studies.

Subregion Description
The province of Ontario covers an area of 1,000,000 square kilometres (415,000 square miles)
with a population of 12 million. The Independent Electricity System Operator (IESO) directs the
operations of the IESO-controlled grid (ICG) and administers the electricity market in Ontario.
The ICG experiences its peak demand during the summer, although winter peaks still remain
strong.




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Québec

Demand
Concerning weather assumptions for the demand forecast, Hydro-Québec Distribution (HQD)
introduced in 2007 a new weather pattern in its load forecast which is based on the average
climatic conditions observed from 1971 to 2006 (36 years) adjusted for a global warming effect
of 0.30°C per decade starting in 1971. Climatic uncertainty is modeled by recreating each hour
of this 36-year period under the current load forecast conditions. Moreover, each year of historic
data is shifted up to ± 3 days to gain information on conditions that occurred during either a
weekend or a weekday. Such an exercise generates a set of 252 different demand scenarios. The
base case scenario is the arithmetical average of those 252 scenarios. Given the global
uncertainty, and assuming a normal distribution, the peak demand standard deviation is 1,690
MW for the 2009/2010 Winter Operating Period.

The latest forecast – based on economic, demographic and energy-use assumptions – will be
made public in the next HQD 2008-2017 Procurement Plan Progress Report to be filed with the
Régie de l’énergie du Québec (Québec Energy Board) in November 2009. The 2009 Progress
Report will be available on the Québec Energy Board website in early November.

HQD is the only Load Serving Entity in the Québec Balancing Authority Area. Thus, there is no
demand aggregating in the forecasts.

The observed peak internal demand for the 2008/2009 winter was 37,230 MW reached on
January 16th, 2009 at 8h00 EST. This is a new all-time record for demand in Québec. Internal
demand was approximately 850 MW higher than the forecast. This is due to a short but sharp
cold spell, culminating on January 16th. Montréal temperature at the time of peak was -26°C (-
11°F) and wind speed was about 11 km/hour (7 mph). The rest of the 2008/2009 winter
experienced close to normal temperatures and internal demand values were close to projected
values.

The internal demand forecast for the 2009/2010 winter is 36,116 MW. This forecast is about 300
MW less than last year’s winter forecast. This decline in electrical demand is driven mainly by
the industrial sector, especially from pulp and paper and from smelting and refining industrial
loads. The Québec area is still affected by the general economic slowdown observed in the
United States and Canada.

There are two interruptible load programs in Québec totalling 1,250 MW. Each program
addresses different industrial customers. Moreover, the area can rely on 250 MW of direct
control load management in the form of voltage reduction. Therefore, for the Winter Operating
Period Québec relies on a total of 1,500 MW of Demand Response programs. This represents
4.2 percent of the internal demand forecast. These interruptible load programs have existed for
quite a number of years and each time customers were called to curtail their loads, response was
very good. Industrial customers participating in these programs are bound by contract to interrupt
their load when required by the System Controller. Customers may thus be required to interrupt
load up to 20 times per winter period totalling 100 hours. Operating instructions addressing the
interruptible load programs are reviewed every year to make sure that the communication


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flowchart between TransÉnergie and the customers are updated (Customer name, address, phone
number, personnel to be contacted, etc.). Follow-up of the interruptible load programs is done
by compiling differences between the customers’ real consumption and an anticipated hourly
load profile of customers at the time the program is scheduled to be in effect.

Concerning current and projected energy efficiency programs, on a yearly basis Hydro-Québec
Distribution presents its Energy Efficiency Plan Update (Plan global en efficacité énergétique –
PGEÉ) to the Québec Energy Board for the next and upcoming years. The capacity contribution
of the different programs implemented by Hydro-Québec in the last few years is estimated to be
about 1,910 MW at peak. Of this amount, the PGEÉ program contributes about 570 MW.

The PGEÉ focuses on energy conservation measures and includes programs tailored to
residential customers, commercial and institutional markets, small and medium industrial
customers, and large-power customers.90

The programs and tools for promoting energy savings are the following:

                For residential customers
                         Energy Wise home diagnostic
                         Recyc-Frigo (old refrigerator recycling)
                         Electronic thermostats
                         Energy Star qualified appliances
                         Lighting
                         Pool-filter timers
                         Energy Star windows and patio doors
                         Rénoclimat renovating grant
                         Geothermal energy

                For business customers – small and medium power users
                         Empower program for buildings optimization
                         Empower program for industrial systems
                         Efficient products program
                         Traffic light optimization program
                         Energy Wise diagnostic

                For business customers – large power users
                         Building initiatives program
                         Industrial analysis and demonstration program
                         Plant retrofit program
                         Industrial initiatives program

In addition to these energy saving programs, a “dual energy” program has been ongoing for some
years in Québec. Recently, the number of interested customers has increased. Program
subscribers are fitted with automatic devices that switch from electrical energy to fuel as a
heating source when outdoor temperature is -12°C or lower. According to the most recent
90
     http://www.hydroquebec.com/energywise/index.html



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program evaluations the peak load for next winter would be 840 MW higher without this
program.

Since the Québec Balancing Authority Area is winter peaking winter conditions are obviously
explicitly addressed in assessing variability in projected demand. For the next winter, the overall
uncertainty (one standard deviation) represents ± 1,690 MW around the peak forecast. Climatic
uncertainty accounts for 1,530 MW (one standard deviation) of this global uncertainty.

Generation
To increase the visibility and transparency of supply-side resource options being considered in
the Québec Balancing Authority Area the following information concerning capacity resources is
supplied in this assessment.

            Existing-Certain Resources:                   39,830 MW
            Existing-Other Resources:                      1,844 MW
            Exiting Inoperable Resources:                    547 MW

The vast majority of capacity resources in the Québec Area are hydro-electric resources. The
variable resources in the area are wind resources. Nameplate capacity is 642 MW. Of this, 195
MW is under contract with Hydro-Québec Production (HQP) and is de-rated by 100 percent for
this report (as in earlier reports) since studies are still ongoing to assess the de-rate factor for
HQP.

The rest, 447 MW, is under contract with HQD and results from the so-called “first call for
tenders” which, when construction ends, will result in approximately 990 MW of wind capacity
for HQD. In previous assessments, the entire wind capacity on the system was de-rated by 100
percent. Little capacity existed on the system and little diversity was observed. Longer term
observation and a larger overall wind capacity in the last year have now prompted HQD to
review the de-rating factor for 2009/2010. Simulations have now shown that a 70 percent de-rate
factor can be safely applied to HQD wind capacity.

A small amount of the capacity in Québec is generated by biomass. This is approximately
180 MW.

No new resources are expected to be placed in-service through this assessment’s timeframe.

Hydro conditions for this upcoming Winter Operating Period are such that reservoir levels are
higher than average. Reservoir levels are sufficient to meet both peak demand and the daily
energy demand throughout the winter. To assess its energy reliability Hydro-Québec has
developed an energy criterion stating that sufficient resources should be available to go through
sequences of 2 or 4 consecutive years of low water inflows totalling 64 TWh and 98 TWh
respectively and having a 2 percent probability of occurrence. Reliability assessments based on
this criterion are presented three times a year to the Québec Energy Board.91


91
     Available in French at this web address:
     http://www.regie-energie.qc.ca/audiences/Suivis/Suivi_HQD_CriteresFiabilite_D-2008-133.html



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Fuel supply and transportation is not an issue in Québec, as oil generation is used for peaking
purpose only and adequate supplies are stored nearby. No other conditions that would create
capacity reductions are expected for the 2009/2010 winter period.

Finally, as was mentioned in previous assessments, the 547-MW natural gas unit operated by
TransCanada Energy at Bécancour has been mothballed for the last two years. On July 2, 2009,
HQD and TCE again filed a contract modification with the Québec Energy Board to renew the
temporary shutdown for 2010 with possible renewals for future years. Deliveries could resume
on January 1, 2011, depending on the evolution of the demand forecast.

One 150-MW fossil fuel generation unit will be out of service this winter. Resource adequacy
and reliability are not affected by these outages. Hydro unit availability is expected to be almost
100 percent.

Capacity Transactions on Peak
Concerning capacity transactions, the Québec Balancing Authority Area does not need external
purchases to ensure resource adequacy for the 2009/2010 Winter Operating Period. However,
HQP has a firm purchase of 200 MW from the Maritimes Area during this period. This is backed
by a firm contract for generation and by a firm reservation on a Maritimes - Hydro-Québec
interconnection path. This transaction adds 200 MW to the Québec Reserve Margin but does not
affect the Regional Reserve Margin.

On the other hand, the Québec Area has firm contracts for total exports of 705 MW to New
England (310 MW), Ontario (145 MW) and New-Brunswick (250 MW). Again, firm generation
and transmission have been secured for these transactions. Moreover, expected sales of
1,050 MW in December, 350 MW in January and 650 MW in February are projected to other
Areas and are under negotiation. The Québec Balancing Authority Area’s Reserve Margin is
higher than the required reserve to meet its resource adequacy criterion. These firm and
expected sales do reduce Reserve Margins but they still remain higher than the required target.

Finally, for the next Winter Operating Period, it is not expected that the Québec Balancing
Authority Area will need external resources for reliability purposes.

Transmission
On July 2, 2009, TransÉnergie commissioned the first HVdc converter of the new Outaouais
substation and its interconnection with IESO in the Ottawa-Gatineau area across the Ottawa
River. The interconnection consists of two 625-MW back-to-back HVdc converters in Québec
and a double-circuit 240 kV line to Hawthorne substation in Ottawa. On the Québec side of the
converters a 315 kV switchyard integrates the interconnection into the existing system. Chénier
735/315 kV substation, north of Montréal is the source station feeding this interconnection.

The second converter is scheduled for commissioning in November 2009 and both converters
will be available for the 2009/2010 Winter Operating Period.

A double-circuit 315 kV line from Chénier feeds the interconnection. These circuits also feed
local load and integrate local generation so that full interconnection capability will not be



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available at all times. Winter capability during peak periods is expected to be 810 MW in the
export mode and 1020 MW in the import mode.

In summer 2010, a fourth 1,650 MVA 735/315 kV transformer will be added at Chénier along
with a new double-circuit 315 kV line from Chénier to Outaouais. This will then permit full use
of the 1,250-MW interconnection capability.

In the meantime, the commissioning of the second converter of the Outaouais Interconnection
should follow the proposed schedule.

As was mentioned earlier, the Québec Balancing Authority Area is winter peaking. Thus no
significant transmission line maintenance is done during the Winter Operating Period and no
transmission line is expected to be out of service during that period.

No internal transmission constraints that could significantly impact reliability are expected in the
Québec Balancing Authority Area. In Québec, transmission and generation maintenance is done
during the summer period. However, no maintenance is scheduled that will impact
interconnection transfer capability to other subregions during peak periods.

Synchronous condenser CS23 at Duvernay substation in the Montréal area, which became
unavailable in June 2008 due to a major transformer fault may not be back in service for the
2009/2010 Winter Operating Period. The Duvernay Synchronous Condenser outage causes 100
to 400 MW of restrictions on three 735 kV interfaces on the system. The normal transfer
capability on these interfaces is usually well over 10,000 MW so that this is not expected to
significantly impact transmission reliability for the 2009/2010 Winter Operating Period.

One phase of transformer T8 at Micoua 735/315 kV substation failed on September 12, 2008 and
is being replaced. This transformer station is situated in the Manicouagan sub-system and
integrates generation from the Manicouagan, Toulnustouc and Outardes river systems
(Approximately 5,000 MW). Presently, the delivery date for the new phase is November 22,
2009 for an in-service date of January 31, 2010.

It was also mentioned in the Winter 2008/2009 Assessment that Carignan 735/230 kV substation
East of Montréal had one of its two transformers on forced outage. This transformer was returned
to service March 27, 2009. The substation will be operated with both transformers for the
2009/2010 Winter Operating Period.

Finally, it was mentioned in the 2009 Summer Assessment that on March 8, 2009, one of the two
back-to-back 500-MW HVdc converters at Châteauguay substation, south of Montréal, had
tripped out with multiple thyristor failure. The converter was back in service on June 21, 2009.
The interconnection with the New York Balancing Authority Area is scheduled to be in service
throughout the 2009/2010 Winter Operating Period.

The following table indicates the interregional transfer capabilities out and into Québec with its
neighbor systems for the 2009/2010 Winter Operating Period.92 These limits represent Normal
92
     Limits obtained and updated from the NPCC Reliability Assessment for Winter 2008/2009.



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Transfer Capability values for the Winter Operating Period. Actual Feasible Transfer Capability
(FTC) values during peak periods in Québec may be lower. For example, the limit into Québec
from New England (Sandy Pond) at the Québec peak is zero because the interconnection is
required for internal Québec transmission needs.

Both NTC and FTC values are shown in the NPCC Seasonal Reliability Assessments.

                     Québec Table 1: 2009/2010 Winter Interconnection
                               Normal Transfer Capability (MW)
       Interconnection                      Limit out of Québec Limit into Québec
       Ontario North (D4Z, H4Z)                      85                110
       Ontario Ottawa (X2Y, P33C, Q4C)              410                140
       Ontario Brookfield (D5A, H9A)                250                200
       Ontario Beauharnois (B5D, B31L)              800                470
       Ontario Ottawa (Outaouais                   1,250              1,250
       Interconnection)
       New York (CD11, CD22)                                               325                     100
       New York (7040)                                                   1,500                    1,000
       New England (Highgate)                                              220                     170
       New England (Stanstead-Derby)                                        50                      0
       New England (Sandy Pond)                                          2,000                    1,700
       New Brunswick (Madawaska + Eel                                 985 to 101793                770
       River)

These limits recognize transmission or generation constraints in both Québec and its neighbors.
They are reviewed periodically with neighboring systems and are posted in the NPCC Reliability
Assessments.

Finally, since the last winter season, no significant substation equipment such as SVCs, FACTS
controllers and HVdc systems have been added in the Québec Balancing Authority Area except
the HVdc and associated equipment that was commissioned at the Outaouais interconnection
substation in July 2009.

Operational Issues
In its review of resource adequacy for the NPCC, HQD includes a high load forecast scenario.
The economic, demographic and energy parameters used for the study are set higher relative to
the base case scenario. The load uncertainty then becomes dependent on weather conditions
only. If the criterion (0.1 day/year of LOLE) is not met, actions to restore reliability are
identified and established (new calls for tenders, new interruptible load contracts or an in service
date for new generation units sooner than expected).


93
     Transfer capability is dependant on New Brunswick radial load.



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Moreover, TransÉnergie continually performs load flow and stability studies to assess system
reliability and transfer capabilities on all its internal interfaces. A peak load study is performed
annually integrating new generation, new transmission and the latest demand forecasts as well as
any unusual operating conditions such as generation and transmission outages. Extreme cold
weather conditions result in a large load pickup over the normal weather forecast and are
included in TransÉnergie’s Transmission Design Criteria. When designing the system, both
steady state and stability assessments are made with winter scenarios involving demands
4,000 MW higher than the normal weather peak demand forecast. This is equivalent to 110
percent of peak winter demand.

The Québec Balancing Authority Area also participates in the seasonal CO-12 and CP-8 NPCC
Working Group assessments of system reliability.

A recent planning study has shown a transfer increase of about 700 MW across the Southern
interface of the TransÉnergie system over the last few years. This is due to a steady load increase
in the southern part of the system combined with a steady load decrease in the northern part of
the system. This change impacts system performance beginning in 2012.

Moreover, during Winter Operating Periods, TransÉnergie has to cope with voltage variations
due to stiff load rises during cold spells coupled with positive ramping at the interconnections.
To reduce the number of Automatic Shunt Reactor Disconnecting System (French acronym:
MAIS) operations ─ MAIS is designed to operate following extreme contingencies to restore
735 kV system voltages ─ a new operating tool to control capacitor bank switching in the
Montréal area was implemented. Also, the assessment of system performance concerning voltage
variations led to the implementation of a new design criterion to specifically address this
problem.

This has led ─ along with the previously mentioned planning study ─ TransÉnergie to bring
forth a project to upgrade its transmission system by 2012. The upgrade consists mainly of series
compensation additions at Jacques-Cartier 735 kV substation, the addition of two SVCs at
Chénier 735 kV substation, other 735 kV series compensation upgrades and 735 kV line
protection modifications. This project has been filed with the Régie de l’énergie du Québec
(Québec Energy board) on April 8, 2009 and approved by the Régie on August 25, 2009.
The upgrades to the system for 2012 have also been presented and studied in the last NPCC
Comprehensive Review Assessment of the Québec Transmission System for 2012 approved by
the NPCC Reliability Coordinating Committee on May 28, 2008.
No other particular operational problems have been observed for the oncoming 2009/2010
Winter Operating Period.

To date, the Québec Balancing Authority Area has no special operating procedures resulting
from integration of variable resources in Québec.

Moreover, the Area does not anticipate any reliability concerns resulting from minimum demand
and over generation resulting from variable resources for the 2009/2010 Winter Operating
Period. In Québec, minimum demand periods occur during the Summer Operating Period. A
certain amount of hydro generation at run of the river installations must be generated along with



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more and more wind generation being integrated on the system ─ which may be contributing if
the right conditions occur ─ so that such conditions may occur on the longer term during
summer. Most of the generation in the Area is hydro with large medium or large size reservoirs
and can be modulated to follow load variations.

No reliability concerns resulting from high levels of Demand Response resources are anticipated.
In the Québec Balancing Authority Area Demand Response resources are uniquely under the
form of interruptible load programs. Contracts with large high voltage industrial customers and
smaller industrial loads permit precise use of Demand Response resources as needed according
to system needs at specific times and intervals during the Winter Operating Period.
There are no environmental and/or regulatory restrictions that could impact reliability in Québec
for the 2009/2010 Winter Operating Period.

No other unusual operating conditions that could significantly impact reliability for the
upcoming winter are anticipated in Québec.

Reliability Assessment Analysis
The Québec Area reliability criterion complies with the NPCC Resource Adequacy Criterion
which uses Loss of Load Expectation (LOLE) of 0.1 day per year as its resource adequacy
criterion. Last year’s report indicated that for the 2009/2010 winter peak period, Québec
required a reserve of 10.4 percent (Reserve Margin over Net Internal Demand). On a less than
one year horizon the required reserve is inferior to 10 percent. In this assessment, the 11 percent
projected reserve is sufficient to cover the 10 percent target required reserve.94

The assessment of short term reliability for the 2009/2010 winter peak period is now in progress.
Preliminary results indicate that the required reserve should be smaller than 10 percent. Final
results of the study will be filed with NPCC in November within the framework of the 2009
Québec Interim Report on Resource Adequacy.

Concerning the adequacy of fuel supplies it was mentioned earlier that the Québec Area fossil
fuel generation stations are used for peaking purposes only. The energy contribution of these
generating stations is minimal. All have adequate fuel reserves as part of their installations and
all are fueled at the beginning of the Winter Operating Period.

Voltage support in the southern part of the system (load area) is a concern during the Winter
Operating Period especially during episodes of heavy load. Hydro-Québec Production (the
largest producer on the system) ensures that maintenance on generators is be finished by
December 1, and that all possible generation is available. This, along with yearly testing of
reactive capability of the generators, ensures maximum availability of both active and reactive
power. The end of TransÉnergie maintenance on the high voltage transmission system is also
targeted for December 1. Also, TransÉnergie has a target for the availability of both high
voltage and low voltage capacitor banks. No more than 200 Mvar of high voltage banks on a
total capacity of approximately 9,000 Mvar should be unavailable during the Winter Operating


94
     The 2008 Quebec Comprehensive Review of Resource Adequacy can be found at the following internet address:
     http://www.npcc.org/documents/reviews/Resource.aspx



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Period. The target for the low voltage banks is 90 percent availability based on installed capacity
in the load area of the system (About 5,500 Mvar).

As mentioned above, voltage variations on the high voltage transmission system are also of some
concern. These are normal variations due to changes in transmitted power from North to South
during load pickup and interconnection ramping. Under peak load conditions, these variations
may be large enough to trigger the Automatic Shunt Reactor Switching System and must be
contained. In 2008 TransÉnergie had recommended and undertaken a number of actions to
optimize shunt reactor switching such as:
      New software (CTRM) for the Montréal Area voltage control at the Control Center
      Enhancement of reactive power control at Châteauguay Converters
      Optimization of DC interconnection power ramping as a function of system conditions
      Study of dynamic shunt compensation additions in the Montréal Area for the 2011-2012
       horizon
This study and others have led, as mentioned, to transmission upgrade projects filed with the
Régie de l’énergie du Québec in April 2009.

Subregion Description
The Québec Balancing Authority Area is winter peaking. The all-time internal peak demand was
37,230 MW set on January 16, 2009. The summer peak demands are in the order of 21,000 MW.
The installed capacity in 2009 is 42,370 MW of which 39,000 MW (92 percent) is hydroelectric
capacity. The transmission voltages on the system are 735, 315, 230, 161 and 120 kV.
Transmission line length totals about 33,058 km (20,540 miles). The Québec Balancing
Authority Area is a separate Interconnection from the Eastern Interconnection into which other
NPCC Areas are interconnected. TransÉnergie ─ the Transmission Owner and Operator in
Québec ─ has interconnections with Ontario, New York, New England and the Maritimes.
Interconnections consist of either HVdc ties or radial generation or load to and from the
neighboring systems.

The population served is around 7 million and the Québec Area covers about 1,668,000 square
km (644,300 square miles). Most of the population is grouped along the St-Lawrence River axis
and the largest load area is in the Southwest part of the province, mainly around the Greater
Montréal area, extending down to the Québec City area.




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Region Description
The Northeast Power Coordinating Council, Inc. (NPCC Inc.) is the international Regional
Reliability Organization (RRO) for Northeastern North America. Its purpose is to promote the
reliable and efficient operation of the international, interconnected bulk power systems in
Northeastern North America through the establishment of Regionally-specific criteria,
coordination of system planning, design and operations, assessment of reliability and monitoring
and enforcement of compliance with such criteria, and other applicable criteria. In the
development of reliability criteria, NPCC Inc., to the extent possible, facilitates attainment of
fair, effective and efficient competitive electric markets. NPCC Inc. is a not-for-profit New York
corporation. The geographic area covered includes New York, the six New England states, and
Ontario, Québec, and Maritime Provinces in Canada. The total population served is
approximately 56 million over approximately 1 million square miles.

NPCC was originally formed shortly after the 1965 Northeast Blackout to promote the reliability
and efficiency of the interconnected power systems within its geographic area. NPCC
restructured in response to U.S. energy legislation signed into law August, 2005, in preparation
for the certification of an Electric Reliability Organization (ERO) and subsequent execution of a
Regional Delegation Agreement and Memorandums of Understanding with appropriate
Canadian Provincial regulatory and governmental authorities. Membership interests were
transferred to NPCC Inc., and a separate and independent, affiliated, not-for-profit corporation,
NPCC: Cross-Border Regional Entity, Inc. (NPCC CBRE). NPCC CBRE will perform functions
delegated or contracted to it from the ERO, to be backstopped by the Federal Energy Regulatory
Commission (FERC) and Canadian Provincial authorities. Additional information can be found
on the NPCC Web site (http://www.npcc.org/).




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RF C
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand        MW                  On-Peak Capacity by Fuel Type
Total Internal Demand                       145,800                                          Dual
  Direct Control Load Management                600                              Gas
                                                                                             Fuel
  Contractually Interruptible (Curtailable)   4,300                  Nuclear     20%
                                                                                              8%
  Critical Peak-Pricing with Control              0                   15%                       Other
  Load as a Capacity Resource                     0                                               2%
Net Internal Demand                         140,900
                                                                                                  Oil
                                                                          Coal
                                                                                                  8%
2008/2009 Winter Comparison                    MW    % Change             47%
                                                                                           Pumped
2008/2009 Winter Projected Peak Demand       143,123    -1.6%
2008/2009 Winter Actual Peak Demand          146,139    -3.6%                              Storage
All-Time Winter Peak Demand                  150,640    -6.5%                                2%


2009/2010 Winter Projected Peak Capacity MW              Margin
Existing Certain and Net Firm Transactions 215,800       53.2%
Deliverable Capacity Resources             215,800       53.2%
Prospective Capacity Resources             217,200       54.2%
NERC Reference Margin Level                   -          15.0%




All ReliabilityFirst Corporation (RFC) members are affiliated with either the Midwest ISO or
the PJM Interconnection (PJM) Regional Transmission Organization (RTO) for market
operations and reliability coordination. Ohio Valley Electric Corporation (OVEC), a generation
and transmission company located in Indiana, Kentucky and Ohio, is not with a member of either
RTO and is not affiliated with their markets; however, PJM performs OVEC’s Reliability
Coordinator services. Also, RFC does not have officially designated subregions. The Midwest
ISO and PJM each operate as a single Balancing Authority area. Since all RFC demand is in
either Midwest ISO or PJM except for a small load (less than 100 MW) within the OVEC
Balancing Authority area, the reliability of the PJM RTO and Midwest ISO are assessed and the
results used to indicate the reliability of the RFC Region.

This assessment provides information on the projected resource adequacy for the upcoming
winter season across the RFC Region. The RFC Resource Adequacy Assessment Standard BAL-
502-RFC-02, requires Planning Coordinators to identify the minimum planning reserves to
maintain resource adequacy for their respective areas of RFC. PJM and Midwest ISO are the
Planning Coordinators for their market areas. The reserve requirements in this assessment are
based upon the explicit probability analyses conducted by these two Planning Coordinators in
RFC. In this report, Demand Response (DR) is defined as the demand that can be interrupted for
system emergencies. This report will divide the RFC Region into the areas operated by PJM and
Midwest ISO. The remaining area of PJM operates within the SERC Region, and the remaining
area of Midwest ISO operates in the MRO or SERC Regions. Demand, capacity and interchange
values in this report are rounded to the nearest 100 MW.



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PJM RTO

Demand
Total Internal Demand (TID) represents the total forecast electric system demand. The forecast is
developed by PJM staff for each of its load zones, and aggregated as the PJM coincident peak
demand. This demand forecast is based on an expected or “50/50” weather forecast. This 50/50
demand forecast uses a winter temperature profile on the peak day at the 50th percentile for cold
weather. This means that there is a 50 percent probability that the temperature on the peak day
would be warmer and 50 percent probability that the temperature would be colder. The winter
demand forecast is from data provided earlier this year. Since the forecast is dated January 2009,
and is based on economic data from late 2008, the demand forecast may not reflect the full
impact of the current economic recession

Energy Efficiency (EE) programs included within the PJM load forecast are programs that have
committed through the PJM Reliability Pricing Model (RPM). No EE programs have been
committed as an RPM resource for this winter. Information on PJM’s measurement and
verification protocols for EE programs are available on PJM’s website95.

Demand Response in this assessment only includes demand that can be interrupted for system
emergencies. PJM currently has two categories of DR, Direct Control and Interruptible. Since
Direct Control is used to reduce air-conditioning demand, there is no Direct Control DR during
the winter for PJM. The 2009/2010 winter Interruptible Demand is 3,300 MW. This is 700 MW
lower than the 2008/2009 interruptible demand of 4,000 MW. The total demand reduction for
DR is the maximum controlled demand mitigation that is expected to be available during peak
demand conditions.

Since DR is a contractual management of system demand, use of DR reduces the Reserve
Margin requirement for the RTO. Net internal demand is TID less DR. Reserve margin
requirements are based on Net Internal Demand.

The Net Internal Demand peak of the entire PJM RTO for the 2009/2010 winter season is
projected to be 109,500 MW and to occur during January 2010. This value is based on the TID
forecast of 112,800 MW with the full use of the 3,300 MW (2.9 percent of TID) of Demand
Response programs (see Table RFC-1).

              TABLE RFC - 1: PJM RTO PROJECTED PEAK DEMANDS (MW)1 WINTER 2009/2010


                                                           DECEMBER             JANUARY          FEBRUARY

        TOTAL INTERNAL DEMAND                                    109,400           112,800               108,700
        Direct Control Load Management                                  0                 0                     0
        Interruptible Demand                                      (3,300)           (3,300)               (3,300)
        NET INTERNAL DEMAND                                      106,100           109,500               105,400

        [1]
              - All demand totals are rounded to the nearest 100 MW.

95
     PJM Energy Efficiency protocols: http://www.pjm.com/documents/~/media/documents/manuals/m18b.ashx



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Comparing this forecast of TID to the winter 2008/2009 metered peak demand of 117,169 MW,
the 2009/2010 forecast is 4,369 MW (3.7 percent) lower than the actual 2008/2009 winter peak
demand. In addition, the 2008 forecast of 2009/2010 winter peak demand was 116,408 MW,
making this year’s winter peak demand forecast 3,608 MW (3.1 percent) lower than last year’s
forecast for the winter 2009/2010 peak demand.

Although the demand forecasts used in this assessment were collected in recent months, some of
these forecasts were prepared months earlier. Both weather and economic conditions have
significant influence on electrical peak demands. Any deviation from the original forecast
assumptions for those parameters could cause the aggregate 2009/2010 winter peak to be
significantly different from the forecast.

For the winter of 2009/2010, a high demand forecast was prepared by PJM staff. This 90/10 TID
forecast uses a winter temperature profile on the peak day at the 90th percentile for (extreme)
cold weather. This means that there is a 90 percent probability that the temperature on the peak
day would be warmer and 10 percent probability that the temperature on the peak day would be
colder. The PJM RTO is forecast to have a coincident 90/10 demand of 119,600 MW, a 6.0
percent increase over the 50/50 demand forecast. The impact of this demand sensitivity is
included within the Reliability Assessment Analysis section of this assessment.

Generation
There are two general categories used when analyzing seasonal capacity resources. “Existing”
capacity represents resources that have been built and are in commercial service. “Future”
capacity represents planned resources that are under construction, have an interconnection
service agreement and are expected to be in commercial service at the start of the planning
period.

The generating capacity on Table RFC-2 represents the capacity of the generation within the
PJM RTO market area. The capacity category of Existing-Certain represents existing resources
within PJM and committed to the market. The PJM RTO has 166,200 MW of capacity (143,600
MW within RFC) for this winter that is identified as Existing-Certain in this assessment.




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                   TABLE RFC - 2: PJM RTO PROJECTED CAPACITY
                       RESOURCES (MW) WINTER 2009/2010
                Capacity as of June 1, 2009
                EXISTING CAPACITY                                          168,000

                 Inoperable (Scheduled Maintenance)                              0
                 Energy Only Resources (including variable gen)            (1,800)
                 Uncommitted Resources                                           0
                 Transmission Limited Resources                                  0
                OTHER EXISTING CAPACITY                                    (1,800)
                EXISTING CERTAIN CAPACITY                                  166,200

                CAPACITY TRANSACTIONS - IMPORTS
                 Purchases                                                     500
                 Owned Capability outside the RTO                            3,200
                                                                             3,700

                CAPACITY TRANSACTIONS - EXPORTS
                 Sales                                                       (500)
                 Owner Capability outside the RTO                          (1,900)
                                                                           (2,400)
                 Net Interchange                                             1,300

                 Net Capacity Resources                                    167,500


The Existing-Other category includes the existing resources that represent expected on-peak
wind/variable resource deratings, and other existing capacity resources within the RTO market
that can participate in the PJM market as energy-only generation. There is up to 1,800 MW of
these types of capacity resources. Since these resources are not in the RPM market, the
deliverability of this generation at the time of the peak is uncertain. Therefore, in this assessment,
none of this capacity is included in the PJM Reserve Margins.

Only capacity additions that are in service prior to the planning year, which starts in June, are
included in determining the winter Reserve Margins. Any Planned, Future capacity additions
expected to go in-service during the winter period would not be included within the Reserve
Margin calculations. There are no Planned, Future capacity additions included in this winter
assessment.

The total nameplate amount of variable generation in PJM is about 1,300 MW. This is nearly all
wind power (with only 3 MW of solar), with the amount of available on-peak variable generation
capability included in the reserve calculations at about 200 MW. PJM uses a three-year average
of actual wind capability during the summer daily peak periods as the expected on-peak wind
capability rating. Until three years of operating data is available for a specific wind project, 13


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percent of nameplate capability is assigned for each missing year of data for that project. The
difference between the nameplate rating and the expected on-peak wind capability rating is
accounted for in the Existing-Other category.

There is also 700 MW of biomass (renewable) resources included in the PJM Reserve Margins.

Each generator operator is expected to coordinate with the fuel industry regarding fuel supplies
and deliveries. The PJM market rules are designed to encourage generator owners and operators
to maintain adequate fuel supplies. PJM does not communicate directly with the fuel industry on
supply adequacy or potential problems, however as an RTO, PJM does receive operational
notices from the gas pipeline operators.

There are no known or expected conditions or situations regarding fuel supply or delivery,
hydro-electric reservoirs, adverse weather, generator availability, or capacity retirement that are
anticipated to adversely impact system reliability during the 2009/2010 winter.

Capacity Transactions on Peak
Only specific transactions identified by PJM as interchange with firm transmission reservations
are included in the Reserve Margin calculations. Some of the total interchange reported by PJM
is due to jointly-owned generation. These resources are located in one RTO but have owners in
both RTOs with entitlements to that generation. In addition, some of the interchange into PJM
comes from OVEC entitlements.

Firm power transfers into PJM are projected to be 3,700 MW. Firm power transfers out are
projected to be 2,400 MW. Net interchange is therefore a 1,300 MW power import flowing into
the PJM RTO. All these imports and exports are firm and fully backed by firm transmission and
firm generation. There are no Liquidated Damages Contracts included in these firm capacity
transfers.

The emergency operating benefit from being interconnected within the Eastern Interconnection
is reflected in the determination of PJM’s RTO Reserve Margin requirement. PJM does not rely
on emergency imports to meet its Reserve Margin requirement.


Reliability Assessment Analysis
This resource assessment relies on the Reserve Margin requirements determined by PJM to
satisfy the RFC Loss of Load Expectation (LOLE) criterion of not exceeding 0.1 day per year.
The LOLE analysis conducted by PJM includes demand forecast uncertainty, generator outage
schedules, and other relevant factors when determining the probability of forced outages
exceeding the available margin for contingencies. Study criteria used in the evaluation can be
found in the PJM Planning Manual M-20, “PJM Resource Adequacy Analysis”.96 The PJM
Resource Adequacy Planning study can be found on the PJM website.97


96
     PJM study criteria: http://www.pjm.com/documents/~/media/documents/manuals/m20.ashx
97
     PJM Resource Adequacy study: http://www.pjm.com/planning/resource-adequacy-planning/reserve-requirement-dev-
     process.aspx



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It is important to note that the capacity resources identified as Existing-Certain in this assessment
have been “pre-certified” by PJM for use within their RTO market area. This means that these
resources were determined to satisfy the deliverability requirements and are considered to be
fully deliverable within the PJM RTO. Other existing resources may be available to serve load,
but since they have not been pre-certified as deliverable, or are not in the PJM capacity market,
they are not included within the Reserve Margin calculations.

In Table RFC-3, the projected reserves during the 2009/2010 winter peak are 58,000 MW for the
PJM RTO, which is 8,900 MW higher than the 49,100 MW of reserves last winter. This is a 53.0
percent Reserve Margin (NID) compared with a 44.4 percent Reserve Margin in the winter of
2008/2009. Since the PJM reserve requirement is based upon the summer peak demand, the total
required capacity is 150,300 MW. The PJM net capacity resources are 167,500 MW, which are
17,200 MW greater than the requirement. Therefore, the PJM RTO has adequate reserves to
serve the 2009/2010 winter peak demand.

          TABLE RFC - 3: PJM RTO PROJECTED RESERVE MARGINS WINTER 2009/2010

                                                 DECEMBER         JANUARY         FEBRUARY

      NET INTERNAL DEMAND (MW)                        106,100         109,500          105,400

      NET CAPACITY RESOURCES (MW)                     167,500         167,500          167,500

      NID RESERVE MARGINS
       -- MW                                            61,400         58,000           62,100
       -- percent of NID                                57.9%          53.0%            58.9%

      PJM Reserve Requirement
       -- Summer NID (MW)                                             130,700
       -- Total MW Resources                                          150,300
       -- percent of Summer NID                                        15.0%




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Midwest ISO

Demand
Total Internal Demand represents the total forecast electric system demand. The forecast is
developed by Midwest ISO Load Serving Entities (LSEs), aggregated to Midwest ISO Local
Balancing Authorities (LBAs), and finally aggregated by Midwest ISO as the coincident peak
demand. This demand forecast is based on an expected or “50/50” demand forecast. This means
that there is a 50 percent probability the demand on the peak day would be expected to be lower
than forecast and a 50 percent probability the peak day demand would be expected to be higher
than what was forecast. The winter demand forecast is from data provided earlier this year. Since
the forecast is based on economic data from late 2008 and early 2009 the demand forecast may
not reflect the full impact of the current economic recession

Energy Efficiency (EE) programs have not been explicitly included in the Midwest ISO load
forecast for the 2009/2010 winter. At this time, Midwest ISO’s measurement and verification
protocols for energy efficiency programs are under development.

Demand Response (DR) in this assessment only includes demand that can be interrupted for
system emergencies. Midwest ISO currently has two categories of DR, Direct Control and
Interruptible. The amount of Direct Control that is expected in the winter is 600 MW. The winter
Interruptible Demand is 1,800 MW. The total demand reduction for DR is the maximum
controlled demand mitigation that is expected to be available during peak demand conditions,
which totals 2,400 MW.

Since DR is a contractual management of system demand, use of DR reduces the Reserve
Margin requirement for the RTO. Net internal demand is TID less DR. Reserve margin
requirements are based on Net Internal Demand.

The net internal peak demand of the entire Midwest ISO RTO for the 2009/2010 winter season is
projected to be 79,500 MW and to occur during January 2010. This value is based on the TID
forecast prepared by Midwest ISO staff from member demand forecasts of 81,900 MW with the
full use of the 2,400 MW (2.9 percent of TID) of Demand Response programs (see Table RFC-
4).

    TABLE RFC - 4: MIDWEST ISO PROJECTED PEAK DEMANDS (MW)1 WINTER 2009/2010


                                                        DECEMBER            JANUARY        FEBRUARY

    TOTAL INTERNAL DEMAND                                     81,700             81,900          79,000
    Direct Control Load Management                              (600)             (600)           (600)
    Interruptible Demand                                      (1,800)           (1,800)         (1,800)
    NET INTERNAL DEMAND                                       79,300             79,500          76,600

    [1]
          - All demand totals are rounded to the nearest 100 MW.




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The 2009/2010 forecast NID is 4,544 MW less than the actual winter 2008/2009 peak demand of
84,044 MW. The 2009/2010 forecast TID is 2,144 MW (2.6 percent) lower than the actual
2008/2009 winter peak demand. In addition, the 2008 forecast of 2009/2010 winter peak demand
is 83,300 MW, making this year’s winter TID forecast 1,400 MW (1.7 percent) lower than last
year’s winter TID forecast.

Although the demand forecasts used in this assessment were collected in recent months, some of
these forecasts were prepared months earlier. Both weather and economic conditions have
significant influence on electrical peak demands. Any deviation from the original forecast
assumptions for those parameters could cause the aggregate 2009/2010 winter peak to be
significantly different from the forecast.

A high demand forecast was calculated by Midwest ISO, based upon a statistical analysis of the
participant’s 50/50 TID forecast and historical demand data. This is a 90/10 TID forecast for the
winter of 2009/2010. This means that there is a 90 percent probability the demand on the peak
day would be expected to be lower than forecast and a 10 percent probability on the peak day
that demand would be expected to be higher. The Midwest ISO RTO is forecast to have a
coincident 90/10 demand of 86,000 MW, a 5.0 percent increase over the 50/50 demand forecast.
The impact of this demand sensitivity is included within the Reliability Assessment Analysis
section of this assessment.


Generation
There are two general categories used when analyzing seasonal capacity resources. “Existing”
capacity represents resources that have been built and are in commercial service. “Future”
capacity represents planned resources that are under construction, have an interconnection
service agreement and are expected to be in commercial service at the start of the planning
period.

The generating capacity on Table RFC-5 represents the capability of the generation in the
Midwest ISO RTO market area. The capacity category of Existing-Certain represents existing
resources committed to the Midwest ISO market. The Midwest ISO RTO has 117,400 MW of
capacity (69,800 MW within RFC) for this winter that is identified as Existing-Certain in this
assessment.




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                       TABLE RFC - 5: Midwest ISO PROJECTED
                     CAPACITY RESOURCES (MW) WINTER 2009/2010


                 Capacity as of June 1, 2009
                 EXISTING CAPACITY                                             129,700

                     Inoperable (Scheduled Maintenance)                         (1,900)
                     Energy Only Resources (including variable gen)             (5,900)
                     Uncommitted Resources                                      (4,500)
                     Transmission Limited Resources                                   0
                 OTHER EXISTING CAPACITY                                       (12,300)
                 EXISTING CERTAIN CAPACITY                                     117,400

                 CAPACITY TRANSACTIONS - IMPORTS
                                                                                          1
                     Purchases                                                   4,300
                     Owned Capability outside the RTO                                0
                                                                                 4,300

                 CAPACITY TRANSACTIONS - EXPORTS
                                                                                          2
                 Sales                                                                0
                                                                                          2
                 Owner Capability outside the RTO                                     0
                                                                                      0
                     Net Interchange                                             4,300

                     Net Capacity Resources                                    121,700

                 1
                   - Midwest ISO reports only the power imports committed to the market
                     area
                 2
                   - This information is not available; exported power comes from
                     uncommitted resources in the Midwest ISO market area



The Existing-Other category includes the existing resources that represent expected on-peak
wind/variable resource deratings, and other existing capacity resources connected to Midwest
ISO member’s transmission systems but are not committed to participating in the Midwest ISO
market. There is up to 12,300 MW of these types of capacity resources. Since these resources are
not in the Midwest ISO market, none of this capacity is included in the Midwest ISO Reserve
Margins.

Only capacity additions that are in service prior to the planning year, which starts in June, are
included in determining the winter Reserve Margins. Any “Future-Planned” capacity additions
expected to go in-service during the winter period would not be included in the Reserve Margin
calculations. There are no Future-Planned capacity additions included in this winter assessment.



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The total nameplate amount of variable generation in Midwest ISO is about 6,600 MW. This is
all wind power, with the amount of available on-peak wind capability included in the reserve
calculations at about 1,400 MW. In Midwest ISO, wind power providers may declare up to 20
percent of their nameplate capability as a capacity resource. The difference between the
nameplate rating and the expected on-peak wind capability rating is accounted for in the
Existing-Other category.

There is also 200 MW of biomass (renewable) resources included in the Midwest ISO Reserve
Margins.

Each generator operator is expected to coordinate with the fuel industry regarding fuel supplies
and deliveries. Midwest ISO market rules encourage generator owners and operators to maintain
adequate fuel supplies. Midwest ISO does not communicate directly with the fuel industry on
supply adequacy or potential problems, however as an RTO, Midwest ISO does receive
operational notices from the gas pipeline operators.

There are no known or expected conditions or situations regarding fuel supply or delivery,
hydroelectric reservoirs, adverse weather, generator availability, or capacity retirement that are
anticipated to adversely impact system reliability during the 2009/2010 winter.

Capacity Transactions on Peak
Midwest ISO reports only firm capacity imports to the Midwest ISO market. Export capacity
comes from resources not in the Midwest ISO market, therefore there are no reported Midwest
ISO exports. Some of the total interchange reported by Midwest ISO is due to jointly-owned
generation. These resources are located in one RTO but have owners in both RTOs with
entitlements to the generation. Also, some of the interchange into Midwest ISO comes from
OVEC entitlements. There are no Liquidated Damages Contracts included in these firm power
transfers.

All these imports are fully backed by firm transmission and firm generation; therefore, they are
included in the Reserve Margin calculations. The reported net import capacity into Midwest ISO
is 4,300 MW.

The emergency operating benefit from being interconnected within the Eastern Interconnection
is reflected in the determination of Midwest ISO’s Reserve Margin requirement. Midwest ISO
does not rely on emergency imports to meet its Reserve Margin requirement.


Reliability Assessment Analysis
This resource assessment relies on the Reserve Margin requirements determined by Midwest ISO
to satisfy the RFC Loss of Load Expectation (LOLE) criterion of not exceeding 0.1 day per year.
The LOLE analysis conducted by Midwest ISO includes demand forecast uncertainty, generator
outage schedules, and other relevant factors when determining the probability of forced outages
exceeding the available margin for contingencies. The study criteria can be found in the Midwest




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ISO Business Practice Manual (BPM 11).98 The Midwest ISO Planning study can be found on
the Midwest ISO website.99

It is important to note that the capacity resources identified as Existing-Certain in this assessment
have been “pre-certified” by Midwest ISO for use within their RTO market area. This means that
these resources were determined to satisfy the deliverability requirements and are considered
fully deliverable within the Midwest ISO. Other existing resources may be connected to Midwest
ISO member’s transmission systems, but since they have not been certified as deliverable, or are
not in the Midwest ISO market, they are not included within the Reserve Margin calculations.

In Table RFC-6, the projected reserves during the 2009/2010 winter peak are 42,200 MW for
the Midwest ISO RTO, which is 6,400 MW higher than the 35,800 MW of reserves last winter.
This is a 53.1 percent Reserve Margin (NID) compared with a 46.5 percent Reserve Margin in
the winter of 2008/2009. The Midwest ISO reserve requirement is 15.4 percent of the monthly
peak demand; therefore, the Midwest ISO RTO has adequate reserves to serve the 2009/2010
winter peak demand.


             TABLE RFC – 6: Midwest ISO PROJECTED RESERVE MARGINS WINTER
                                         2009/2010

                                                         DECEMBER             JANUARY           FEBRUARY

        NET INTERNAL DEMAND (MW)                                 79,300            79,500               76,600

        NET CAPACITY RESOURCES (MW)                            121,700            121,700              121,700

        NID RESERVE MARGINS
         -- MW                                                   42,400            42,200               45,100
         -- percent of NID                                       53.5%             53.1%                58.9%

        Midwest ISO Reserve Requirement
         -- MW                                                                     12,200
         -- percent of NID                                                         15.4%




98
     Midwest ISO study criteria: http://www.midwestiso.org/publish/Document/20f443_ffd16ced4b_-7e630a3207d2?rev=15
99
     Midwest ISO Resource Adequacy study: http://www.midwestiso.org/publish/Document/62c6cd_120e7409639_-7f2a0a48324a



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ReliabilityFirst Corporation

Demand
In this assessment, the data related to the RFC areas of PJM (RFC-PJM) and Midwest ISO
(RFC-MISO) are combined with the data from OVEC to develop the RFC Regional data. The
demand forecasts used in this assessment are all based on the coincident peak demand of
Midwest ISO’s local balancing authorities and the coincident peak of PJM’s load zones. Both
PJM and Midwest ISO demand forecasts are based on an expected or 50/50 demand forecast.
Actual data from the past three years indicates minimal diversity (less than 100 MW) between
the RTO coincident peak demands and the RFC coincident peak demands. For this assessment,
no additional diversity is included for the RFC Region; therefore, the RFC coincident peak
demand is simply the sum of the PJM, Midwest ISO and OVEC peak demands (rounded to
nearest 100 MW). The composite RFC Region forecast is considered a 50/50 demand forecast.

Neither PJM nor Midwest ISO has identified any demand reduction to the winter demand
forecast explicitly due to Energy Efficiency (EE) programs. However, the two categories of
Demand Response, Direct Control and Interruptible, are expected to provide for a combined
potential Demand Response reduction of 4,900 MW within the RFC Region. The Direct Control
during the winter is 600 MW and the winter Interruptible Demand is 4,300 MW. The total
demand reduction for DR is the maximum controlled demand mitigation that is expected to be
available during peak demand conditions.

Since DR is a contractual management of system demand, use of DR reduces the Reserve
Margin requirement for the RTO. Net internal demand is TID less DR. Reserve margin
requirements are based on Net Internal Demand.

The Net Internal Demand peak of the RFC Region for the 2009/2010 winter season is 140,900
MW and is projected to occur during January 2010. This value is based on a TID forecast of
145,800 MW, with the full reduction of 4,900 MW (3.4 percent of TID) from the Demand
Response programs within the Region (see Table RFC-7).




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            TABLE RFC – 7: RFC PROJECTED PEAK DEMANDS (MW)1 WINTER
                                    2009/2010

                                                   DECEMBER             JANUARY        FEBRUARY

      RFC - PJM Area
      TOTAL INTERNAL DEMAND                                94,300            96,600           93,100
      Direct Control Load Management                            0                 0                0
      Interruptible Demand                                (3,200)           (3,200)          (3,200)
      NET INTERNAL DEMAND                                  91,100            93,400           89,900

      RFC - MISO Area
      TOTAL INTERNAL DEMAND                                49,100            49,100           47,500
      Direct Control Load Management                        (600)             (600)            (600)
      Interruptible Demand                                (1,100)           (1,100)          (1,100)
      NET INTERNAL DEMAND                                  47,400            47,400           45,800

      RFC Totals [2]
      TOTAL INTERNAL DEMAND                              143,500           145,800          140,700
      Direct Control Load Management                        (600)             (600)            (600)
      Interruptible Demand                                (4,300)           (4,300)          (4,300)
      NET INTERNAL DEMAND                                138,600           140,900          135,800


      [1]
            - All demand totals are rounded to the nearest 100 MW.
      [2]
            - The RFC Regional demand includes OVEC with the PJM and Midwest ISO areas of RFC.

Compared to the actual winter 2008/2009 peak demand of 146,039 MW, the 2009/2010 forecast
TID is 239 MW (0.2 percent) lower than the actual 2008/2009 winter peak demand. In addition,
the 2008 forecast of 2009/2010 winter peak demand was 149,100 MW, making this year’s winter
peak demand forecast 3,300MW (2.2 percent) lower than last year’s 2009/2010 winter peak
demand forecast.

Weather and economic conditions have significant influence on electrical peak demands. Any
deviation from the original forecast assumptions for those parameters could cause the aggregate
2009/2010 winter peak to be significantly different from the forecast.

For the winter of 2009/2010, the high demand forecasts for PJM and Midwest ISO were
combined with the OVEC demand to create a high demand forecast for the RFC Region. The
forecast high demand is 154,100 MW, a 5.7 percent increase over the 50/50 demand forecast.
The impact of this demand sensitivity is included within the Reliability Assessment Analysis
section of this assessment.




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Generation
There are two general categories used when analyzing seasonal capacity resources. Existing
capacity represents resources that have been built and are in commercial service. Future capacity
represents planned resources that are under construction, have an interconnection service
agreement and are expected to be in commercial service at the start of the planning period.

The generating capacity on Table RFC-8 represents the capacity of the generation in the RFC
Region. The capacity category of Existing-Certain represents existing resources in the RFC areas
of PJM and Midwest ISO and the capability of OVEC generation. The RFC Region has 215,600
MW of capacity for this winter that is identified as Existing-Certain in this assessment.


           TABLE 8; RFC PROJECTED CAPACITY RESOURCES (MW) WINTER
                                  2009/2010

                                                                       RFC - PJM         RFC-MISO               RFC
    Capacity as of June 1, 2009
    EXISTING CAPACITY                                                       145,400           72,500         220,100

         Inoperable (Scheduled Maintenance)                                       0             (800)           (800)
         Energy Only Resources (including variable gen)                     (1,800)             (300)         (2,100)
         Uncommitted Resources                                                    0           (1,600)         (1,600)
         Transmission Limited Resources                                           0                 0               0
    OTHER EXISTING CAPACITY                                                 (1,800)           (2,700)         (4,500)
    EXISTING CERTAIN CAPACITY                                               143,600           69,800         215,600


    CAPACITY TRANSACTIONS - IMPORTS 1
                                                                                                        2
         Purchases                                                              200             1,000          1,200
         Owned Capability outside the RFC Region                                100                 0            100
                                                                                300             1,000          1,300


    CAPACITY TRANSACTIONS - EXPORTS 1
                                                                                                        3
        Sales                                                                 (700)                 0          (700)
                                                                                                        3
        Other Owner Capability transferred outside the RFC Region             (400)                 0          (400)

                                                                            (1,100)                 0         (1,100)
        Net Interchange                                                       (800)             1,000            200
        Net Capacity Resources                                              142,800           70,800         215,800

    1
      - Intra-regional transfers reported by the RTOs (between RTOs and with OVEC) have been removed
    2
      - Midwest ISO reports only the power imports committed to the market area
    3
      - This information is not available; exported power comes from uncommitted resources in the Midwest ISO market
    area




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The Existing-Other category includes the existing resources that represent expected on-peak
wind/variable resource deratings, and other existing capacity resources within the RFC Region
that are not part of the PJM or Midwest ISO markets. There is up to 4,500 MW of these types of
capacity resources. Since these resources are not in the respective PJM and Midwest ISO
markets, none of this capacity is included in the Reserve Margins.

Only capacity additions that are in service prior to the planning year, which starts in June, are
included in determining the winter Reserve Margins. Any Future-Planned capacity additions
expected to go in-service during the winter period would not be included within the Reserve
Margin calculations. There are no Future-Planned capacity additions included in this winter
assessment.

The total nameplate amount of variable generation in RFC is about 1,700 MW. This is nearly all
wind power (with only 3 MW solar), with the amount of available on-peak variable generation
capability included in the reserve calculations at about 300 MW. The difference between the
nameplate rating and the on-peak expected wind capability rating is accounted for in the
Existing-Other category.

There is also 700 MW of biomass (renewable) resources included in the RFC Reserve Margins.

Each generator operator is expected to coordinate with the fuel industry regarding fuel supplies
and deliveries. Although PJM and Midwest ISO do not explicitly communicate with the fuel
industry regarding fuel supply issues, their respective market rules encourage generator owners
and operators to have adequate fuel supplies. RFC does not communicate directly with the fuel
industry on supply adequacy or potential problems; however, RFC does periodically survey its
generator owners and operators about relevant fuel issues. The last survey was in 2008.

There are no known or expected conditions or situations regarding fuel supply or delivery,
hydro-electric reservoirs, adverse weather, generator availability, or capacity retirement that are
anticipated to adversely impact system reliability during the 2009/2010 winter.

Capacity Transactions on Peak
PJM and Midwest ISO have reported expected imports and exports of capacity across their RTO
boundaries at the time of the winter peak demand. Only specific transactions identified as
interchange with firm transmission reservations are included within the Reserve Margin
calculations.

The capacity imports and exports include both contracted transactions as well as member
ownership interest in generation outside the RTO boundary. Since the jointly-owned generation
and OVEC generation is all located in the RFC Region, the jointly-owned and OVEC generation
is included in RFC’s generation and is not included in RFC capacity imports and exports.
Therefore, the firm capacity transactions for the RFC Region are not a simple summation of the
PJM, Midwest ISO and OVEC capacity imports and exports.




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The firm capacity imports for the RFC Region is projected to be 1,300 MW. The firm capacity
exports is projected to be 1,100 MW. At the time of the winter peak, this results in a net 200 MW
capacity import into RFC.
There are no Liquidated Damages Contracts included in these firm power transactions. For both
Midwest ISO and PJM, any firm capacity from outside the Region could be used for emergency
and reserve sharing purposes; however, it is not necessary for PJM or Midwest ISO to rely on
emergency imports to meet its respective Reserve Margin requirement.

Transmission
New transmission additions to the bulk power system, since last winter, that have been placed in-
service include a total of 83 miles of transmission line(s) at 138 kV and above, plus ten
transformers with a total capacity rating of about 6,100 MVA. An additional total of 43 miles of
transmission line(s) at 138 kV and above is expected to be placed in-service by this winter, plus
three transformers with a total capacity rating of about 4,500 MVA. These system changes are
expected to enhance reliability of the bulk power system. The tables below shows the new bulk-
power transmission (line) projects and transformer projects expected to be in-service for the
winter of 2009/2010.

 Transmission Project    Voltage   Length       In-service
                                                                   Description/Status
          Name            (kV)     (Miles)       Date(s)                                   RTO
 North Longview-Fort                                               Completed             PJM
                           500       2.0     May-2009
 Martin
 Pontiac-Cayuga Ridge                                                                    PJM
                           345        10     December-2009
 South-Wilton Center                                               Under Construction
 Cresent-Brunot Island     345       7.1     December-2009         Under Construction    PJM
 Branchburg-Flagtown       230        4      May-2009              Completed             PJM
 Orchard-Churchtown-                                               Under Construction    PJM
                           230        15     December-2009
 Cumberland
 Remer-St. Clair #2        138       2.9     April-2009            Completed             MISO
 Elliott-Scott             138        6      May-2009              Completed             MISO
 Relocate Carlisle                                                 Completed             MISO
                           138       1.5     June-2009
 Substation
 Culley-Oak Grove          138        10     June-2009             Completed             MISO
 Indiana Arsenal                                                   Under Construction    MISO
 Junction-Clark            138       8.5     December-2009
 Maritime Center
 Delta-ZincOx-Waseon       138       0.85    December-2009         Under Construction    MISO
 Albright-Garrett          138        1      May-2009              Completed             PJM
 Cheswick-Plum             138       8.27    June-2009             Completed             PJM
 Oak Hall-Wattsville       138        3      June-2009             Completed             PJM
 Waverly-Don Marquis-                                              Completed             PJM
                           138        13     August-2009
 Lick
 Valley-Legionville        138      14.13    August-2009           Completed             PJM
 Legionville-Koppel                                                Under Construction    PJM
                           138       1.72    December-2009
 Steel-Hopewell




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                                 High-        Low-
          Transformer            Side         Side           In-service
                                                                                Description/Status    RTO
          Project Name          Voltage      Voltage          Date(s)
                                 (kV)         (kV)
        Kammer                    765           500       November-2009        Under Construction    PJM
        Brighton                  500           230       June-2009            Completed             PJM
        Bedington                 500           230       June-2009            Completed             PJM
        Waugh Chapel              500           230       December-2009        Under Construction    PJM
        Pierce                    345           138       May-2009             Completed             MISO
        Hiple                     345           138       May-2009             Completed             MISO
        Tangy                     345           138       June-2009            Completed             MISO
        Avon 92-AV-T              345           138       June-2009            Completed             MISO
        Murphy                    345           138       June-2009            Completed             MISO
        Don Marquis               345           138       November-2009        Under Construction    PJM
        Red Lion                  230           138       May-2009             Completed             PJM
        Roseland                  230           138       June-2009            Completed             PJM
        Cumberland                230           138       July-2009            Completed             PJM

There are no reliability concerns in meeting the in-service dates for the above facilities.

PJM does anticipate that some existing transmission lines will be out-of-service this winter, and
will maintain reliability by re-dispatch, re-configuration, Market-to-Market re-dispatch with
Midwest ISO, and use of the NERC transmission loading relief (TLR) procedure, if necessary.

One new significant transmission facility that has been added to the bulk power system is the
Linden Variable Frequency Transformer (VFT), which is a merchant transmission project that is
an AC tie with 300 MW of transmission transfer capability. This project will connect the Linden
Cogen plant located in New Jersey and within PJM to the Goethals station on Staten Island in the
New York system . The VFT is a transmission technology that provides for a continuously
controllable, variable phase-shift connection to control the direction and magnitude of AC power
flows. The Linden VFT will become a transmission owner within PJM, who will have the
operational authority over the facility. The VFT is expected to have power flowing across it by
November 1, 2009. The VFT will be the first merchant transmission project with multiple parties
holding the entitlements to the new transmission capacity. Developing this unique project
involved numerous technical, economic feasibility, and interconnection studies by the developer,
PJM and the New York ISO (NYISO), which culminated in an auction process to sell the new
transmission rights.100

There are no other significant substation equipment additions, such as SVCs, FACTS devices, or
HVdc, planned to be in-service for the winter of 2009/2010.

Phase Angle Regulators (PARs) are located on all major ties between northeastern PJM and
southeastern New York to help control unscheduled power flows. The Ramapo PARs in NPCC
control power flow from RFC to NPCC. The Michigan-Ontario PARs have not yet achieved
100
      More information on this project can be found at:
      http://www.gepower.com/prod_serv/products/transformers_vft/en/downloads/C1_107_2008.pdf.



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long-term operation for all four units. The B3N PAR in Michigan, that previously failed, will be
replaced by two series 800 MVA PARs sometime in early 2010. An Operating Agreement for
controlling the transmission interface will be completed for use once all four PARs are in-service
and regulating. This delay is not expected to adversely impact system reliability for this winter.

Historically, ReliabilityFirst transmission systems have experienced widely varying power flows
due to various transactions and prevailing weather conditions across the Region. As a result, the
transmission system could become constrained during peak demand periods because of unit
unavailability and unplanned transmission outages, concurrent with large power transactions.
Generation re-dispatch has the potential to mitigate these potential constraints. Notwithstanding
the benefits of this re-dispatch, should transmission constraint conditions occur, local operating
procedures, system re-configuration, as well as the NERC TLR procedure, are all available to
transmission owners/operators to maintain adequate transmission system reliability.

RFC representatives and staff actively participate in all three of the Eastern Interconnection
Reliability Assessment Group (ERAG), interregional seasonal transmission assessment efforts.
However, for the winter of 2009/2010, ERAG decided to perform a long-term summer
assessment in lieu of the normal 2009/2010 winter assessment. In 2010, ERAG plans to perform
its normal winter assessment (for the winter of 2010/2011). RFC also conducts its own winter
transmission transfer capability analyses and assessment.101 Incremental transfer capability
results are included within the separate RFC winter transmission assessment report and are
shown in the table below. Simultaneous import capabilities are projected to be adequate for this
winter. These values do reflect transmission and generation constraints external to RFC.

      Transfer Direction                   Incremental Transfer Capability (MW) for 2009/2010 Winter
      RFC-MISO to PJM                      No limit found at 6,000 MW incremental transfer level
      PJM to RFC-MISO                      No limit found at 6,000 MW incremental transfer level
      SERC East to RFC-MISO                No limit found at 6,000 MW incremental transfer level
      SERC East to PJM                     No limit found at 5,000 MW incremental transfer level
      NPCC to RFC-MISO                     2,800 MW
      NPCC to PJM                          2,800 MW
      MRO to RFC West                      5,200 MW
      SPP to RFC West                      2,300 MW
      SERC West to RFC West                2,600 MW

Operational Issues
PJM performs pre-seasonal summer and winter operational assessments. These assessments are
studied using peak seasonal demand forecasts. At the Regional level, the operational problems
are primarily West-to-East transfers. At the local level, the operational problems are high
loadings on local equipment. PJM has not yet identified any special operating problem from the
integration of variable resources.




101
      http://www.rfirst.org/Reliability/ReliabilityHome.aspx



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PJM does not anticipate any reliability concerns resulting from over-generation by variable
resources at the current level of penetration, nor does it anticipate any reliability concerns from
Demand Response resources at the current level of implementation.
While some generators within the PJM RTO may be temporarily limited due to environmental or
emissions restrictions, PJM does not anticipate that these limitations will impact system
reliability.

The Midwest ISO, as a Reliability Coordinator and Balancing Authority, does not expect any
reliability concerns resulting from variable resources during minimum demand and over-
generation conditions for the 2009/2010 winter assessment period. The Midwest ISO’s Public
Emergency Procedure entitled “Supply Surplus Procedure” (RTO-EOP-003) steps the
Reliability Coordinator and Balancing Authority through the steps necessary to continuously
balance load and generation during these types of conditions, including variable resources as
necessary. 102

No unusual operating conditions are foreseen within RFC that could impact system reliability for
this winter.

Reliability Assessment Analysis
This resource assessment relies on the Reserve Margin requirements determined by PJM and
Midwest ISO to satisfy the RFC Loss of Load Expectation (LOLE) criterion of not exceeding 0.1
day per year. These LOLE analyses are conducted by PJM and Midwest ISO in accordance with
RFC’s “Planning Resource Adequacy Analysis, Assessment and Documentation” Standard,
BAL-502-RFC-02.103

The assessment of PJM and Midwest ISO resource adequacy is therefore based on the results
from these LOLE analyses. It is not meaningful to calculate a specific Reserve Margin
requirement for all of RFC, since each RTO operates as a single Balancing Authority and has
different demand characteristics, capacity resource availabilities and calculated reserve
requirements. However, it follows that when PJM and Midwest ISO have satisfied their
respective reserve requirements, then the RFC Region can be considered to have resource
adequacy.

Since the PJM RTO reserve requirement is based on the summer peak demand, the total required
capacity is 150,300 MW. The PJM net capacity resources are 167,500 MW, which is 17,200
MW greater than the requirement. Therefore, the PJM RTO has adequate reserves for the
2009/2010 winter peak demand.

The projected reserves during the 2009/2010 winter peak demand for the Midwest ISO are
42,200 MW, which is a 53.1 percent Reserve Margin (NID). Since the Midwest ISO reserve
requirement is 15.4 percent of the monthly peak, Midwest ISO has adequate reserves for the
2009/2010 winter peak demand.



102
      http://www.midwestiso.org/publish/Document/24743f_11ad9f8f05b_-7b610a48324a?rev=5
103
      http://www.rfirst.org/Documents/Standards/Approved/BAL-502-RFC-02.pdf



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In Table RFC-9, the calculated Reserve Margin for RFC is 74,900 MW, which is 53.2 percent
based on Net Internal Demand and Net Capacity Resources. This compares to a 49.8 percent
Reserve Margin found within last winter’s assessment. Since PJM and Midwest ISO have
sufficient resources to satisfy their respective Reserve Margin requirements, the RFC Region has
adequate resources for the 2009/2010 winter period.

        TABLE RFC – 9: RFC PROJECTED RESERVE MARGINS WINTER 2009/2010

                                                        DECEMBER             JANUARY          FEBRUARY

     NET INTERNAL DEMAND (MW)                                  138,600          140,900             135,800

     NET CAPACITY RESOURCES (MW)                               215,800          215,800             215,800

     NID RESERVE MARGINS
      -- MW                                                     77,200            74,900             80,000
      -- percent of NID                                         55.7%             53.2%              58.9%

For winter 2009/2010, a high demand forecast was used to prepare a Reserve Margin sensitivity
case across the RFC Region. This high demand forecast was developed by adding the 90/10
demand forecasts of PJM and Midwest ISO to the OVEC demand. This high demand forecast for
the RFC Regional area is being used to evaluate the sensitivity to higher than expected demand.
On Table RFC-10, this high demand forecast amounts to a potential demand increase of about
8,300 MW in January 2010 under this scenario. On a Net Internal Demand basis, the Reserve
Margin would be 66,600 MW or 44.6 percent.

      TABLE RFC – 10: SIMULATED EXTREME DEMAND (MW) WINTER 2009/2010

                                                          TOTAL          TOTAL                TOTAL
                                                           PJM            MISO                 RFC

      EXTREME DEMAND1
      PJM 90/10 TID in RFC2                                                                        102,400
      MISO 90/10 TID in RFC2                                                                        51,600
      TOTAL INTERNAL DEMAND [TID]                            119,600         86,000                154,100

      PJM 90/10 NID in RFC2                                                                         99,200
      MISO 90/10 NID in RFC2                                                                        49,900
      NET INTERNAL DEMAND [NID]                              115,800         83,600                149,200

      NET CAPACITY RESOURCES                                 167,500        121,700                215,800

      NID RESERVE MARGINS
       -- MW                                                  51,700         38,100                 66,600
       -- percent of NID                                      44.6%          45.6%                  44.6%

      [1]
          - The combination of the 90/10 demand forecasts for the PJM and Midwest ISO areas of RFC is
            not a 90/10 forecast for RFC. These values are used to simulate conditions of extreme demand.
      [2]
          - These are the coincident LBA or Load Zone peak demands within the RFC Region.


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This analysis illustrates that higher than expected demand can significantly reduce the Reserve
Margin available (from 53.2 percent to 44.6 percent) to cover potential generator outages.
However, at this level of reserves, it is highly unlikely that additional demand would create any
reliability problems within the RFC Region.

Region Description
RFC currently consists of 47 Regular Members, 22 Associate Members, and 4 Adjunct Members
operating within 3 NERC Balancing Authorities (Midwest ISO, OVEC, and PJM), which
includes over 350 owners, users, and operators of the bulk-power system. They serve the
electrical requirements of more than 72 million people in a 238,000 square-mile area covering
all of the states of Delaware, Indiana, Maryland, Ohio, Pennsylvania, New Jersey, and West
Virginia, plus the District of Columbia; and portions of Illinois, Kentucky, Michigan, Tennessee,
Virginia, and Wisconsin. The RFC area demand is primarily summer peaking. Additional
details are available on the RFC website (http://www.rfirst.org).




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SERC
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand        MW                    On-Peak Capacity by Fuel Type
Total Internal Demand                       179,659
  Direct Control Load Management                646                                     Dual    Oil
                                                                           Gas
  Contractually Interruptible (Curtailable)   4,180                        22%          Fuel    3%
  Critical Peak-Pricing with Control              0                                     16%     Hydro
  Load as a Capacity Resource                   184                  Nuclear                     5%
Net Internal Demand                         174,649                   14%
                                                                                 Coal           Pumped
2008/2009 Winter Comparison                      MW    % Change                  36%            Storage
2008/2009 Winter Projected Peak Demand         177,929    -1.8%
                                                                                                  4%
2008/2009 Winter Actual Peak Demand            186,225    -6.2%
All-Time Winter Peak Demand                    186,446    -6.3%

2009/2010 Winter Projected Peak Capacity MW                Margin
Existing Certain and Net Firm Transactions 248,181         42.1%
Deliverable Capacity Resources             248,680         42.4%
Prospective Capacity Resources             259,037         48.3%
NERC Reference Margin Level                   -            15.0%




SERC is the Regional Entity (RE) for all or portions of 16 central and southeastern states. For
purposes of reporting data and assessing reliability, the utilities within the SERC Region are
assigned to one of five subregions: Central, Delta, Gateway, Southeastern, and VACAR, that
together supply power to more than 20 percent of the electric customers in the United States.
Most electric utilities within SERC operate under some degree of traditional vertical integration
with planning philosophies based on an obligation to serve ensuring that designated generation
operates under optimal economic dispatch to serve local area customers. Some utilities in the
SERC Region however, have selected or have been ordered to adopt a non-traditional operating
structure whereby management of the transmission system operation is provided by a third party
under an Independent Coordinator of Transmission (ICT) contract or a Regional Transmission
Organization (RTO) that manages transmission flows to customers over a broader Regional area
through congestion-based locational marginal pricing. Transmission systems within the SERC
footprint are closely interconnected and the Region has operated with high reliability for many
years.




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Demand
SERC is a summer-peaking Region. The actual 2008/2009 winter peak for the utilities in the
SERC Region was 186,225 MW. The total aggregate internal demand for the 2009/2010 winter
is forecast to be 179,659 MW; this is 3,984 MW (2.2 percent) lower than the forecast 2008/2009
winter Total Internal Demand of 183,643 MW. The actual winter peak demand does not take into
account new energy-efficiency programs, diversity stand-by load or additions for non-member
load, whereas the internal peak demand values account for these factors

This projection is based on average historical winter weather and is the sum of non-coincident
forecast data reported by utilities in the SERC Region. Some entities have lowered their forecasts
due to the economic recession.

Because of the varied nature of energy-efficiency programs, they are separately described in the
subregion portions of this report. A number of utilities in the SERC Region have some form of
efficiency program or Demand-side Management (DSM) efforts in place or under development.
Entities measure and verify their programs in various ways. Some entities use measurement
verification programs to measure energy savings and costs programs. Other entities use third-
party vendors to assess their programs and analyze results. These techniques have been useful to
fine-tune energy-efficiency programs and to determine each program’s cost effectiveness.

Traditional load management and interruptible programs such as air conditioning load control
and large industrial interruptible services are common within the Region. Interruptible demand
and DSM capabilities for 2009/2010 winter are 5,237 MW as compared with the 5,836 MW
reported last winter. This year’s Demand Response is 2.9 percent of the Total Internal Demand
forecast for 2009/2010. Traditional Demand Response programs include monetary incentives to
reduce demand during peak periods. Some examples are real-time pricing programs and
voluntary curtailment riders. The programs are more fully described in each subregion as part of
the more detailed reports below. There are no measurement verification programs implemented
at the SERC Region level.

               SERC Table 1: SERC Demand Response Programs MW
                                           2008/2009        2009/2010
 Program
                                              Winter           Winter
 Direct Control Load Management              428 MW           646 MW
 Contractually Interruptible (Curtailable) 4,943 MW         4,180 MW
 Critical Peak-Pricing (CPP) with Control    215 MW             0 MW
 Load as a Capacity Resource                 127 MW           184 MW
 Energy-Efficiency Programs                  123 MW           227 MW

Ambient temperatures that are higher or lower than normal and the degree to which interruptible
demand and DSM is used, result in actual peak demands that vary from the forecast. The utilities
within the SERC Region perform detailed extreme weather and/or load sensitivity analyses in
their respective operational and planning studies.

While utility methodologies vary, many common attributes exist. Common attributes include:



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   •      Use of econometric linear regression models
   •      Relationship of historical annual peak demands to key variables such as weather, economic
          conditions, and demographics
   •      Variance of forecasts due to high- and low-economic scenarios and mild and severe
          weather
   •      Development of a suite of forecasts to account for the variables mentioned above, and
          associated studies using these forecasts.

In addition, many utilities within the SERC Region use sophisticated, industry-accepted
methodologies to evaluate load sensitivities in the development of load forecasts. Utilities in the
SERC Region adhere to their respective state commissions’ regulations, RTO requirements, and
internal business practices for determining their reserve requirements.

Generation
In aggregate, utilities within the SERC Region expect to have 266,346 MW of resources
including 251,792 MW of Existing-Certain resources, 12,166 MW of Existing-Other resources,
and 2,388 MW of inoperable resources during the winter 2009/2010 period. The utilities within
SERC report 12,100 MW of Existing-Certain variable generation and 850 MW of Existing-Other
variable generation during the winter 2009/2010 period. The utilities in the SERC Region
anticipate a nominal amount of Future-Planned and Future-Other capacity resources during the
assessment period.

Generation facilities are planned and constructed to ensure that aggregate generation capacity
keeps pace with the electric demand and allows for adequate planning (and operating) reserves.
Among the utilities in the SERC Region, generation reserve capacity is sufficient to mitigate
postulated generation and transmission contingencies. Additionally, a number of independent
power generating units are interconnected to the transmission system and selling their output into
the electricity market where such markets exist within the SERC Region.

In the SERC Region there has been significant merchant generation development. A significant
amount of merchant capacity within the Region has been participating in the short-term energy
markets, indicating that a portion of these resources may be deliverable during certain system
conditions.

There are small amounts of Biomass104 generation in the SERC Region totaling 193 MW. The
amount of variable generation (Hydro) is 5.1 percent of the SERC Region’s capacity resources.

In the recent past years, utilities in the SERC Region had experienced various levels of impacts
on generation due to drought within the Region. Currently drought conditions have moderated in
the SERC Region. Regarding hydro conditions and its impact on production for the upcoming
winter season, the SERC Region thermal and hydro production are expected to experience no
impact relative to 2009/2010 winter load-serving obligations.

Entities within the Region are currently not experiencing or expecting to experience any
conditions that would impact reliability negatively. It is common amongst the entities to rely on a

104
      Defined by EIA as: “organic non-fossil material of biological origin constituting a renewable energy source”



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portfolio of firm-fuel resources to ensure adequate fuel supplies to generating facilities during
projected winter peak demand. Forecasts are based on normal weather conditions for winter
peaks. In addition, entities within SERC are not expecting a significant amount of generation to
be out of service during the winter, though a few large units are scheduled out of service for
overhaul or nuclear refueling. Outages are routinely scheduled for some generating units during
the winter. Outage plans are developed so that anticipated loads can be met with available
resources. A few plants have also been proposed to be retired for this winter period. These
retirements coupled with the planned outages are not expected to result in any reliability issues
for the winter 2009/2010 period.

Capacity Transactions on Peak
These firm purchases have been included in the Reserve Margin calculations for the Region and
are backed by firm contracts for both generation and transmission. No entities reported import or
export assumptions that are based on partial path reservations. Utilities in the Region are not
considered to be dependent on purchases or transfers outside the SERC Region to meet the
demands of the load in the Region. Several entities within the Region reported use of contracts
within their subregions that are Liquidated Damages Contracts (LDCs). These contracts are
considered to be make-whole contracts.

                  SERC Table 2: SERC Region Purchases/Sales MW
        Transaction Type         Purchases             Sales
        Firm                     1,147 MW         5,058 MW
        Non-Firm                     0 MW             0 MW
        Expected                     0 MW             0 MW
        Provisional                  0 MW             0 MW

Transmission
New bulk power transmission facilities projects anticipated to be in-service for the 2009/2010
winter that were added since the 2008/2009 winter are listed in detail within the SERC
subregional sections of the report. There are no reported project delays that create concerns for
reliability. Reported delays are expected to be mitigated appropriately to ensure no impacts on
the system for the upcoming winter.

No significant lines are planned to be out of service throughout the Region at this time. All
significant, planned transmission facility outages are scheduled for spring and fall (off-peak
seasons). Utilities commonly study and plan transmission facility outages based on forecasted
system conditions and potential reliability impacts. In the event of forced, weather-related
outages (i.e., ice storm), companies will activate individual transmission emergency operations
centers to coordinate restoration of service to customers.

There are no transmission constraints that could significantly impact reliability of the utilities in
the SERC Region during winter 2009/2010. Discussions in subregional portions of the report for
certain utilities indicate a few situations which require monitoring. With load projected to be
lower as compared to the prior year, the system has been tested at greater load levels.



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Coordinated interregional transmission reliability and transfer capability studies for the
2009/2010 winter season are in process among all the SERC subregions. Preliminary results of
these studies indicate the bulk transmission systems within the SERC Region have no issues that
will significantly impact reliability

The SERC Region has extensive transmission interconnections between its subregions. SERC
also has extensive interconnections to the FRCC, MRO, RFC, and SPP Regions. These
interconnections permit the exchange of firm and non-firm power and allow systems to assist one
another in the event of an emergency. Approximately 323 miles of 115 kV, 138 kV, 161 kV, 230
kV, 345 kV, and 500 kV transmission lines are scheduled for completion by winter 2009/2010.
There are no concerns with respect to the impact on reliability performance relating to the
completion of these projects because summer is the more demanding season in the SERC
Region.

While utilities within the SERC Region plan to add new substation equipment for the coming
winter, none of these new facilities are considered to be significant.

Operational Issues
Operational planning studies are done individually by utilities within the SERC Region.
Individual company studies were reported to be done daily, weekly, and monthly, taking into
consideration demand and unit availability. This helps to address any inadequacies as well as
mitigate potential risks. No generation or operational problems have been identified in recently
completed planning studies. Entities within the Region participate in SERC study groups that
assess the Region on a seasonal basis. An assessment is currently being conducted in the SERC
NTSG 2009/2010 Winter Reliability report.

No special operating procedures are reported to be in place as a result of variable resource
integration. Most of the SERC Region is in the lowest wind resource area of the country. One
operational change to note is that for the utilities in the Gateway subregion who are members of
the Midwest Independent Transmission System Operator (Midwest ISO), on January 6, 2009, the
Midwest ISO began operation as a single balancing authority in conjunction with the
commencement of the Midwest ISO Ancillary Services Market. In addition, no significant
reliability concerns resulting from high-levels of Demand Response resources or minimum
demand and over-generation have been identified or anticipated for the upcoming season.

Environmental and/or regulatory restrictions are not a reliability issue for the Region, even
though some entities have reported insignificant factors resulting from Selective Catalytic
Reduction (SCR) device limits and continued restoration of dams within the Central subregion.
To mitigate these concerns, limits are studied by individual companies and are taken into account
during resource planning. These limits are not a concern for reliability or economic dispatch
situations.

Unusual operating conditions are not expected to impact reliability for the upcoming winter
season. Entities will rely on redispatch plans, modest increases in imports, or implementation of
operating guidelines to help mitigate reliability concerns as needed.




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Reliability Assessment Analysis
In aggregate, the utilities in the SERC Region expect 499 MW of planned capacity to be placed
in service by January 1, 2010. The aggregate projected 2009/2010 winter Reserve Margin for the
utilities in the SERC Region is 42.2 percent indicating capacity resources are expected to be
adequate to supply the projected firm winter demand. The Reserve Margin projected for winter
2008/2009 was 35.2 percent. Approximately 266,350 MW of generating capability is expected to
be connected in the Region. An extreme peak for 2009/2010 winter equates to 190,440 MW of
peak demand for the Region. The Reserve Margin for this scenario is estimated to be 33.9
percent, which, although reduced from margins based on 50/50 forecasts, is an adequate level for
these conditions.

SERC does not implement a Regional or subregional reserve requirement. As described in more
detail within the subregional reports, many utilities in the SERC Region adhere to their
respective state commissions’ regulations or internal business practices regarding maintaining
adequate resources. For example, a target margin is implemented by regulatory authorities in the
state of Georgia, where the regulation is only applicable to the investor-owned utilities in that
state. Based on a recent review of resource adequacy assessment practices, many utilities in the
SERC Region use a probabilistic generation and load model to assess and determine that
adequate resources are available and deliverable to the load.

All utilities with the SERC Region project fuel supplies to be adequate for this coming winter.
Communication between utilities and suppliers and transporters in the fuel industry is ongoing.
This topic is covered in detail in the subregional sections of this report. Although fuel
deliverability problems are possible for limited periods of time due to weather extremes such as
flooding, rail, pipeline and other transportation system disruptions, assessments indicate that this
should not have a negative impact on reliability. The immediate impact will likely be economic
as some production is shifted to other fuels. Secondary impacts could involve changes in
emission levels and increased deliveries from alternate fuel suppliers. The utilities within the
SERC Region anticipate that fuel deliverability constraints would not reduce the availability of
capacity resources due to strength of the utilities’ programs coupled with the economic recession
which have reduced pressure on rail service providers and pipelines.

The projected 2009/2010 winter capacity mix reported by utilities within the SERC Region is
well diversified at approximately 36.4 percent coal, 13.7 percent nuclear, 3.7 percent
hydro/pumped storage, 40.7 percent gas and/or oil, and 5.5 percent for purchases and
miscellaneous other capacity. Generation with coal, nuclear, and hydro fuels continues to lead
the Regional fuel mix accounting for roughly 55.1 percent of net operable capacity. Sufficient
inventories (including access to salt-dome natural gas storage), fuel-switching capabilities,
alternate fuel delivery routes and suppliers, and emergency fuel delivery contracts are some of
the important measures used by the utilities within SERC to reduce reliability risks due to fuel
supply issues.

Dual fuel units are tested to ensure their availability and that back-up fuel supplies are
adequately maintained and positioned for immediate availability. Some generating units have
provisions to switch between two different natural-gas pipeline systems, reducing the
dependence on any single interstate pipeline system. Moreover, the diversity of generating



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resources further reduces the risk. Current projections indicate that the fuel supply infrastructure
and fuel inventories for the winter period are adequate even considering possible impacts due to
weather extremes.

SERC does not have Regional criteria for dynamic, voltage, or small signal stability; however,
utilities within the Region maintain individual criteria to address any stability issues and these
processes are discussed in the subregional reports. There are no issues in this area on a SERC-
wide basis. There is also no overarching summary that can be provided except to assure that each
utility involved in planning has clear criteria for voltage and transient performance.

The Annual Report of the SERC Reliability Review Subcommittee (RRS) to the SERC
Engineering Committee (EC) summarizes the work of the SERC subcommittees relative to the
transmission and generation adequacy and provides the overview of the state of the systems
within SERC. 105

Other Region Specific Issues
To minimize reliability concerns within the Region, entities are relying on a variety of
procedures to avoid negative impacts on the system. Some activities such as monthly, weekly,
and daily operational planning analyses, improvement of vegetation management procedure
programs, preventative maintenance on units during the off-peak period, routine maintenance on
transmission equipment and maintaining adequate reserves are examples of steps that utilities
within SERC have implemented to maintain the reliability of the bulk power system. Even
though negative impacts are not expected, these steps show that entities are focused on
mitigating risks and maintaining reliability.




105
               Because it is considered CEII, the SERC RRS Annual Report to the Engineering Committee is available only upon
  request through the SERC website at www.serc1.org.



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Central

Demand
The actual 2008/2009 winter peak for the utilities in the Central subregion was 43,961 MW. The
projected Total Internal Demand for the 2009/2010 winter season is 43,230 MW; this is 548 MW
(1.3 percent) lower than the forecast 2008/2009 winter Total Internal Demand of 43,778 MW.
The actual winter peak demand does not take into account energy efficiency, diversity stand-by
load or additions for non-member load, whereas the internal peak demand values account for
these values.

The winter peak forecast in 2008/2009 was higher than the 2009/2010 forecast due to lower
temperatures and the effects of the economic recession on industrial demand. The change in
demand from prior forecasts for 2009/2010 also reflects the effects of the economic recession
which were due to continued reductions or shutdowns during 2009 at several large facilities that
had been operating in January. Declining economic conditions have also slowed household
formation and manufacturing employment, which have contributed to the significant changes in
the forecast as well. However, some entities within the Central subregion are reporting an
increase in forecasted demand driven by an expectation of additional customers added to the
system.

The 2009/2010 winter demand forecast is based on normal weather conditions and economic
data from population, income, expected demographics for the area, employment, energy exports,
and gross Regional product increases and decreases. Economic data from the national level is
also considered. To assess variability, members within the subregion use forecasts assuming
normal weather and then develop models for milder and more historical peaks and demand
models to predict variance. Optimistic and pessimistic economic growth scenarios, price, number
of households, and commercial and industrial growth are also taken into account as variables in
long-term base case models.

As with other subregions, strong emphasis is placed on energy efficiency and consideration of
renewables. Entities within this subregion reported 1.9 percent of Total Internal Demand as
Demand Response that can reduce peak demand. Programs such as voluntary curtailment tariffs
for larger industrial customers, direct control load management programs and other interruptible
demand programs that reduce peak demand are common around the subregion. Most voluntary
curtailment programs are driven by economics. As part of the Region’s energy-efficiency
program implementation, energy audits, low-income assistance, HVAC system improvements,
lighting, and verification/measurement groups are in place. Residential programs currently focus
on building-shell thermal efficiency, high-efficiency heat pumps, new manufactured-homes, and
self-administered paper and electronic online energy audits.

Some entities measure the impact of the interruptible demand program by comparing the
magnitude of the customer’s load before and during an interruption. Other companies report that
a load must be interruptible with no more than 60 minutes notice to qualify as interruptible for
planning purposes. During the 2009/2010 winter, approximately 820 MW of load is expected to
be available for interruption. Although most of the programs mentioned above are used only
during summer operation, these programs are reported to be active and are a part of company



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supply portfolios around the subregion for the use of peak reduction and energy efficiency.

Generation
Utilities in the Central subregion expect to have the following capacity in-service through the
assessment timeframe. This capacity is expected to help meet demand during this time period.

              Central Table 1: Winter 2009/2010 Capacity Breakdown
              Capacity Type                      Winter 2009/2010
              Existing-Certain                         54,324 MW
                Wind                                        0 MW
                Solar                                       0 MW
                Biomass                                    18 MW
                Hydro                                   4,124 MW
              Existing-Other                            1,108 MW
                Wind                                        0 MW
                Solar                                       0 MW
                Biomass                                     0 MW
                Hydro                                     762 MW
              Energy Only                                   0 MW
              Existing Inoperable                           0 MW
              Future-Planned                                0 MW
              Future-Other                                  0 MW

As seen in the table above, 4,124 MW of hydro and 18 MW of biomass capacity are expected
on-peak for the upcoming season. To address variable capacity calculations, entities within the
subregion either have no variable capacity or do not consider them toward capacity requirements.

Hydro conditions are currently anticipated to be normal in the Central subregion for the period.
Marginal capacity needs have been addressed without dependence on hydro capacity. Sufficient
reservoir levels are expected for the Dix Dam hydro station, Laurel Dam, Greenup hydro, etc.

Although hydro generation is still limited at Wolf Creek Dam, short-term purchases will be
available as necessary to meet peak demand for the season. Hydro generation estimates are based
on the analysis of historic operating practices and flow conditions. The numbers quoted above
are consistent with the latest long-term hydro forecast.

Currently, the Central Region of the National Climatic Data Center is indicating that no
significant areas within the subregion are experiencing moisture levels consistent with any level
of drought condition as measured by the Palmer Drought Severity Index. However, dryer than
normal conditions resulting from prior years’ drought have created capacity reductions. These
reductions have been taken into consideration in company capacity planning. Most entities in the
subregion only count Existing-Certain capacity toward firm capacity requirements. Purchases are
made from short-term markets as needed to compensate from any reductions that may occur
during abnormal seasons.



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River conditions remain sufficient, with very little flooding or drought conditions creating delays
in inland river transportation via barge. Coal trucks have continued to maintain current and
planned deliveries. There is no reason to believe, at this time, that fuel deliveries will not be
made according to contractual agreements and forecasts for delivery.

No significant generating units that will affect reliability within the subregion are expected to be
out of service or retired for the upcoming season. However, 71 MW is planned to be on inactive
reserve this winter due to the economic recession. Approximately 812 MW will be on planned
maintenance at some point during the winter season. No outages have been scheduled during the
upcoming winter peaking month. These planned outages have been accounted for in generation
planning with no impact to overall reliability. Again, entities within the subregion use purchases
from the short-term markets, as necessary.

Capacity Transactions on Peak
Central subregional utilities have reported the following imports and exports for the upcoming
2009/2010 winter season. The majority of these exports/imports are backed by firm contracts,
which include dedicated generation, transmission reservations and fuel transportation that count
toward firm capacity. There are no reports of imports/exports based on partial path reservations
or associated with LDCs. These reports have been included in the aggregate Reserve Margin for
utilities in the subregion.

                     Central Table 2: Subregional Imports/Exports
          Transaction Type                             Winter 2009/2010
          Firm Imports (Internal Subregion)                   0 MW
          Firm Exports (Internal Subregion)                  95 MW
          Non-Firm Imports (Internal Subregion)               0 MW
          Non-Firm Exports (Internal Subregion)               0 MW
          Expected Imports (Internal Subregion)               0 MW
          Expected Exports (Internal Subregion)               0 MW
          Firm Imports (External Subregion)                 916 MW
          Firm Exports (External Subregion)                 842 MW
          Non-Firm Imports (External Subregion)               0 MW
          Non-Firm Exports (External Subregion)               0 MW
          Expected Imports (External Subregion)               0 MW
          Expected Exports (External Subregion)               0 MW

For reliability analysis/Reserve Margin calculations, entities within this subregion may use a
request for proposal (RFP) system for forward-capacity markets or use firm contract purchases
(both generation and transmission) toward firm capacity. Overall, the utilities in the subregion do
not depend on outside purchases or transfers from other Regions or subregions to meet their
demand requirements.

Transmission
The following table shows bulk power system transmission categorized as under construction,
planned, or conceptual that is expected to be in-service for the upcoming 2009/2010 winter



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season since the winter season of 2008. Information on in-service dates associated with various
facilities that will be in-service this winter is also listed in the table below.

 Central Table 3: Expected Under-construction, Planned, Conceptual Transmission
 Transmission Project     Transmission Type    In-Service   Concerns in     Reliability     Mitigation
       Name                    (Under           Date(s)       meeting     Issues with In-    Plans to
                            Construction,                    In-Service    Service Date      Address
                             Planned, or                       Date?          Delay?          Delay
                             Conceptual)                      (yes/no)       (yes/no)
 Pineville-West Garrard   Under Construction    10/2009        No              NA               NA
 J.K. Smith-West          Under Construction   12/31/2009      Yes             No            Purchase
 Garrard 345kV                                                                              additional
 Interconnection                                                                            power off-
                                                                                              system
 E.ON U.S.-Cinergy        Under Construction   12/31/2009       No             NA               NA
 345kV Interconnection
 Trimble County -         Under Construction   06/30/2009      NA              NA              NA
 Ghent-Speed Line
 Rutherford - Almaville   Planned              07/08/2009       No             NA              NA
 Tilton - Resaca          Planned              09/30/2009       No             NA              NA
 J.K.Smith 345/138kV      In-service            06/2009         No             NA              NA
 Second
 Autotransformer
 Huntsville-McCreary      Planned               11/2009        No              NA               NA
 Mill Creek-Hardin        Under Construction    12/2009        Yes             No              None
 County                                                                                       needed
 Higby Mill-West          Under Construction    11/2009        Yes              No             None
 Lexington                                                                                    needed.
                                                                                            Date moved
                                                                                            to 06/2010
 Middletown-Collins       Under Construction    12/2009         No             NA               NA
 Tyner-Fallen Rock        Under Construction    05/2009         No             NA               NA

No significant lines are planned to be out of service throughout the Central subregion at this
time. In the event of forced, weather-related outages (i.e., ice storm), companies will activate
individual transmission emergency operations centers to coordinate restoration of service to
customers.

No major constraints have been identified that could significantly impact reliability for the
2009/2010 winter season. Companies continuously evaluate the transmission system to identify
any future constraints that could significantly impact reliability. These future constraints and
proposed solutions are annually published in transmission expansion plans on file with the ITO
(SPP) and other Regional reliability studies for the season.

Although no major constraints have been reported for the upcoming winter season, repairs at
Wolf Creek Dam and the resulting lowered level of Lake Cumberland are expected to be an issue
within southern Kentucky and will result in reduced availability of the Wolf Creek hydroelectric
generating units. A subsequent outage of both Cooper units during peak load periods can result
in unacceptably low voltages on the 161 kV transmission system in the area. Entities within this
area are continuing to assess the situation with the development of operating guides for this


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scenario. Possible mitigation measures include use of the Laurel Dam hydroelectric generating
unit for support (if possible), use of the Wolf Creek hydroelectric units for real and/or reactive
support (if possible), and/or load shedding in the area.

Subregional entities reported no new plans to install significant substation equipment. An
Operator Training Simulator (OTS) is projected to be in-service in the last quarter of 2009.

Operational Issues
Monthly, weekly, and daily operational planning efforts take into consideration demand and unit
availability. This helps to address any inadequacies as well as mitigate these risks. Based on
recent planning studies that have been conducted, no generation or operational problems have
been identified.

Most entities within this subregion count Existing-Certain capacity toward firm capacity
requirements. These entities do not generally depend on Existing-Uncertain, Planned, or
Proposed capacity resources to meet capacity requirements. Therefore, there are no special
operating procedures required for variable resources. In addition, no reliability concerns resulting
from high-levels of Demand Response resources or minimum demand and over-generation have
been identified or anticipated for the upcoming season.

Also, no major generating unit outages, generation additions, environmental/regulatory
restrictions, temporary operating measures, or unusual operating conditions are expected to
affect the reliability of the Central subregion this winter season.

Resource Assessment Analysis
The projected January 2010 winter peak Reserve Margin for the utilities in the subregion is 28.0
percent. This is 11.5 percent higher compared to last year’s peak Reserve Margin at 16.5 percent.
The subregion does not have a Regional or subregional marginal target for comparison purposes.

The Reserve Margin analysis in the company-integrated resource plans incorporate sensitivities
on load unit availability, production cost, purchase power availability, unserved energy cost, and
varying Reserve Margin levels. Monthly and long-term resource planning efforts take into
consideration demand and unit availability. This helps to address any inadequacies in achieving
the desired Reserve Margin. If resource inadequacies cause the reserves to be reduced below the
desired level, companies within the subregion can make use of purchases from the short-term
markets in the near-term and various ownership options in the long-term, as necessary. Several
entities within the Central subregion are members of the Midwest Contingency Reserve Sharing
Group (MCRSG) which includes the Midwest ISO and 10 other Balancing Authorities in SERC
and MRO. The MCRSG is intended to provide immediate response to contingencies enabling the
group to comply with the DCS standard.

Utilities within the subregion are not relying on short-term outside purchases or transfers from
other Regions or subregions to meet demand requirements. Options to meet long-term demand
needs may include building capacity, using existing capacity, expanding current capacity, or
contracting for capacity.




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In order to ensure fuel delivery, the practice of having a diverse portfolio of suppliers, including
purchase of high-sulfur coal from Northern and Central Appalachia (West Virginia, East
Kentucky), Ohio and the Illinois Basin (West Kentucky, Indiana, Illinois) is common within the
subregion. Fuel departments typically monitor supply conditions on a daily basis through review
of receipts and coal burns and interact daily with both coal and transportation suppliers to review
situations and foreseeable interruptions. Any identifiable interruptions are assessed with regard
to current and desired inventory levels. By purchasing from different Regions, coal is expected to
move upstream and downstream to various plants. Some plants have the ability to re-route
deliveries between them. Some stations having coal delivered by rail can also use trucks to
supplement deliveries. Utilities have reported that they maintain targets greater than 30 days of
on-site coal inventory. Fuel supplies are adequate and readily available for the upcoming winter.
Multiple contracts are in place for local coal from area mines.

Companies within the subregion maintain individual criteria to address any problems with
stability issues. Recent stability studies identified no stability issues that could impact the system
reliability during the 2009/2010 winter season. Criteria for dynamic reactive requirements are
addressed on an individual company basis. Utilities employ study methodologies designed to
assess dynamic reactive margins. Programs such as Reactive Monitoring Systems give operators
an indication of reactive reserves within defined zones on the system.

Voltage stability margins are also upheld by utilities on an individual basis. Some utilities follow
the procedure of making sure that the steady-state operating point be at least 5 percent below the
voltage collapse point at all times to maintain voltage stability. Studies are performed on peak
cases to verify system stability margins. Other utilities follow guidelines to ensure that voltage
stability will be maintained via Q-V analysis.

Utilities within the Central subregion are not anticipating reliability concerns for the upcoming
winter season. Monthly, weekly, and daily operational planning efforts take into consideration
demand and unit availability. This helps to address any inadequacies as well as mitigate these
risks.




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Delta

Demand
The actual 2008/2009 winter peak for utilities in the Delta subregion was 23,386 MW. The
projected Total Internal Demand for the 2009/2010 winter season is forecast to be 22,064 MW;
this forecast is 2,737 MW (11.0 percent) lower than the forecast 2008/2009 winter Total Internal
Demand of 24,801 MW. The actual winter peak demand does not take into account energy
efficiency, diversity stand-by load, or additions for non-member load, whereas the internal peak
demand values account for these factors.

The year-over-year decline primarily reflects the anticipated impacts of increased energy
efficiency and conservation, reductions in wholesale load and electric use, and an economic
recession. The 2009/2010 forecast is based on a new forecast study which produced new
econometrically based forecasts of commercial/industrial load, future economic/demographic
conditions, and historical data. Distribution cooperative personnel assess the likelihood of these
potential new loads and a probability adjusted load is incorporated into cooperative load forecast.

DSM programs among the utilities in the subregion include traditional industrial and large
commercial interruptible rate programs and a range of conservation/load management programs
for all customer segments. The terms and conditions of these tariffs permit load curtailment at
anytime, including winter months. The amount of interruptible load can vary from year-to-year
because of changes in customer operations, adding or removing customers from participation in
interruptible rate programs, and increasing or decreasing the amount of interruptible load under
contract. Entities within this subregion reported 3.6 percent of Total Internal Demand as Demand
Response that can reduce peak demand. There are no significant changes in the amount and
availability of load management and interruptible demand since last year.

Various energy-efficiency programs are offered within the subregion. Examples of these
voluntary programs are home energy audits, CFL lighting, Energy Star-rated washing machines
and dishwashers, and Energy Star-rated heat pumps and air conditioners. In general, the
programs are available for every customer class and provide incentives for improvements that go
beyond established efficiency standards. Companies within the subregion adhere to the
measurement and verification (M&V)protocol established by the regulating entity. Utilities plan
to offer these types of programs as long as they are determined to be cost-effective. In 2008, the
M&V program was started to measure energy savings and costs for each of the energy-efficiency
programs. Information from this M&V program will be used to fine tune energy-efficiency
programs and to determine each program’s cost effectiveness. The current forecast includes
energy-efficiency programs that have received regulatory approval and have been incorporated
into the sales and load forecasts.

Load scenarios for outage planning purposes are developed regularly to address variability issues
in demand. These load scenarios include load forecasts based on high and low load scenarios for
energy sales and scenarios for alternative capacity factors. Load scenarios for load-flow analyses
in transmission planning are also developed and posted to OASIS. Some of these scenarios
developed within the subregion were reported to be based on an assumption of extreme weather,
which were more severe than the expected peaking conditions but less severe than the most
severe conditions found in the historical records. Special analyses are performed to examine


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expected peak loads associated with cold fronts, ice storms, hurricanes, and heat waves. These
analyses are performed on an ad-hoc basis and may be conducted for various parts of the Delta
subregion.

Generation
Companies within the Delta subregion expect to have the following capacity on-peak. This
capacity is expected to help meet demand during this time period.

                 Delta Table 1: Winter 2009/2010 Capacity Breakdown
                 Capacity Type                     Winter 2009/2010
                 Existing-Certain                       39,719 MW
                   Wind                                       0 MW
                   Solar                                      0 MW
                   Biomass                                    0 MW
                   Hydro                                    228 MW
                 Existing-Other                           1,471 MW
                   Wind                                       0 MW
                   Solar                                      0 MW
                   Biomass                                    0 MW
                   Hydro                                     70 MW
                 Energy Only                              1,235 MW
                 Existing Inoperable                      1,985 MW
                 Future-Planned                             103 MW
                 Future-Other                                 0 MW

As seen in the table above, 228 MW of hydro capacity is expected on-peak for the upcoming
season. Reservoirs are currently projected to be near 100 percent moving into the fall/winter
season. Therefore, reservoir levels are sufficient to meet both projected peak demand and the
daily energy demand throughout the winter season. If river levels are inadequate to operate the
hydro facility at maximum capacity, agreements are in place to serve demand with firm energy
and transmission. To address variable capacity calculations, entities within the subregion either
have no variable capacity or do not consider them toward peak capacity requirements.

Utilities within the subregion are not currently experiencing or expecting to experience any
conditions that would impact reliability negatively. It is common amongst the entities to rely on a
portfolio of firm-fuel resources to ensure adequate fuel supplies to generating facilities during
projected winter peak demand. Those resources include nuclear and coal-fired generation that are
relatively unaffected by winter weather events, fuel oil inventory located at the dual-fuel
generating plants, approximately 10 Bcf of natural gas in storage at a company-owned natural
gas storage facility, and short-term purchases of firm natural gas generally supplied from other
gas storage facilities and delivered using firm gas transportation contracts. This mix of resources
provides diversity of fuel supply and minimizes the likelihood and impact of weather, fuel
supply, and fuel transportation conditions that might otherwise reduce capacity.




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Routine scheduled maintenance outages are scheduled for some generating units during the
winter. Outage plans are developed so that anticipated loads can be met with available resources.
There are no other anticipated system conditions expected for the winter.

Capacity Transactions on Peak
Delta subregional utilities expect the following imports and exports for the upcoming 2009/2010
winter season. These imports and exports have been accounted for in the Reserve Margin
calculations for the subregion. Utilities within the subregion use certain emergency short-term
imports, transfers, or contracts in the form of reserve sharing to meet the demands of its load. All
contracts for these imports/exports are considered to be backed by firm transmission and are tied
to specified generators. No imports are based on partial path reservations. The majority of the
contracts are not LDCs, but the LDCs that are in the subregion are considered to be all make-
whole contracts. Overall, the utilities in the subregion do not depend on outside purchases or
transfers from other Regions or subregions to meet their demand requirements. Entities within
the Delta subregion participate in reserve sharing groups for their external resources. These
sharing groups allow entities to receive emergency short term imports from remote balancing
authorities in SPP as well as from the Delta subregion.

                      Delta Table 2: Subregional Imports/Exports
                                                            Winter
          Transaction Type
                                                          2009/2010
          Firm Imports (Internal Subregion)              406 MW
          Firm Exports (Internal Subregion)               70 MW
          Non-Firm Imports (Internal Subregion)            0 MW
          Non-Firm Exports (Internal Subregion)            0 MW
          Expected Imports (Internal Subregion)            0 MW
          Expected Exports (Internal Subregion)            0 MW
          Firm Imports (External Subregion)              814 MW
          Firm Exports (External Subregion)            1,371 MW
          Non-Firm Imports (External Subregion)            0 MW
          Non-Firm Exports (External Subregion)            0 MW
          Expected Imports (External Subregion)            0 MW
          Expected Exports (External Subregion)            0 MW

Transmission
The following table shows bulk power system transmission categorized as under construction,
planned, or conceptual that is expected to be in-service for the upcoming 2009/2010 winter
season since the 2008 winter season. Utilities do not expect any delays in meeting in-service
dates for projects to be completed this season. Unexpected significant transmission facility
outages that would impact bulk power system reliability for the 2009/2010 winter season were
not reported. Any planned maintenance outages would be studied to identify impacts to
reliability




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 Delta Table 3: Expected Under-construction, Planned, Conceptual Transmission
  Transmission       Transmission    In-Service   Concerns in      Reliability Issues   Mitigation Plans
  Project Name           Type         Date(s)       meeting         with In-Service     to Address Delay
                        (Under                     In-Service        Date Delay?
                     Construction,                   Date?             (yes/no)
                      Planned, or                   (yes/no)
                     Conceptual)
 Thomas Hill -      Under             12/2009         No                 N/A                  N/A
 Higbee             Construction
 Conway West -      Under             12/2009         No                 N/A                  N/A
 Donaghey -         Construction
 Conway South
 Gillette 115 kV    Under             12/2009         No                 N/A                  N/A
 capacitor bank     Construction
 Rich Fountain-     Under             12/2009        N/A                 N/A                  N/A
 Osage              Construction
 Panama-Dutch       In-Service        02/2009        N/A                 N/A                  N/A
 Bayou new 230
 kV line
 Conway-Bagatelle   In-Service        03/2009        N/A                 N/A                  N/A
 230 kV line
 upgrade
 Liberty-Gloster    In-Service        04/2009        N/A                 N/A                  N/A
 115 kV line
 upgrade
 Acadia 138 kV      In-Service        06/2009        N/A                 N/A                  N/A
 capacitor bank

Several improvement projects are planned to be in-service by the end of 2009 to enhance bulk
system reliability. These include 115 kV through 161 kV projects to improve line loading and
voltage conditions. Within the subregion, various improvements have been completed since the
last winter assessment. Completed projects to improve transfer capability within the Amite South
area in south Louisiana include 230 kV line upgrades and a new line construction. Originally
intended to be in service by 2007, the projects were delayed to 2009 due to the effects of
Hurricane Katrina on the load pocket, including load loss. Another project includes the Paterson
substation, which was flooded in New Orleans during Hurricane Katrina damaging all major
transmission equipment. The station has since been operated in a split through-bus configuration.
This project entails the rebuilding of the substation to join two buses and connecting four
transmission lines. The Natchez, Mississippi area improvement plans are also another example of
improvement projects to enhance the system during the winter season. The area is served by five
long (40-50 miles) transmission 115 kV lines. When one of these lines is out of service, the area
has a potential for low voltages and overloads on the remaining lines. This project entails the
upgrade of the existing Liberty - Gloster 115 kV segment to 190 MVA and installation of 60
MVAr of capacitor banks and 16 MVAr of dynamic reactive power.

No transmission constraints are expected to significantly impact bulk system reliability for the
upcoming winter peak season. Several entities participate in the SERC Near-term Study Group
(NTSG) 2009/2010 Winter Reliability Study. The preliminary results of this study indicate that
imports into the subregion can be limited due to the McAdams 500/230 kV autotransformer for
the loss of the McAdams - Lakeover 500 kV flowgate. This flowgate, which is located near a



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500 kV tie to the Central subregion, can be constrained due to excess generation on the interface
along with transactions across the interface. Real-time operating limits have been addressed
using the appropriate NERC operating procedures. Additional fans were added to the McAdams
autotransformer in July 2008 to increase its rating, and further upgrades have been identified in
the area with a projected completion date of 2011.

To address transfer capability studies, some entities currently use an Available Flowgate
Capability (AFC) process to calculate available transfer capability and evaluate transmission
service requests in the Day 1 to Month 18 time frame. Because of the inherent granularity and
update frequency provided by the AFC process, specific seasonal transfer capabilities are not
calculated. Entities are also currently participating in the SERC NTSG 2009/2010 Winter
Reliability Study. This study, which has not yet been finalized, tests transmission transfer
capabilities between the Delta subregion and other SERC subregions. The analyses performed to
calculate the transfer limits presented in the SERC NTSG 2009/2010 Winter Reliability Study
consider all transmission elements identified by participating member companies within SERC.

There were no new technologies, systems, or tools put in service since last winter season. Some
utilities are currently operating static var compensation (SVC) devices in order to provide
reactive power support and maintain voltage stability. Series compensation has been installed on
two key transmission lines on the system in order to regulate power flows. Utilities plan to
continue to employ and research these technologies in order to improve and maintain bulk power
system reliability.

Operational Issues
No reliability concerns are anticipated for the upcoming peak season. Resource availability, fuel
availability and hydro conditions are expected to be normal during the winter. Loss-of-Load
studies are performed annually for the regulated utilities in the subregion for the current year
based on updated load forecast and unit availability data. The long-term test of resource
adequacy is met by achieving adequate planning Reserve Margin.

Entities within the subregion reported no special operating procedures resulting from integration
of variable resources. There are also no reliability concerns resulting from high levels of Demand
Response resources, unusual operating conditions, local environmental or regulatory restrictions,
or minimum demand and over generation from variable resources.
Because Level 3 Energy Emergency Alerts (EEA-3s) were issued in the Acadiana area during
this past summer, the SPP RTO will continue to monitor this area closely as part of its Reliability
Coordinator function.

Reliability Assessment Analysis
The projected February 2010 winter peak Reserve Margin for the utilities in the subregion is 85.9
percent. This is 36.5 percent higher compared to last year’s peak (January 2009) Reserve Margin
at 49.4 percent. The increase is largely due to more complete reporting using NERC’s new
capacity definitions for 2009/2010. Increases in capacity for the upcoming season are expected to
be adequate to meet demand for the upcoming winter season. There are no required state Reserve
Margins for the subregion. Due to NERC’s new reporting requirements and capacity definitions,
the 85.9 percent peak Reserve Margin is higher than previously reported as it includes both



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committed and uncommitted resources within the subregion. This revised calculation method
does not reflect the deliverability of certain uncommitted resources. Discounting the impact of
uncommitted resources, the subregion expects the upcoming winter peak Reserve Margin to be
adequate.

Various utility resource planning departments in the subregion conduct studies annually (either
in-house or through contract) to assess resource adequacy. Sophisticated modeling is used
throughout the subregion in all phases of the study. An example of this type of modeling is the
Entergy Reliability Analysis with Interruptible Loads (ERAILS) model that is used to perform
resource requirements analyses. The ERAILS model uses Monte Carlo statistical techniques to
estimate each day’s “actual” peak load based on the forecast load and the load forecast variance,
the total resources available to serve that load based on available resources, forced outages, and
the characteristics of each resource, and the probability of being able to meet the load, plus off-
system sales and operating reserves. The fundamental objective of the process is to identify the
amount of incremental resources necessary to serve firm load at a reliability level of no more
than 1d/10y loss-of-load expectation and to serve interruptible retail and limited-firm wholesale
loads with an average of ten or fewer days of interruption during the year. Studies like these are
used to ensure resources are available at the time of system peak. Some companies have reported
that results are approved by the board of directors internally. Subregional transmission planning
departments also conduct sophisticated studies to ensure transfer capability is adequate under
various contingency conditions. The balancing authority has a full requirements contract to
ensure studies are performed, upon request of the supplier, by the transmission provider. These
studies will evaluate the availability of firm transmission from resources. All resources were
considered to meet the criteria or target margin level for last winter and for the upcoming winter.

Fuel supplies are anticipated to be adequate. Coal stockpiles are maintained at 30 or more days.
Natural gas contracts are firm. Extreme weather conditions will not affect deliverability of
natural gas. Typically, supplies are limited only when there are hurricanes in the Gulf. There is
access to local gas storage to offset typical gas curtailments. Many utilities maintain portfolios of
firm-fuel resources to ensure adequate fuel supplies to generating facilities during projected peak
demand. Those firm-fuel resources include nuclear and coal-fired generation that are relatively
unaffected by winter weather events. Various portfolios contain fuel oil inventories located at the
dual-fuel generating plants, approximately 10 Bcf of natural gas in storage at a company-owned
natural gas storage facility, and short-term purchases of firm natural gas generally supplied from
other gas storage facilities and firm gas transportation contracts. This mix of resources provides
diversity of fuel supply and minimizes the likelihood and impact of potentially problematic
issues on system reliability. Close relationships are maintained with coal mines, gas pipelines,
gas producers, and railroads that serve its coal power plants. These close relationships have been
beneficial to ensure adequate fuel supplies are on hand to meet load requirements.

Companies throughout the subregion individually perform studies to assess transient dynamics,
voltage and small-signal stability issues for winter conditions in the near-term planning horizons
as required by NERC Reliability Standards. As part of annual winter assessments, some
companies model single and multiple contingencies across the system. In load-flow analysis, bus
voltages are monitored and were found to remain within acceptable range. In stability
simulations, generator reactive power outputs were monitored and were found to stay within



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adequate limits. These studies confirm that the available reactive power resources (generators,
capacitors, reactors, SVCs) are adequate for the 2009/2010 winter and no critical impacts to the
bulk electric power system are expected. While there are no common subregion-wide criteria to
address transient dynamics, voltage and small-signal stability issues, some utilities have noted
they adhere to voltage schedules and voltage stability margins. In addition, some utilities employ
static var compensation devices to provide reactive power support and voltage stability. Under-
voltage load-shedding (UVLS) programs are also used to maintain voltage stability and protect
against bulk power system cascading events.

Although certain areas within the Delta subregion are susceptible to multiple forms of weather
events including hurricanes, tornadoes and ice storms, entities have reported that they have
developed emergency restoration plans to respond to such events. These plans are periodically
tested through drills where opportunities for process improvements are identified. However,
Delta subregion companies do not anticipate reliability concerns outside of normal operational
planning processes for the 2009/2010 winter season.




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Gateway

Demand
The actual 2008/2009 winter peak for the utilities in the Gateway subregion was 15,323 MW.
Total aggregate internal demand for 2009/2010 winter season is forecast to be 15,640 MW and is
675 MW (4.5 percent) higher than the 2008/2009 winter forecast Total Internal Demand of
14,965 MW. The actual winter peak demand may not take into account energy efficiency,
diversity stand-by load or additions for non-member load, whereas the forecast internal peak
demand values account for these factors.

The Gateway subregion’s peak forecast is non-coincident and capacity reserves are evaluated for
summer conditions. The increase in the 2009/2010 forecast load compared to the 2008/2009
forecast load is largely the result of an adjustment made by a larger entity due to the higher load
and temperature conditions that were experienced in January, 2009, although four of the seven
load-reporting entities provided load forecasts that were higher than last year’s. The higher load
experienced is partially offset by reductions due to the economic recession and large industrial
customer outages that are expected to extend into 2010. The normal forecast weather
assumptions are based on 10 to 30 years of historical data along with adjustments for observation
practices and economic conditions. Economic data was taken from sources such as
Economy.com, which forecasts GDP growth of -4.4 percent in 2009 and 0.7 percent in 2010 for
the service territories of the larger members of the subregion.

Entities within this subregion reported no significant Demand Response that can reduce peak
demand in the winter season. This is not surprising as many of the Demand Response programs
are designed to curtail air conditioning load, which is not present in the winter. Also, there are no
needs for demand-side programs during winter peak conditions because the capacity reserves
that were acquired to cover the summer peak load will adequately cover the forecast winter peak
loads. The Gateway forecast 2009/2010 winter peak load is approximately 82 percent of the
forecast 2009 summer peak load. Several entities within this subregion have recently begun
making significant investments in energy-efficiency programs. These programs are typically
designed for summer and have not been forecasted to make a material impact on the peak
forecast for winter 2009/2010. Programs that are available for customer use include energy-
efficient lighting rebate programs, appliance recycling, energy audits, and HVAC rebate
programs. The final reports on the effectiveness of these programs in Illinois are due to the
Illinois Commerce Commission by the end of the year.

In order to assess the uncertainty and variability in projected demand, some utilities within the
Gateway subregion use regression models, multiple forecast scenario models, and econometric
models. Economic assumptions, alternative fuel pricing, electric pricing, and historical
temperature and weather (pessimistic and optimistic conditions) pattern information are
considered individually by each subregional utility. These models are developed individually
using different variables to establish the best standard statistical tests. DSM programs are not
commonly modeled separately since their impact is reflected in the peak demand information
used for forecasting purposes. All of these measurements provide information with which to
assess potential variability around the forecasted peak.




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Generation
Member companies within the Gateway subregion expect to have the following aggregate
capacity on peak. This capacity is expected to help meet demand during this time period.

             Gateway Table 1: Winter 2009/2010/10 Capacity Breakdown
            Capacity Type                      Winter 2009/2010
            Existing-Certain                        25,626 MW
              Wind                                       0 MW
              Solar                                      0 MW
              Biomass                                    0 MW
              Hydro                                    372 MW
            Existing-Other                             811 MW
              Wind                                       0 MW
              Solar                                      0 MW
              Biomass                                    0 MW
              Hydro                                      1 MW
            Energy Only                                  0 MW
            Existing Inoperable                        360 MW
            Future-Planned                               0 MW
            Future-Other                                 0 MW

The generation resources to serve the Gateway loads for this winter are predominantly located
within the Gateway subregion. No variable resources are included in the capacity breakdown of
the Gateway members. However, a 100 MW wind farm was connected to the Ameren-Illinois
transmission system during the summer of 2009. Hydro capacity of 372 MW of hydro is
expected to be available on-peak for the upcoming winter season. Hydro conditions are expected
to be normal; reservoir levels are expected to be sufficient.

Changes to the Existing-Certain capacity totals from last year include the addition of the CWLP
(Springfield Illinois) Dallman unit #4 200 MW coal-fired unit. CWLP’s Dallman unit #1 (86
MW), which was out of service last winter, has been returned to service.

Entities do not expect weather to impact the utility generation in the subregion. Coal is
sufficiently available to service coal-fired plants. Firm gas transportation or oil back-up for the
generating units is expected to be adequate as well.

Entities within the subregion have reported adequate capacity for the upcoming season, and some
are also planning for scheduled generation outages during the assessment period. The following
units are expected to be out of service some time during the winter period: Coffeen unit #2 (560
MW) and Rush Island unit #2 (600 MW) are scheduled for major unit overhauls. Clinton Nuclear
Plant (1078 MW) is scheduled for a refuel outage. Meredosia unit #3 will be out of service to
install low NOx burners. Grand Tower combined-cycle plant (525 MW), Meredosia unit #4 (166
MW), and the MEPI CTGs (240 MW) will be on seasonal shutdown. Venice CTG #1 (25 MW)
and the Taum Sauk pumped storage plant (400 MW) will also remain out of service through the
2009/2010 winter.



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CWLP’s Lakeside units #6 and #7 (76 MW total) are being retired this fall; however, they are
being replaced by the new Dallman #4 unit (200 MW). Meredosia units #1 and #2 (120 MW) are
expected to be retired before this winter period, contingent upon approval from the Midwest ISO
Attachment Y process. The above outages are not expected to affect reliability on the system for
the upcoming winter season. Midwest ISO monitors generation availability throughout its
footprint and has procedures in place if generation shortfalls would occur.

Capacity Transactions on Peak
The Gateway subregion reported the following imports and exports for the upcoming 2009/2010
winter season. These firm imports and exports have been accounted for in the Reserve Margin
calculations for the subregion. All capacity purchases and sales are on firm transmission within
the Midwest ISO footprint and direct ties with neighbors. Day-to-day capacity and energy
transactions are managed by Midwest ISO with security-constrained economic dispatch and
LMP. Overall, the subregion is not dependent on outside imports or transfers to meet the
demands of its load.

                     Gateway Table 2: Subregional Imports/Exports
                                                         Winter
           Transaction Type
                                                      2009/2010
           Firm Imports (Internal Subregion)              0 MW
           Firm Exports (Internal Subregion)            559 MW
           Non-Firm Imports (Internal Subregion)          0 MW
           Non-Firm Exports (Internal Subregion)          0 MW
           Expected Imports (Internal Subregion)          0 MW
           Expected Exports (Internal Subregion)          0 MW
           Firm Imports (External Subregion)            190 MW
           Firm Exports (External Subregion)          3,389 MW
           Non-Firm Imports (External Subregion)          0 MW
           Non-Firm Exports (External Subregion)          0 MW
           Expected Imports (External Subregion)          0 MW
           Expected Exports (External Subregion)          0 MW

Several contracts within the subregion are LDCs and are considered to be all make-whole
contracts. Many of the Gateway entities reported that they are a part of Midwest ISO and count
on Midwest ISO to supply its needs during emergencies. Most of the Gateway members are also
members of Midwest ISO and participate in Midwest ISO reserve-sharing group and ancillary
service markets to ensure their resource needs.

Transmission
The following table shows bulk power system transmission additions since the 2008/2009 winter
season, categorized as under construction, planned, or conceptual for the Gateway subregion.




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                 Gateway Table 3: Expected Under Construction, Planned,
                                Conceptual Transmission
  Transmission Project        Transmission    In-Service   Concerns in     Reliability     Mitigation
        Name                       Type        Date(s)     meeting In-   Issues with In-    Plans to
                                  (Under                     Service      Service Date      Address
                              Construction,                   Date?          Delay?          Delay
                                Planned, or                 (yes/no)        (yes/no)
                               Conceptual)
 Interstate - East            In-Service      06/01/2009      NA              NA              NA
 Springfield
 Interstate - San Jose Rail   In-Service      06/01/2009      NA              NA              NA
 Hamilton Substation -        Under           12/01/2009      NA              NA              NA
 Norris City Substation       Construction

The new Ameren-CWLP 138 kV interconnection at CWLP’s Interstate Substation was
completed this summer to provide additional transmission outlet for the CWLP Dallman unit #4
generator addition. A new Hamilton-Norris City 138kV transmission tie line is under
construction and is planned to be in-service by the upcoming winter season. This tie line is being
constructed to increase the reliability on the SIPC transmission system.

A number of upgrade projects involving terminal equipment have been completed since winter
2008/2009, resulting in increased thermal rating for several transmission facilities.
Reconductoring work was completed on the Havana-Monmouth 138 kV line and Havana-Ipava
138 kV line prior to 2009 summer. Work to increase ground clearances on the St. Francois-
Rivermines-1 138 kV line is expected to be completed before winter 2009.

Several transmission line additions are proposed for the Gateway subregion over the next several
years, but these lines will not be able to enhance transmission reliability for the 2009/2010 winter
period. Longer lead-times are being reported by several members as it is becoming increasingly
difficult to obtain permits and transmission rights-of-way to support new line construction. These
delays presently are not impacting the reliability of the bulk power system, but local reliability
may be degrading until these facilities can be constructed. The local entities will continue to rely
on operational solutions until such facilities are in service.

Gateway utilities have not scheduled any significant transmission facilities being out of service
for the upcoming winter season. All significant, planned transmission facility outages are
scheduled for spring and fall (off-peak seasons) and are coordinated and approved by Midwest
ISO. However, some equipment that has recently failed, including the St. Francois 345/138 kV
transformer #1, and may be out of service during the winter period as its replacement is not
needed for reliable operation until next summer. Refer to the SERC section of this report for the
aggregate view of transfers.

Gateway members are planning the expanded installation of phasor measurement equipment, at
various plants and substations around the subregion, to enhance the collection of pre- and post-
disturbance generation and transmission data. These installations, in combination with other such
phasor-measuring equipment installed elsewhere on the interconnected system, may provide
another tool to operations personnel in assessing immediate near-term conditions on the


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interconnected system. Some utilities are investigating the implementation of a "smart grid" on
their systems, and the use of D-FACTS devices on its transmission system for loss reduction,
transmission system flow control, and voltage control.

Operational Issues
Based on studies and previous winter operating experience, reliability problems are not expected
on the Gateway transmission system for this winter. Operating conditions similar to last year are
expected, and near-term operating studies performed to date have not identified any major
reliability concerns. As unique operating problems have not been experienced and reliability
concerns have not been identified in studies, no special operating studies have been performed.
Entities reported that they have capacity and energy plans in place for emergencies or problems
caused by extreme weather conditions. Midwest ISO also has procedures in place to address
reliability concerns.

Utilities reported greater operating concerns during off-peak or light load conditions than for
winter peak conditions. During off-peak periods when generation is plentiful in the Midwest,
heavy transmission flows to the east and south often occur as the available coal, nuclear, and
wind capacity can be used to economically displace gas and oil-fired generation. Generation in
the Gateway subregion contributes to these heavy line loadings. At times, the transmission
system limits the amount of power that can be economically transferred, and Midwest ISO must
redispatch some generation through LMP and security constrained economic dispatch to keep
transmission flows within facility ratings. TLR may need to be called if the local generation
redispatch is ineffective.

The Renshaw-Livingston 161 kV tie line between SIPC and Big Rivers Electric Cooperative is
an example of this phenomenon. The line has been reported to have occasional heavy loading
during off-peak times, and TLR has been requested in an attempt to alleviate the line loading.
This constraint does not impact the reliability of the bulk power system. Other entities within the
subregion are not anticipating constraints that will affect reliability on the system.

During light load or minimum load conditions, too much generation may be operated causing
overgeneration in the system. The continuing addition of variable resources, including wind
generation in the subregion and throughout the Midwest exacerbates the problem. Some entities
have reported that variable resources, particularly wind, have presented new operating challenges
at minimum load levels, as Midwest ISO has issued several minimum generation alerts,
warnings, and emergencies. As a result, some entities within the subregion have responded by
taking generating units off-line and by reducing online units to absolute minimum levels to
comply with Midwest ISO orders. No significant reliability concerns have been experienced or
are expected due to Demand Response, minimum demand levels, and over generation resulting
from the integration of variable resources. .

Environmental and regulatory restrictions are a factor for some entities within the subregion. One
Gateway utility reported the loss of net generation capability of approximately 20 MW due to the
installation of Selective Catalytic Reduction (SCR) devices. Other entities reported that their gas-
fired CTGs, which are typically used to cover summer peak load conditions, are limited by
emissions to 950 hours of operation per year because of the type of regulatory air permit



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acquired. CTG hours of operation are reviewed by individual companies on a continuing basis
and are considered during resource planning and for availability to the Midwest ISO market.
Although environmental restrictions exist for some units around the subregion, to date, these
restrictions have not limited or prevented the use of the units for reliability or economic dispatch
situations. Overall, Gateway entities do not expect unusual operating conditions which could
impact reliability for the upcoming winter season.

Reliability Assessment Analysis
The projected January 2010 winter peak Reserve Margin for the utilities in the subregion is 39.8
percent, which is much lower than last year’s peak (January 2009) Reserve Margin at 66.4
percent. The decrease is largely due to more complete capacity reporting using NERC’s new
definitions for 2009/2010. Entities within the SERC Region perform individual studies to assess
their individual systems. Some entities within the Region participate in various study groups to
assess the reliability of the system on a near-term and long-term basis. Some utilities have filed
integrated resource plans with their local commissions, but there are no required state Reserve
Margins for the utilities in the subregion. Although Gateway subregion utilities have traditionally
tried to maintain a planning Reserve Margin of at least 15 percent, this requirement has been
reduced to a minimum of 12.7 percent based on the latest loss-of-load-expectation studies
performed by Midwest ISO. The Illinois Power Authority, which procures capacity resources for
Ameren Illinois Utilities, has no long-term capacity contract requirements at this time but would
follow the planning reserve requirements of Midwest ISO. The capacity and reserves acquired
for summer 2009 will be more than adequate to cover the load for the winter 2009/2010.

Midwest ISO resource adequacy and operational procedures are located within the Midwest ISO
Resource Adequacy Business Practice Manual106. A 50/50 load uncertainty was used in their
latest LOLE analysis. A 90/10 load forecast was not done; however, if it were done it is not
expected to increase the reserve requirements significantly due to the geographical size and load
diversity within Midwest ISO. The use of a 90/10 forecast would increase demand by about 5
percent above the 50/50 forecast level for the Gateway subregion. Capacity resources in the
Gateway subregion are expected to be adequate for the upcoming peak-demand winter season.

Most load-serving entities within this subregion are members of the Midwest ISO Contingency
Reserve Sharing Group. Entity membership within this group also ensures coverage on any
short-term emergency imports, generation tests, Demand Response, or renewable portfolio
procedures (variable resource requirements can be found under the Midwest ISO Resource
Adequacy Business Practice Manual). Other entities use contracts with various companies to
supply them with access to variable generating resources and renewable energy. Midwest ISO is
studying the impacts of integrating large amounts of variable resources on the system. This issue
of wind integration has been elevated to a higher level as the amount of wind generation is
expected to increase dramatically in Midwest ISO and throughout the midwest over the next
several years.

Fuel supply in the area is not expected to be a problem and policies considering fuel diversity
and delivery have been put in place throughout the area to ensure that reliability is not impacted.

106
   Midwest ISO Resource Adequacy Business Practice Manual can be found at:
  http://www.misostates.org/OMSModuleEadopted27NOV07FINAL%20.pdf



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Several entity policies take into account contracts with surrounding facilities, alternative
transportation routes, and alternative fuels. These practices help to ensure balance and flexibility
to serve anticipated generation needs. Communication maintained with suppliers to ensure
adequate supplies are available and all potential problems are known by all parties as soon as
possible.

Members within the Gateway subregion individually perform dynamic and static reactive power
studies as part of their annual assessment to comply with NERC Standards TPL-001 through
TPL-004. Some generating entities have reported that the procedures of the reactive power
studies are performed specific to the NERC Standard MOD-025 testing parameters. Because
load power factors are generally higher during the winter season than during the summer season,
and the loads are generally lower, this reduces the reactive power requirements in the subregion
during the winter period. For these reasons, most entities reported that no specific tests were
performed for the winter 2009/2010 period.




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Southeastern

Demand
The actual 2008/2009 winter peak for utilities in the Southeastern subregion was 43,969 MW.
Total aggregate internal demand for the 2009/2010 winter season is forecast to be 41,740 MW;
this is 675 MW (1.6 percent) lower than the forecast 2008/2009 winter peak demand of 42,415
MW. This projection is based on average historical winter weather and is the sum of non-
coincident forecast data reported by utilities in the SERC Region. Some entities have lowered
their forecasts due to the economic recession. The actual winter peak demand does not take into
account energy efficiency, diversity, stand-by load, or additions for non-member load, whereas
the internal peak demand values account for these factors.

Most forecast assumptions are based on median (50/50) weather conditions. One Southeastern
entity reported that these particular weather conditions are determined by using hourly dry bulb
temperatures for six weather stations that are strategically located within their service area. A
single “weighted average” is calculated for each hour. The weighted averages are derived based
on the amount of load served near the weather stations as well as taking into consideration the
weather patterns that cross the company’s territory. Entities factor historical years of weather
data into their modeling processes to determine a median “expected normal” winter peak
demand. This year’s forecast was reported to be based on actual data; the peak demand models
have been updated to better reflect current conditions.

Demand response programs are typically not used to reduce peak demand in the winter periods.
External adjustments are normally made to the load and energy forecast for demand side
programs; however, the majority of demand adjustments are not applied during winter months as
most programs are designed for application during summer months. Adjustments are based on
price response to certain demand-side programs in the system. The subregion has a mix of
various demand-response programs including interruptible demand, customer curtailing
programs, and direct load control (irrigation, A/C and water heater controls). Entities within this
subregion reported 4.3 percent of Total Internal Demand as Demand Response that can reduce
peak demand. To address M&V, some entities have reported that two-way communication
devices have been used as a functionality to allow customers to perform M&V at any desired
level. An entity also reports small pilot tests scheduled for 2010 regarding HVAC cycling and
direct load for pool pumps.

Utilities within the subregion have a variety of energy-efficiency programs. Residential programs
may include home energy audits, compact fluorescent light bulbs, electric water heater
incentives, heat pump incentives (geothermal or ground-source), EPA-approved ventilation and
air-conditioning (HVAC) technology, energy-efficient new home programs, Energy Star
appliance promotions, loans or financing options, weatherization, programmable thermostats,
and ceiling insulation. Commercial programs including energy audits, lighting programs, and
plan review services are available to various customers within this subregion. Some energy-
efficiency programs are measured by engineering models. The Conserve101 energy-
efficiency/conservation program was put in place by one utility in 2009 to educate residential
consumers about no-cost/low-cost methods they can use in order to reduce their monthly
household electric use and to provide methods on how to wisely use electricity in their home.



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These methods are simple to implement, inexpensive, and non-intrusive to the consumers’
lifestyles. Other programs such as business assistance/audits, weatherization assistance for low-
income customers, residential energy audits, and comfort advantage energy-efficient home
programs promote reduced energy consumption, supply information, and develop energy-
efficiency presentations for various customers and organizations. Utilities also work with the
State Energy Division on energy-efficiency planning efforts. Training seminars addressing
energy efficiency, HVAC sizing, and energy related end-use technologies are also offered to
educate customers. External adjustments are made to the load and energy forecast for energy-
efficiency programs. Energy efficiency and Demand Response adjustments are not applied
during winter months as most programs are designed for application during summer months.

The 2009/2010 winter demand forecast is based on normal weather conditions and uses
normal/median weather, normal load growth and conservative economic scenarios. To assess
variability, some subregional entities develop forecasts using econometric analysis based on
approximately 30 to 40 year weather (normal, extreme, and mild), economics and demographics.
Others within the subregion use the analysis of historical peaks, Reserve Margins, and demand
models to predict variance. One entity who used demand models reported that winter peaks are
projected for each of these weather years and then the peaks are ranked from the mildest to the
most extreme. The median peak is typically used in its forecasting process to best determine
normal weather conditions. The median forecast has been used in past studies because the mean
and midpoint forecast tend to be impacted by particular values obtained in the extreme weather
years, primarily during the 1980’s and the winter of 2003. Variables are compared to actual
weather conditions and adjusted to determine a forecast that this normal or extreme for the
service area. Reserves are built into the system to take into account factors such as weather
volatility and load forecast error. Companies continue to study the impacts of all factors to
perfect their processes in determining peak demand.

Generation
Utilities within the Southeastern subregion expect to have the following aggregate capacity on-
peak to help meet demand during this time period.
            Southeastern Table 1: Winter 2009/2010 Capacity Breakdown
           Capacity Type                        Winter 2009/2010
           Existing-Certain                          58,528 MW
             Wind                                          0 MW
             Solar                                         0 MW
             Biomass                                       0 MW
             Hydro                                     3,300 MW
           Existing-Other                              7,905 MW
             Wind                                          0 MW
             Solar                                         0 MW
             Biomass                                       0 MW
             Hydro                                         0 MW
           Energy Only                                     0 MW
           Existing Inoperable                             0 MW
           Future-Planned                                350 MW
           Future-Other                                  426 MW


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For planning purposes, potential future biomass generation is included in the Integrated Resource
Plan at half of the nameplate capacity for converted boilers and close to nameplate for units
receiving new boilers. Currently no variable resources are planned for the upcoming season.

Hydro conditions are expected to be normal. Some entities have reported that, based on current
weather and operational forecasts for this winter, the output of total hydro-generation will be
below normal. The major weather factor contributing to this would be the forecasted
strengthening of El Nino. If lower than normal rainfall occurs, it is anticipated that reservoirs can
be managed to meet the short-duration peak demand that is typical of winter hydro-peaking
operations. However, recent prolonged heavy rain in the subregion area has likely addressed any
below normal hydro concerns.

Utilities in the subregion are not experiencing or expecting conditions (i.e., weather, fuel supply,
fuel transportation) that would reduce capacity for the upcoming season. Supplies are expected to
be adequate and communications are in place to reduce any unanticipated impacts. The utilities
anticipate only regular scheduled generation maintenance for the winter season totaling 315 MW
in the peak month of January 2010. Although multiple large units are planned to have
overlapping outages during other months of this winter season, plans are already taken into
account to minimize impacts on reliability. These outage plans are routinely monitored and
revised if necessary to ensure availability of adequate reserves. The system has ample reserves to
replace the outages. System winter season loads typically peak at approximately 85 percent of
average summer peak and reserve level are further increased due to cost-saving capacity
additions and load erosion driven by the economic recession. There are no unit retirements
expected during the 2009/2010 winter season.

Capacity Transactions on Peak
Southeastern utilities reported the following imports and exports for the upcoming 2009/2010
winter season. The majority of these imports/exports are backed by firm contracts, with none
associated with LDCs. These firm imports and exports have been included in the Reserve Margin
calculations for the subregion. None of the reported imports or exports are based on partial path
reservations. Overall, the subregion is not dependent on outside imports or transfers to meet the
demands of its load.
                 Southeastern Table 2: Subregional Imports/Exports
          Transaction Type                         Winter 2009/2010
          Firm Imports (Internal Subregion)            624 MW
          Firm Exports (Internal Subregion)              0 MW
          Non-Firm Imports (Internal Subregion)          0 MW
          Non-Firm Exports (Internal Subregion)          0 MW
          Expected Imports (Internal Subregion)          0 MW
          Expected Exports (Internal Subregion)          0 MW
          Firm Imports (External Subregion)          1,901 MW
          Firm Exports (External Subregion)          2,780 MW
          Non-Firm Imports (External Subregion)          0 MW
          Non-Firm Exports (External Subregion)          0 MW
          Expected Imports (External Subregion)          0 MW
          Expected Exports (External Subregion)          0 MW


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Entities do not rely on resources outside of the Region. However, some of the companies within
the subregion participate in the SPP reserve sharing group (external to subregion) or market
models to acquire resources. Forced outage rates, weather anomalies, and load forecast errors are
continuously monitored to maintain reliability.

Transmission
The following table shows bulk power system transmission that either has entered or is expected
to enter service between the 2008/2009 and 2009/2010 winter seasons.

     Southeastern Table 3: Transmission Expected In-service Since 2008/2009
                                    Winter
   Transmission         Transmission   In-Service   Concerns in     Reliability Issues   Mitigation Plans to
   Project Name             Type         Date(s)     meeting         with In-Service      Address Delay
                           (Under                   In-Service        Date Delay?
                       Construction,                  Date?             (yes/no)
                         Planned, or                 (yes/no)
                        Conceptual)
 Calvert SS -         In-service       03/12/2009      NA                  NA                   NA
 Tensaw SS
 Tensaw SS - TK       In-service       03/24/2009      NA                  NA                   NA
 Rolling Mill
 Tensaw SS - TK       In-service       03/24/2009      NA                  NA                   NA
 Rolling Mill
 Tensaw SS - TK       In-service       06/24/2009      NA                  NA                   NA
 EAF
 Tensaw SS - TK       In-service       06/24/2009      NA                  NA                   NA
 EAF
 Tensaw SS - TK       In-service       06/24/2009      NA                  NA                   NA
 EAF
 Bucks SS -           Under            10/06/2009       No                 No                   NA
 Tensaw SS            Construction
 Bio - Airline        In-service          NA           NA                  NA                   NA
 McConnell Road -     In-service          NA           NA                  NA                   NA
 Woodlore
 Woodlore -           In-service          NA           NA                  NA                   NA
 Battlefield
 Nebo - New           Under            11/30/2009       No                 No                   NA
 Georgia              Construction
 Chevron Cogen -      In-service       11/28/2008      NA                  NA                   NA
 Chevron PRCP
 Bowen - Villa        In-service          NA           NA                  NA                   NA
 Rica Primary 500
 kV line
 conversion to 230
 kV
 Black Pond Tap -     In-service       08/04/2009      NA                  NA                   NA
 Black Pond DS
 161 kV line
 Cavender Drive       In-service          NA           NA                  NA                   NA
 230 kV SS
 Battlefield – Frey   Under            11/15/2009       No                 No                   NA
 Road 230 kV line     Construction
 Frey Road 230 kV     Under            11/15/2009       No                 No                   NA
 SS                   Construction


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     Southeastern Table 3: Transmission Expected In-service Since 2008/2009
                                    Winter
   Transmission       Transmission    In-Service   Concerns in     Reliability Issues   Mitigation Plans to
   Project Name           Type          Date(s)     meeting         with In-Service      Address Delay
                         (Under                    In-Service        Date Delay?
                      Construction,                  Date?             (yes/no)
                       Planned, or                  (yes/no)
                      Conceptual)
 Bethabara           Under            12/1/2009        No                 No                   NA
 230/115 kV          Construction
 substation
 Bethabara –         Under            12/1/2009        No                 No                   NA
 Georgia Square      Construction
 115 kV line
 Thomasville         Under            12/31/2009       No                 No                   NA
 Primary 230kV       Construction
 and 115kV bus tie
 breakers
 East Pelham         In-Service       9/30/2009       NA                  NA                   NA
 230kV substation

Several significant bulk power transmission facilities have entered service since the previous
winter assessment. Examples of these are the Bonaire Primary and East Social Circle 230/115
kV transformer upgrades expected to be in-service June 2009 and conversion of the Bowen-Villa
Rica 500kV line to 230kV operation by the end of 2009. All of these projects are expected to
improve reliability with no concerns with the in-service dates.

Entities coordinate maintenance outages around the subregion. All planned transmission facility
outages are thoroughly studied based on forecasted system conditions and evaluated for potential
reliability impacts. When required, procedures are developed to mitigate potential reliability
impacts. No significant transmission line outages are scheduled for this winter season except for
115kV outages associated with the Plant McIntosh Units 4 & 5 addition project. However, these
have been scheduled to avoid winter peak conditions and a detailed system impact study did not
identify any reliability issues for the temporary system configuration.

The utilities in the subregion have not identified any anticipated unusual transmission constraints
that could significantly impact reliability. However, to further improve reliability, some entities
within the subregion have reported efforts to install more Remote Controlled Motor Operated
Switches (RCMOS) on the transmission system and replace electromechanical protective relays
with microprocessor relays. The deployment of these relays will provide for additional analysis
of events and allow faster clearing times using communication-assisted schemes.

Operational Issues
Entities within the subregion reported to have performed routine system studies for the
2009/2010 winter season which include the most up-to-date information regarding transmission
status, generation status, and load forecasts. The studies are updated on a monthly basis to
capture operating conditions for 12 months into the future. The current operational planning
studies do not identify any unique operational problems. Special operating studies are not
commonly performed unless dictated by changing system conditions. Most entities do not
integrate any variable resources into their generation supply portfolios; therefore, they do not


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have special operating procedures with regard to variable resources.

Southeastern entities have not identified any reliability concerns related to environmental or
regulatory restrictions, Demand Response or minimum demand and over generation resulting
from variable resources. Unusual conditions are not expected to be a concern for the upcoming
season. However, some parts of the subregion routinely experience significant loop flows due to
transactions external to the service area. The availability of large amounts of excess generation
within the southeast results in fairly volatile day-to-day scheduling patterns. The transmission
flows are often more dependent on the weather patterns, fuel costs, or market conditions outside
the service area, rather than by loading within the various control area. Significant changes in gas
pricing dramatically impact dispatch patterns. All transmission constraints identified in current
operational planning studies for the 2009/2010 winter can be mitigated through generation
adjustments, system reconfiguration, or system purchases.

Reliability Assessment Analysis
The projected Reserve Margin in the Southeastern subregion is 46.8 percent compared to 42.9
percent last year. Entities within the subregion reported that Reserve Margins have been slightly
affected due to the economic recession and the corresponding downward sloping load forecast.
Even though entities have reported that the State of Georgia requires utility companies to
maintain 15 percent long-term capacity reserves, the Southeastern subregion as a whole does not
have a single target margin or guideline. Individual company analyses account for planned
generation additions, retirements, and deratings due to environmental control additions, load
deviations, weather uncertainties, forced outages, and other factors. Resource adequacy is
determined by extensive analysis of costs associated with expected unserved energy, market
purchases and new capacity. These costs are balanced to identify a minimum cost point which is
the optimum Reserve Margin level.

The latest resource adequacy studies show that Reserve Margin for winter 2009/2010 is expected
to have a wide range of Reserve Margins between 15 percent and 75 percent for utilities within
the subregion. It is not expected to drop below 15 percent for any single entity due primarily to
winter peaks within the subregion being only a portion of the subregion’s summer peak. Even
though utilities use purchases and reserve sharing agreements, they are not relying on resources
from outside the Region or subregion to meet load. Additionally, post-peak assessments are
conducted on an as-needed basis, to evaluate system capability resulting from an extreme-peak
season. Results indicate that existing and planned resources exceed the target Reserve Margin for
the upcoming season; therefore, no significant changes in planned external resources to establish
the margins during these periods are anticipated.

The fuel supply infrastructure, fuel delivery system, and fuel reserves are all adequate to meet
peak gas demand. As with other subregions within SERC, communications with suppliers and
transportation agents are considered to be strong. For example, one entity reported receiving
daily email updates/alerts from Florida Gas Transmission regarding any problems or potential
problems that may affect the transport of natural gas to their facilities. Daily communications are
also common between gas production companies and suppliers through which entities can be
made aware of any potential problems.




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Various companies within the subregion have firm transportation diversity, gas storage, firm
pipeline capacity, and on-site fuel, oil, and coal supplies to meet the peak demand. Many utilities
reported that fuel vulnerability is not an expected reliability concern for the winter reporting
period. The utilities have a highly diverse fuel mix to supply its demand, including nuclear, PRB
coal, Eastern coal, natural gas, and hydro. Some utilities have implemented fuel storage, coal
conservation programs, and various fuel policies to address this concern. Policies have been put
in place to ensure that storages are filled well in advance of hurricane season (by June 1 of each
year). These tactics help to ensure balance and flexibility to serve anticipated generation needs.
Relationships with coal mines, coal suppliers, daily communications with railroads for
transportation updates, ongoing communications with the coal plants, and constant
communication with The Energy Authority ensure that supplies are adequate and potential
problems are communicated well in advance to enable adequate response time. The Energy
Authority maintains daily contact with suppliers, pipelines, and other utilities that may be able to
assist in an emergency.

The Southeastern subregion does not have subregional criteria for dynamics, voltage, or small
signal stability; however, various utilities within the subregion maintain individual criteria to
address any stability issues. Appropriate entities perform annual transmission assessments that
analyze system voltage and reactive performance under contingencies as required by the TPL
Reliability Standards, including system stability studies to analyze the dynamic characteristics of
the system. Current year studies show that reactive resources are adequate for base case as well
as contingency conditions and have not identified any deficiencies that would need to be
addressed for winter 2009/2010.

In order to minimize system reliability concerns for this winter, entities within the subregion plan
to perform preventative maintenance on units during the off-peak period, continue to perform
operating studies ahead of the season and continue routine maintenance on transmission
equipment on the system. These steps should help to avoid negative impacts on the system and
improve the performance of the system for upcoming seasons.




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VACAR

Demand
The actual 2008/2009 winter peak demand for the utilities in the VACAR subregion was
59,586MW. The total aggregate internal demand for the 2009/2010 winter season is forecast to
be 57,210 MW based on normal weather conditions; this is 474 MW (0.8 percent) lower than the
forecast 2008/2009 winter Total Internal Demand of 57,684 MW. The actual winter peak
demand does not take into account energy efficiency, diversity stand-by load, or additions for
non-member load, whereas the internal peak demand values account for these factors. A variety
of reasons account for the decreases in demand from last year’s reporting to this year. Some of
those reasons are due to economic recession, an increase in load management, regressing
demographics, a loss of large customers, winter peak adjusted to normal peaking temperatures,
and the slowdown in growth in residential and commercial sales. Slowed growth trends are
expected to continue into 2010. Projected demands have been adjusted to account for downward
and normalizing weather conditions.

As with other subregions within SERC, entities within VACAR use multiple years of historical
weather data to develop weather variables for forecasting peak demands. One entity reported that
it factors in the sum of heating degree hours on the winter peak day and the heating degree hours
on the day before the winter peak day as two weather variables, to assess forecasted winter peak
demands. Another factor that is commonly used around the subregion to assess forecast is
economic projections. Economy.com seems to be a common economic consulting firm for the
development of SERC demand forecasts.

The utilities in the subregion have a variety of programs offered to their customers that support
energy efficiency and Demand Response. Some of the programs are current energy-efficiency
and DSM programs that include interruptible capacity, load control curtailing programs,
residential air conditioning direct load, energy products loan program, standby generator control,
residential time-of-use, Demand Response programs, Power Manager PowerShare conservation
programs, residential Energy Star rates, Good Cents new and improved home program,
commercial Good Cents program, thermal storage cooling program, H20 Advantage water heater
program, general service and industrial time-of-use, and hourly pricing for incremental load
interruptible, etc. These programs can be used to reduce the affects of winter peaks and are
considered as part of the utilities’ resource planning. Historically, load management is not
needed or anticipated to be used in the winter, but entities are committed to the use of these
programs as part of a long-term, balanced energy strategy to meet future energy needs. Winter
assessment reporting for the VACAR Region shows that 3 percent of Total Internal Demand as
Demand Response can be used to reduce peak demand.

Future M&V analyses along with new product development and ongoing product management
decisions are used to incorporate updated information into the resource plans. Some of the
approaches of M&V are: monitoring parameters and variables, monitoring interval and period,
measurement equipment specifications, measurement data collection and management, data
validation, editing and estimating plan, accuracy of monitoring and verification method, savings
uncertainty and confidence level, and factors most uncertain or difficult to quantify. Some of the
calculations and adjustments during this process account for verification of equations,
calculations, the analysis of procedures for baseline and post-installation demand and energy


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consumption, performance model development, population description, sample size calculations,
methods of sampling, demand and energy savings calculations, and the method of adjustments to
the data. More information of this method can be found in the PJM manual 18B.

To assess demand variability, some utilities within the subregion use a variety of assumptions to
create forecasts. These assumptions are developed using economic models, historical weather
(normal and extreme) conditions, energy consumption, and demographics. Others assess
variability of forecast demand by accounting for Reserve Margins through continuous evaluation
of inputs used in forecasting processes, high and low forecasts, tracking of forecast versus actual,
and multiple forecasts per year.

Generation
Companies within the VACAR subregion expect to have the following aggregate capacity on
peak. This capacity is expected to help meet demand during this time period.

                VACAR Table 1: Winter 2009/2010 Capacity Breakdown
                Capacity Type                Winter 2009/2010
                Existing-Certain                  73,281 MW
                  Wind                                  0 MW
                  Solar                                 0 MW
                  Biomass                             175 MW
                  Hydro                             3,889 MW
                Existing-Other                      1,571 MW
                  Wind                                  0 MW
                  Solar                                 0 MW
                  Biomass                               0 MW
                  Hydro                                 0 MW
                Energy Only                            48 MW
                Existing Inoperable                    43 MW
                Future-Planned                         46 MW
                Future-Other                            0 MW

Very few entities within the VACAR subregion have reported use of biomass as a resource
within their portfolios within the subregion. The table above shows that 175 MW of biomass is
captured as a resource in the subregion. One of the entities within the subregion reported that this
capacity (namely, landfill gas) is calculated from published unit ratings and is commensurate
with actual operating capabilities of these resources.

Hydro conditions are expected to be normal. Reservoir levels are sufficient to meet peak demand
and daily energy demand throughout the winter; however, entities are recovering from the prior
year’s drought. Some entities have reported that the effects of the prior year’s drought have been
an impact on a small run of river hydro units that make up a small portion of total generating
capacity. If the drought conditions continue, approximately 576 MW of pumped storage and 415
MW of fossil generation could be potentially impacted. Currently, companies do not expect to
experience capacity reductions. They plan to continue to monitor water levels and will take
appropriate actions if these levels get to the point where capacity could be affected. Coupled with


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other resources in resource portfolios, projected hydro generation and reservoir levels are
expected to be adequate to meet both normal and emergency energy demands for the 2009/2010
winter. There are no known or expected conditions that would reduce capacity in the VACAR
subregion. No peak capacity reductions are expected for the coming season.

Significant generators within the subregion are not expected to be out of service or retired.
Planned outage schedules and retirements are coordinated ahead of time with the transmission
operators to preserve the reliability of the bulk power system.

Capacity Transactions on Peak
Utilities within the VACAR area reported the following imports and exports for the upcoming
2009/2010 winter season. These sales and purchases are external and internal to the Region and
subregion and help to ensure resource adequacy for the utilities within the VACAR area.

                     VACAR Table 2: Subregional Imports/Exports
                                                        Winter
           Transaction Type
                                                     2009/2010
           Firm Imports (Internal Subregion)             0 MW
           Firm Exports (Internal Subregion)             0 MW
           Non-Firm Imports (Internal Subregion)         0 MW
           Non-Firm Exports (Internal Subregion)         0 MW
           Expected Imports (Internal Subregion)         0 MW
           Expected Exports (Internal Subregion)         0 MW
           Firm Imports (External Subregion)         1,687 MW
           Firm Exports (External Subregion)           737 MW
           Non-Firm Imports (External Subregion)         0 MW
           Non-Firm Exports (External Subregion)         0 MW
           Expected Imports (External Subregion)         0 MW
           Expected Exports (External Subregion)         0 MW

Contracts that were identified are backed by both firm generation and firm transmission
commitment. VACAR entities reported that approximately 455 MW are associated with LDCs.
The majority of the reported contracts are considered to be make-whole. Outside imports or
transfers of capacity from other Regions or subregions are not expected to be relied on to meet
emergency imports and reserve sharing requirements for the upcoming season. However, some
VACAR companies have reported that they are a member of the VACAR Reserve Sharing
Group and occasionally use their participation to meet emergency import and reserve
requirements. This arrangement is based upon a collection of bilateral contracts between Reserve
Sharing Group members within the VACAR subregion of SERC.

Transmission
Several improvements to transmission facilities of utilities within VACAR have been completed
or planned to be completed by the winter of 2009/2010. The following table shows bulk power
system transmission categorized as under construction, planned or conceptual that is expected to
be in-service for the upcoming 2009/2010 winter season since 2008.



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 VACAR Table 3: Expected Under Construction, Planned, Conceptual Transmission
  Transmission        Transmission    In-Service   Concerns in   Reliability Issues   Mitigation Plans
  Project Name            Type         Date(s)       meeting      with In-Service     to Address Delay
                         (Under                     In-Service     Date Delay?
                      Construction,                   Date?          (yes/no)
                       Planned, or                   (yes/no)
                      Conceptual)
 Clarendon -         Planned           02/2010        N/A               No                 None
 Rosslyn
 Bristers -          In-service        05/2009        N/A              N/A                  N/A
 Gainesville
 Rockingham -        Under            06/01/2009       No               No                 None
 Wadesboro           Construction
 Bowman School
 Nantahala Hydro -   In-service        02/2009        N/A              N/A                  N/A
 Santeetlah and
 Fontana
 Pepperhill          In-service       07/15/2009      N/A              N/A                  N/A
 230/115 kV
 Substation
 Transformer w/
 Terminals
 Lake Murray –       In-service       11/13/2008      N/A              N/A                  N/A
 Lexington
 Junction
 Westvaco –          In-service       10/15/2008      N/A              N/A                  N/A
 Thomas Island
 115 kV extension

Several other improvements were reported within the subregion to improve reliability. Examples
of these improvements are Graniteville - Aiken #1 115 kV upgrade to 1272 ACSR and Goose
Creek - Ashley Phosphate 115 kV upgrade to 1272 ACSR. A 230-115 kV transformation
(90/120/150 MVA) was established at the Shamrock 115 kV Switching Station, providing local
transmission service support from the Cross-Aiken 230 kV Line. Close coordination between
construction management and operations planning ensures schedule requirements and
completion requirements are well understood. Several other large-scale construction projects are
planned and implemented in phases around seasonal peak load periods to mitigate line clearances
and non-routine operating arrangements during higher seasonal load periods.

There are no concerns with the projected in-service dates with the reported improvement
projects. However, some existing transmission lines are expected to be out of service this winter.
The McGuire-Harrisburg 230kV line (Mecklenburg White line) is anticipated to be out of service
for much of the 2009/2010 winter season. Studies have indicated that there are no reliability
concerns with this extended outage. Companies will maintain reliability by re-dispatch, re-
configuration, market-to-market re-dispatch with Midwest ISO, and NERC TLR if necessary.
Transmission maintenance schedules are carefully reviewed and evaluated to insure reliability
concerns are addressed prior to seasonal peak periods.

Regional studies are performed on a routine basis both internally as well as externally.
Coordinated single transfer capability studies with external utilities are performed quarterly
through the SERC NTSG. Projected seasonal import and export capabilities are consistent with


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those identified in these assessments. Constraints that are external to the SERC subregion are
evaluated as part of the SERC East RFC seasonal study group efforts. No transmission
constraints have been identified that are anticipated to significantly impact reliability.

Entities within the subregion are monitoring industry activities involving the installation and use
of synchro phasors and have the capability to retrofit many existing relays to convert them to
Phasor Measurement Units (PMU). Smart grid technology is also being investigated for
installation around the subregion.

Operational Issues
To assess operating issues and studies, entities reported that they forecast typical/severe weather
cases and plans and secure additional firm capacity on a seasonal basis for typical/severe demand
forecasts. Other short-term firm purchases with firm transmission service are made on an as-
needed basis if situations on the system occur. Entities within this subregion participate in SERC
study groups that assess the subregion on a seasonal basis. An assessment within this study can
be found in the SERC NTSG 2009/2010 Winter Reliability report which is submitted to FERC
via FERC filings. For the projected 2009/2010 winter peak season, study efforts do not identify
any unique or significant operational problems that would impact the reliable operation of the
bulk transmission system.

VACAR entities have not identified special operating problems from the integration of variable
resources. Additionally, they do not anticipate any reliability problems resulting from minimum
demand over generation due to variable resources, Demand Response, or unusual operating
conditions for the upcoming winter season. There are no anticipated local environmental and/or
regulatory restrictions that could potentially impact reliability.

Reliability Assessment Analysis
The projected aggregate Reserve Margin of the utilities within the VACAR area is 33.9 percent,
compared to 29.9 percent last winter. Capacity in the subregion should be adequate to supply
forecast demand.

Although some utilities within this subregion adhere to North Carolina Utility Commission
regulations, VACAR entities individually use various methods to establish Regional/subregional
Reserve Margin criterions. There currently is not a target margin for the subregion. Companies
have reported using techniques such as: Loss-Of-Load Expectation studies (1d/10y), generation
resource plans (plant availability, plant forced outages, VACAR reserve sharing agreement,
adverse weather impacts, loss of load probability, and the sizes of units), multi-regional studies,
and historical performances. There are a number of increased risks involved with these factors
that need to be considered with regard to Reserve Margin targets. These risks include: 1) the
increasing age of existing units on the system; 2) the inclusion of a significant amount of
renewables (which are generally less available than traditional supply-side resources) in the plan
due to the enactment of the REPS in North Carolina; 3) uncertainty regarding the impacts
associated with significant increases in company energy efficiency and DSM programs; 4) longer
lead times for building baseload capacity such as coal and nuclear; 5) increasing environmental
pressures which may cause additional unit derates and/or unit retirements; and 6) increases in
derates of units due to drought conditions. Each of these risks would negatively impact the



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resources available to provide reliable service to customers. Companies will continue to monitor
these risks in the future and make any necessary adjustments to the Reserve Margin target in
future plans.

Resource adequacy is assessed by forecasted normal/severe weather cases with additional firm
capacity (existing, future, and outage models included) and forecasted demand plans on a
seasonal basis. In addition, forecast of peak demand is made under a variety of both weather and
economic conditions as required under RUS 1710 requirements. From this analysis, resources are
planned accordingly. This year’s studies are expected to be adequate based on the current
forecast, generation, and demand side resources.

Communication amongst entities and the fuel industry is considered to be strong. On an ongoing
and regular basis, supply adequacy, whether the fuel be oil-based or gas-based, is discussed and
assessed in conjunction with suppliers taking into account historical and projected demand. In
those discussions, issues such as market trends, vendor performances, and associated potential
resource constraints are framed to ensure potential interruptions can be mitigated and addressed
in a timely manner. Utilities have reported that their generation facilities are expected to
maintain enough diesel fuel to run the units for an order cycle of fuel. Fuel supply or delivery
problems during the projected winter are not anticipated, as coal demand is expected to be
somewhat lower in 2009/2010 and general demand for rail capacity is down as well. Coal
stockpiles are adequate to meet peak demand and to accommodate short-term supply disruptions.
Sites that have the capability to maintain redundant and diversified fuel supplies will do so in
order to be prepared to respond to various emergency and or economic scenarios. Some unit
outages were also reported to be mitigated through exchange agreements or alternative fuel
sources.

Tests are also done to assess various stability-study criterion as well as stressed system scenarios
and contingencies. Studies of this type are routinely performed, both internally and through
subregional and Regional study group efforts. Stability assessments/criteria are performed and
produced on an individual company basis within the VACAR area. Some utilities follow
practices such as using a reactive power supply operating strategy based on adopted generating
station voltage schedules and electric system operating voltages managed through real-time
Reactive Area Control Error (RACE) calculations. Through this operating practice, primary
support of generator switchyard bus voltage schedules using transmission system reactive
resources, dynamic reactive capability of spinning generators may be held in reserve to provide
near-instantaneous support in the event of a transmission system disturbance. Other utilities may
develop Reactive Transfer Interfaces to ensure sufficient dynamic MVAR reserve in load centers
that rely on economic imports to serve load. Day-ahead and real-time Security Analysis ensure
sufficient generation is scheduled/committed to control pre-/post-contingency voltages and
voltage drop criteria within acceptable predetermined limits. Reactive transfer limits are
calculated based on a predetermined back-off margin from the last convergent case. System
operations around the subregion also track the available static and dynamic reactive reserves in
real time via the EMS system as a regular process. Overall, no stability issues have been
identified as impacting reliability during the 2009/2010 winter season.

Although no expected reliability impacts are expected to occur this winter season, certain entities
have reported that they are taking steps to prevent reliability concerns for the upcoming season.


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The following techniques are expected to be used this season to avoid situations that will
compromise reliability on the system: ensuring that all forced outages have a short duration,
focus on maintaining adequate reserves, prepare and review seasonal assessment studies
configured to peak loading conditions, pre-arranging construction schedules, and taking steps to
mitigate risks.




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SPP
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand            MW                 On-Peak Capacity by Fuel Type
Total Internal Demand                            32,636
                                                                                                    Dual
  Direct Control Load Management                     33
                                                                              Gas                   Fuel
  Contractually Interruptible (Curtailable)         377
                                                                              43%                    7%
  Critical Peak-Pricing with Control                 35
                                                                                                      Other
  Load as a Capacity Resource                       203
Net Internal Demand                              31,988                                             Oil 2%
                                                                           Coal                     2%
                                                                                                  Nuclear
2008/2009 Winter Comparison                       MW    % Change           38%
                                                                                                    2%
2008/2009 Winter Projected Peak Demand           31,146     2.7%
                                                                                          Hydro
2008/2009 Winter Actual Peak Demand              32,809    -2.5%
                                                                                           6%
All-Time Winter Peak Demand                      32,361    -1.2%

2009/2010 Winter Projected Peak Capacity MW                 Margin
Existing Certain and Net Firm Transactions 49,549           54.9%
Deliverable Capacity Resources             49,972           56.2%
Prospective Capacity Resources             58,822           83.9%
NERC Reference Margin Level                  -              15.0%




Demand
Although actual demand is very dependent on the fluctuation of weather and economic
conditions, SPP’s forecasted Net Internal Demand is based on 10-year average winter weather.
This is similar to a 50/50 forecast, in which the actual weather on the peak winter day is expected
to have a 50 percent likelihood of being hotter and a 50 percent likelihood of being cooler than
the weather assumed in deriving the load forecast. The SPP RTO does not explicitly address
extreme winter conditions in the Region, as SPP is a summer peaking Region with relatively
mild winters. However, the Region has a 13.6 percent Reserve Margin to address any such
extreme winter weather scenario.

The non-coincident Total Internal Demand forecast for the 2009/2010 winter peak is 32,636
MW, a 0.5 percent decrease compared to the 2008/2009 actual winter peak monthly non-
coincident Total Internal Demand of 32,809 MW. Actual 2008/2009 winter demand was 2.6
percent higher than the forecasted projection of 31,964 MW for the same period (see Table SPP-
1). In 2009, SPP experienced an increase in demand from the normal forecast due to cooler than
expected temperatures throughout the SPP footprint.

 Table SPP-1: Winter Demand Summary
 Year                 Total Demand MW (Forecast)                   Total Demand MW (Actual)
 2008/2009            31,964                                       32,809
 2009/2010            32,636                                       N/A
Forecast data is collected from individual reporting entities as monthly peak values and summed


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to produce the SPP RTO’s total forecast. This forecasted data is aggregated to create a non-
coincident value for the SPP RTO Region. Each SPP reporting entity also provides its Demand
Response program information, then subtracts that value from its load forecast to report the net
load forecast. Based on the SPP’s reporting entity inputs, the Region has 377 MW of
interruptible demand, 33 MW of load management, 35 MW of critical peak pricing, and 203
MW of load as a capacity resource. Currently, SPP does not have its own Demand Response
program in place.

Generation
The SPP RTO expects to have 59,441 MW of total internal capacity for the 2009/2010 winter
season. This consists of Existing-Certain capacity of 48,954 MW, Existing-Other capacity of
9,520 MW, and Future-Planned capacity of 423 MW. The SPP RTO does not forecast any
variable capacity resources to come into service during the assessment timeframe. The SPP RTO
relies on its reporting entities to submit generation output (portion of variable) towards certain
capacity based on historical and actual test data. This data is routinely scrutinized by SPP staff
for accuracy. In addition, SPP performs an internal supply adequacy audit every five years to
verify and document historical and test data for all capacity resources.

The amount of expected on peak variable resources available during the 2009/2010 winter is 70
MW of wind and 2,850 MW of hydro. Guidelines for calculating the expected on peak values are
in SPP Criteria 12.1.5.3.g. No biomass capacity is reported for the winter.

Hydro capacity within the SPP RTO Region represents a small fraction (approx. 1 percent) of
total capacity resources. The SPP RTO’s operations group monitors potential fuel supply
limitations for hydro and gas resources by consulting with its generation owning/controlling
members at the beginning of each year. It is anticipated that reservoir levels will be sufficient to
meet peak and daily energy demands during the 2009/2010 winter season. The SPP RTO
footprint has been experiencing normal rainfall and is not forecasted to experience drought-like
conditions during the winter season that would prevent the Region from meeting its capacity
needs.

There are no known or forecasted conditions with the Region that would reduce capacity
resources. The SPP RTO does not anticipate significant generating units being out of service or
retired during the winter season.

Capacity Transactions on Peak
The SPP RTO has 1,339 MW of projected imports from firm contracts. None of the import contracts
are Liquidated Damage Contracts. SPP has adequate transmission capability to back firm imports
with no partial path reservations.

The SPP RTO has 744 MW of firm exports for 2009/2010 winter to Regions external to the Region.
None of the export contracts are liquidated damage contracts. SPP has adequate transmission
capability to back firm exports with no partial path reservations.

There are no non-firm contracts for the upcoming winter season.




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SPP RTO members, along with neighboring entities such as Entergy from the SERC Region,
have a Reserve Sharing Group. Members can receive contingency reserve assistance from other
SPP Reserve Sharing Group members. The SPP’s Operating Reliability Working Group sets the
minimum daily contingency reserve requirement for the SPP Reserve Sharing Group. The SPP
Reserve Sharing Group maintains a minimum first contingency reserve equal to the generating
capacity of the largest unit scheduled to be on-line.

Transmission
The SPP RTO has five projects that are either under construction or were put in-service since the
end of winter 2008/2009. There are no concerns about meeting target in-service dates. There are
two new lines in New Mexico: a 16.3 mile 230 kV line from Potash to Pecos, and a 17.5 mile
230 kV line from Seven Rivers to Pecos. Details of these two projects can be found in Table
SPP-2.

 Table SPP-2: Transmission Additions
  Transmission Project Name  Voltage  Length                 In-Service     Description / Status
                               (kV)   (miles)                   Date
 Potash Junction to Pecos   230      16.3                   06/01/09      New 230kV line

 Seven Rivers to Pecos             230          17.5        06/01/09      New 230kV lines

There is a new transformer at the Pecos Interchange to increase voltage from 138 kV to 230 kV.
At the Iatan substation south of Kansas City, Missouri a new sub (345/161) is planned to be
installed as part of Iatan unit #2. There are also plans to install a new 345/115 transformer at
Stranger Creek located northeast of Kansas City.

The SPP RTO continues to participate in the ERAG MRSWS (Eastern Interconnection
Reliability Assessment Group MRO, RFC, SERC West and SPP) inter-regional assessment. The
ERAG Steering Committee concluded that in 2009 the group will conduct a long-term 2014
summer study and will use 2008/2009 winter study results for this year’s assessment. The
2008/2009 winter study results indicated adequate import capability into SPP Region.

There is no known transmission planned to be out-of-service during the 2009/2010 winter season
that would affect Regional reliability. No transmission constraints that could significantly impact
reliability have been identified for intraregional transmission transfer capability.

From a reliability perspective, SPP expects the transfer capability for imports and exports to be
adequate.

Operational Issues
The SPP RTO formed the Wind Integration Task Force (WITF) in January 2009. The WITF is
conducting and reviewing studies to determine the impact of integrating wind generation into
SPP’s transmission system and energy markets. These impacts include both planning and
operational issues. The WITF report should lead to recommendations for developing new tools
SPP needs to properly evaluate requests for interconnecting wind generating resources to the
transmission system. The result of the WITF report is expected in the first quarter of 2010. SPP


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RTO members are not conducting any other special operating studies at this time.

SPP does not have a high level of Demand Response resources so there are no known reliability
concerns. Due to the integration of potential variable resources, additional data collection and
situational awareness tools have been put in place to begin assessing regulation and spinning
reserve needs.

Within the SPP Region there are no scheduled maintenance outages of operational concern that
will impact reliability during the 2009/2010 winter months. SPP operations staff does not
anticipate any environmental and/or regulatory restrictions that could potentially impact
reliability. There are no unusual operating conditions for the 2009/2010 winter as a result of
flowgate analysis.

Reliability Assessment Analysis
SPP Criteria requires members to maintain a minimum Reserve Margin of 13.6 percent. The SPP
Reserve Margin based on certain resources is forecasted to be 54.9 percent for 2009/2010 winter,
which exceeds the SPP minimal Reserve Margin criteria107. SPP’s projected 2009/2010 Reserve
Margin is 54.9 percent, compared to the 2008/2009 Reserve Margin of 47 percent.

SPP RTO staff recently completed Loss-of-Load Expectation (LOLE) and Expected Unserved
Energy studies. Results of these studies indicated some potential concerns during the summer
peak of 2011 conditions in the western part of the SPP system. Based on inputs received from
SPP members in that part of the footprint, the SPP RTO conducted a sensitivity analysis with
wind penetration. Many different mitigation options were examined to address this issue. As a
near-term mitigation plan, emergency import across DC ties will lower the LOLE number to an
acceptable level (i.e. less than one day in 10 years). In addition, SPP members in this area
anticipate an ATC increase on the SPS North-South Flowgate, as some transmission and
generation has recently been added. The long-term solution includes construction of a 345 kV
line from Mooreland-Woodward District EHV–Tuco. This project has been approved by the SPP
Board of Directors as a part of a Balanced Portfolio of transmission projects.108

Historically, the SPP RTO has adhered to a 13.6 percent Reserve Margin to ensure that the minimum
LOLE of one day in 10 years is met. This 13.6 percent Reserve Margin requirement is checked
annually in EIA-411 reporting as well as through supply adequacy audits of SPP members that are
conducted every five years. The last supply adequacy audit was conducted in 2007. Due to future
transmission expansion and possible imports from the Western Interconnection, SPP does not
foresee the need to raise the Reserve Margin above 13.6 percent at this time.

Due to the SPP RTO’s diverse generation portfolio, there is no concern about fuel supply being
affected by winter weather extremes. If a fuel shortage is expected, it is communicated to SPP RTO
operations staff in advance so they can take appropriate measures. In such a situation, the SPP RTO
would assess if capacity or reserves would become insufficient due to unavailable generation. If so,
SPP would declare either an EEA (Energy Emergency Alert) or OEC (Other Extreme Contingency)
and post as needed on the RCIS (Reliability Coordinator Information System).

107
      http://www.spp.org/publications/Criteria07282009-with%20AppendicesCurrent.pdf
108
      http://www.spp.org/publications/2009%20Balanced%20Portfolio%20-%20Final%20Approved%20Report.pdf



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The SPP RTO develops an annual SPP Transmission Expansion Plan (STEP) that includes a
Regional group of transmission expansion projects needed to address system reliability needs for the
next 10 years (2009/2010 through 2018/19). The latest STEP approved by the SPP Board of
Directors is available on the Engineering section of SPP.org109. In addition to STEP process, SPP
performs a dynamic stability analysis. The dynamic study completed for the 2009/2010 winter
operating condition did not indicate any dynamic stability issues for the SPP RTO Region. The SPP
RTO also performs an annual review of reactive reserve requirements for load pockets within the
Region. SPP does not have specific criteria for maintaining minimum dynamic reactive requirement
or transient voltage dip criteria. However, according to the reactive requirement study scope, which
is completed as a STEP process, each load pocket or constrained area was studied to verify that
sufficient reactive reserves are available to cover loss of the largest unit. The STEP did not indicate
any dynamic or static reactive power limited areas on the bulk power system. SPP has not conducted
an investigation on small signal damping.

SPP has an under-voltage load shedding program in western Arkansas within the AEP-West
footprint. This program targets about 140 MW of load shed during peak winter conditions to protect
the bulk power system against under-voltage events.

Because SPP is summer peaking Region, it does not conduct an operation planning study to evaluate
extreme cold weather conditions. SPP’s capacity (reserve) margin criteria is intended to address the
load forecast uncertainty.

Other Region-Specific Issues
The western part of the SPP Region continues to see a surge in wind development. Although
wind–generated capacity is currently only a small fraction of the total Region capacity
(approximately two percent) SPP will begin monitoring operational issues this winter, especially
in the western part of the SPP RTO footprint. In the coming years, the SPP RTO will develop
additional criteria, such as requiring voltage support, to handle issues native to variable wind
farm operations.

Region Description
The Southwest Power Pool (SPP) RTO Region covers a geographic area of 370,000 square miles
and has members in nine states: Arkansas, Kansas, Louisiana, Missouri, Mississippi, Nebraska, New
Mexico, Oklahoma, and Texas. SPP manages transmission in eight of those states. SPP’s RTO
footprint includes 29 balancing authorities and 47,000 miles of transmission lines. The SPP RTO has
54 members that serve over 5 million customers. SPP’s RTO membership consists of 12 investor–
owned utilities, 11 generation and transmission cooperatives, 10 power marketers, 9 municipal
systems, 5 independent power producers, 4 state authorities, and 3 independent transmission
companies. SPP experiences its peak annual demand in the summer. Additional information can be
found on the SPP Web site at http://www.spp.org.




70
     http://www.spp.org/publications/2007%20SPP%20Transmission%20Expansion%20Plan%2020080131_BOD_Public.pdf



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WECC
Regional Assessment Summary

2009/2010 Winter Projected Peak Demand        MW                   On-Peak Capacity by Fuel Type
Total Internal Demand                       133,864                                          Dual
  Direct Control Load Management                654                                          Fuel
                                                                               Gas
  Contractually Interruptible (Curtailable)   1,913                            37%
                                                                                              6%
                                                                                                     Other
  Critical Peak-Pricing with Control              5
                                                                                                      4%
  Load as a Capacity Resource                   217
                                                                       Coal
Net Internal Demand                         131,075                                               Pumped
                                                                       18%
                                                                                                  Storage
2008/2009 Winter Comparison                     MW    % Change                Hydro
                                                                                                     2%
2008/2009 Winter Projected Peak Demand        136,515    -4.0%                 28%
                                                                                           Nuclear
2008/2009 Winter Actual Peak Demand           136,592    -4.0%                               5%
All-Time Winter Peak Demand                   136,592    -4.0%

2009/2010 Winter Projected Peak Capacity MW               Margin
Existing Certain and Net Firm Transactions 193,940        48.0%
Deliverable Capacity Resources             197,834        50.9%
Prospective Capacity Resources             197,834        50.9%
NERC Reference Margin Level                   -           16.1%




Western Electricity Coordinating Council (WECC) is one of eight electric reliability councils in
North America. WECC is responsible for coordinating and promoting bulk electric system
reliability in the Western Interconnection. WECC ensures open and nondiscriminatory
transmission access among its members, provides a forum for resolving transmission access
disputes, and provides an environment for coordinating the operating and planning activities of
its members as set forth in the WECC Bylaws.

WECC is geographically the largest and most diverse of the eight Regional Entities that have
Delegation Agreements with the North American Electric Reliability Corporation (NERC).
WECC’s service territory extends from Canada to Mexico. It includes the provinces of Alberta
and British Columbia in Canada, the northern portion of Baja California in Mexico, and all or
portions of the 14 Western states in between. Due to the vast and diverse characteristics of the
Region, WECC and its members face unique challenges in coordinating the day-to-day
interconnected system operation and the long-range planning needed to provide reliable electric
service across nearly 1.8 million square miles.

WECC is divided into four subregions: The Northwest Power Pool (NWPP), the Rocky
Mountain Power Area (RMPA), the Arizona-New Mexico-Southern Nevada Area (AZ-NM-
SNV) and the California-Mexico Power Area (CAMX). The NWPP is a winter peaking
subregion with a large amount of hydro resources. Because it is winter peaking, the NWPP is
the main focus of this winter assessment. The RMPA’s peak can occur in either the summer or




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the winter, and it has a large amount of coal generation. The AZ-NM-SNV and the CAMX
subregions peak in the summer and the majority of their resources are gas fired.

WECC expects to have adequate generation capacity, reserves, and transmission for the
forecasted 2009/2010 winter peak demands and energy loads. This is attributed to the
combination of a lower demand forecast, additional generation resources, and transmission
system enhancements.

Demand
The aggregate WECC 2009/2010 winter Total Internal Demand is forecast to be 133,864 MW
(U.S. systems 110,921 MW, Canadian systems 21,548 MW, and Mexican system 1,395 MW)
and is projected to occur in December 2009. The forecast is based on normal weather and
reflects generally adverse economic conditions. The forecast is 2.0 percent below last winter’s
actual peak demand which was established under generally above normal temperatures in the
Region. The 2009/2010 winter Total Internal Demand forecast is 3.8 percent less than last
winter’s forecast peak demand of 139,135 MW for winter 2008/2009.

                     WECC REGION & SUBREGION GROWTH RATES
          WINTER PEAK                  WECC           NWPP          RMPA      AZ-NM-SNV     CA/MX

         2008/2009 Forecast            139,135        62,689       10,529         19,508    46,565
          2008/2009 Actual             136,592        65,660        10,298         17,992    42,919
          Difference (MW)                -2,543        2,971          -231         -1,516    -3,646
            Difference %                -1.83%        4.74%        -2.19%         -7.77%    -7.83%

          2008/2009 Actual             136,592        65,660        10,298        17,992    42,919
         2009/2010 Forecast            133,864        62,215         9,859        18,880    43,226
          Difference (MW)                -2,728       -3,445          -439           888       307
            Difference %                -2.00%       -5.25%        -4.26%         4.94%     0.72%

        2008/2009 Forecast               139,135       62,689       10,529        19,508    46,565
        2009/2010 Forecast              133,864         62,215        9,859       18,880    43,226
         Difference (MW)                   -5,271         -474         -670          -628    -3,339
           Difference %                   -3.79%       -0.76%       -6.36%        -3.22%    -7.17%
     Note: All actual and forecast loads are monthly non-coincident

WECC specifically directs its balancing authorities (BAs) to submit forecasts with a 50 percent
probability of occurrence. These forecasts generally consider various factors such as
population growth, economic conditions and normalized weather so that there is a 50 percent
probability of exceeding the forecast. The internal peak demand forecasts presented here are
non-coincident sums of the forecasted demands from WECC’s load-serving BAs. Comparisons
with hourly demand data indicate that WECC non-coincident peak demands generally exceed
coincident peak demands by two to four percent.

The peak demand forecasting methods used by entities vary widely and range from not making
any weather or economic assumptions to using a combination of the EPRI-developed
Residential End-Use Energy Planning System (REEPS) and the Commercial End-Use Model
(COMMEND) to forecast the commercial sector energy demands by end-use and then using an


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econometric method by major Standard Industrial Classification codes. WECC does not assess
the demand forecasting methods of the various entities.

Energy efficiency programs vary by location and are generally offered by the Load Serving
Entity (LSE). Programs include: ENERGY STAR builder incentive programs, business lighting
rebate programs, retail compact fluorescent light bulb (CFL) programs, home efficiency
assistance programs, and programs to identify and develop ways to streamline energy use in
agriculture, manufacturing, water systems, etc. For purposes of verification, some LSEs retain
independent third parties to evaluate their programs.

Demand-side management (DSM) programs offered by BAs or LSEs vary widely. The
2009/2010 internal demand forecast includes 654 MW of direct control load management, 1,913
MW of interruptible demand capability, 217 MW of load as a capacity resource and 5 MW of
critical-peak-pricing with control. Direct control load management programs largely focus on air
conditioner cycling programs while interruptible demand programs are focused primarily on
large water pumping operations and large industrial operations such as mining. For a variety of
reasons, the winter forecast DSM of 2,789 MW is 263 MW less than the DSM forecast for last
winter. Approximately 68 percent of the total DSM is located in California and most of the
DSM decline occurred in California. Each LSE is responsible for verifying the accuracy of its
DSM and energy efficiency programs. Methods for verification include: Direct end-use
metering, sample end-use metering, and baseline comparisons of metered demand and use.

Generation
For the peak winter month of December, WECC expects a Reserve Margin of 50.9 percent
(66,759 MW), which significantly exceeds this year’s supply adequacy model planning Reserve
Margin of about 16.1 percent. The net capacity resources for this winter are expected to be
197,834 MW compared to 185,758 MW for winter 2008/2009. The net capacity resources
include no firm capacity transactions with Regions external to WECC. No significant generating
units are scheduled to be out of service or retired during the winter period. The following table
presents the existing and planned resources through the end of the winter period.

               Existing and Potential Resources (WECC through February, 2010)
                                             Existing-Certain      Existing-Other    Future-Planned
                                                  (MW)                 (MW)          & Other (MW)
           Total On-Peak Resources                     189,395                                 5,584
             Conventional Expected On-Peak             126,707                                 4,487
             Wind Expected On-Peak                       2,063                                   470
             Solar Expected On-Peak                         87                                   314
             Hydro Expected On-Peak                     58,852                                    84
             Biomass Expected On-Peak                    1,686                                   229
           Derates                                                          14,572             4,404
             Wind Derate On-Peak                                             6,782             2,883
             Solar Derate On-Peak                                              470             1,484
             Hydro Derate On-Peak                                            7,028                 0
             Biomass Derate On-Peak                                            292                37
           Existing, Inoperable                             0                    0                 0




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The projected hydro levels for the 2009/2010 winter season are below normal, but the hydro
generation is expected to be sufficient to meet the winter peak demands and energy loads. Hydro
resources have been derated to reflect low hydro conditions, and are not expected to have any
further impact on margins.

WECC does not analyze possible fuel supply interruption. Historically, coal-fired plants have
been built at or near their fuel source and generally have long-term fuel contracts with the mine
operators, or actually own the mines. Gas-fired plants are historically located near major load
centers and rely on relatively abundant western gas supplies. Many of the older gas-fired
generators in the Region have backup fuel capability and normally carry an inventory of backup
fuel, but WECC does not require verification of the operability of the backup fuel systems and
does not track onsite backup fuel inventories. Most of the newer generators are strictly gas-fired
plants.

Some of the WECC entities have taken steps to mitigate possible fuel supply vulnerabilities
through obtaining long-term, firm transport capacity on gas lines, having multiple pipeline
services, natural gas storage, back-up oil supplies, maintaining adequate coal supplies or
acquiring purchase power agreements for periods of possible adverse hydro conditions. A
survey of major power plant operators indicates that their natural gas supplies largely come from
the San Juan Basin in northwest New Mexico and the Permian Basin in western Texas, from the
gas fields in the Rocky Mountains, and from the Sedimentary Basin in western Canada.
Individual entities may have fuel supply interruption mitigation procedures in place, including
on-site coal storage facilities. Extreme winter weather during peak load conditions is not
expected to have a significant impact on the fuel supply.

Capacity Transactions on Peak
Some WECC entities rely heavily on short-term power markets, generally using the Western
System Power Pool (WSPP) contracts. The WSPP Agreement is a set of FERC-approved
standardized power sales contracts used by jurisdictional and non-jurisdictional entities. The
most commonly used WSPP contract is the firm capacity/ energy sale or exchange, which
contains liquidated damage (LD) provisions and is heavily relied upon as the template for such
transactions. These contracts do not reference specific generating units or a system of units, and
LDs are the only remedy for non-delivery.

This assessment does not include firm capacity transactions with entities located in the Eastern
Interconnection. However, the individual subregion resources include firm transfers between
subregions within WECC. These transfers represent assumed firm purchases and/or sales and
plant contingent transfers from one subregion to another. The plant contingent transfers usually
have transmission rights associated with them. Most balancing authorities are associated with
one to the three reserve sharing groups within WECC. These reserve sharing groups do not cross
the WECC Regional boundary and do not rely on outside assistance from other Regions for
emergency imports.

Transmission
WECC and subregional entities have processes in place to assess generation deliverability.
WECC prepares an annual power supply assessment that is designed to identify major load zones



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within the Region that may experience load curtailments due to physically-constrained paths and
internal resource limitations. In addition, extensive operating studies are prepared that model the
transmission system under a number of load and resource scenarios, and operating procedures
are developed to maintain safe and reliable operations. Also, major power system operators have
internal processes for identifying and addressing local area resource limitations, and independent
grid operators have formal procedures for obtaining reliability must run capability, including
voltage support capability, for resource-constrained areas. The resources reported in this
assessment have been reduced by 25 MW to reflect deliverability constraints identified by
transfer capability studies, interconnection agreement studies, etc.

The transmission system is considered adequate for all projected firm transactions and significant
amounts of economy energy transfers. Reactive Reserve Margins are expected to be adequate
for all expected peak load conditions in all areas. Close attention to maintaining appropriate
voltage levels is expected to prevent voltage problems.

Operational Issues
WECC does not expect any major scheduled generating unit outages, transmission facility
outages, or unusual operating conditions that would adversely impact reliable operations this
winter. The BAs and Planning Authorities coordinate the planning of long range scheduled
maintenance outages. This assures that there is sufficient generation availability during
scheduled transmission outages and that there is sufficient transmission availability during
scheduled generation outages to access other resources.

No environmental or regulatory restrictions have been reported that are expected to adversely
impact reliability. The integration of wind generation will continue to require modifications to
the way system operators dispatch generation resources in order to provide sufficient operating
flexibility. WECC does not anticipate reliability issues related to renewables generation during
minimum demand periods and does not anticipate reliability issues related to high levels of
Demand Response resources.

Reliability Assessment Analysis
For the winter assessment, WECC requested information from its Balancing Authorities (BAs)
about any studies they have performed for the winter assessment period. WECC also requests
BAs to update any applicable data (actual loads, forecasts, outages, future and existing resource
status changes) that have been previously submitted to WECC. The submitted information and
data is then reviewed and compiled into the resulting resource assessment for the WECC Region
and subregions.

The loads and resources are compared against the target Reserve Margins that were developed
for WECC’s Power Supply Assessment110 (PSA) and WECC’s Long Term Reliability
Assessment111 (LTRA). The target Reserve Margins were developed using a building block
method for developing Planning Reserve Margins. The building block approach has four
elements: contingency reserves, regulating reserves, reserves for additional forced outages, and
reserves for 1-in-10 weather events. The building block values were developed for each

110
      WECC Power Supply Assessment
111
      WECC Long Term Reliability Assessment



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balancing authority and then aggregated by subregions and the entire WECC for the PSA, LTRA
and the seasonal assessment analyses. The aggregated winter season Planning Reserve Margin
target for WECC was 16.06 percent. This Reserve Margin maybe lower or higher than some of
the state, provincial or Load Serving Entity requirements within WECC, but was developed
specifically for use in the above mentioned assessments.

Individual entities within the Western Interconnection have established generator interconnection
requirements that include power flow and stability studies to identify adverse impacts from
proposed projects. In addition, WECC has established a review procedure that is applied to
larger transmission projects that could impact the interconnected system. The details of this
review procedure are located in Section III of the WECC Planning Coordinating Committee’s
Handbook. These processes identify potential deliverability issues that may result in actions such
as the implementation of system protection schemes designed to enhance deliverability and to
mitigate possible adverse power system conditions.

Transmission Providers use the method and criteria contained in the appropriate standards
including WECC Standard TOP-STD-007-0- Operating Transfer Capability and FAC-012-1-
Transfer Capability Methodology.

Each of WECC’s transmission authorities or transmission planners performs reliability studies
on its own system and compares the study results to NERC and/or WECC standards. As
mentioned earlier in the transmission section, WECC staff and the System Review Working
Group help develop various base cases and studies as reported in the Annual Study Report. As
part of the studies, WECC staff performs selective transient dynamics and post-transient analyses
on the base cases and publishes the analyses in WECC’s Annual Study Report.

WECC’s Annual Study Program provides an assessment of the transmission system in the
Western Interconnection and helps support compliance with the following requirements in the
NERC Reliability Standards relating to reliability assessment, Special Protection Schemes, and
system data:

   • MOD 010,012 – Steady State and Dynamics Data for Transmission System Modeling and
                    Simulation
   • FAC 005 – Electrical Facility Ratings for System Modeling
   • PRC 006 – UFLS Dynamics Data Base
   • PRC 014 – Special Protection System Assessment
   • PRC 020 – UVLS Dynamics Data Base
   • TPL 001-004 – Transmission Planning (System Performance)

If the study results do not meet expected performance levels established in the criteria, the
responsible organizations are obligated to provide a written response that specifies how and
when they expect to achieve compliance with the criteria. Other measures that have been
implemented to reduce the likelihood of widespread system disturbances include: an islanding
scheme for loss of the AC Pacific Intertie that separates the Western Interconnection into two
islands and drops load in the generation-deficit southern island; a coordinated off-nominal
frequency load shedding and restoration plan; measures to maintain voltage stability; a



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comprehensive generator testing program; enhancements to the processes for conducting system
studies; and a reliability management system.

Operating studies are reviewed to ensure that simultaneous transfer limitations of critical
transmission paths are identified and managed through nomograms and operating procedures.
Four subregional study groups prepare seasonal transfer capability studies for all major paths in a
coordinated subregional approach for submission to WECC’s Operating Transfer Capability
Policy Committee.

On the basis of these ongoing activities, transmission system reliability within the Western
Interconnection is expected to meet NERC and WECC standards.




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Rocky Mountain Power Area (RMPA)

The Rocky Mountain Power Area’s (RMPA) peak demand may occur in either summer or
winter. The 2009/2010 winter peak demand of 9,859 MW is projected to occur in December and
is 4.3 percent less than last winter’s actual peak demand of 10,298 MW, which occurred in
December. The 2009/2010 winter peak forecast is 6.4 percent less than last winter’s projected
forecast peak demand of 10,529 MW which was projected to occur in December 2008. The
expected load growth decline for the 2009/2010 winter season is largely attributed to the
economic decline that has affected the area. Last winter’s peak demand was 2.2 percent less than
the forecast peak demand. For the 2009/2010 winter period, direct control load management
demand, contractually interruptible demand, critical peak-priding with control demand and load
as a capacity resources demand total 179MW. The projected Reserve Margin for the peak month
is 46.9 percent.

Hydro conditions for the 2009/2010 winter period are expected to be below normal but the
reservoir releases should be similar to last year. The following table presents the existing and
planned resources through the end of the winter period.

                                      Existing and Potential Resources
                                      (RMPA through February, 2010)
                                                        Existing-     Existing-      Future-
                                                        Certain        Other        Planned &
                                                         (MW)          (MW)        Other (MW)
                 Total On-Peak Resources                     13,279                       1,092
                   Conventional Expected On-Peak             11,956                       1,073
                   Wind Expected On-Peak                        137                          19
                   Solar Expected On-Peak                         0                           0
                   Hydro Expected On-Peak                     1,183                           0
                   Biomass Expected On-Peak                       3                           0
                 Derates                                                   1,102            168
                   Wind Derate On-Peak                                       972            131
                   Solar Derate On-Peak                                        8              0
                   Hydro Derate On-Peak                                      122              0
                   Biomass Derate On-Peak                                      0             37
                 Existing, Inoperable                            0             0              0

The transmission system is expected to be adequate for all firm transfers and most economy
energy transfers. However, the transmission path between southeastern Wyoming and Colorado
often becomes heavily loaded, as do the transmission interconnections to Utah and New Mexico.
WECC’s Unscheduled Flow Mitigation Plan112 may be invoked to provide line loading relief for
these paths, if needed.




112
      WECC Unscheduled Flow Mitigation Plan



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Arizona-New Mexico-Southern Nevada Power Area (AZ-NM-SNV)

This is a summer-peaking area. The 2009/2010 winter peak demand of 18,880 MW, which is
projected to occur in January, is 4.9 percent above last winter’s actual peak demand of 17,992
MW, which occurred in January. The 2009/2010 peak forecast is 3.2 percent less than last
winter’s forecast peak demand of 19,508 MW which was projected to occur in December 2008.
Last winter’s peak demand was higher than normal due to cooler temperatures. For the
2009/2010 winter period, direct control load management demand, contractually interruptible
demand, critical peak-priding with control demand and load as a capacity resources demand total
692 MW. The projected Reserve Margin for the peak month is 111.0 percent and excludes 25
MW of transmission limited resources.

The following table presents the existing and planned resources through the end of the winter
period.

                               Existing and Potential Resources
                            (AZ-NM-SNV through February, 2010)
                                                   Existing-     Existing-      Future-
                                                   Certain        Other        Planned &
                                                    (MW)          (MW)        Other (MW)
            Total On-Peak Resources                     38,790                       1,190
              Conventional Expected On-Peak             34,564                       1,190
              Wind Expected On-Peak                        197                           0
              Solar Expected On-Peak                        22                           0
              Hydro Expected On-Peak                     3,936                           0
              Biomass Expected On-Peak                      71                           0
            Derates                                                     922              0
              Wind Derate On-Peak                                       213              0
              Solar Derate On-Peak                                       58              0
              Hydro Derate On-Peak                                      651              0
              Biomass Derate On-Peak                                      0              0
            Existing, Inoperable                            0             0              0

Based on inter- and intra-area studies, the transmission system is considered adequate for
projected firm transactions and a significant amount of economy electricity transfers. When
necessary, phase-shifting transformers in the southern Utah/Colorado/Nevada transmission
system will be used to help control unscheduled flows. Reactive Reserve Margins have been
studied and are expected to be adequate throughout the area.

Fuel supplies are expected to be adequate to meet winter peak demand and energy load
conditions. In addition, firm coal supply and transportation contracts are in place, and sufficient
coal inventories are anticipated for the winter season.




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California–Mexico Power Area (CA-MX)

The California-Mexico power area is a summer-peaking area. The 2009/2010 winter peak
demand of 43,226 MW, which is projected to occur in December, is 0.7 percent greater than last
winter’s actual peak demand of 42,919 MW and is 7.2 percent less than last winter’s forecast
peak demand of 46,565 MW. The areas’ 2008/2009 winter peak demand occurred during a
period of generally normal to warmer than normal temperatures and was 7.8 percent below the
forecast for that month. For the 2009/2010 winter period, direct control load management
demand, contractually interruptible demand, critical peak-priding with control demand and load
as a capacity resources demand total 1,893 MW. The projected Reserve Margin for the peak
month is 58.7 percent.

California is currently in a low hydro condition with low reservoir levels, but they report they
have sufficient resources to meet their winter peak demand and energy resources. The following
table presents the existing and planned resources through the end of the winter period.

                                Existing and Potential Resources
                                (CAMX through February, 2010)
                                                  Existing-     Existing-      Future-
                                                  Certain        Other        Planned &
                                                   (MW)          (MW)        Other (MW)
            Total On-Peak Resources                    57,117                       2,677
              Conventional Expected On-Peak            43,530                       1,852
              Wind Expected On-Peak                       522                         283
              Solar Expected On-Peak                       65                         314
              Hydro Expected On-Peak                   12,262                          29
              Biomass Expected On-Peak                    738                         199
            Derates                                                  4,664          2,734
              Wind Derate On-Peak                                    2,568          1,234
              Solar Derate On-Peak                                     404          1,484
              Hydro Derate On-Peak                                   1,400              0
              Biomass Derate On-Peak                                   292             16
            Existing, Inoperable                           0             0              0

Although several major constrained transmission paths have been upgraded in recent years, path
constraints can still exist. Operating procedures are in place to manage any high loading
conditions that may occur during the winter. Entities within the area report having no concerns
with maintaining adequate reactive Reserve Margins.

All power plants in California are required to operate in accordance with strict air quality
environmental regulations. Some plant owners have upgraded emission control equipment to
remain in compliance with increasing emission limitations while other owners have chosen to
discontinue operating some plants. The effects of owners’ responses to environmental
regulations have been accounted for in the area’s resource data and it is not expected that
environmental issues will have additional adverse impacts on resource adequacy within the area
during the upcoming winter season.


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Northwest Power Pool (NWPP)

The Northwest Power Pool (NWPP) area is one of the four subregions of the Western Electricity
Coordinating Council (WECC) and is comprised of all or major portions of the states of
Washington, Oregon, Idaho, Wyoming, Montana, Nevada, and Utah; a small portion of Northern
California; and the Canadian provinces of British Columbia and Alberta. This vast area covers
1.2 million square miles of the WECC’s 1.8 million square miles. The NWPP, in collaboration
with it members (18 Balancing Authorities), has conducted an assessment of reliability in
response to questions raised regarding the ability of the NWPP to meet the load requirements
during the winter 2009/2010. Since the NWPP covers a large and diverse area of the Western
Interconnection, its members face unique issues in the day-to-day coordinated operations of the
system. The NWPP area in aggregate is a winter peaking subregion with a large amount of hydro
resources.

Analyses indicate the NWPP area will have adequate generation capacity and energy, required
operating reserves (regulating reserve and contingency reserve), and available transmission to
meet the forecasted firm loads for the 2009/2010 winter operations, assuming normal ambient
temperature and normal weather conditions.

This assessment is valid for the NWPP area as a whole. However, these overall results do not
necessarily apply to all sub-areas (individual members, balancing authorities, states or provinces)
when assessed separately.

In 2007, Sacramento Municipal Utility District (SMUD) and Turlock Irrigation District (TID)
joined the NWPP and will be fully integrated into the NWPP Reserve Sharing Group for the
2009/2010 winter season. However, for purposes of the 2009/2010 winter assessment, SMUD
(Sacramento) and TID (Turlock) are included in the California subregion and not in the NWPP
area assessment.

The NWPP has a publicly available document on its website that addresses 2009/2010 winter
conditions.113

Demand
The NWPP 2008/2009 coincidental winter peak demand of 63,435 MW occurred on December
15, 2008. The 2008/2009 coincidental winter peak demand was 104 percent of the forecast;
however, the coincidental peak demand occurred during below normal temperature conditions.
There is still a large component of electric space heating load within the NWPP area.
Normalizing for temperature variance (50 percent probability), the 2008 coincidental peak
demand would have been 60,500 MW or 99.18 percent of the forecast.

The economic recession that began in 2007 has had an impact on the NWPP power use and
future forecasts. The 2009 summer coincident peak demand forecast for the NWPP area was
54,500 MW. The actual was 50,000 MW adjusted for temperature. The recession that has taken
place has reduced the NWPP area peak demand by 5 to 10 percent. Historically, the NWPP area
lags the economic recovery by approximately one year.
113
      That document is available at: http://www.nwpp.org/publications.html.



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The 2009/2010 winter coincident peak demand forecast for the NWPP of 59,000 MW is based
on normal weather, reflects the prevailing economic climate (down-turn), and has a 50 percent
probability of not being exceeded.

The NWPP area has approximately 255 MW of interruptible demand capability and load
management. In addition, the load forecast incorporates any benefit (load reduction) associated
with demand-side resources not controlled by the individual utilities. Some of the entities within
the NWPP area have specific programs to manage peak issues during extreme conditions.
Normally these programs are used to meet the entities’ operating reserve requirements and have
no discernable impacts on the projected NWPP area peak load.

Under normal weather conditions, the NWPP area does not anticipate dependence on imports
from external areas during winter peak demand periods. However, if much lower than normal
precipitation occurs, it may be extremely advantageous to use transfer capabilities from outside
the NWPP area to reduce reservoir drafts and aid reservoir filling.

Generation
Approximately 60 percent of the NWPP resource capability is from hydro generation. The
remaining generation resources are conventional thermal plants and miscellaneous resources
such as non-utility owned gas-fired cogeneration or wind. The following table presents the
existing and planned resources through the end of the winter period.

                                Existing and Potential Resources
                                (NWPP through February, 2010)
                                                   Existing-     Existing-      Future-
                                                   Certain        Other        Planned &
                                                    (MW)          (MW)        Other (MW)
            Total On-Peak Resources                     80,209                         625
              Conventional Expected On-Peak             36,657                         372
              Wind Expected On-Peak                      1,207                         168
              Solar Expected On-Peak                         0                           0
              Hydro Expected On-Peak                    41,471                          55
              Biomass Expected On-Peak                     874                          30
            Derates                                                   7,884          1,539
              Wind Derate On-Peak                                     3,029          1,518
              Solar Derate On-Peak                                        0              0
              Hydro Derate On-Peak                                    4,855              0
              Biomass Derate On-Peak                                      0             21
            Existing, Inoperable                            0             0              0

Hydro Capability – NWPP power planning is done by sub-area. Idaho, Nevada, Wyoming, Utah,
British Columbia and Alberta individually optimize their resources to their demand. The
Coordinated System (Oregon, Washington and western Montana) coordinates the operation of its
hydro resources to serve its demand. The Coordinated System hydro operation is based on
critical water planning assumptions (currently the 1936-1937 water years). Critical water in the
Coordinated System equates to approximately 11,000 average megawatts of firm energy load


2009/2010 Winter Reliability Assessment                                                  Page 170
Regional Reliability Self-Assessments


carrying capability, when reservoirs start full. Under Average water year conditions, the
additional non-firm energy available is approximately 3,000 average megawatts.

The Coordinated System hydro reservoirs refilled to approximately 80 percent of the energy
content curve by July 31, 2009. The water “fueling” associated with hydro powered resources
can be difficult to manage because there are several competing purposes including but not
limited to: current electric power generation; future (winter) electric power generation; flood
control; biological opinion requirements resulting from the Endangered Species Act; and special
river operations for recreation, irrigation, navigation, and the refilling of the reservoirs each year.
Any time precipitation levels are below normal, balancing these interests becomes even more
difficult. With the competition for the water, power operations for the winter must be effective
and efficient. The goal is to manage all the competing requirements while refilling the reservoirs
to the highest extent possible.

Sustainable Hydro Capability – Operators of the hydro facilities optimize the use of available
water throughout the year while assuring all the competing purposes are evaluated. Although
available Reserve Margin at time of peak can be calculated to be greater than 20 percent, this can
be misleading. Since hydro can be limited due to conditions (either lack of water or imposed
restrictions), the expected sustainable capacity must be determined before establishing a
representative Reserve Margin. In other words, the firm energy load carrying capability
(FELCC) is the amount of energy that the system may be called on to produce on a firm or
guaranteed basis during actual operations. The FELCC is highly dependent upon the availability
of water for hydroelectric generation.

The NWPP has developed the expected sustainable capacity based on the aggregated information
and estimates that the members have made with respect to their own hydro generation.
Sustainable capacity is for periods greater than two hours during daily peak periods assuming
various conditions. This aggregated information yielded a reduction for sustained capability of
approximately 7,000 MW. This reduction is more relevant to the Northwest in the winter;
however, under summer extreme low water conditions, it impacts summer conditions, too.

Thermal Generation Capacity – No thermal plant or fuel problems are anticipated. To the extent
that existing thermal resources are not scheduled for maintenance, thermal and other resources
should be available as needed during the winter peak period.

Wind Generation Capacity – Several states have enacted renewable portfolio standards that will
require some NWPP members, by the mid-2010 decade, to satisfy at least 20 percent of their
load with energy generated from renewable resources. With the significant increase in variable
generation within the NWPP area, new operational issues are arising and will continue to be
addressed into the future. Some of the safety net programs such as contingency reserve and
under frequency load shedding will be re-evaluated for effectiveness.

The NWPP area estimated the installed wind generation capacity for the winter season will be
approximately 5,900 MW, contributing about 1,100 MW of capacity on-peak. With the
increasing variable generation, conventional operation of the existing hydro and thermal
resources will be impacted.



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The wind generation manufacturers’ standard operating temperature for wind turbines range
from -10° C to + 40° C (14° F to 104° F). During the winter peaking period, the temperature in
the areas where the majority of the wind turbines are located can go below 14°F, leaving no
capability from the wind generation during those periods. In addition, there is a risk of over-
generation in the spring and fall. When both the wind and hydro generation are in high
generation mode, and given the environmental constraints on dissolved gases in the river, there
are times when desired generation may exceed expected load plus the ability to export.
Operating procedures have been introduced to address this situation.

Biomass Generation – The installed capacity of biomass generation within the NWPP area is
670 MW with expected on-peak amounts of 895 MW.

Other Generation – Within the NWPP area there is an underground natural gas storage facility
that is 100 percent full. This storage is located near many of the gas plants located in the NWPP
area, minimizing any effect that a Regional gas problem may cause. In addition, one entity in the
NWPP area has over 700 MW of generation that can be fired on diesel fuel.

External Resources – No reliance on resources external to the NWPP area is assumed for the
winter season. However, one BA located in the NWPP area has an exchange agreement with an
entity in the California Region for additional energy, up to 300 MW per hour, delivered firm to
the BA system. This exchange agreement is for the period November through February with a
total potential import of 413,000 MWh.

Transmission
Several BAs are constructing new transmission within the NWPP area to address load service
issues. No significant transmission lines are scheduled to be out-of-service during the winter
season.

Constrained paths within the NWPP area are known and operating studies modeling these
constraints have been performed. As a result of these studies, operating procedures have been
developed to assure safe and reliable operations.

System Operating Limits (SOL) – The interregional transmission transfer capabilities based on
System Operating limits as determined by the Northwest Operational Planning Group have been
approved by WECC’s Operating Transfer Capability Policy Committee. These limits recognize
transmission or generation constraints in systems external to the Region or subregion.

Outage Coordination – The NWPP coordinated outage (transmission) system was designed to
assure that outages could be coordinated among all stakeholders (operators, maintenance
personnel, transmission users, and operations planners) in an open process. This process had to
assure that proper operating studies were accomplished and transmission impacts and limits
known, to fulfill a requirement from the 1996 west coast disturbances that the system be operated
only under studied conditions. The WECC Reliability Coordinator is involved in the outage
coordination process and has direct access to the outage database.




2009/2010 Winter Reliability Assessment                                                Page 172
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Monthly Coordination – The outage coordination process requires NWPP members to designate
significant facilities that, if out of service by itself or in conjunction with another outage, will
impact system capabilities. The significant facilities are defined and updated annually by the
NWPP members. The scheduled outage of these critical facilities is posted on a common
database. All utilities post proposed significant outages on WECC’s Coordinated Outages
System (COS). Outages are to be submitted to the COS at least 45 days ahead of the month they
are proposed to occur so they can be viewed by interested entities. The involved entities then
facilitate the NWPP coordination of all these outages. Entities can comment on the preliminary
impacts and schedules may be adjusted to maximize reliability and minimize market impacts. If
coincidental outages cause too severe an impact, the requesting utilities work together to adjust
schedules accordingly. A final outage plan is posted with estimated path capabilities 30 days
prior to the month in which the outages will occur. Detailed operational transfer capability
studies are then performed and the limits for each affected path are posted at least 15 days prior
to the outage.

Emergency outages can be requested outside these schedule guidelines. Emergency outages are
coordinated among adjacent utilities to minimize system exposure. Utilities can use the COS
system to assure the system topology is correct for the next-day operating studies. As
transmission operators increase the number of short term outages in addition to the significant
outages, the WECC Reliability Coordinator will be able to access the WECC COS data base and
use the final outage schedule in its real-time system analysis. This coordinated outage process
has been very effective. The outage information is used by NWPP member utilities to perform
system studies to maximize system reliability.

Semi-annual planning - Long-Range Significant Outage Planning (LRSOP) – The NWPP
staff facilitates outage meetings every six months with each utility’s outage coordinator to
discuss proposed longer term outages. Utilities discuss anticipated outages needed for time-
critical construction and periods where transmission capacity may need to be maximized. The
outages are posted on the WECC COS and on the individual companies’ OASIS sites.

Specific responsibilities of LRSOP include:

      Share outage information with all parties affected by outages of significant equipment
       (i.e., equipment that affects the transfer capability of rated paths). Information is shared
       two times each year for a minimum of a six-month period. The first meeting each year
       coordinates outages for July through December. The second meeting coordinates outages
       for January through June.
      Review the outage schedules to assure that needed outages can be reliably accomplished
       with minimal impact on critical transmission use.
      Outage coordinators are to post the outages on the Coordinated Outages System within
       the applicable timeframes.

Next-Day Operating Studies – Additional path curtailments may be required depending upon
current system conditions and outages. These curtailment studies are performed by the
individual path operators based on the outage schedule developed through the COS process.
According to the COS process, these studies are performed at least 15 days prior to the outage.


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Individual path operators and transmission owners may also perform updated next-day studies to
capture emergency outage requests and current system conditions such as generation dispatch to
determine if the SOL studies and limits are still accurate. Based on these studies, additional SOL
curtailments may be made by the path operators. The modified SOLs are posted on the
individual transmission owner’s OASIS and the Reliability Coordinator is notified.

The WECC Reliability Coordinator also performs system studies to ensure interconnected
system reliability. The WECC Reliability Coordinator performs real-time system thermal studies
to evaluate current operating conditions across the entire Interconnection. The WECC
Reliability Coordinator is in the process of incorporating real-time voltage tools to complement
the thermal analysis currently being performed. Transient stability analysis capability is planned
in the future. When the WECC Reliability Coordinator observes real-time reliability problems it
contacts the path operator to discuss the issue and work on a solution. The WECC Reliability
Coordinator will make a directive for action if there is an imminent reliability threat and the
balancing authority does not eliminate the reliability issue within an appropriate time frame.

Voltage Stability – The WECC-1-CR System Performance Criteria, requirement WRS3 is used
to plan adequate voltage stability margin in the NWPP area as appropriate. Simulations are used
to assure system performance is adequate and meets the required criteria.

Operational Issues
The NWPP area does not anticipate any operating issues for the 2009/2010 winter season.

The NWPP has developed an Adequacy Response Process whereby a team addresses the area’s
ability to avoid a power emergency by promoting Regional coordination and communications.
Essential pieces of that effort include timely analyses of the power situation and communication
of that information to all parties including but not limited to utility officials, elected officials and
the general public.

In the fall of 2000, the area developed an Emergency Response Process to address immediate
power emergencies. The ERT remains in place and would be used in the event of an immediate
emergency. The ERT would work with all parties in pursuing options to resolve the emergency
including but not limited to load curtailment and or imports of additional power from other areas
outside of the NWPP.

Reliability Assessment Analysis
The NWPP area does not have one explicit method for determining an adequacy margin.
Bonneville Power Administration uses the NWPP and Conservation Council’s resource
adequacy standard, which establishes targets for both the energy and capacity adequacy metrics
derived from a loss of load probability analysis. Others use a Reserve Margin approach.

Since no one method exists for the entire NWPP area, the NWPP has elected to use a Reserve
Margin analysis for the winter assessment. The 2009/2010 NWPP area generating capability is
projected to be 80,000 MW, prior to adjusting for maintenance. In determining planning margin
for the current winter season one must further adjust for operating reserve requirement, which is




2009/2010 Winter Reliability Assessment                                                       Page 174
Regional Reliability Self-Assessments


approximately 4,200 MW. At this point, based on a load of 50 percent probability of not being
exceeded, the planning margin is approximately 27 percent.

A severe weather event for the entire NWPP area will add approximately 6,000 MW of load
while at the same time, under extreme water restrictions, the sustained hydro generation
capability would be reduced by 7,000 MW. In addition, under the severe weather, wind
generation is expected to be minimal. Accounting for the severe weather event and the operating
reserve yields a planning margin of approximately 5 percent.

Contingency Reserve Sharing Procedure

As permitted by NERC and WECC criteria and standards, the Operating Committee of the
NWPP has instituted a Reserve Sharing Program for contingency reserve. The reserve sharing
process for the NWPP has been automated. A manual backup process is in place if
communication links are down or the computer system for reserve sharing is not functioning
correctly.

The NWPP is designated as a reserve sharing group (RSG) as provided under WECC Operating
Reliability Criteria. Each member of the RSG submits its contingency reserve obligation (CRO)
and most severe single contingency (MSSC) to a central computer. The combined member CRO
must be larger than the RSG MSSC. If not, then each member’s CRO is proportionally increased
until this requirement is met. When any RSG member loses generation they have the right to call
upon reserves from the other RSG members as long as they have first committed their own CRO.
A request for contingency reserve must be sent within four minutes after the generation loss and
the received contingency reserve can only be held for 60 minutes. A request is sent via the
member’s energy management system to the central computer. The central computer then
distributes the request proportionally among members within the RSG. Each member may be
called to provide reserve up to its CRO. Critical transmission paths are monitored in this process
to ensure SOL limits are not exceeded. If a transmission path SOL is exceeded the automated
program redistributes the request among RSG members that are delivering reserve along non-
congested paths. The WECC Reliability Coordinator continuously monitors the adequacy of the
RSG reserve obligation, MSSC, and the deployment of reserve. If a reserve request fails due to
various reasons, backup procedures are in place to fully address the requirements.

Conclusions
In view of the present overall power conditions, including the forecasted water condition, the
area represented by the NWPP is estimating that it will be able to meet firm loads including the
required operating reserve. Should any resources be lost to the area beyond the contingency
reserve requirement and or loads are greater than expected as a result of extreme weather, the
NWPP area may have to look to alternatives which may include emergency measures to meet
obligations.




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                                                          Regional Reliability Self-Assessments


Regional Description
WECC’s 243 members, including 37 balancing authorities, represent the entire spectrum of
organizations with an interest in the bulk power system. Serving an area of nearly 1.8 million
square miles and 71 million people, it is the largest and most diverse of the eight NERC Regional
reliability organizations. Additional information regarding WECC can be found on its Web site
(www.wecc.biz).

AZ/NM/SNV             —       230,100 Sq. Mi.
RMPA                  —       167,000 Sq. Mi.
CAMX                  —       156,000 Sq. Mi.
NWPP                  —     1,214,000 Sq. Mi.
WECC TOTAL            —     1,760,000 Sq. Mi.




2009/2010 Winter Reliability Assessment                                                Page 176
About This Report


About This Report

The 2009/2010 Winter Reliability Assessment represents NERC’s independent judgment of the
reliability of the bulk power system in North America for the 2009/2010 winter season (Table
2).114 The report specifically provides a high-level reliability assessment of 2009/2010 winter
resource adequacy and operating reliability, an overview of projected electricity demand growth,
Regional highlights, and Regional self-assessments.

 NERC’s primary objective in providing
this assessment is to identify areas of               Table B: NERC’s Annual Assessments
concern regarding the reliability of the            Assessment            Outlook         Published
North American bulk power system and to
                                                      Summer
make recommendations for their remedy               Assessment
                                                                      Upcoming season        May
as needed.        The assessment process
enables bulk power system users, owners,             Long-Term
                                                                           10 year          October
and operators to systematically document            Assessment
their operational preparations for the
coming season and exchange vital system Winter Assessment Upcoming season November
reliability information. This assessment is
prepared by NERC in its capacity as the Electric Reliability Organization.115 NERC cannot
order construction of generation or transmission or adopt enforceable standards having that
effect, as that authority is explicitly withheld by Section 215 of the U.S. Federal Power Act and
similar restrictions in Canada.116 In addition, NERC does not make any projections or draw any
conclusions regarding expected electricity prices or the efficiency of electricity markets.

Report Preparation

NERC prepared the 2009/2010 Winter Reliability Assessment with support from the Reliability
Assessment Subcommittee (RAS), which is under the direction of the NERC Planning
Committee (PC). The report is based on data and information submitted by each of the eight
Regional Entities in September 2009 and updated, as required, throughout the drafting process.
Any other data sources consulted by NERC staff in the preparation of this document are
identified in the report.

NERC’s staff performed detailed data checking on the reference information received by the
Regions, as well as review of all self-assessments to form its independent view and assessment
of the reliability of the 2009/2010 winter season. NERC also uses an active peer review process
in developing reliability assessments. The peer review process takes full advantage of industry
subject matter expertise from many sectors of the industry. This process also provides an

114
    Bulk power system reliability, as defined in the How NERC Defines Bulk Power System Reliability section of this report, does
  not include the reliability of the lower voltage distribution systems, which systems account for 80 percent of all electricity
  supply interruptions to end-use customers.
115
    Section 39.11(b) of the U.S. FERC’s regulations provide that: “The Electric Reliability Organization shall conduct
  assessments of the adequacy of the Bulk-Power System in North America and report its findings to the Commission, the
  Secretary of Energy, each Regional Entity, and each Regional Advisory Body annually or more frequently if so ordered by the
  Commission.”
116
    http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=109_cong_bills&docid=f:h6enr.txt.pdf


Page 177                                                                     2009/2010 Winter Reliability Assessment
                                                                                                          About this Report

essential check and balance for ensuring the validity of the information provided by the Regional
entities.

Each Region prepares a self-assessment, which is assigned to three or four RAS members,
including NERC Operating Committee (OC) liaisons, from other Regions for an in-depth and
comprehensive review. Reviewer comments are discussed with the Regional Entity’s
representative and refinements and adjustments are made as necessary. The Regional self-
assessments are then subjected to scrutiny and review by the entire subcommittee. This review
ensures members of the subcommittee are fully convinced that each Regional self-assessment is
accurate, thorough, and complete.

The PC endorses the report for NERC’s Board of Trustee (BOT) approval, considering
comments from the OC. The entire document, including the Regional self-assessments, is then
reviewed in detail by the Member Representatives Committee (MRC) and NERC management
before being submitted to NERC’s BOT for final approval.

In the 2009/2010 Winter Reliability Assessment, the baseline information on future electricity
supply and demand is based on several assumptions:117

         Supply and demand projections are based on industry forecasts submitted in September
          2009. Any subsequent demand forecast or resource plan changes may not be fully
          represented.
         Peak demand and Reserve Margins are based on average weather conditions and assumed
          forecast economic activity at the time of submittal. Weather variability is discussed in
          each Region’s self-assessment.
         Generating and transmission equipment will perform at historical availability levels.
         Future generation and transmission facilities are commissioned and in-service as planned;
          planned outages take place as scheduled.
         Demand reductions expected from Demand Response programs will yield the forecast
          results, if they are called on.
         Other peak Demand-Side Management programs are reflected in the forecasts of Net
          Internal Demand.

Enhancements to the 2009/2010 Winter Reliability Assessment

In light of the guidance in FERC’s Order 672 and comments received from other authorities and
industry representatives, NERC’s Planning Committee (PC) concluded the Seasonal and Long-
Term Reliability Assessment processes required improvement. To achieve this goal, the PC
formed a task force, the Reliability Assessment Improvement Task Force, and directed it to
develop recommendations and a plan for improvement.




117
   Forecasts cannot precisely predict the future. Instead, many forecasts report probabilities with a range of possible outcomes.
  For example, each Regional demand projection is assumed to represent the expected midpoint of possible future outcomes.
  This means that a future year’s actual demand may deviate from the projection due to the inherent variability of the key factors
  that drive electrical use, such as weather. In the case of the NERC Regional projections, there is a 50 percent probability that
  actual demand will be higher than the forecast midpoint and a 50 percent probability that it will be lower (50/50 forecast).


2009/2010 Winter Reliability Assessment                                                                               Page 178
About This Report

A number of the task force’s recommendations118 were incorporated into the 2009/2010 Winter
Reliability Assessment, including:

      1. The Reliability Assessment Guidebook Task Force released its Reliability Assessment
         Guidebook (Version 1.2),119 to provide increased transparency on the reliability
         assessments process, resource reporting, load forecasting, and general assumptions
         made in NERC’s Assessments. Regions referenced the guidebook to enhance their
         contributions to this report.
      2. In order to improve data accuracy, NERC has implemented improved data checking
         methods. A brief summary of these data checking methods is summarized in the Data
         Checking Methods Applied Section.
      3. In order to broaden stakeholder input, OC involvement was incorporated to support the
         assessment development and approval process.
      4. Supply categories have been enhanced to better assess capacity. Notably, this
         assessment uses the following supply categories: “Existing-Certain,” “Existing-Other”
         and “Existing, but Inoperable.” A brief summary of these terms are provided in the
         Resources, Demand and Reserve Margins Section.
      5. “Reserve Margin” replaced “Capacity Margin” used in the 2008/2009 Winter
         Assessment to be consistent with industry practices and reduce confusion. An
         explanation for this change is provided in the Capacity Margin to Reserve Margin
         Changes Section.

Report Content Responsibility
The following NERC industry groups have collaborated efforts to produce NERC’s 2009/2010
Winter Reliability Assessment:

               NERC Group                      Relationship                     Contribution

        Planning Committee (PC)           Reports to NERC’s               Review Assessment and
                                          Board of Trustees                Endorse

        Operating Committee (OC)          Reports to NERC’s               Review Assessment and
                                          Board of Trustees                provide comments to PC
        Reliability Assessment            Reports to the PC               Provide Regional
        Subcommittee (RAS)                                                 Self-Assessments
                                                                          Peer Reviews
                                                                          Review Report
        Reliability Assessment            Reports to the PC               Develop Reliability
        Guidebook Task Force                                               Assessment Guidebook
        (RAGTF)
        Data Coordination Working         Reports to the RAS              Develop data and Regional
        Group (DCWG)                                                       reliability narrative requests
        Board of Trustees                 NERC’s Independent           ●   Review Assessment
                                          Board                        ●   Approve for publication



118
   See http://www.nerc.com/files/Reliability%20Improvement%20Report%20RAITF%20100208.pdf
119
   For the Reliability Assessment Guidebook, Version 1.2, see
  http://www.nerc.com/docs/pc/ragtf/Reliability_Assessment_%20Guidebook%20v1.2%20031909.pdf



Page 179                                                             2009/2010 Winter Reliability Assessment
                                                                        Reliability Concepts Used in This Report


Reliability Concepts Used in This Report
How NERC Defines Bulk Power System Reliability
NERC defines the reliability of the interconnected BPS in terms of two basic and functional
aspects120:

          Adequacy — is the ability of the electric system to supply the aggregate electric power
          and energy requirements of the electricity consumers at all times, taking into account
          scheduled and reasonably expected unscheduled outages of system components.

          Operating Reliability — is the ability of the electric system to withstand sudden
          disturbances such as electric short circuits or unanticipated loss of system components.

Regarding adequacy, system operators can and should take “controlled” actions or procedures to
maintain a continual balance between supply and demand within a balancing area (formerly
control area). These actions include:

         Public appeals.
         Interruptible demand — demand that the end-use customer makes available to its LSE
          via contract or agreement for curtailment.121
         Voltage reductions (sometimes referred to as “brownouts” because incandescent lights
          will dim as voltage is lowered, sometimes as much as 5 percent).
         Rotating blackouts — the term “rotating” is used because each set of distribution feeders
          is interrupted for a limited time, typically 20–30 minutes, and then those feeders are put
          back in service and another set is interrupted, and so on, rotating the outages among
          individual feeders.

Under the heading of Operating Reliability, are all other system disturbances that result in the
unplanned and/or uncontrolled interruption of customer demand, regardless of cause. When
these interruptions are contained within a localized area, they are considered unplanned
interruptions or disturbances. When they spread over a wide area of the grid, they are referred to
as “cascading blackouts” — the uncontrolled successive loss of system elements triggered by an
incident at any location.




120
    See http://www.nerc.com/docs/pc/Definition-of-ALR-approved-at-Dec-07-OC-PC-mtgs.pdf more information about the
  Adequate Level of Reliability (ALR).
121
    Interruptible Demand (or Interruptible Load) is a term used in NERC Reliability Standards. See Glossary of Terms Used in
  Reliability Standards, February 12, 2008, at http://www.nerc.com/files/Glossary_12Feb08.pdf.


2009/2010 Winter Reliability Assessment                                                                            Page 180
Reliability Concepts Used in This Report

Demand Response Concepts and Categorization

As the industry’s use of Demand-Side Management (DSM) evolves, NERC’s data collection and
reliability assessment need to change highlighting programs and demand-side service offerings
that have an impact on bulk system reliability.
NERC’s seasonal and long-term reliability assessments currently assume projected energy
efficiency EE programs are included in the Total Internal Demand forecasts, including
adjustments for utility indirect Demand Response programs such as conservation programs,
improvements in efficiency of electric energy use, rate incentives, and rebates. DSM involves all
activities or programs undertaken to influence the amount and timing of electricity use (See
Figure Demand 1).
Note the context of these activities and programs is DSM, rather than bulk power systems and,
therefore, they are not meant to mirror those used in the system context. The Demand Response
categories defined in Terms Used in this Report support Figure Demand 1


                Figure Demand 1: Demand-Side Management and NERC’s Data Collection

                                             Demand-Side Management (DSM)


                                      Demand Response (DR)                                        New Energy Efficiency

                         Dispatchable                                Non-Dispatchable

                     Controllable                  Economic        Time-Sensitive Pricing


                                  Energy-                               Time-of-Use
     Capacity       Ancillary    Voluntary        Energy-Price

                                                                     Critical Peak Pricing
      Direct                                       Demand
       Load         Spinning     Emergency         Bidding &
      Control       Reserves                                          Real Time Pricing
                                                   Buyback

    Interruptible   Non-Spin                                        System Peak Response
      Demand        Reserves                                          Transmission Tariff

      Critical
       Peak         Regulation
                                                                      Future Areas of Interest
      Pricing
     w/Control
                                                                                             NERC Inaugurated Projected
    Load as a                                                                                 DR Data Collection in 2008
    Capacity
    Resource




.




Page 181                                                                    2009/2010 Winter Reliability Assessment
                                                                   Data Checking Methods Applied


Data Checking Methods Applied

NERC's Reliability Assessment Data Validation and Error Checking Program ensures the
Reliability Assessment Database operates with consistent data. It uses routines, often called
“validation rules,” that check for correctness, meaningfulness, and security of data that are added
into the system.

Internal data checking and validation refers to the practice of validating and checking data
through internal processes (e.g., Historical Comparison, Range and Limits, Data Entry
Completeness, Correct Summations) to maintain high quality data (See Table Data Checking 1).
The rules are implemented through automated processes — data dictionary for data checking and
logic for validation. Incorrect data can lead to data corruption or a loss of data integrity. Data
validation verifies it is valid, sensible, and secure before it is processed for analysis. The program
uses scripts, developed on a composite Microsoft Excel and Microsoft Access platform, to
provide a semi-automated solution.


  Table Data Checking 1: NERC Data Quality Framework and Attributes
  Data Quality Attribute            Responsible Entity  Data Check Performed
  Accuracy                          Industry             Validation rules
  Ensure data are the correct                            Consistent with other
  values                                                  external sources
  Accessibility                     DCWG, NERC, and RE   Data is submitted in the
  Data items should be easily                             provided template
  obtainable and in a usable format
  Comprehensiveness                 DCWG, RE, and        Check for null values
  All required data items are       Stakeholders         Compare to prior year’s
  submitted                                               null values
                                                         Inquiries to the RE
  Currentness                       RE and Stakeholders  Consistent with other
  The data should be up-to-date                           external sources

  Consistency                             DCWG, NERC                     DCWG leads in
  Definitions of the data elements                                        this effort
  should be the same across                                              Assumptions are
  different reporting entities                                            verified with the RE
  Definition                              DCWG, NERC Staff               The DCWG leads in
  Clear definitions should be                                             this effort
  provided so the current and
  future data users can understand
  the assumptions




2009/2010 Winter Reliability Assessment                                                     Page 182
Data Checking Methods Applied

In 2009, NERC implemented a two-phase approach to data checking and validation. Phase I is a
data collection form-side validation procedure based on defined rules. It also specifies the error
type or condition not met. This phase was applied to the data collection forms to prevent the
incorrect entry of data and prompts the user with feedback explaining the error. Validation rules
are used to ensure entered data meets defined thresholds, ranges, or both. An error halts the input
of data until a valid entry is provided. For example, the reported deratings of existing generating
units is a subset of the “Existing-Other” supply category; therefore, the sum of all deratings must
be less than or equal to the value reported as “Existing-Other.” This example is shown below:
                                                                             Incorrect Correct
   6b      Existing-Other (Note: The sum of 6b1 through 6b7 must be <= 6b)      5,000       5,000
   6b1            Wind Derate On-Peak                                             800         400
   6b2            Solar Derate On-Peak                                            445         232
   6b3            Hydro Derate On-Peak                                            789           0
   6b4            Biomass Derate On-Peak                                            0           0
   6b5            Load as a Capacity Resource Derate On-Peak                        0           0
   6b6            Energy Only                                                     435       1,345
   6b7            Scheduled Outage - Maintenance                                4,000       2,398
   6b8            Transmission-Limited Resources                                    0           0

Once data is submitted to NERC, reported values can be analyzed for validity. Phase II of
NERC’s data checking and validation effort involves comparing submitted data to historical
submissions. For this phase, a back-end database is used to compare key values, such as peak
demand projections and installed capacity to what was reported in prior years. Only values with
comparable definitions are considered. In addition, a preliminary analysis can identify potential
errors. If a potential error is detected, it is flagged and categorized by one of the following error
types:
         Categorization — values may be incorrectly categorized
         Summation — values are incorrectly summed
         Double Count — identifies a possible double counting issue
         Missing Data — key values are null
         Confirmation — a notable discrepancy which must be confirmed

The Reliability Assessment Data Validation and Error Checking Program identifies potential
errors and generates a report for further investigation. Thresholds are determined for each value
and flagged when a major deviation is determined. For example, peak demand projections must
be within a +/- 2 percent threshold to pass; all others are flagged. When errors are identified,
NERC staff can send a request for data corrections to the Regional Entities. The Regional
Entities then have the opportunity to update their data submittals or explain the flagged error.

In addition, NERC’s Data Coordination Working Group (DCWG) monitors the quality of data
reported. The DCWG serves as a point of contact responsible for supporting NERC staff,
continuously maintaining high quality data and provide enhancements to current practices.

Due to improved data checking processes in 2009 and increased coordination between NERC
staff and Regional representatives, data errors were minimal for the 2009/2010 Winter Reliability
Assessment.



Page 183                                                     2009/2010 Winter Reliability Assessment
                                                                      Capacity Margin to Reserve Margin Changes


Capacity Margin to Reserve Margin Changes

Background
The term Reserve Margin is widely used throughout the power industry. However, the word
“reserve” engendered much misunderstanding on the part of policy makers. Therefore, the
NERC Board of Trustees adopted the use of “Capacity Margin” to measure supply adequacy in
1984. Although NERC adopted the term Capacity Margin (25 years ago), the majority of the
power industry continues to use “Reserve Margin.” 122

Discussion
The Reliability Assessment Subcommittee (RAS) has reviewed the use of Reserve Margin and
Capacity Margin terms. Both terms are used throughout the Long-Term Reliability Assessment
and seasonal reliability assessments. This multiple use has caused significant confusion to the
readers.

In a recent survey conducted by the Resource Issues Subcommittee (RIS), 29 of 38 Planning
Authorities (PA) perform their work relying on “Reserve Margin.” In contrast, only one PA
referenced “Capacity Margin.” The same survey shows that five of eight Regional Entities
reference “Reserve Margin” as the metric they use to measure resource adequacy and while none
reference “Capacity Margin.”

Since the audience of NERC’s assessments consists of a wide range of readers (including state
and local regulatory bodies), industry terms should be consistent. NERC’s goal is to convey
reliability assessments in a way that reduces confusion. Since NERC’s focus is to maintain BPS
reliability in order to serve customer load and therefore, it is appropriate to express resource
margins normalized by customer load (“Reserve Margin”).

Approval
Upon recommendations from the                         Figure: Reserve Margin to be Used for Future
RAS and RIS, the Planning                                     NERC Reliability Assessments
Committee approved the use of
“Reserve Margin” in place of                         Capacity Margin                    Reserve Margin
“Capacity Margin,” on December 3,
2008 for all future reliability                     (Capacity – Demand)                (Capacity – Demand)
assessments,       beginning     with
reliability assessments in 2009.                           Capacity                          Demand

This report uses only Reserve
Margin for adequacy assessment.




122
      http://www.nerc.com/docs/pc/Updated_PC_Agenda_3-4Dec2008.doc



2009/2010 Winter Reliability Assessment                                                               Page 184
Terms Used in This Report


Terms Used in This Report
Ancillary (Controllable Demand Response) — Demand-side resource displaces generation
deployed as operating reserves and/or regulation; penalties are assessed for nonperformance.
Capacity (Controllable Demand Response) — Demand-side resource displaces or augments
generation for planning and/or operating resource adequacy; penalties are assessed for
nonperformance.
Capacity Categories — See Existing Generation Resources, Future Generation Resources,
and Conceptual Generation Resources.
Capacity Margin (%) — See Deliverable Capacity Margin (%) and Prospective Capacity
Margin (%). Roughly, Capacity minus Demand, divided by Capacity or (Capacity-
Demand)/Capacity. Replaced in 2009 with Reserve Margin(s) (%) for NERC Assessments.
Conceptual Generation Resources — This category includes generation resources that are not
included in Existing Generation Resources or Future Generation Resources, but have been
identified and/or announced on a resource planning basis through one or more of the following
sources:
   1.   Corporate announcement
   2.   Entered into or is in the early stages of an approval process
   3.   Is in a generator interconnection (or other) queue for study
   4.   “Place-holder” generation for use in modeling, such as generator modeling needed to
        support NERC Standard TPL analysis, as well as, integrated resource planning resource
        studies.

Resources included in this category may be adjusted using a confidence factor (%) to reflect
uncertainties associated with siting, project development or queue position.
Conservation – see Energy Conservation
Contractually Interruptible (Curtailable) (Controllable Capacity Demand Response) —
Dispatchable, Controllable, Demand-side management achieved by a customer reducing its load
upon notification from a control center. The interruption must be mandatory at times of system
emergency. Curtailment options integrated into retail tariffs that provide a rate discount or bill
credit for agreeing to reduce load during system contingencies. It is the magnitude of customer
demand that, in accordance with contractual arrangements, can be interrupted at the time of the
Regional Entity’s seasonal peak. In some instances, the demand reduction may be effected by
action of the System Operator (remote tripping) after notice to the customer in accordance with
contractual provisions.
Controllable (Demand Response) — Dispatchable Demand Response, demand-side resources
used to supplement generation resources resolving system and/or local capacity constraints.
Critical Peak Pricing (CPP) (Non-dispatchable Time-Sensitive Pricing Demand Response) —
Rate and/or price structure designed to encourage reduced consumption during periods of high
wholesale market prices or system contingencies by imposing a pre-specified high rate for a
limited number of days or hours.
Critical Peak Pricing (CPP) with Control (Controllable Capacity Demand Response) —
Dispatchable, Controllable, Demand-side management that combines direct remote control with
Page 185                                                   2009/2010 Winter Reliability Assessment
                                                                                            Terms Used in This Report

a pre-specified high price for use during designated critical peak periods, triggered by system
contingencies or high wholesale market prices.
Curtailable — See Contractually Interruptible
Deliverable Capacity Margin (%) — Deliverable Capacity Resources minus Net Internal
Demand shown as a percent of Deliverable Capacity Resources. Replaced in 2009 with
Deliverable Capacity Reserve Margin (%) for NERC Assessments.
Deliverable Capacity Resources – Existing-Certain and Net Firm Transactions plus Future-
Planned capacity resources plus Expected Imports, minus Expected Exports. (MW)
Deliverable Reserve Margin (%) –Deliverable Capacity Resources minus Net Internal Demand
shown as a percent of Net Internal Demand.
Demand – See Net Internal Demand, Total Internal Demand
Demand Bidding & Buyback (Controllable Energy-Price Demand Response) — Demand-side
resource that enable large consumers to offer specific bid or posted prices for specified load
reductions. Customers stay at fixed rates, but receive higher payments for load reductions when
the wholesale prices are high.
Demand Response — Changes in electric use by demand-side resources from their normal
consumption patterns in response to changes in the price of electricity, or to incentive payments
designed to induce lower electricity use at times of high wholesale market prices or when system
reliability is jeopardized.
Derate (Capacity) — The amount of capacity that is expected to be unavailable on seasonal
peak.
Direct Control Load Management (DCLM) or Direct Load Control (DLC) (Controllable
Capacity Demand Response) — Demand-Side Management that is under the direct control of the
system operator. DCLM may control the electric supply to individual appliances or equipment on
customer premises. DCLM as defined here does not include Interruptible Demand.123
Dispatchable (Demand Response) — Demand-side resource curtails according to instruction
from a control center.
Economic (Controllable Demand Response) — Demand-side resource that is dispatched based
on an economic decision.
Emergency (Controllable Energy-Voluntary Demand Response) — Demand-side resource
curtails during system and/or local capacity constraints.
Energy Conservation — The practice of decreasing the quantity of energy used.
Energy Efficiency — Permanent changes to electricity use through replacement with more
efficient end-use devices or more effective operation of existing devices. Generally, it results in
reduced consumption across all hours rather than event-driven targeted load reductions.




123
   DCLM is a term defined in NERC Reliability Standards. See Glossary of Terms Used in Reliability Standards, Updated April
  20, 2009 www.nerc.com/files/Glossary_2009April20.pdf

2009/2010 Winter Reliability Assessment                                                                        Page 186
Terms Used in This Report

Energy Emergency Alert Levels — The categories for capacity and emergency events based on
Reliability Standard EOP—002-0:
    Level 1 — All available resources in use.
             Balancing Authority, Reserve Sharing Group, or Load Serving Entity foresees or
               is experiencing conditions where all available resources are committed to meet
               firm load, firm transactions, and reserve commitments, and is concerned about
               sustaining its required Operating Reserves, and Non-firm wholesale energy sales
               (other than those that are recallable to meet reserve requirements) have been
               curtailed.
        Level 2 — Load management procedures in effect.
             Balancing Authority, Reserve Sharing Group, or Load Serving Entity is no longer
               able to provide its customers’ expected energy requirements, and is designated an
               Energy Deficient Entity.
             Energy Deficient Entity foresees or has implemented procedures up to, but
               excluding, interruption of firm load commitments. When time permits, these
               procedures may include, but are not limited to: Public appeals to reduce demand,
               Voltage reduction, Interruption of non-firm end use loads in accordance with
               applicable contracts, Demand-side management, and Utility load conservation
               measures.
        Level 3 — Firm load interruption imminent or in progress.
             Balancing Authority or Load Serving Entity foresees or has implemented firm
               load obligation interruption. The available energy to the Energy Deficient Entity,
               as determined from Level (Alert) 2, is only accessible with actions taken to
               increase transmission transfer capabilities.
Energy Only (Capacity) — Energy Only Resources are generally generating resources that are
designated as energy-only resources or have elected to be classified as energy-only resources and
may include generating capacity that can be delivered within the area but may be recallable to
another area.
Energy-Price (Controllable Economic Demand Response) — Demand-side resource that
reduces energy for incentives.
Energy-Voluntary (Controllable Demand Response) — Demand-side resource curtails
voluntarily when offered the opportunity to do so for compensation, but nonperformance is not
penalized.
Existing-Certain (Existing Generation Resources) — Existing generation resources available to
operate and deliver power within or into the Region during the period of analysis in the
assessment. Resources included in this category may be reported as a portion of the full
capability of the resource, plant, or unit. This category includes, but is not limited to the
following:
       1. Contracted (or firm) or other similar resource confirmed able to serve load during the
          period of analysis in the assessment.
       2. Where organized markets exist, designated market resource124 that is eligible to bid into
          a market or has been designated as a firm network resource.
       3. Network Resource125, as that term is used for FERC pro forma or other regulatory
          approved tariffs.
124
   Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but
  rather must be subtracted from the appropriate category in the demand section.

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                                                                                                   Terms Used in This Report

       4. Energy-only resources126 confirmed able to serve load during the period of analysis in
          the assessment and will not be curtailed.127
       5. Capacity resources that can not be sold elsewhere.
       6. Other resources not included in the above categories that have been confirmed able to
          serve load and not to be curtailed128 during the period of analysis in the assessment.
Existing-Certain & Net Firm Transactions – Existing-Certain capacity resources plus Firm
Imports, minus Firm Exports. (MW)
Existing-Certain and Net Firm Transactions (%) (Margin Category) – Existing-Certain & Net
Firm Transactions minus Net Internal Demand shown as a percent of Net Internal Demand.
Existing Generation Resources — See Existing-Certain,                                  Existing-Other,           Existing, but
Inoperable.
Existing, Inoperable (Existing Generation Resources) — This category contains the existing
portion of generation resources that are out-of-service and cannot be brought back into service to
serve load during the period of analysis in the assessment. However, this category can include
inoperable resources that could return to service at some point in the future. This value may vary
for future seasons and can be reported as zero. This includes all existing generation not included
in categories Existing-Certain or Existing-Other, but is not limited to, the following:
      1. Mothballed generation (that can not be returned to service for the period of the
          assessment).
      2. Other existing but out-of-service generation (that can not be returned to service for the
          period of the assessment).
      3. This category does not include behind-the-meter generation or non-connected
          emergency generators that normally do not run.
      4. This category does not include partially dismantled units that are not forecasted to
          return to service.
Existing-Other (Existing Generation Resources) — Existing generation resources that may be
available to operate and deliver power within or into the Region during the period of analysis in
the assessment, but may be curtailed or interrupted at any time for various reasons. This
category also includes portions of intermittent generation not included in Existing-Certain. This
category includes, but is not limited to the following:
      1. A resource with non-firm or other similar transmission arrangements.
      2. Energy-only resources that have been confirmed able to serve load for any reason
         during the period of analysis in the assessment, but may be curtailed for any reason.
      3. Mothballed generation (that may be returned to service for the period of the
         assessment).
      4. Portions of variable generation not counted in the Existing-Certain category (e.g., wind,
         solar, etc. that may not be available or derated during the assessment period).
      5. Hydro generation not counted as Existing-Certain or derated.
      6. Generation resources constrained for other reasons.

125
    Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but
  rather must be subtracted from the appropriate category in the demand section.
126
    Energy Only Resources are generally generating resources that are designated as energy-only resources or have elected to be
  classified as energy-only resources and may include generating capacity that can be delivered within the area but may be
  recallable to another area (Source: 2008 EIA 411 document OMB No. 1905-0129).” Note: Other than wind and solar energy,
  WECC does not have energy-only resources that are counted towards capacity.
127
    Energy only resources with transmission service constraints are to be considered in category Existing, Other.
128
    Energy only resources with transmission service constraints are to be considered in category Existing, Other.

2009/2010 Winter Reliability Assessment                                                                                Page 188
Terms Used in This Report

Expected (Transaction Category) — A category of Purchases/Imports and Sales/Exports
contract including:
     1. Expected implies that a contract has not been executed, but in negotiation, projected or
          other. These Purchases or Sales are expected to be firm.
     2. Expected Purchases and Sales should be considered in the reliability assessments.
Firm (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract
including:
     1. Firm implies a contract has been signed and may be recallable.
      2. Firm Purchases and Sales should be reported in the reliability assessments. The
         purchasing entity should count such capacity in margin calculations. Care should be
         taken by both entities to appropriate report the generating capacity that is subject to
         such Firm contract.
Future Generation Resources (See also Future-Planned and Future-Other) — This category
includes generation resources the reporting entity has a reasonable expectation of coming online
during the period of the assessment. As such, to qualify in either of the Future categories, the
resource must have achieved one or more of these milestones:
     1. Construction has started.
     2. Regulatory permits being approved, any one of the following:
         a. Site permit
         b. Construction permit
         c. Environmental permit
     3. Regulatory approval has been received to be in the rate base.
     4. Approved power purchase agreement.
     5. Approved and/or designated as a resource by a market operator.
Future-Other (Future Generation Resources) — This category includes future generating
resources that do not qualify in Future-Planned and are not included in the Conceptual category.
This category includes, but is not limited to, generation resources during the period of analysis in
the assessment that may:
      1. Be curtailed or interrupted at any time for any reason.
      2. Energy-only resources that may not be able to serve load during the period of analysis
          in the assessment.
      3. Variable generation not counted in the Future-Planned category or may not be
          available or is derated during the assessment period.
      4. Hydro generation not counted in category Future-Planned or derated.
      5. Resources included in this category may be adjusted using a confidence factor to reflect
          uncertainties associated with siting, project development or queue position.

Future-Planned (Future Generation Resources) — Generation resources anticipated to be
available to operate and deliver power within or into the Region during the period of analysis in
the assessment. This category includes, but is not limited to, the following:
      1. Contracted (or firm) or other similar resource.
      2. Where organized markets exist, designated market resource129 that is eligible to bid into
          a market or has been designated as a firm network resource.


129
   Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but
  rather must be subtracted from the appropriate category in the demand section.

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                                                                                                   Terms Used in This Report

       3. Network Resource130, as that term is used for FERC pro forma or other regulatory
          approved tariffs.
       4. Energy-only resources confirmed able to serve load during the period of analysis in the
          assessment and will not be curtailed.131
       5. Where applicable, included in an integrated resource plan under a regulatory
          environment that mandates resource adequacy requirements and the obligation to serve.
Load as a Capacity Resource (Controllable Capacity Demand Response) — the magnitude of
customer demand that, in accordance with contractual arrangements, is committed to pre-
specified load reductions when called upon by a balancing authority. These resources are not
limited to being dispatched during system contingencies and may be subject to economic
dispatch from wholesale balancing authorities. Additionally, this capacity may be used to meet
resource adequacy obligations when determining planning Reserve Margins.
NERC Reference Reserve Margin Level (%) — Either the Target Reserve Margin provided by
the Region/subregion or NERC assigned based on capacity mix (i.e., thermal/hydro). Each
Region/subregion may have their own specific margin level based on load, generation, and
transmission characteristics as well as regulatory requirements. If provided in the data
submittals, the Regional/subregional Target Reserve Margin level is adopted as the NERC
Reference Reserve Margin Level. If not, NERC assigned 15 percent Reserve Margin for
predominately thermal systems and for predominately hydro systems, 10 percent.
Net Internal Demand: Equals the Total Internal Demand reduced by the total Dispatchable,
Controllable, Capacity Demand Response equaling the sum of Direct Control Load
Management, Contractually Interruptible (Curtailable), Critical Peak Pricing (CPP) with Control,
and Load as a Capacity Resource.
Non-dispatchable (Demand Response) — Demand-side resource curtails according to tariff
structure, not instruction from a control center.
Non-Firm (Transaction Category) — A category of Purchases/Imports and Sales/Exports
contract including:
   1. Non-Firm implies a non-firm contract has been signed.
   2. Non-Firm Purchases and Sales should not be considered in the reliability assessments.
Non-Spin Reserves (Controllable Ancillary Demand Response) — Demand-side resource not
connected to the system but capable of serving demand within a specified time.
On-Peak (Capacity) — The amount of capacity that is expected to be available on seasonal
peak.
Prospective Capacity Margin (%) — Prospective Capacity Resources minus Net Internal
Demand shown as a percent of Prospective Capacity Resources. Replaced in 2009 with
Prospective Capacity Reserve Margin (%) for NERC Assessments.
Prospective Capacity Reserve Margin (%) – Prospective Capacity Resources minus Net
Internal Demand shown as a percent of Net Internal Demand.
Prospective Capacity Resources – Deliverable Capacity Resources plus Existing-Other
capacity resources, minus all Existing-Other deratings (Includes derates from variable resources,


130
    Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but
  rather must be subtracted from the appropriate category in the demand section.
131
    Energy only resources with transmission service constraints are to be considered in category Future-Other.

2009/2010 Winter Reliability Assessment                                                                                 Page 190
Terms Used in This Report

energy only resources, scheduled outages for maintenance, and transmission-limited resources),
plus Future-Other capacity resources, minus all Future-Other deratings. (MW)
Provisional (Transaction Category) — A category of Purchases/Imports and Sales/Exports
contract including:
   1. Provisional implies that the transactions are under study, but negotiations have not begun.
       These Purchases and Sales are expected to be provisionally firm.
   2. Provisional Purchases and Sales should be considered in the reliability assessments.
Purchases/Imports Contracts – See Transaction Categories
Real Time Pricing (RTP) (Non-dispatchable Time-Sensitive Pricing Demand Response) —
Rate and price structure in which the price for electricity typically fluctuates to reflect changes in
the wholesale price of electricity on either a day-ahead or hour-ahead basis.
Reference Reserve Margin Level – See NERC Reference Reserve Margin Level
Regulation (Controllable Ancillary Demand Response) — Demand-side resources responsive to
Automatic Generation Control (AGC) to provide normal regulating margin.
Renewable Energy — The United States Department of Energy, Energy Efficiency &
Renewable Energy glossary defines “Renewable Energy” as “energy derived from resources that
are regenerative or for all practical purposes can not be depleted. Types of renewable energy
resources include moving water (hydro, tidal and wave power), thermal gradients in ocean water,
biomass, geothermal energy, solar energy, and wind energy. Municipal solid waste (MSW) is
also considered to be a renewable energy resource.”132 The government of Canada has a similar
definition.133 Variable generation is a subset of Renewable Energy—See Variable Generation.
Renewables — See Renewable Energy
Reserve Margin (%) — See Deliverable Capacity Reserve Margin (%) and Prospective
Capacity Reserve Margin (%). Roughly, Capacity minus Demand, divided by Demand or
(Capacity-Demand)/Demand. Replaced Capacity Margin(s) (%) for NERC Assessments in
2009.
Sales/Exports Contracts – See Transaction Categories
Spinning/Responsive Reserves (Controllable Ancillary Demand Response) — Demand-side
resources that is synchronized and ready to provide solutions for energy supply and demand
imbalance within the first few minutes of an electric grid event.
System Peak Response Transmission Tariff (Non-dispatchable Time-Sensitive Pricing
Demand Response) - Rate and/or price structure in which interval metered customers reduce load
during coincident peaks as a way of reducing transmission charges.
Target Reserve Margin (%) — Established target for Reserve Margin by the Region or
subregion. Not all Regions report a Target Reserve Margin. The NERC Reference Reserve
Margin Level is used in those cases where a Target Reserve Margin is not provided.
Total Internal Demand: The sum of the metered (net) outputs of all generators within the
system and the metered line flows into the system, less the metered line flows out of the system.
The demands for station service or auxiliary needs (such as fan motors, pump motors, and other
equipment essential to the operation of the generating units) are not included. Internal Demand

132
      http://www1.eere.energy.gov/site_administration/ glossary.html#R
133
      http://www.cleanenergy.gc.ca/faq/ index_e.asp#whatiscleanenergy

Page 191                                                                 2009/2010 Winter Reliability Assessment
                                                                        Terms Used in This Report

includes adjustments for indirect Demand-Side Management programs such as conservation
programs, improvements in efficiency of electric energy use, all non-dispatchable Demand
Response programs (such as Time-of-Use, Critical Peak Pricing, Real Time Pricing and System
Peak Response Transmission Tariffs) and some dispatchable Demand Response (such as
Demand Bidding and Buy-Back). Adjustments for controllable Demand Response should not be
incorporated in this value.
Time-of-Use (TOU) (Non-dispatchable Time-Sensitive Pricing Demand Response) — Rate
and/or price structures with different unit prices for use during different blocks of time.
Time-Sensitive Pricing (Non-dispatchable Demand Response) — Retail rates and/or price
structures designed to reflect time-varying differences in wholesale electricity costs, and thus
provide consumers with an incentive to modify consumption behavior during high-cost and/or
peak periods.
Transaction Categories (See also Firm, Non-Firm, Expected and Provisional) — Contracts
for Capacity are defined as an agreement between two or more parties for the Purchase and Sale
of generating capacity. Purchase contracts refer to imported capacity that is transmitted from an
outside Region or subregion to the reporting Region or subregion. Sales contracts refer to
exported capacity that is transmitted from the reporting Region or subregion to an outside Region
or subregion. For example, if a resource subject to a contract is located in one Region and sold
to another Region, the Region in which the resource is located reports the capacity of the
resource and reports the sale of such capacity that is being sold to the outside Region. The
purchasing Region reports such capacity as a purchase, but does not report the capacity of such
resource. Transmission must be available for all reported Purchases and Sales.
Transmission-Limited Resources — The amount of transmission-limited generation resources
that have known physical deliverability limitations to serve load within the Region.
     Example: If capacity is limited by both studied transmission limitations and generator
     derates, the generator derates take precedence. For example, a 100 MW wind farm with a
     wind capacity variation reduction of 50 MW and a transmission limitation of 60 MW
     would take the 50 MW wind variation reduction first and list 10 MW in the transmission
     limitation.
Transmission Status Categories — Transmission additions were categorized using the
following criteria:
     Under Construction
            Construction of the line has begun
     Planned (any of the following)
            Permits have been approved to proceed
            Design is complete
            Needed in order to meet a regulatory requirement
     Conceptual (any of the following)
            A line projected in the transmission plan
            A line that is required to meet a NERC TPL Standard or included in a powerflow
               model and cannot be categorized as “Under Construction” or “Planned”
            Projected transmission lines that are not “Under Construction” or “Planned”

Variable Generation — Variable generation technologies generally refer to generating
technologies whose primary energy source varies over time and cannot reasonably be stored to


2009/2010 Winter Reliability Assessment                                                Page 192
Terms Used in This Report

address such variation.134 Variable generation sources which include wind, solar, ocean and
some hydro generation resources are all renewable based. Variable generation in this report
refers only to wind and solar resources. There are two major attributes of a variable generator
that distinguish it from conventional forms of generation and may impact the bulk power system
planning and operations: variability and uncertainty.
     Variability: The output of variable generation changes according to the availability of the
        primary fuel (wind, sunlight and moving water) resulting in fluctuations in the plant
        output on all time scales.
     Uncertainty: The magnitude and timing of variable generation output is less predictable
        than for conventional generation.

                                                     References:

Glossary of Terms Used in Reliability Standards, Updated April 20, 2009
www.nerc.com/files/Glossary_2009April20.pdf

Instructions for NERC Winter Reliability Assessment – Data Reporting Form ERO-2009W,
May 15, 2009

Reliability Assessments Guidebook, Version 1.2, March 18, 2008
http://www.nerc.com/docs/pc/ragtf/Reliability_Assessment_%20Guidebook%20v1.2%20031909
.pdf

Reliability Standards for the Bulk Electric Systems in North America, Updated May 20, 2009
http://www.nerc.com/files/Reliability_Standards_Complete_Set_2009May20.pdf




134
      http://www.nerc.com/files/IVGTF_Report_041609.pdf

Page 193                                                           2009/2010 Winter Reliability Assessment
                                                                Abbreviations Used in This Report


Abbreviations Used in This Report

A/C                 Air Conditioning
AEP                 American Electric Power
AFC                 Available Flowgate Capability
ASM                 Ancillary Services Market
ATCLLC              American Transmission Company
ATR                 AREA Transmission Review (of NYISO)
AWEA                American Wind Energy Association
AZ-NM-SNV           Arizona-New Mexico-Southern Nevada (Subregion of WECC)
BA                  Balancing Authorities
BCF                 Billion cubic feet
BCFD                Billion cubic feet per day
CA-MX-US            California-México (Subregion of WECC)
CFE                 Commission Federal de Electricidad
CFL                 Compact Fluorescent Light
CMPA                California-Mexico Power Area
COI                 California-Oregon Intertie
COS                 Coordinated Outage (transmission) System
CPUC                California Public Utilities Commission
CRO                 Contingency Reserve Obligation
CRPP                Comprehensive Reliability Planning Process (of NYISO)
DADRP               Day-Ahead Demand Response Program
dc                  Direct Current
DCLM                Direct Controlled Load Management
DFW                 Dallas/Fort Worth
DLC                 Direct Load Control
DOE                 U.S. Department of Energy
DSG                 Dynamics Study Group
DSI                 Direct-served Industry
DSM                 Demand-Side Management
DVAR                D-VAR® reactive power compensation system
EDRP                Emergency Demand Response Program
EE                  Energy Efficiency
EEA                 Energy Emergency Alert
EECP                Emergency Electric Curtailment Plan
EIA                 Energy Information Agency (of DOE)
EILS                Emergency Interruptible Load Service (of ERCOT)
EISA                Energy Independence and Security Act of 2007 (USA)
ELCC                Effective Load-carrying Capability
EMTP                Electromagnetic Transient Program
ENS                 Energy Not Served
EOP                 Emergency Operating Procedure
ERAG                Eastern Interconnection Reliability Assessment Group
ERCOT               Electric Reliability Council of Texas
ERO                 Electric Reliability Organization
FCITC               First Contingency Incremental Transfer Capability
FCM                 Forward Capacity Market
FERC                U.S. Federal Energy Regulatory Commission
FP                  Future-Planned
FO                  Future-Other

2009/2010 Winter Reliability Assessment                                                Page 194
Abbreviations Used in This Report

FRCC                 Florida Reliability Coordinating Council
GADS                 Generating Availability Data System
GDP                  Gross Domestic Product
GGGS                 Gerald Gentleman Station Stability
GHG                  Greenhouse Gas
GRSP                 Generation Reserve Sharing Pool (of MAPP)
GTA                  Greater Toronto Area
GWh                  Gigawatt hours
HDD                  Heating Degree Days
HVac                 Heating, Ventilating, and Air Conditioning
IA                   Interchange Authority
ICAP                 Installed Capacity
ICR                  Installed Capacity Requirement
IESO                 Independent Electric System Operator (in Ontario)
IOU                  Investor Owned Utility
IPL/NRI              International Power Line/Northeast Reliability Interconnect Project
IPSI                 Integrated Power System Plan
IRM                  Installed Reserve Margin
IROL                 Interconnection Reliability Operating Limit
IRP                  Integrated Resource Plan
ISO                  Independent System Operator
ISO-NE               New England Independent System Operator
kV                   Kilovolts (one thousand volts)
LaaRs                Loads acting as a Resource
LCR                  Locational Installed Capacity Requirements
LDC                  Load Duration Curve
LFU                  Load Forecast Uncertainty
LNG                  Liquefied Natural Gas
LOLE                 Loss of Load Expectation
LOLP                 Loss Of Load Probability
LOOP                 Loss of off-site power
LRP                  Long Range Plan
LSE                  Load-serving Entities
LTRA                 Long-Term Reliability Assessment
LTSG                 Long-term Study Group
MAAC                 Mid-Atlantic Area Council
Maf                  Million acre-feet
MAIN                 Mid-America Interconnected Network, Inc.
MAPP                 Mid-Continent Area Power Pool
MCRSG                Midwest Contingency Reserve Sharing Group
MISO                 Midwest Independent Transmission System Operator
MPRP                 Maine Power Reliability Program
MRO                  Midwest Reliability Organization
MVA                  Megavolt amperes
Mvar                 Mega-vars
MW                   Megawatts (millions of watts)
MWEX                 Minnesota Wisconsin Export
NB                   New Brunswick
NBSO                 New Brunswick System Operator
NDEX                 North Dakota Export Stability Interface
NEEWS                New England East West Solution
NERC                 North American Electric Reliability Corporation
NIETC                National Interest Electric Transmission Corridor

Page 195                                                        2009/2010 Winter Reliability Assessment
                                                                 Abbreviations Used in This Report

NOPSG               Northwest Operation and Planning Study Group
NPCC                Northeast Power Coordinating Council
NPDES               National Pollutant Discharge Elimination System
NPPD                Nebraska Public Power District
NSPI                Nova Scotia Power Inc.
NTSG                Near-term Study Group
NWPP                Northwest Power Pool Area (subregion of WECC)
NYISO               New York Independent System Operator
NYPA                New York Planning Authority
NYRSC               New York State Reliability Council, LLC
NYSERDA             New York State Energy and Research Development Agency
OASIS               Open Access Same Time Information Service
OATT                Open Access Transmission Tariff
OP                  Operating Procedure
OPA                 Ontario Power Authority
OPPD                Omaha Public Power District
ORWG                Operating Reliability Working Group
OTC                 Operating Transfer Capability
OVEC                Ohio Valley Electric Corporation
PA                  Planning Authority
PACE                PacifiCorp East
PAR                 Phase Angle Regulators
PC                  NERC Planning Committee
PCAP                Pre-Contingency Action Plans
PCC                 Planning Coordination Committee (of WECC)
PJM                 PJM Interconnection
PRB                 Powder River Basin
PRC                 Public Regulation Commission
PRSG                Planned Reserve Sharing Group
PSA                 Power Supply Assessment
PUCN                Public Utilities Commission of Nevada
QSE                 Qualified Scheduling Entities
RA                  Resource Adequacy
RAP                 Remedial Action Plan
RAR                 Resource Adequacy Requirement
RAS                 Reliability Assessment Subcommittee of NERC Planning Committee
RC                  Reliability Coordinator
RCC                 Reliability Coordinating Committee
RFC                 ReliabilityFirst Corporation
RFP                 Request For Proposal
RGGI                Regional Greenhouse Gas Initiative
RIS                 Resource Issues Subcommittee of NERC Planning Committee
RMPA                Rocky Mountain Power Area (subregion of WECC)
RMR                 Reliability Must Run
RMRG                Rocky Mountain Reserve Group
RP                  Reliability Planner
RPM                 Reliability Pricing Mode
RRS                 Reliability Review Subcommittee
RSG                 Reserve Sharing Group
RTEP                Regional Transmission Expansion Plan (for PJM)
RTO                 Regional Transmission Organization
RTP                 Real Time Pricing
RTWG                Renewable Technologies Working Group

2009/2010 Winter Reliability Assessment                                                 Page 196
Abbreviations Used in This Report

SA                   Security Analysis
SasKPower            Saskatchewan Power Corp.
SCADA                Supervisory Control and Data Acquisition
SCC                  Seasonal Claimed Capability
SCD                  Security Constrained Dispatch
SCDWG                Short Circuit Database Working Group
SCEC                 State Capacity Emergency Coordinator (of FRCC)
SCR                  Special Case Resources
SEMA                 Southeastern Massachusetts
SEPA                 State Environmental Protection Administration
SERC                 SERC Reliability Corporation
SMUD                 Sacramento Municipal Utility District
SOL                  System Operating Limits
SPP                  Southwest Power Pool
SPS                  Special Protection System
SPS/RAS              Special Protection Schemes / Remedial Action Schemes
SRIS                 System Reliability Impact Studies
SRWG                 System Review Working Group
STATCOM              Static Synchronous Compensator
STEP                 SPP Transmission Expansion Plan
SVC                  Static Var Compensation
TCF                  Trillion Cubic Feet
TFCP                 Task Force on Coordination of Planning
THI                  Temperature Humidity Index
TIC                  Total Import Capability
TID                  Total Internal Demand
TLR                  Transmission Loading Relief
TOP                  Transmission Operator
TPL                  Transmission Planning
TRE                  Texas Regional Entity
TRM                  Transmission Reliability Margins
TS                   Transformer Station
TSP                  Transmission Service Provider
TSS                  Technical Studies Subcommittee
TVA                  Tennessee Valley Authority
USBRLC               United States Bureau of Reclamation Lower Colorado Region
UFLS                 Under Frequency Load Shedding Schemes
UVLS                 Under Voltage Load-Shedding
var                  Voltampre reactive
VACAR                Virginia and Carolinas (subregion of SERC)
VSAT                 Voltage Stability Assessment Tool
WALC                 Western Area Lower Colorado
WECC                 Western Electricity Coordinating Council
WTHI                 Weighted Temperature-Humidity Index
WUMS                 Wisconsin-Upper Michigan Systems




Page 197                                                    2009/2010 Winter Reliability Assessment
                                                                Reliability Assessment Subcommittee Roster


Reliability Assessment Subcommittee Roster
Chair       William O. Bojorquez     Hunt Transmission Services, L.L.C.            (512) 721–2653
            Vice President,          701 Brazos Street, Suite 970                  (512) 721–2656 Fx
            Planning                 Austin, Texas 78701–2559                      bbojorquez@hunttransmis
                                                                                   sion.com

Vice        Mark J. Kuras            PJM Interconnection, L.L.C.                   (610) 666-8924
Chair       Senior Engineer, NERC    955 Jefferson Avenue                          (610) 666-4779 Fx
            and Regional             Valley Forge Corporate Center                 kuras@pjm.com
            Coordination             Norristown, Pennsylvania 19403–2497

ERCOT       Dan Woodfin              Electric Reliability Council of Texas, Inc.   (512) 248–3115
            Director, System         2705 West Lake Drive                          (512) 248–4235 Fx
            Planning                 Taylor, Texas 76574                           dwoodfin@ercot.com

FRCC        Vince Ordax              Florida Reliability Coordinating Council      (813) 207–7988
            Manager of Planning      1408 N. Westshore Boulevard                   (813) 289–5646 Fx
                                     Suite 1002                                    vordax@frcc.com
                                     Tampa, Florida 33607–4512

MRO         Hoa Nguyen               Montana-Dakota Utilities Co.                  (701) 222–7656
            Resource Planning        400 North Fourth Street                       (701) 222–7970 Fx
            Coordinator              Bismarck, North Dakota 58501                  hoa.nguyen@mdu.com

NPCC        John G. Mosier, Jr.      Northeast Power Coordinating Council, Inc.    (917) 697–8565 Cell
            AVP-System               1040 Avenue of the Americas-10th floor        (212) 840–4907
            Operations               New York, New York 10018–3703                 (212) 302 –2782 Fx
                                                                                   jmosier@npcc.org

RFC         Jeffrey L. Mitchell      ReliabilityFirst Corporation                  (330) 247–3043
            Director - Engineering   320 Springside Drive                          (330) 456–3648 Fx
                                     Suite 300                                     jeff.mitchell@rfirst.org
                                     Akron, Ohio 44333

RFC         Bernard M. Pasternack,   American Electric Power                       (614) 552–1600
            P.E.                     700 Morrison Road                             (614) 552–1602 Fx
            Managing Director -      Gahanna, Ohio 43230–8250                      bmpasternack@aep.com
            Transmission Asset
            Management

SERC        Hubert C. Young          South Carolina Electric & Gas Co.             (803) 217–2030
            Manager of               220 Operations Way                            (803) 933–7264 Fx
            Transmission Planning    MC J37                                        cyoung@scana.com
                                     Cayce, South Carolina 29033

SPP         Mak Nagle                Southwest Power Pool                          (501) 614–3564
            Manager of Technical     415 North McKinley                            (501) 666–0346 Fx
            Studies & Modeling       Suite 140                                     mnagle@spp.org
                                     Little Rock, Arkansas 72205–3020

WECC        James Leigh-Kendall      Sacramento Municipal Utility District         (916) 732–5357
            Manager, Reliability     Mail Stop B305                                (916) 732–7527 Fx
            Compliance and           P.O. Box 15830                                jleighk@smud.org
            Coordination             Sacramento, California 95852–1830


2009/2010 Winter Reliability Assessment                                                             Page 198
Reliability Assessment Subcommittee Roster

WECC        Bradley M. Nickell         Western Electricity Coordinating Council    (801) 455-7946
            Renewable Integration      615 Arapeen Drive, Suite 210                (720) 635-3817
            and Planning Director      Salt Lake City, UT 84108                    bnickell@wecc.biz

Canadian-   Daniel Rochester, P.       Independent Electricity System Operator     (905) 855-6363
At-Large    Eng.                       Station A, Box 4474                         (416).574.4018 Cell
            Manager, Reliability       Toronto, Ontario, M5W 4E5                   (905) 403-6932 Fx
            Standards and                                                          dan.rochester@ieso.ca
            Assessments

IOU &       K. R. Chakravarthi         Southern Company Services, Inc.             (205) 257–6125
DCWG        Manager,                   13N-8183                                    (205) 257–1040 Fx
Chair       Interconnection and        P.O. Box 2641                               krchakra@southernco.com
            Special Studies            Birmingham, Alabama 35291

LFWG        Yves Nadeau                Hydro-Québec                                (514) 879–4100 ext 6131
Chair       Manager, Load and          Complexe Desjardins, Tour Est 25 étage --   nadeau.yves@hydro.qc.ca
            Revenue Forecasting        Case postale 10000 Montréal, Québec H5B
                                       1H7

ISO/RTO     Jesse Moser                Midwest ISO                                 (612) 718–6117
            Manager-Regulatory         P.O. Box 4202                               jmoser@midwestiso.org
            Studies                    Carmel, IN 46082–4202


ISO/RTO     John Lawhorn, P.E.         Midwest ISO, Inc.                           (651) 632–8479
            Director, Regulatory       1125 Energy Park Drive                      (651) 632–8417 Fx
            and Economic               St. Paul, Minnesota 55108                   jlawhorn@midwestiso.org
            Standards Transmission
            Asset Management

ISO/RTO     Peter Wong                 ISO New England, Inc.                       (413) 535–4172
            Manager, Resource          One Sullivan Road                           (413) 540–4203 Fx
            Adequacy                   Holyoke, Massachusetts 01040–2841           pwong@iso-ne.com

FERC        Keith N. Collins           Federal Energy Regulatory Commission        (202) 502-6383
            Manager, Electric          888 First Street, NE                        (202) 219-6449 Fx
            Analysis Group             Washington, D.C. 20426                      keith.collins@ferc.gov

FERC        Sedina Eric                Federal Energy Regulatory Commission        (202) 502–6441
            Electrical Engineer,       888 First Street, NE, 92–77                 (202) 219–1274 Fx
            Office of Electric         Washington, D.C. 20426                      sedina.eric@ferc.gov
            Reliability, Division of
            Bulk Power System
            Analysis

DOE         Patricia Hoffman           Department of Energy                        (202) 586–1411
            Acting Director            1000 Independence Avenue                    patricia.hoffman@hq.doe.
            Research and               SW 6e–069                                   gov
            Development                Washington, D.C. 20045

Alternate   Herbert Schrayshuen        SERC Reliability Corporation                (704) 940–8223
SERC        Director Reliability       2815 Coliseum Centre Drive                  (315) 439–1390 Cell
            Assessment                 Charlotte, North Carolina 28217             hschrayshuen@serc1.org




Page 199                                                           2009/2010 Winter Reliability Assessment
                                                               Reliability Assessment Subcommittee Roster

Alternate   John E. Odom, Jr.        Florida Reliability Coordinating Council   (813) 207–7985
FRCC        Vice President of        1408 N. Westshore Blvd.                    (813) 289–5646 Fx
            Planning and             Suite 1002                                 jodom@frcc.com
            Operations               Tampa, Florida 33607

Alternate   John Seidel              Midwest Reliability Organization           (651) 855–1716
MRO         Reliability Assessment   2774 Cleveland Ave                         (651) 855–1712 Fx
            Manager                  Roseville, Minnesota 55113                 ja.seidel@midwestreliabili
                                                                                ty.org

Alternate   Salva R. Andiappan       Midwest Reliability Organization           (651) 855–1719
MRO         Principal Engineer       2774 Cleveland Ave                         (651) 855–1712 Fx
                                     Roseville, Minnesota 55113                 sr.andiappan@midwestreli
                                                                                ability.org

Alternate   Paul D. Kure             ReliabilityFirst Corporation               (330) 247–3057
RFC         Senior Consultant,       320 Springside Drive                       (330) 456–3648 Fx
            Resources                Suite 300                                  paul.kure@rfirst.org
                                     Akron, Ohio 44333

Alternate   Alan C. Wahlstrom        Southwest Power Pool                       (501) 688–1624
SPP         Lead Engineer,           16101 La Grande Drive                      (501) 664–6923 Fx
            Compliance               Suite 103                                  awahlstrom@spp.org
                                     Little Rock, Arkansas 72223

Member      Jerry D. Rust            Northwest Power Pool Corporation           (503) 445–1074
            President                7505 N.E. Ambassador Place                 (813) 445–1070 Fx
                                     Portland, Oregon 97220                     jerry@nwpp.org

Member      James Useldinger         Kansas City Power & Light Co.              (816) 654–1212
            Manager, T&D System      PO Box 418679                              (816) 719–9718 Fx
            Operations               Kansas City, Missouri, 64141               jim.useldinger@kcpl.com

Observer    Stan Kaplan              Congressional Research Service             (202) 707–9529
            Specialist in Energy     101 Independence Avenue, SE                (301) 452–1349 Fx
            Policy                   Washington, D.C. 20540–7450                skaplan@crs.loc.gov




2009/2010 Winter Reliability Assessment                                                         Page 200
North American Electric Reliability Corporation Staff Roster


North American Electric Reliability Corporation Staff
Roster
North American Electric Reliability Corporation                      Telephone: (609) 452-8060
116-390 Village Boulevard                                            Fax: (609) 452-9550
Princeton, New Jersey 08540-5721

Reliability Assessment and Performance Analysis

         Mark G. Lauby                  Director of Reliability            mark.lauby@nerc.net
                                        Assessment and
                                        Performance Analysis

         Jessica Bian                   Manager of Benchmarking            jessica.bian@nerc.net
         Aaron Bennett                  Engineer of Reliability            aaron.bennett@nerc.net
                                        Assessments
         John Moura                     Technical Analyst, Reliability     john.moura@nerc.net
                                        Assessment
         Rhaiza Villafranca             Technical Analyst,                 rhaiza.villafranca@nerc.net
                                        Benchmarking


Contributing NERC Staff

         Kelly Ziegler                   Manager of Communications         kelly.ziegler@nerc.net
         Elizabeth Crouse                Administrative Assistant          elizabeth.crouse@nerc.net
         Karen Spolar                    Committee and Event               karen.spolar@nerc.net
                                         Services Administrator




Page 201                                                            2009/2010 Winter Reliability Assessment
            to ensure
 the reliability of the
bulk power system

								
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