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					2008 Summer
Reliability Assessment


                                                    to ensure
                 reliability of the
                  the
            bulk power system
                   May 2008
       116-390 Village Blvd., Princeton, NJ 08540
           609.452.8060 | 609.452.9550 fax
                     www.nerc.com
         This Page Left Intentionally Blank




Page 2                              NERC 2008 Summer Reliability Assessment
                                                                                                                                                      Table of Contents



Table of Contents

INTRODUCTION............................................................................................................. 5

PROGRESS SINCE SUMMER 2007 .............................................................................. 8

KEY FINDINGS............................................................................................................... 9
    1. Capacity Margins Adequate ..................................................................................................................................9
    2. Coal Inventories Below Average, Natural Gas Supply is Healthy ......................................................................11
    3. Demand Response Reduces Demand, Provides Ancillary Service .....................................................................13
    4. Wind Resources Contribute to Capacity .............................................................................................................16


RESOURCES, DEMAND AND CAPACITY MARGINS ................................................ 17
    Projected Margins Adequate for 2008 Summer ......................................................................................................18
    Extreme Weather Impact on Reliability ..................................................................................................................20
    Notes for Table 1a through 1d.................................................................................................................................25


REGIONAL RELIABILITY ASSESSMENT HIGHLIGHTS............................................ 26
    ERCOT....................................................................................................................................................................26
    FRCC ......................................................................................................................................................................26
    MRO........................................................................................................................................................................27
    NPCC ......................................................................................................................................................................27
    RFC .........................................................................................................................................................................29
    SERC.......................................................................................................................................................................30
    SPP ..........................................................................................................................................................................31
    WECC .....................................................................................................................................................................31


REGIONAL RELIABILITY SELF-ASSESSMENTS ...................................................... 32
ERCOT.......................................................................................................................................................................33

FRCC..........................................................................................................................................................................40

MRO ...........................................................................................................................................................................46

NPCC..........................................................................................................................................................................58
  Maritime Area .........................................................................................................................................................59
  New England...........................................................................................................................................................62
  New York ................................................................................................................................................................68
  Ontario ....................................................................................................................................................................73
  Québec ....................................................................................................................................................................78

RFC.............................................................................................................................................................................85

SERC ..........................................................................................................................................................................96
  Central...................................................................................................................................................................100
  Delta ......................................................................................................................................................................102

Page 3                                                                                                     NERC 2008 Summer Reliability Assessment
                                                                                                                                                    Table of Contents


    Gateway ................................................................................................................................................................105
    Southeastern ..........................................................................................................................................................106
    VACAR.................................................................................................................................................................108

SPP............................................................................................................................................................................112

WECC.......................................................................................................................................................................117
 Northwest Power Pool (NWPP) Area ...................................................................................................................120
 California–Mexico Power Area.............................................................................................................................122
 Rocky Mountain Power Area ................................................................................................................................123
 Arizona-New Mexico-Southern Nevada Power Area ...........................................................................................124


ABBREVIATIONS USED IN THIS REPORT .............................................................. 129

CAPACITY & DEMAND DEFINITIONS IN THIS REPORT ........................................ 131

RELIABILITY ASSESSMENT SUBCOMMITTEE ...................................................... 134




Page 4                                                                                                    NERC 2008 Summer Reliability Assessment
                                                                                                              Introduction




Introduction
The North American Electric Reliability Corporation’s (NERC) mission is to ensure the bulk
power system in North America is reliable. To achieve this objective, NERC develops and
enforces reliability standards; monitors the bulk power system; assesses and reports on future
adequacy; evaluates owners, operators, and users for reliability preparedness; and offers
education and certification programs to industry personnel. NERC is a non-profit, self-
regulatory organization that relies on the diverse and collective expertise of industry participants
that comprise its various committees and sub-groups. It is subject to oversight by governmental
authorities in Canada and the United States (U.S.).1

NERC assesses and reports on the reliability and adequacy of the North American bulk power
system divided into the eight regional areas as shown on the map below2. 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, Mexico.


                                                              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
                                                              NPCC
                                                                                               WECC
                                                              Northeast Power
                                                                                               Western Electricity
Note: The highlighted area between SPP and SERC               Coordinating Council,
                                                                                               Coordinating Council
denotes overlapping regional boundaries                       Inc.

The 2008 Summer Reliability Assessment provides key findings, a high-level reliability
assessment, projected electricity demand/resource growth, regional assessment highlights, and
regional self-assessments. The report represents NERC’s independent judgment of the reliability
and adequacy of the bulk power system in North America for the 2008 summer season. NERC’s
primary role is to identify areas of concern regarding the reliability of the North American bulk
power system and to make recommendations for their remedy.

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. Reliability standards are also mandatory and enforceable in Ontario and New
    Brunswick, and NERC is seeking to achieve comparable results in the other Canadian provinces. NERC will seek recognition
    in Mexico once the necessary legislation is adopted.
2
    Note ERCOT and SPP are tasked with reliability assessments as they are regional electrical areas. SPP-RE (SPP – Regional
    Entity) and TRE (Texas Regional Entity) are functional entities to whom NERC delegates certain authorities.


Page 5                                                                     NERC 2008 Summer Reliability Assessment
                                                                                                                  Introduction


This assessment is prepared by NERC in its capacity as the U.S. Electric Reliability
Organization.3 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. Energy Policy Act of 20054. In addition, NERC does not make any projections or draw
any conclusions regarding expected electricity prices or the efficiency of electricity markets.

Assessment Preparation

NERC prepared the 2008 Summer Reliability Assessment with support from the Reliability
Assessment Subcommittee (RAS) under the direction of NERC’s Planning Committee (PC).
The report enables bulk power system users, owners and operators to systematically document
their operational preparations for the coming season and exchange vital system reliability
information. Data and regional self-assessments are submitted by each of the eight regional
entities in March 2008 and updated, as required. Other data sources consulted by NERC staff are
also identified.

NERC uses an active peer review process in developing its reliability assessments, which takes
full advantage of industry subject matter expertise from all sectors of the industry. This process
also provides an essential check and balance for ensuring the validity of the data and information
provided by the regional entities.

Each     regional    self-assessment    is
individually assigned to two or three                 NERC’s Annual Assessments
subcommittee members from other                Assessment             Outlook        Published
regions     for    an     in-depth    and
                                                  Summer
comprehensive review.            Reviewer       Assessment
                                                                 Upcoming season        May
comments are discussed with the Region
Entity’s representative and refinements         Long-Term
                                                                      10 year          October
and adjustments are made as necessary.          Assessment
Each regional self-assessment is then
subjected to scrutiny and review by the Winter Assessment Upcoming season November
entire subcommittee. This review ensures
that each member of the subcommittee is fully convinced that each regional self-assessment is
accurate, thorough, and complete. The entire document, including the regional self-assessments,
is reviewed by the PC and the Member Representatives Committee (MRC). At the conclusion of
this process, NERC management reviews the assessment results in detail before the report is
submitted to the NERC Board of Trustees for final approval.




3
   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.”
4
  http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=109_cong_bills&docid=f:h6enr.txt.pdf

Page 6                                                                      NERC 2008 Summer Reliability Assessment
                                                                                       Introduction


In this assessment, the baseline calculations of electricity supply and internal demand projections
are based on several assumptions, outlined below.

   •     NERC’s projections are based on the forecasts provided to the Regional Entities and
         submitted by them to NERC in March 2008. Any subsequent resource plan changes may
         not be fully represented.
   •     Baseline calculations of peak demand and capacity margins are established on average
         weather conditions as well as assumptions for economic activity. The impact of the
         variability of weather is discussed in each of the regional self assessment narratives.
   •     Generating and transmission equipment will perform at historical availability levels.
   •     Planned outages and additions/upgrades of generation and transmission will be completed
         as scheduled.
   •     Demand reductions expected from demand response contracts will be effective, if and
         when they are needed.
   •     Other peak demand-side management programs are reflected in the forecasts of net
         internal demand.
   •     Firm transfers between regions are contractually arranged and occur as projected.

See http://www.nerc.com/~members/reliability_concepts/documents.htm for more background
on reliability concepts used in this report.




Page 7                                                    NERC 2008 Summer Reliability Assessment
                                                                      Progress Since Summer 2007


Progress Since Summer 2007
Several of the reliability issues and concerns highlighted in NERC’s 2007 Summer Reliability
Assessment are being addressed, including:

   •     Reliability in the Boston, Southwest Connecticut and Greater Connecticut areas have
         improved with the addition of transmission and both supply and demand-side resources.
   •     Texas has increased existing generation resources resulting in higher capacity margins.
   •     Transmission investments in the Southeast totaling more than $1.1 billion in 2007 and
         nearly $1.5 billion projected for 2008 are improving reliability in the region.
   •     Agreements are now in place to operate the installed phase angle regulators between
         Canada (Ontario) and the U.S. (Michigan). They are expected to help manage system
         congestion and control circulating or “loop” flows. Due to equipment failure, only three
         of the four phase angle regulators are expected to operate for the summer months.
   •     Over 240 miles of bulk transmission have been added in WECC since last summer.




Page 8                                                    NERC 2008 Summer Reliability Assessment
                                                                                                                                                                         Key Findings

Key Findings

1. Capacity Margins Adequate
Net capacity margins for the U.S. increased by 1.9 percent over last summer’s assessment; net
capacity margins in Canada show a slight decrease of 1 percent. These incremental changes are
small and may be influenced by the changes in NERC’s capacity categories.5 Capacity margins,
reflecting existing resources reasonably anticipated to operate and deliver power to or into the
region along with firm capacity purchases, appear adequate6 for the 2008 summer months.
                                           Figure 1a: Change in U.S. Projected                                                             Figure 1b: Change in Canadian
                                               Net Capacity Margins from                                                                Projected Net Capacity Margins from
                                              Summer 2007 to Summer 2008                                                                   Summer 2007 to Summer 2008
                                    50.0                                                                                             50.0


                                    45.0                                                                                             45.0


                                    40.0                                                                                             40.0


                                                                                                     Net Capacity Resources Margin
    Net Capacity Resources Margin




                                    35.0                                                                                             35.0                                1%
                                                                                                                                                                       Decrease

                                    30.0                                                                                             30.0
                                                                                     1.9%
                                                                                   Increase                                                                                       2007
                                    25.0                                                      2007                                   25.0
                                                                                                                                                                                  2008

                                                                                              2008
                                    20.0                                                                                             20.0


                                    15.0                                                                                             15.0


                                                                                                                                     10.0
                                    10.0

                                                                                                                                      5.0
                                     5.0

                                                                                                                                      0.0
                                     0.0




A key factor in forecasting summer demands and, thereby, capacity margins are summer
temperatures. During the 2006 and 2007 summers, temperatures for cooling (air conditioning)
degree days was higher by 12 percent and 10 percent, respectively compared to normal
conditions. For the 2008 summer, the U.S. National Oceanic and Atmospheric Administration
(NOAA) has predicted temperatures will be near normal (i.e., 0.2 percent below normal)

Reliability in Southern California Remains a Concern

Though capacity resources were increased and system reinforcements completed in the southern
California area, capacity margins still remain tight. Significant amounts of imported power are
required to fortify capacity margins and preserve reliability, resulting in heavily loaded
transmission lines into this area during peak conditions. As a result, unplanned major
transmission or generation outages, or extreme temperatures/demand may lead to resource

5
    The definitions of capacity categories were modified in 2008 (See Resources, Demand and Capacity Section); as a result,
    capacity margins may not be directly comparable to those cited in previous reports.
6
    NERC defines the reliability of the interconnected bulk power system in terms of two basic and functional aspects:

                               • Adequacy — The ability of the bulk power system to supply the aggregate electrical demand and energy requirements of the
                                       customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.
                               • Operating Reliability — The ability of the bulk power system to withstand sudden disturbances such as electric short circuits
                                       or unanticipated loss of system elements.

Page 9                                                                                                                                       NERC 2008 Summer Reliability Assessment
                                                                                                     Key Findings
                                                                                       7
constraints. The California ISO’s April 28, 2008 summer assessment presents deterministic and
probabilistic analyses for its portion of southern California. The assessment states that
“…voluntary conservation and on-call interruptible loads could be needed more frequently than
normal.” The assessment also references a 10 percent probability that its portion of southern
California may experience reserves declining to 3 percent.

Drought Conditions in SERC Improving; Reliability Concerns Relieved

Parts of the Southeast experienced severe drought conditions during 2007, leading to concerns
over plant operability as water levels threatened to drop below plant cooling water intakes. A
special reliability assessment conducted in March by SERC members studied hydrological
scenarios (including some more severe than the projected 2008 summer conditions) and showed
that there should be no reliability concerns for the upcoming summer, though some resource
redispatch, increased imports and operating procedures may be required if drought conditions
were to worsen.

Current projections forecast normal rainfall in the Southeast during the 2008 summer.8 Reservoir
levels are expected to be sufficient to support the generation needed to meet forecasted peak and
daily energy demands for the summer period. At the present time, conditions in 2008 are
improving in many (but not all) affected areas. If drought conditions were to worsen from this
point forward in 2008, conditions in 2009 could be more severe than 2007.

                       Figure 2: 2008 Summer Seasonal Drought Outlook in the U.S.




              Drought conditions persisting in southern California, Nevada, eastern New Mexico and
               western Texas currently appear to have no impact on reliability, though potential for
              wildfires as a result of dry conditions can threaten infrastructure and will be monitored
                                            throughout the summer months.

7
    http://www.caiso.com/docs/2003/04/25/200304251132276595.html
8
    http://www.cpc.ncep.noaa.gov/products/expert_assessment/drought_assessment.shtml
Page 10                                                                   NERC 2008 Summer Reliability Assessment
                                                                                                                                                                                                                                                                                                                                  Key Findings



2. Coal Inventories Below Average, Natural Gas Supply is Healthy

Coal9

Eastern U.S. coal markets have been                                               70

                                                                                                                                        Days of Burn                                                                                      5-Yr Rolling Ave
disrupted by events in the world coal market,
which began in late 2007. A shortage of coal
                                                                                  60


in the world market has driven world prices




                                                               Days of Burn
                                                                                  50
for both thermal and coking coals to record
levels. Exports of eastern U.S. coal are                                          40
projected to jump in 2008 by 20 to 30
million tons over 2007 volumes.                                                   30



These events have created a possibility of                                        20
tight coal supplies for east electric power

                                                                                          1/1/2003

                                                                                                           4/1/2003

                                                                                                                            7/1/2003

                                                                                                                                             10/1/2003

                                                                                                                                                               1/1/2004

                                                                                                                                                                              4/1/2004

                                                                                                                                                                                             7/1/2004

                                                                                                                                                                                                            10/1/2004

                                                                                                                                                                                                                            1/1/2005

                                                                                                                                                                                                                                           4/1/2005

                                                                                                                                                                                                                                                         7/1/2005

                                                                                                                                                                                                                                                                       10/1/2005

                                                                                                                                                                                                                                                                                     1/1/2006

                                                                                                                                                                                                                                                                                                  4/1/2006

                                                                                                                                                                                                                                                                                                               7/1/2006

                                                                                                                                                                                                                                                                                                                           10/1/2006

                                                                                                                                                                                                                                                                                                                                        1/1/2007

                                                                                                                                                                                                                                                                                                                                                    4/1/2007

                                                                                                                                                                                                                                                                                                                                                                7/1/2007

                                                                                                                                                                                                                                                                                                                                                                             10/1/2007

                                                                                                                                                                                                                                                                                                                                                                                         1/1/2008
generators for the summer of 2008. Many
power generators did not purchase all of their
coal needs for 2008 in advance of the change                                                                                    Figure 3a: Northern Appalachia Coal
                                                                                                                                         StocksMarch-2008
in the market, and the remaining coal that is                                            70
available is in limited supply at very high                                                                      Days of Burn                                                                                       5-Yr Rolling Ave
prices.   Power generators, therefore are
                                                                                         60
relying on coal inventory at the power plants.

Coal inventories were at healthy levels at the 50
                                                                      D ays o f B u rn




beginning of 2008, with the average for all
eastern U.S. generators at 51.6 days of 40
average burn, which is near the 5-year high.
However, the inventory levels differ for 30
different coal types. Inventories of western
coal from the Powder River Basin have fully 20
recovered from the disruption of 2005, and
                                                                                               1/1 /2003
                                                                                                                4/1 /2003
                                                                                                                                 7/1 /2003
                                                                                                                                                  10/1 /2003
                                                                                                                                                                  1/1 /2004
                                                                                                                                                                                 4/1 /2004
                                                                                                                                                                                                7/1 /2004
                                                                                                                                                                                                               10/1 /2004
                                                                                                                                                                                                                              1/1 /2005
                                                                                                                                                                                                                                             4/1 /2005
                                                                                                                                                                                                                                                           7/1 /2005
                                                                                                                                                                                                                                                                        10/1 /2005
                                                                                                                                                                                                                                                                                      1/1 /2006
                                                                                                                                                                                                                                                                                                   4/1 /2006
                                                                                                                                                                                                                                                                                                               7/1 /2006
                                                                                                                                                                                                                                                                                                                           10/1 /2006
                                                                                                                                                                                                                                                                                                                                        1/1 /2007
                                                                                                                                                                                                                                                                                                                                                    4/1 /2007
                                                                                                                                                                                                                                                                                                                                                                7/1 /2007
                                                                                                                                                                                                                                                                                                                                                                            10/1 /2007
                                                                                                                                                                                                                                                                                                                                                                                         1/1 /2008
were unusually high entering 2008 at 64 days of
average burn.         Inventories of northern
Appalachia coal had already fallen to relatively        Figure 3b: Central Appalachia Coal
                                                                Stocks March-2008
low levels (36.8 days) by the beginning of 2008
(Figure 3a), as this coal entered the export
market earlier than any other thermal coal. Inventories of central Appalachia coal, the largest
eastern coal region, were at a healthy 52 days of average burn entering 2008, but fell quickly in
the first two months of 2008, dropping to 48 days of burn (Figure 3b).

If the world coal market continues at its recent highs, it is possible that eastern power generators
will see coal inventories drop during the summer of 2008. Reliability concerns are not expected
as a result of this shift, but NERC will closely monitor these levels over the summer months to
ensure adequate inventories exist to meet peak demands.

9
    This material was prepared by Energy Ventures Analysis, Inc. providing an independent view of the coal and natural gas
    conditions for the 2008 Summer
Page 11                                                                                                                                                  NERC 2008 Summer Reliability Assessment
                                                                                                                 Key Findings




Natural Gas
The outlook for U.S. natural gas supply is healthy heading into the 2008 summer season on all
fronts. U.S. dry production of natural gas experienced a net increase of 2.2 BCFD in 2007
averaging 52.8 BCFD on the heels of record drilling levels and the industry’s focus on
unconventional resources, such as the Barnett shale and Rockies region that offset decline in the
more mature Gulf of Mexico. The upward trend has continued in early 2008 following
production increases in the deepwater Gulf of Mexico in late 200710 and despite a very slight
decline in the U.S. drilling rig count. Natural gas pipeline infrastructure has also experienced
favorable expansion over the past two years adding a record high level of new capacity to the
U.S. pipeline grid with additions of 12.7 BCFD in 2006 and 14.9 BCFD in 2007.

U.S. working gas in storage ended the 2007/2008 winter season on March 31st at 1.242 trillion
cubic feet (TCF), on par with the five-year average of 2003-2007 but below the record high
levels of the prior two years. Minimum average injections of 9.7 BCFD will be required through
the summer season to reach the five year average of 3.321 TCF by the start of the 2008/2009
winter season on November 1st, and with 10.1 BCFD required to reach 3.400 TCF. These rates
of injection compare favorably to the five year range of 8.2-11.5 BCFD. U.S. natural gas storage
capacity increased about 150 BCF during the past two years, with another 45 BCF of new
capacity expected in 2008.

North America will also benefit from the addition of six new LNG regasification terminals
coming online through 2008, with additions of global LNG liquefaction plants lagging
somewhat. While the U.S.’s ability to attract LNG imports will partially depend on relative
global prices, U.S. imports of LNG are likely to rise moderately in 2008, possibly by as much as
0.5 to 1.0 BCFD compared to last year, potentially reaching the 3.0 BCFD mark with peak
deliveries likely occurring in the summer months.

Despite the rosy U.S. natural gas supply outlook, U.S. Gulf production remains vulnerable to
disruption by summer hurricanes especially during the peak months of August and September
when the frequency of historical occurrences rise. Veteran weather forecaster, Dr. William Gray
of Colorado State University, has predicted a busy 2008 hurricane season with 8 hurricanes
predicted (compared to an average of 5.9), including 4 severe hurricanes, and 15 named storms
predicted (compared to an average of 9.6).11 While the likelihood is for potential hurricanes to
disrupt pipeline operations only temporarily, if at all, the initial production losses from
Hurricanes Katrina and Rita in 2005 of 8 to 9 BCFD (with a sustained loss of about 1.0 BCFD)
stand as a sober reminder of potential supply displacement by severe hurricanes.




10
     The spring 2008 gasket problems for the 1 BCFD Independence platform are expected to shut down the facility for one to four
     weeks, and is considered only a temporary interruption in the upward trend for domestic production.
11
     In simplified terms the 2008 hurricane forecast is 160% above normal. In comparison 2005 which included Hurricanes
     Katrina and Rita was about 250% above normal.
Page 12                                                                      NERC 2008 Summer Reliability Assessment
                                                                                                                                  Key Findings



3. Demand Response Reduces Demand, Provides Ancillary Service
Demand response is increasing as a resource to meet electricity demands. NERC completed
studies in 2007 on demand-side management12 and load forecasting13 resulting in more detailed
data on forecasted demand-side management resources (See Capacity and Demand Definitions
Section for definitions). Dispatchable, controllable capacity used to reduced peak demand is
shown in Figure 4.

                     Figure 4: Forecast Dispatchable, Controllable Capacity Demand Response for 2008
                                                            Summer Peak



                                  7.0%                                                                                             7.0%


                                  6.0%                                                                                             6.0%


                                  5.0%                                                                                             5.0%
     % of Total Internal Demand




                                  4.0%                                                                                             4.0%


                                  3.0%                                                                                             3.0%


                                  2.0%                                                                                             2.0%


                                  1.0%                                                                                             1.0%


                                  0.0%                                                                                             0.0%
                                         ERCOT     FRCC         MRO        NPCC        RFC      SERC         SPP       WECC

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




Comparison of the growth in dispatchable, controllable demand response normalized to total
internal demand (Figure 5) shows a significant increase in the MRO and NPCC regions. As this
figure is normalized to projected summer peak, year-on-year decreases in some regions may be
due to load growth, as opposed to reduced demand response, during the 2008 summer months.


12
     ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_DSMTF_Report_040308.pdf
13
     ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_Load_Forecasting_Survey_LFWG_Report_111907.pdf
Page 13                                                                                       NERC 2008 Summer Reliability Assessment
                                                                                                             Key Findings

        Figure 5: Comparison of Dispatchable Demand Response between 2007 and 2008
                           Summer Peak normalized to Total Internal Demand




                                         7.0%

                                         6.0%
            % of Total Internal Demand




                                         5.0%

                                         4.0%

                                         3.0%

                                         2.0%

                                         1.0%

                                         0.0%
                                                ERCOT FRCC   MRO NPCC   RFC      SERC       SPP       WECC

                                                               2007           2008




For the first time, NERC also collected projected demand response used for ancillary services14
defined as demand-side resource displacing generation deployed as operating reserves and/or
regulation; penalties are assessed for nonperformance. In portions of the U.S., demand response
used to support ancillary services may increase, in part due to FERC’s Order 890 pro-forma
tariff15 being revised in 2007.

Demand response used for ancillary services is used to reduce demand during system operations
to increase flexibility for bulk power system reliability. Figure 6 shows forecast dispatchable
demand response deployed for ancillary services during the 2008 summer months.




14
     See Glossary of ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_DSMTF_Report_040308.pdf for detailed definitions
15
     http://ferc.gov/industries/electric/indus-act/oatt-reform.asp
Page 14                                                                   NERC 2008 Summer Reliability Assessment
                                                                                                                                           Key Findings

 Figure 6: Forecast Dispatchable, Controllable Demand Response for Ancillary Services
  % of Total Demand Response Used for Ancillary Services


                                                           3.0%                                                                               3.0%



                                                           2.5%                                                                               2.5%



                                                           2.0%                                                                               2.0%



                                                           1.5%                                                                               1.5%



                                                           1.0%                                                                               1.0%



                                                           0.5%                                                                               0.5%



                                                           0.0%                                                                               0.0%
                                                                  ERCOT   FRCC      MRO      NPCC       RFC       SERC      SPP     WECC

                                                                          Ancillary Services Demand Response   Spinning Reserves
                                                                          Non-Spinning Reserves                Regulation




Page 15                                                                                                        NERC 2008 Summer Reliability Assessment
                                                                                                    Key Findings


4. Wind Resources Contribute to Capacity
Wind resources are growing in importance as many areas of North America see new facilities
come online. This growth is supported by state and provincial Renewable Portfolio Standards
(RPS), which generally require utilities to increase the proportion of energy generated by
renewable resources to up to 30 percent of their resource mix over the next five to 15 years.
Further, U.S. Federal renewable tax credits concentrated on encouraging wind plant construction
has fortified interest in development of renewable energy.

As noted in previous NERC assessments, certain operational considerations are critical to
reliably integrating wind and other “variable” renewable generation into the bulk power system –
notably including an analysis of how much capacity can be counted upon to serve peak demand.
Figure 7 shows the proportion of output available at the time of peak plotted against “nameplate”
or total installed capacity at 100 percent output. On-peak wind capacity figures vary significantly
between regions (from 8.7 percent to 27.8 percent), though wind contributes significantly as an
off-peak energy-only resource.

Anticipating the continued growth of variable generation resources in North America, NERC’s
Integration of Variable Generation Task Force16 is preparing a report to include 1) philosophical
and technical considerations for integrating variable resources into the Interconnection, and 2)
specific recommendations for practices and requirements, including reliability standards that
cover the planning, operations planning, and real-time operating timeframes. The final report is
expected in the first quarter of 2009.

                     Figure 7: Wind Plant Nameplate and 2008 Summer Peak Capacity



              8000                                                                    30.0%
                                                                           27.8%
              7000
                                                                                      25.0%
              6000
                                                                                              Wind Capacity on
                                                                                      20.0%   Summer Peak
                                                 21.1%
              5000                       20.0%
                                                                                              Wind Nameplate
         MW




              4000                                                            17.1%   15.0%   Capacity

              3000                                       12.6%                                Wind Capacity as
                                                                                      10.0%   % of Total Wind
                           8.7%
              2000
                                                                                      5.0%
              1000
                                  0.0%                           0.0%
                 0                                                                    0.0%
                     ERCOT FRCC          MRO     NPCC    RFC     SERC   SPP   WECC



16
     http://www.nerc.com/~filez/ivgtf.html
Page 16                                                                 NERC 2008 Summer Reliability Assessment
                                                          Resources, Demand and Capacity Margins


Resources, Demand and Capacity Margins
To improve consistency and increase the          assessment. Table 1a through 1d provides a
granularity/transparency of how regional         month-by-month summary of 2008 summer
resource projections are represented in NERC     resources, demand and capacity margins.
assessment reports, NERC’s Planning
Committee approved new categories for            Net Internal Demand (MW) —Total Internal
capacity resources and capacity purchases and    Demand reduced by dispatchable controllable
sales. The categories of “committed” and         (capacity) demand response17.
“uncommitted” resource designations used in
                                                 Total Internal Capacity — The Sum of Existing
the 2007 Summer Reliability Assessment are       (both Certain and Uncertain) and Planned
now replaced with the following:                 Capacity.

1. Existing                                      Existing-Certain Capacity and Net Firm
   a) Certain — Existing capacity resources      Transactions (MW) — Existing capacity
      reasonably anticipated to be available     resources reasonably anticipated to be available
      and operate and that are deliverable to    and operate and that are deliverable to or into the
      or into the region.                        region plus net Firm Purchases/Sales.
   b) Uncertain — Includes mothballed
      generation and portions of variable        Net Capacity Resources (MW) — Total Internal
      generation not included in “Certain”       Capacity, less Transmission-Limited Resources,
                                                 all Derates, Energy Only, and Inoperable
                                                 resources; plus     net Firm, Expected and
2. Planned — Capacity resources expected         Provisional Purchases/Sales.     Net Capacity
   to be available for the 2008 Summer that      Resources     do    not    include   Non-Firm
   have achieved one or more of the              Purchases/Sales.
   following milestones:
       a) Construction has started               Total Potential Resources (MW) — Total
       b) Regulatory permits approved            Internal Capacity, less Transmission-Limited
       c) Approved by corporate or               Resources plus the net of all Purchases/Sales.
           appropriate senior management
                                                 Existing Certain Capacity and Net Firm
                                                 Transactions Margin (%) — Existing-Certain
3. Capacity Purchases and Sales – the
                                                 Capacity and Net Firm Transactions less Net
   following categories may be applied to        Internal Demand shown as a percent of Existing
   existing and future capacity calculations.    Certain Capacity and Net Firm Transactions.
       a) Firm
       b) Non-Firm                               Net Capacity Resources Margin (%) — Net
       c) Expected                               Capacity Resources reduced by the Net Internal
       d) Provisional                            Demand; shown as a percent of Net Capacity
                                                 Resources.
See the section entitled “Capacity Definitions
Used in this Report” for more detail on the      Total Potential Resources Margin (%) — Total
definition of these categories.                  Potential Resources reduced by the Net Internal
                                                 Demand; shown as a percent of Total Potential
                                                 Resources.
Data gathered using the improved resource
categories were used to develop capacity         17

margins for trending and comparative             ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_DSMTF
                                                 _Report_040308.pdf
Page 17                                                  NERC 2008 Summer Reliability Assessment
                                                                                         Resources, Demand and Capacity Margins

Projected Margins Adequate for 2008 Summer
Capacity margins, reflecting existing resources reasonably anticipated to be available to operate
and deliver power to or into the region, along with firm capacity purchases, appear adequate for
the 2008 summer months (Figures 1a-1c). Net capacity margins18 for the U.S. increased by 1.9
percent over last summer’s assessment; net capacity margins in Canada decreased by 1.0 percent.
Potential reasons for the decrease in Canada include year-on-year load growth not fully offset by
new resources or higher firm transactions to the U.S. in 2008 summer season.


                                             Figure 1a: Change in U.S. Projected Net Capacity Margins from
                                                            Summer 2007 to Summer 2008



                                      50.0


                                      45.0


                                      40.0
      Net Capacity Resources Margin




                                      35.0


                                      30.0
                                                                                                            1.9%
                                                                                                          Increase
                                      25.0                                                                             2007

                                                                                                                       2008
                                      20.0


                                      15.0


                                      10.0


                                       5.0


                                       0.0




18
     The granularity of capacity was expanded in 2008 (See Resources, Demand and Capacity Section) and capacity margins may
     not be directly comparable.
Page 18                                                                                 NERC 2008 Summer Reliability Assessment
                                                                                                                          Resources, Demand and Capacity Margins

                                                                                 Figure 1b: Change in Canadian Projected Net Capacity Margins from
                                                                                                   Summer 2007 to Summer 2008


                                                                      50.0


                                                                      45.0


                                                                      40.0
                                     Net Capacity Resources Margin




                                                                      35.0                                                                    1%
                                                                                                                                            Decrease

                                                                      30.0
                                                                                                                                                         2007
                                                                      25.0
                                                                                                                                                         2008

                                                                      20.0


                                                                      15.0


                                                                      10.0


                                                                           5.0


                                                                           0.0




                                                                                 Figure 1c19: U.S. Subregional Projected Net Capacity Margins from
                                                                                                    Summer 2007 to Summer 2008


                                                           50.0


                                                           45.0


                                                           40.0
     Net Capacity Resources Margin




                                                           35.0


                                                           30.0


                                                           25.0                                                                                        2007

                                                                                                                                                       2008
                                                           20.0


                                                           15.0


                                                           10.0


                                                                     5.0


                                                                     0.0




19
     This is the first year PJM and MISO have been reported as subgroups within RFC.
Page 19                                                                                                                  NERC 2008 Summer Reliability Assessment
                                                                                Resources, Demand and Capacity Margins

Summer demand for 2008 (Figure 1d) is forecast to increase20 by 1.5 percent in 2008 compared
to last year’s forecast, assuming normal weather conditions. The summer weather experienced
across much of North America in 2007 drove actual peak demand 0.2 percent higher than
forecast. Overall, the 2008 summer forecast demand assuming normal weather is 1.3 percent
higher than the 2007 actual summer demand. Percent changes from 2007 actual to 2008 summer
forecast are: ERCOT: 4.2 percent, FRCC: 1.5 percent, MRO: 7.4 percent, NPCC: 2.4 percent,
RFC: 1.3 percent, SERC21: -2.8 percent, SPP: 0.9 percent and WECC: 2.9 percent.

       Figure 1d: Year-on-Year Comparison of Projected Total Internal & Actual Demand 7


                           900,000
                                                                                                               1.3%
                                                                                                             Increase
                                                                                      1.5% Increase



                           850,000
             Demand (MW)




                           800,000




                           750,000




                           700,000
                                     2001   2002   2003       2004       2005         2006            2007              2008

                                                            Projected     Actual




Extreme Weather Impact on Reliability
Extreme weather driven by higher temperatures can impact both the overall demand and can
increase reactive power requirements. NERC regions or their stakeholders have studied and
prepared for this possibility as described below:

•      High temperatures can substantially increase demand and reduce forecast capacity margins.
       System simulations were performed, and operational procedures were explored for increased
       demand and reduced capacity margins conditions. In some cases, regions reported the need
       for operational procedures to mitigate the impact of extreme weather.
•      The reactive supply resources were reviewed to ensure they are adequate to provide suitable
       voltage profiles and manage system stability. For example, low voltage excursions caused by
       bulk power and distribution system switching can result in single phase air conditioner
       stalling. System reactive supply requirements increase when air conditioners stall and can
       impact the bulk power system reliability. Studies indicate the 2008 summer should have
       sufficient supplies. Local conditions on the distribution system, with no impact on bulk
       power system reliability, are being managed by the respective distribution and transmission
       entities.

20
     Comparing 2007 actual and 2008 forecast demand does not account for actual demand response reducing 2007 actual demand.
21
     The 2008 summer load forecast for SERC is 2.8 percent lower than the actual summer 2007 peak demand as an all-time peak
     occurred during an unusually hot 2007 summer.
Page 20                                                                    NERC 2008 Summer Reliability Assessment
                                                                        Resources, Demand and Capacity Margins



Table 1a: Estimated June 2008 Resources and Demands (MW) and Margins (%)

June 2008                                                                        Existing
                                           Existing                             Certain and
                                          Certain and                            Net Firm      Net             Total
                                           Net Firm      Net            Total     Trans-     Capacity        Potential
                             Net Internal   Trans-     Capacity       Potential   actions   Resources       Resources
                              Demand       actions    Resources      Resources    Margin      Margin          Margin
                               (MW)         (MW)        (MW)           (MW)         (%)        (%)             (%)
United States
ERCOT                            56,477       72,058       73,070       82,389         21.6%        22.7%        31.5%
FRCC                             40,241       53,077       53,552       54,606         24.2%        24.9%        26.3%
MRO                              39,193       47,480       48,777       52,176         17.5%        19.6%        24.9%
NPCC                             55,161       69,666       72,311       74,177         20.8%        23.7%        25.6%
 New England                     23,017       30,950       31,057       31,161         25.6%        25.9%        26.1%
 New York                        32,144       38,716       41,254       43,016         17.0%        22.1%        25.3%
RFC                             165,500      213,400      213,400      216,300         22.4%        22.4%        23.5%
 RFC-MISO                        56,400       70,000       70,000       71,300         19.4%        19.4%        20.9%
 RFC-PJM                        109,000      141,200      141,200      142,800         22.8%        22.8%        23.7%
SERC                            183,105      235,006      235,684      237,013         22.1%        22.3%        22.7%
 Central                         39,521       49,652       50,835       50,835         20.4%        22.3%        22.3%
 Delta                           25,902       31,822       31,822       32,211         18.6%        18.6%        19.6%
 Gateway                         16,387       22,966       22,966       23,841         28.6%        28.6%        31.3%
 Southeastern                    44,811       56,548       56,548       56,548         20.8%        20.8%        20.8%
 VACAR                           56,483       74,017       73,952       74,017         23.7%        23.6%        23.7%
SPP                              38,467       48,993       58,096       59,379         21.5%        33.8%        35.2%
WECC                            126,944      165,847      172,877      184,724         23.5%        26.6%        31.3%
 AZ-NM-SNV                       28,559       35,531       36,274       37,134         19.6%        21.3%        23.1%
 CA-MX US                        51,859       61,379       65,759       69,981         15.5%        21.1%        25.9%
 NWPP                            35,303       55,974       57,418       63,117         36.9%        38.5%        44.1%
 RMPA                            11,223       12,963       13,309       14,375         13.4%        15.7%        21.9%

Total-United States             705,088      905,527      927,767      960,764         22.1%        24.0%        26.6%

Canada
MRO                               5,762        7,501        7,514         7,596        23.2%        23.3%        24.1%
NPCC                             47,361       62,477       62,984        76,656        24.2%        24.8%        38.2%
 Maritimes                        3,039        5,789        5,790         6,220        47.5%        47.5%        51.1%
 Ontario                         23,351       27,139       27,382        31,540        14.0%        14.7%        26.0%
 Quebec                          20,971       29,549       29,812        38,896        29.0%        29.7%        46.1%
WECC                             17,644       21,287       21,348        26,237        17.1%        17.4%        32.8%

Total-Canada                     70,767       91,265       91,846      110,489         22.5%        23.0%        36.0%

Mexico
WECC CA-MX Mex                    2,071         2,356        2,356        2,357        12.1%        12.1%        12.1%

Total-NERC                        777,926    999,148 1,021,969 1,073,610                22.1%       23.9%          27.5%
* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for
  demand and capacity within its region.



Page 21                                                                NERC 2008 Summer Reliability Assessment
                                                                         Resources, Demand and Capacity Margins


Table 1b: Estimated July 2008 Resources and Demands (MW) and Margins (%)

July 2008                                                                         Existing
                                            Existing                             Certain and
                                           Certain and                            Net Firm      Net             Total
                                            Net Firm      Net            Total     Trans-     Capacity        Potential
                              Net Internal   Trans-     Capacity       Potential   actions   Resources       Resources
                               Demand       actions    Resources      Resources    Margin      Margin          Margin
                                (MW)         (MW)        (MW)           (MW)         (%)        (%)             (%)
United States
ERCOT                            63,702        72,058       73,096       82,689         11.6%        12.9%         23.0%
FRCC                             42,523        53,077       53,552       54,606         19.9%        20.6%         22.1%
MRO                              42,198        47,614       48,900       52,312         11.4%        13.7%         19.3%
NPCC                             58,431        69,666       72,403       74,324         16.1%        19.3%         21.4%
 New England                     26,287        30,950       31,131       31,308         15.1%        15.6%         16.0%
 New York                        32,144        38,716       41,272       43,016         17.0%        22.1%         25.3%
RFC                             177,700       213,400      213,400      216,300         16.7%        16.7%         17.8%
 RFC-MISO                        59,900        70,000       70,000       71,300         14.4%        14.4%         16.0%
 RFC-PJM                        117,700       141,200      141,200      142,800         16.6%        16.6%         17.6%
SERC                            197,040       236,328      237,006      238,335         16.6%        16.9%         17.3%
 Central                         42,177        49,639       50,822       50,822         15.0%        17.0%         17.0%
 Delta                           26,888        31,623       31,623       32,012         15.0%        15.0%         16.0%
 Gateway                         19,105        23,496       23,496       24,371         18.7%        18.7%         21.6%
 Southeastern                    47,767        57,460       57,460       57,460         16.9%        16.9%         16.9%
 VACAR                           61,103        74,110       74,045       74,110         17.6%        17.5%         17.6%
SPP                              41,735        48,993       58,096       59,379         14.8%        28.2%         29.7%
WECC                            137,925       164,754      171,791      184,300         16.3%        19.7%         25.2%
 AZ-NM-SNV                       30,996        35,448       36,191       37,113         12.6%        14.4%         16.5%
 CA-MX US                        57,108        61,472       65,852       69,584          7.1%        13.3%         17.9%
 NWPP                            37,778        54,422       55,873       62,662         30.6%        32.4%         39.7%
 RMPA                            12,043        13,412       13,758       14,824         10.2%        12.5%         18.8%

Total-United States             761,254       905,890      928,244      962,245         16.0%        18.0%         20.9%

Canada
MRO                                5,848        7,495        7,514        7,596         22.0%        22.2%         23.0%
NPCC                              48,443       63,559       63,928       76,525         23.8%        24.2%         36.7%
 Maritimes                         3,014        5,772        5,772        6,221         47.8%        47.8%         51.6%
 Ontario                          24,351       28,194       28,268       31,376         13.6%        13.9%         22.4%
 Quebec                           21,078       29,593       29,888       38,928         28.8%        29.5%         45.9%
WECC                              17,797       22,287       22,433       26,421         20.1%        20.7%         32.6%

Total-Canada                      72,088       93,341       93,875      110,542         22.8%        23.2%         34.8%

Mexico
WECC CA-MX Mex                     2,223        2,788        2,788         2,790        20.3%        20.3%         20.3%

Total-NERC                      835,565     1,002,019    1,024,907    1,075,577         16.6%        18.5%         22.3%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for
  demand and capacity within its region.


Page 22                                                                 NERC 2008 Summer Reliability Assessment
                                                                         Resources, Demand and Capacity Margins


Table 1c: Estimated August 2008 Resources and Demands (MW) and Margins (%)

August 2008                                                                      Existing
                                           Existing                             Certain and
                                          Certain and                            Net Firm      Net              Total
                                           Net Firm      Net            Total     Trans-     Capacity         Potential
                             Net Internal   Trans-     Capacity       Potential  actions    Resources        Resources
                              Demand       actions    Resources      Resources    Margin      Margin           Margin
                               (MW)         (MW)        (MW)           (MW)         (%)        (%)              (%)
United States
ERCOT                            62,749       72,058        73,147       83,272         12.9%        14.2%        24.6%
FRCC                             44,417       53,077        53,552       54,606         16.3%        17.1%        18.7%
MRO                              41,072       47,669        48,953       52,371         13.8%        16.1%        21.6%
NPCC                             58,431       69,666        72,400       74,324         16.1%        19.3%        21.4%
 New England                     26,287       30,950        31,131       31,308         15.1%        15.6%        16.0%
 New York                        32,144       38,716        41,269       43,016         17.0%        22.1%        25.3%
RFC                             172,100      213,400       213,400      216,300         19.4%        19.4%        20.4%
 RFC-MISO                        59,800       70,000        70,000       71,300         14.6%        14.6%        16.1%
 RFC-PJM                        112,200      141,200       141,200      142,800         20.5%        20.5%        21.4%
SERC                            195,258      236,290       236,968      238,297         17.4%        17.6%        18.1%
 Central                         41,546       49,639        50,822       50,822         16.3%        18.3%        18.3%
 Delta                           27,927       31,590        31,590       31,979         11.6%        11.6%        12.7%
 Gateway                         18,174       23,516        23,516       24,391         22.7%        22.7%        25.5%
 Southeastern                    48,215       57,451        57,451       57,451         16.1%        16.1%        16.1%
 VACAR                           59,395       74,094        74,029       74,094         19.8%        19.8%        19.8%
SPP                              42,827       48,993        58,096       59,379         12.6%        26.3%        27.9%
WECC                            135,725      163,495       171,102      185,127         17.0%        20.7%        26.7%
 AZ-NM-SNV                       30,099       35,370        36,209       37,209         14.9%        16.9%        19.1%
 CA-MX US                        57,507       61,662        66,479       70,138          6.7%        13.5%        18.0%
 NWPP                            36,500       53,519        55,007       63,304         31.8%        33.6%        42.3%
 RMPA                            11,619       12,944        13,290       14,359         10.2%        12.6%        19.1%

Total-United States             752,579      904,648       927,618      963,676         16.8%        18.9%        21.9%

Canada
MRO                               5,849         7,508        7,527        7,609         22.1%        22.3%        23.1%
NPCC                             47,947        63,242       63,604       76,519         24.2%        24.6%        37.3%
 Maritimes                        2,969         5,763        5,763        6,222         48.5%        48.5%        52.3%
 Ontario                         23,634        27,920       27,987       31,369         15.4%        15.6%        24.7%
 Quebec                          21,344        29,559       29,854       38,928         27.8%        28.5%        45.2%
WECC                             17,907        22,407       22,575       26,444         20.1%        20.7%        32.3%

Total-Canada                     71,703        93,157       93,706      110,572         23.0%        23.5%        35.2%

Mexico
WECC CA-MX Mex                     2,217        2,655        2,655        2,657         16.5%        16.5%        16.6%

Total-NERC                      826,499     1,000,460    1,023,979    1,076,905         17.4%        19.3%        23.3%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for
  demand and capacity within its region.


Page 23                                                                 NERC 2008 Summer Reliability Assessment
                                                                         Resources, Demand and Capacity Margins


  Table 1d: Estimated September 2008 Resources and Demands (MW) and Margins (%)

September 2008                                                                   Existing
                                           Existing                             Certain and
                                          Certain and                            Net Firm      Net              Total
                                           Net Firm      Net            Total     Trans-     Capacity         Potential
                             Net Internal   Trans-     Capacity       Potential  actions    Resources        Resources
                              Demand       actions    Resources      Resources    Margin      Margin           Margin
                               (MW)         (MW)        (MW)           (MW)         (%)        (%)              (%)
United States
ERCOT                            50,205       72,058       73,147       83,272         30.3%        31.4%        39.7%
FRCC                             41,909       53,077       53,552       54,606         21.0%        21.7%        23.3%
MRO                              37,328       47,723       49,023       52,437         21.8%        23.9%        28.8%
NPCC                             52,516       69,666       72,432       74,353         24.6%        27.5%        29.4%
 New England                     20,372       30,950       31,160       31,337         34.2%        34.6%        35.0%
 New York                        32,144       38,716       41,272       43,016         17.0%        22.1%        25.3%
RFC                             150,300      213,400      213,400      216,300         29.6%        29.6%        30.5%
 RFC-MISO                        50,700       70,000       70,000       71,300         27.6%        27.6%        28.9%
 RFC-PJM                         99,500      141,200      141,200      142,800         29.5%        29.5%        30.3%
SERC                            176,267      233,081      233,759      235,057         24.4%        24.6%        25.0%
 Central                         39,455       48,847       50,030       50,030         19.2%        21.1%        21.1%
 Delta                           24,371       31,570       31,570       31,959         22.8%        22.8%        23.7%
 Gateway                         15,473       22,779       22,779       23,654         32.1%        32.1%        34.6%
 Southeastern                    43,653       55,861       55,861       55,861         21.9%        21.9%        21.9%
 VACAR                           53,315       74,024       73,990       74,024         28.0%        27.9%        28.0%
SPP                              37,964       48,993       58,096       59,379         22.5%        34.7%        36.1%
WECC                            126,574      161,954      170,154      186,183         21.8%        25.6%        32.0%
 AZ-NM-SNV                       27,631       35,005       35,844       37,191         21.1%        22.9%        25.7%
 CA-MX US                        54,861       61,563       66,925       70,834         10.9%        18.0%        22.5%
 NWPP                            33,508       52,859       54,391       63,611         36.6%        38.4%        47.3%
 RMPA                            10,574       12,527       12,877       14,430         15.6%        17.9%        26.7%

Total-United States             673,063      899,952      923,563       961,587        25.2%         27.1%        30.0%

Canada
MRO                               5,489        7,522         7,546        7,628        27.0%        27.3%         28.0%
NPCC                             45,839       60,447        60,565       76,278        24.2%        24.3%         39.9%
 Maritimes                        3,055        5,854         5,854        6,223        47.8%        47.8%         50.9%
 Ontario                         21,487       25,643        25,444       31,105        16.2%        15.6%         30.9%
 Quebec                          21,297       28,950        29,267       38,950        26.4%        27.2%         45.3%
WECC                             17,617       21,986        22,253       26,534        19.9%        20.8%         33.6%

Total-Canada                     68,945       89,955        90,364      110,440        23.4%         23.7%        37.6%

Mexico
WECC CA-MX Mex                     2,118        2,455        2,455        2,457        13.7%        13.7%         13.8%

Total-NERC                      744,126      992,362     1,016,382    1,074,484        25.0%         26.8%        30.7%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for
  demand and capacity within its region.


Page 24                                                                 NERC 2008 Summer Reliability Assessment
                                                         Resources, Demand and Capacity Margins




Notes for Table 1a through 1d
Note 1: Existing-Certain and Net Firm Transactions and Net Capacity Resources are assumed to
be deliverable.

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

Note 3: The WECC-U.S. area subregional net capacity resources numbers include use of
seasonal demand diversity.

Note 4: The WECC-U.S. systems demand side management resources are not necessarily
sharable between all the WECC-US subregions

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




Page 25                                                 NERC 2008 Summer Reliability Assessment
                                                          Regional Reliability Assessment Highlights




Regional Reliability Assessment Highlights

                           ERCOT
                           Total Internal Demand in the ERCOT Region for summer 2008 is
                           expected to be 64,827 MW, based on typical summer weather
                           conditions. This expected demand is 4.7 percent higher than the
                           actual peak demand for 2007, which occurred during milder than
                           typical weather conditions. Net Capacity Resources in the ERCOT
                           Region have increased by 1,926 MW since summer 2007. The
                           resulting reserve margin for the ERCOT Region for 2008 summer is
                           12.9 percent, which meets its target margin level.

The continued rapid installation of wind generation in West Texas is expected to result in
congestion on multiple transmission paths within and out of West Texas, which will require
increased operational attention. However, none of these expected constraints or unusual
operating conditions is expected to cause reliability problems.



                           FRCC
                           The 2008 summer demand forecast is 1 percent higher than for 2007.
                           This smaller growth in demand over years past is primarily due to a
                           slowdown in the Florida economy and the higher cost of electricity.
                           A net increase in generation capacity from 2007 of 476 MW is the
                           result of the expected addition of one new unit for this summer.
                           FRCC expects a 21 percent reserve margin for this upcoming
                           summer, which meets its target margin level.

The transmission capability within the FRCC region is expected to be adequate to supply firm
customer demand and to provide planned firm transmission service. The most notable
transmission improvements are in Central Florida where a new 230 kV line and the rebuild of an
existing 230 kV line are expected to be in-service by the summer.

No unusual operating conditions impacting reliability are expected. Operational issues in Central
Florida can develop due to unplanned outages of generating units serving this area. However, it
is anticipated that existing operational procedures, pre-planning, and training will adequately
manage and mitigate the impacts to the bulk transmission system.




Page 26                                                  NERC 2008 Summer Reliability Assessment
                                                                          Regional Reliability Assessment Highlights




                                     MRO
                                The MRO Net Internal Demand forecasted for the 2008 summer is
                                1.8 percent higher than forecasted for the 2007 summer. An
                                additional 1,428 MW of planned resources will be in service this
                                summer. MRO’s projected 2008 summer reserve margin is 17.5
                                percent not counting uncertain resources. Last summer’s margin
                                was 20.8 percent not counting uncommitted resources (These two
                                values cannot be directly compared because of the changes in
     capacity definitions described earlier in the report.) No significant transmission or
     operational reliability concerns are expected in the MRO region. The completion of the
     Arrowhead – Stone Lake – Gardner Park 345 kV line in January 2008 provides needed
     transmission reinforcement on the Minnesota - Wisconsin interface and improves the area’s
     transmission reliability and transfer capability. MRO’s transmission system is expected to
     perform reliably during the summer months.


                                     NPCC
                           No significant reliability issues have been cited for the 2008
                           summer period22. The non-coincident aggregate 2008 summer total
                           projected Internal Demand is 111,557 MW23 (Canadian systems
                           49,778 MW; U.S. systems 61,779 MW). This forecast peak
                           demand is little changed (-0.2 percent) from last summer’s 111,830
                           MW24 forecast aggregate demand. The forecast is based on
average weather conditions and is 2.4 percent higher than last summer’s non-coincident
aggregate actual 108,958 MW peak demand.

                           2007              2007                2008             2007 Actual        2008 Forecast
NPCC Subregion             Actual            Forecast            Forecast         w/r 07             w/r 07
                           Peak              Peak                Peak             Forecast-%         Forecast-%
Maritimes                  3,496             3,738               3,542            -6.92              -5.24
New England                26,145            27,360              27,970           -4.65              2.23
New York                   32,169            33,447              33,809           -3.97              1.08
Ontario                    25,737            25,516              24,892           0.86               -2.45
Québec                     21,411            21,769              21,344           -1.67              -1.95
Canadian Total             50,644            51,023              49,778           -0.75              -2.44
US Total                   58,314            60,807              61,779           -4.28              1.60
NPCC Total                 108,958           111,830             111,557          -2.64              -0.2


22
   These figures differ from NPCC's May 1, 2008 Summer Assessment (http://www.npcc.org/documents/reports/Seasonal.aspx)
   as NPCC includes the month of May as part of the summer period in their non-coincident demand.
23
   This demand figure is the sum of sub-regional summer season forecast peaks, regardless of month. NERC’s Total Internal
   Demand is the greatest sum of sub-regional monthly forecast peaks. Therefore these figures may differ.
24
   This demand figure is the sum of sub-regional summer season actual peaks, regardless of month. NERC’s Total Internal
   Demand is the greatest sum of sub-regional monthly actual peaks. Therefore these figures may differ.

Page 27                                                                  NERC 2008 Summer Reliability Assessment
                                                           Regional Reliability Assessment Highlights




About 1,100 MW of new capacity additions are projected to be in service for the 2008 summer
peak.

All NPCC sub-regions — ISO New England (ISO-NE), the New York Independent System
Operator (NYISO), Hydro-Québec TransÉnergie, the Ontario Independent Electricity System
Operator (IESO) and the Maritimes — expect sufficient resources to be available to meet
projected demands during 2008 Summer and have monthly projected net capacity margins
ranging from 15.6 percent to 53.0 percent. Québec and the Maritimes are predominately winter
peaking areas, and therefore adequate resources, including the supply for firm external sales, are
expected to be available.

A new 345 kV transmission line between Point Lepreau, New Brunswick, and Orrington, Maine,
went into service during December of 2007. It has increased the New Brunswick – Maine
Electric Power Company (MEPCO) Total Transfer Capability (TTC) from 700 to 1,000 MW and
the MEPCO – NB TTC from 300 to 550 MW.

Reliability has previously been a concern in the Boston area. However, transmission upgrades
completed in the spring of 2007 increased the import capability into the Boston area by 1,000
MW, to a total of 4,600 MW. As a result of those improvements, the capacity margin was
forecasted to be positive in 2007 and is expected to remain so in 2008.

Just prior to the summer peak season, New England and New York expect to energize a
replacement set of 138 kV submarine cables in the 1385 circuit (Norwalk Harbor-Northport 138
kV) connecting southwestern Connecticut to Long Island, NY. The original cables had become
highly unreliable because they had been damaged by marine anchors.

Phase angle regulators (PARs) are installed on three of the four Michigan to Ontario
interconnections. One PAR, on the Keith to Waterman 230 kV circuit J5D has been in service
and regulating since 1975. The other two available PARs, on circuits L51D and L4D, which had
been bypassed pending completion of agreements between the IESO, the Midwest ISO, Hydro
One and the International Transmission Company, were placed in service on April 14, 2008, and
are expected to start regulating before the summer. All parties have committed to completing the
necessary operating agreements to meet this schedule. The operation of the PARs will assist in
the management of system congestion and control of circulating flows. The fourth PAR, located
in Michigan at the Bunce Creek terminal of circuit B3N, responsible for controlling the tie flow
on the 230 kV circuit B3N, remains unavailable and is undergoing replacement.

Upgrades in the Rochester, New York vicinity were made to accommodate the Russell Station
retirement this summer. A capacitor bank at is scheduled to be added to by June 1, 2008.




Page 28                                                   NERC 2008 Summer Reliability Assessment
                                                         Regional Reliability Assessment Highlights




                            RFC
                          Approximately 85 percent of the PJM RTO demand and
                          approximately 60 percent of the MISO market load is within the
                          RFC region. Since the Ohio Valley Electric Corporation (OVEC) is
                          not a member of either RTO, the 88 MW of OVEC demand was
                          added to the demand of the PJM and MISO areas, a 2.0 percent
                          diversity factor was applied, and the result rounded to the nearest
                          100 MW. The resulting coincident peak for the RFC region is
                          177,700 MW Net Internal Demand (NID) and 184,000 Total
Internal Demand. The forecast NID peak is 3,200 MW (1.7 percent) lower than the forecast
demand for 2007.

The amount of “Certain” OVEC, PJM and MISO capacity in RFC is 212,900 MW. No additional
capacity is expected to go in service during the summer. All of the “certain” capacity in each
RTO is determined to be fully deliverable by PJM and MISO within their respective RTOs.
There is also 2,900 MW of capacity in the RFC region that is “uncertain” capacity, which is not
included in the reserve margin. This total of 215,800 MW of existing capacity this summer is
less (3,265 MW) than the 219,065 MW reported as existing capacity in last summer’s assessment
due to the new capacity definitions.

The RFC 2008 summer assessment for the regional area is derived by RFC from the results of
PJM and MISO assessments. It is not meaningful to calculate a specific reserve margin
requirement for all of RFC since each RTO has slightly different demand characteristics,
capacity resource availabilities and calculated reserve requirements. However, since PJM and
MISO each operate as single entities, it follows that when each RTO has adequate resources
based on satisfying their respective reserve requirements, then the RFC reserves can be
considered to be adequate.

The resulting reserve margin for RFC is 35,700 MW, which is 20.1 percent based on NID and
Net Capacity Resources. Both MISO and PJM have sufficient resources to satisfy their reserve
margin requirements. Therefore, the calculated reserve margin for this summer in the RFC
region is adequate. This compares to a 20.7 percent reserve margin documented in 2007 Summer
Assessment.

   PJM Reserve Margin
   The reserve margin for the PJM RTO is 29,200 MW, which is 21.8 percent of the NID and is
   greater than the reserve requirement of 15.0 percent, which is 20,100 MW.

   MISO Reserve Margin
   The applicable reserve margin requirements in the Midwest ISO for the 2008 planning year
   were combined by RFC to a reserve requirement for MISO of 15,900 MW or 14.1 percent.
   The projected reserve margin for MISO is 21.6 percent of the NID, which is 21,600 MW.
   Therefore, the reserves are expected to be adequate within MISO.



Page 29                                                 NERC 2008 Summer Reliability Assessment
                                                           Regional Reliability Assessment Highlights


Many new additions to the bulk-power system since last summer have been placed in service and
include a total of 85 miles of transmission lines at 230 kV and above, plus ten transformers with
a total capacity of about 6,000 MVA. An additional total of 30 miles of transmission lines at 230
kV and above is expected to be placed in service by this summer, plus six transformers with a
total capacity of about 3,000 MVA. These system changes are expected to enhance reliability of
the bulk power system.

The output of one power plant in the Washington, DC area is still restricted due to environmental
issues. However, the restriction may be lifted for emergency operating conditions. Recent
transmission enhancements have relieved local deliverability issues related to this restriction. No
other unusual operating conditions that could impact reliability are foreseen for this summer.



                                  SERC
                                  The 2008 summer load forecast is 2.8 percent lower than the
                                  actual summer 2007 peak demand. An all-time peak occurred
                                  during an unusually hot 2007 summer, though earlier weather
                                  forecasts predicted “normal” weather.

                                   SERC projects a 16.6 percent capacity margin on the basis of
                                   Existing-Certain and Net Firm Transactions for the region as a
                                   whole in this upcoming summer. A net 1,800 MW in
generation capacity increase was reported. This change is not due to any significant increase in
generation additions, but to the transfer of ownership of existing generation between a non-
SERC member and a SERC member. Most of this incremental capacity owned by non-SERC
members existed in 2007, although some of it was not reported for the 2007 Summer Reliability
Assessment. Further, by adhering to the enhanced definitions used this year, some capacity was
reallocated to different reporting categories.

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

SERC members conducted a special drought assessment considering a hydrological scenario
more severe than the forecast 2008 summer conditions. The study projects that there will be no
major reliability issues under the severe case tested in the study. At the present time, (early
spring 2008) conditions are improving in many (but not all) of the drought-affected areas.




Page 30                                                   NERC 2008 Summer Reliability Assessment
                                                         Regional Reliability Assessment Highlights




                               SPP
                               The 2008 summer peak forecast is 1 percent higher than the
                               forecast for the summer of 2007. SPP experienced a slight
                               increase in demand from the normal forecast due to higher
                               temperatures in the summer and the modest load growth
                               throughout the SPP footprint. A net increase in generation
                               capacity from 2007 of 1,607 MW is primarily due to the
                               expected addition of several small units for this summer across
                               the SPP footprint

SPP expects to have a 14.1 percent reserve margin for summer 2008, which is higher than the
required reserve margin per SPP criteria. AEP-West plans to add new 14-mile 345 kV line from
Chamber Springs to Tontitown in northwest Arkansas. SPP does not anticipate any operational
issues that will impact reliability of the system for the upcoming summer and no reliability
concerns are expected in SPP.



                             WECC
                             The WECC 2008 summer total internal demand is forecast to be
                             162,052 MW. This is 3.2 percent greater than last summer’s
                             forecast peak demand of 156,988 MW for the 2007 summer
                             period.

                              The 2008 summer period direct control load management and
                              interruptible demand capability has increased by about 560 MW
                              compared to 2007. It is important to note that the total WECC
                              Demand-Side Management (DSM) capability value shown is the
sum of each of the subregions, so it is not available for use across all subregions. The
deliverable internal capacity for 2008 is projected to be 196,545 MW compared to previously
projected 192,312 MW for 2007 (185,940 actual).

The WECC Regional capacity margin is projected to be 19.8 percent for July of 2008 based on
Existing resources (Certain), Planned Capacity Additions and Net Firm Transactions for the
region. If only the Existing resources (Certain) and the Net Firm Transactions are considered,
without the Planned Capacity Additions, the projected capacity margin would be 16.8 percent.

The southern California area is dependent on the transmission system for imports of significant
amounts of power, as in the past; unplanned major transmission and/or generation outages
coupled with lower import levels, or extreme temperatures coupled with lower import levels,
may cause resource constraints due to system limits.




Page 31                                                 NERC 2008 Summer Reliability Assessment
                                                                                       Regional Reliability Self-Assessments




Regional Reliability Self-Assessments

Regional Resource and Demand Projections
The figures in the regional self-assessment pages show the regional historical demand, projected
demand growth, capacity margin projections, and generation expansion projections reported by
the regions.

Capacity Fuel Mix
The regional capacity fuel mix charts show each region’s relative reliance on specific fuels25 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 database.


                                 Sample — Relative Capacity by Fuel Mix


                                             Sample: Relative Capacity by Fuel Mix


                                                   Coal                 Dual Fuel


                                       Pumped
                                       Storage

                                          Other
                                                                               Gas
                                        Nuclear


                                                                                 Oil

                                                      Hydro            Geothermal




25
     Note: The category “Other” may include capacity for which a fuel type has yet to be determined.

Page 32                                                                      NERC 2008 Summer Reliability Assessment
                                                                                     Regional Reliability Self-Assessments


ERCOT
     2008 Projected Peak Demand                            MW
                                                                                                    Relative Capacity by Fuel Mix
       Total Internal Demand                                64,827
         Direct Control Load Management                          0
         Contractually Interruptible (Curtailable)               0                              Coal 16%
         Critical Peak-Pricing with Control                      0                                                                  Dual Fuel
         Load as a Capacity Resource                         1,125                    Hydro 0.6%                                      27%
       Net Internal Demand                                  63,702
                                                                                      Nuclear 7%

                                                           MW      Change
     2007 Actual Summer Peak Demand                         62,188    2.4%
     All-Time Summer Peak Demand                                                   Wind 7%
                                                            62,339    2.2%
                                                                                   Other 0.8%
     2008 Projected Capacity                               MW      Margin
                                                                                           Un-
       Existing Certain and Net Firm Transactions           72,058   11.6%             determined
       Net Capacity Resources                               73,096   12.9%                0.3%
                                                                                                                   Gas 41%
       Total Potential Resources                            82,689   23.0%




Introduction
Market participants in the ERCOT Region have added 3,722
MW of resources since last summer, which results in an
increase in net dependable resources of 1,926MW26. A
projected slowdown in economic conditions in Texas is
reflected in the decrease of the 2008 peak demand forecast
from the 2007 projection of 65,135 MW to the current
projection for 2008 of 64,827 MW. Together, these changes
result in a projected reserve margin for 2008 of 12.9%. This
level of reserves is above the 12.5% minimum reserve margin, indicating that the ERCOT region
is expected to have sufficient resources to serve its peak demand in the region this summer.

ERCOT has implemented a new Emergency Interruptible Load Service, implemented as Step 3
of Emergency Electric Curtailment Plan27 (EECP), as a new tool for operators in the event
reserves are depleted and in order to avoid interruption of firm demand during system-wide
emergencies.

There are no known transmission constraints that could significantly impact reliability across the
ERCOT region. The continuing increase of installed wind generation in west Texas is likely to
require increased operational focus during this summer due to transmission congestion within
and out of west Texas. ERCOT continues to have a Reliability Must Run agreement to maintain
reliability in the Laredo area.

Demand
The 2007 summer actual peak demand for the ERCOT region was 62,188 MW. This peak
demand was set with temperatures during the summer in 2007 that were unusually mild (below
normal). In 2007, the summer peak demand forecast for 2008 was 65,135 MW. This year, the


26
     The balance of the 3,722MW is the portion of the new wind generation that is considered derated on-peak.
27
     http://www.ercot.com/mktrules/protocols/current.html Section 5.6.6.1

Page 33                                                                       NERC 2008 Summer Reliability Assessment
                                                                                    Regional Reliability Self-Assessments

2008 summer peak demand is forecasted to be 64,827 MW. The 2008 forecast is lower than last
year’s forecast for 2008 due to the forecasted slowdown in economic conditions.

The forecasted peak demands are produced by ERCOT for the ERCOT Region (which is a single
Balancing Authority area) based on the coincident actual demands. The weather assumptions on
which the forecasts are based are considered to represent an average weather profile (50/50). An
average weather profile is calculated for each of the eight weather zones in the ERCOT grid,
which are used in developing the forecast. These average weather profiles are based on a Rank-
Median method. This method ranks the yearly temperatures from highest to lowest for all years
in the database and assigns the ranked temperatures to a calendar. The calendar is selected using
a minimum squared error criterion. Median temperatures are preferred as they are not affected as
much by outliers as the average.

The economic variables used in the ERCOT weather zone models are employment, real personal
per-capita income and population. Employment is a measure of the growth in the commercial
and industrial areas. Population is a proxy for capturing customer formation, and income
addresses overall standard of living which translates into increase in comfort and convenience
and in many instances leads directly to an increase in electricity demand.

The key factors driving the lower peak demands and energy consumption forecasts reflect the
overall state of the economy as captured by economic indicators listed above, such as the real per
capita personal income, population, and various employment measures including non-farm
employment and total employment. These economic variables are used throughout the eight
weather zones that comprise the ERCOT electric grid.

These economic indicators used in the 2008 forecast show a minor slowdown of the economy in
the short-run, which results in an impact of about 300 MW in the summer forecast in 2008.
There is a deceleration in the TX employment, but employment continues to grow faster than the
weak pace of the US. High energy prices continue to power the Houston economy.

The actual demands used for forecasting purposes are coincident hourly values across the
ERCOT Region. The data used in the forecast is by weather zones. ERCOT has the Load acting
as a Resource (LaaR) program28, which amounts to approximately 1,125 MW, slightly more than
last year, which was 1,112 MW. The LaaR capacity is available through ERCOT’s ancillary
services market. ERCOT has added a new load reduction program called Emergency
Interruptible Load Service (EILS)29, which is designed to be deployed as Step 3 of an Emergency
Electric Curtailment Plan (EECP) event. EILS loads are deployed after the Loads acting as
Resources (LaaRs) but before the involuntary firm load. EILS is not considered an offset to net
demand. Currently, there are 262 MW of participation in the EILS program.

To assess the impact of weather variability on the peak demand for ERCOT, alternative weather
scenarios are used to develop extreme MW forecasts. A high demand scenario is produced using
the 90th percentile of the temperatures in the database spanning the last fourteen years available.


28
     http://www.ercot.com/mktrules/protocols/current/06-030108.doc
29
     http://www.ercot.com/mktrules/protocols/current/06-030108.doc Section 6.1.13

Page 34                                                                     NERC 2008 Summer Reliability Assessment
                                                                            Regional Reliability Self-Assessments

The lower temperatures that rank in the bottom 10th percentile of the database are also used to
produce a lower range forecasts.

The extreme temperatures are input into the load-shape and energy models to obtain the
forecasts. The higher temperature assumptions consistently produce MW forecasts that are
approximately 5.5% higher than the base forecasts (50/50). Together, the forecasts from these
temperature scenarios are usually referred to as 90/10 MW forecasts.

Generation
Currently, ERCOT has 71,704 MW of Existing-Certain generation, approximately 9,056 MW
Existing-Uncertain generation, and 1,575 MW Planned generation capacity either presently in
service or expected to be in service during the 2008 summer period. Of the Existing Certain
amount, 53 MW of biomass is included, however only 8.7% of existing and planned wind
generation nameplate capacity is used, based on a 2006 study of the effective load carrying
capacity of wind30. The remaining existing wind capacity amount is included in the Existing-
Uncertain generation amount.

ERCOT is not dependent on hydro generation to meet summer peak demand or the daily energy
demand because less than 1% of the generation mix in the ERCOT region is comprised of hydro
generation. ERCOT is not currently experiencing drought conditions. Reservoir levels are
currently at or near full capacity31. ERCOT does not expect significant capacity reduction
implications due to low water levels.

Purchases and Sales
ERCOT has only limited connection with other regions through five DC ties (two between
ERCOT and SPP and three between ERCOT and Mexico) and therefore has few long term firm
contracts for transfer between the ERCOT region and SPP included in sales and purchases. An
import to ERCOT from SPP is tied to a long term contract for a purchase of 48 MW of firm
power from specific generation. There are a total of 820 MW of DC tie transfer capability
between ERCOT and SPP and 286 MW of capability between ERCOT and Mexico’s Comision
Federal de Electricidad (CFE), of which 553 MW are included as purchases under emergency
support agreements. There are no non-Firm contracts signed or pending. There are also no
known contracts under negotiation or under study.

SPP members’ ownership of 247 MW of a power plant located in ERCOT is tied to long term
firm contracts, which result in transfers from ERCOT to SPP. There are no non-firm contracts
signed or known to be in negotiation. Additionally, there are no other transactions currently
under study.

ERCOT does not share reserves on a regular basis with any other regions. The only reliance on
outside resources is for emergency service by request only.




30
     http://www.ercot.com/meetings/gatf/keydocs/2007/20070112-GATF/ERCOT_Reserve_Margin_Analysis_Report.pdf
31
     http://wiid.twdb.state.tx.us/ims/resinfo/BushButton/lakeStatus.asp

Page 35                                                               NERC 2008 Summer Reliability Assessment
                                                                         Regional Reliability Self-Assessments



Fuel
No significant disruptions in gas supply were experienced in ERCOT in the summer of 2007 and
are not anticipated in 2008. Natural gas fuel supply interruptions are a potential concern during
the winter due to demand for gas for home heating, but these interruptions typically do not occur
in summer. No problems with coal supply deliveries to ERCOT are expected this summer.

Transmission
Approximately 167 miles of new or rebuilt 138kV transmission lines were completed since the
2007 summer and an additional 120 miles of rebuilt 138kV transmission lines are expected to be
completed before the 2008 summer period. Approximately 45 miles of rebuilt 69kV
transmission lines were completed since the 2007 summer and an additional 38 miles of rebuilt
69kV is anticipated before the 2008 summer.

The continued rapid installation of new wind generation in West Texas is expected to result in
congestion on multiple constraints within and out of West Texas for the next several years until
new bulk transmission lines are added between West Texas and the rest of the ERCOT system.

The existing transmission system into the Laredo area cannot support the energy imports to south
Texas necessary to satisfy the area and maintain N-1 security requirements during high load
periods without generation in the area. Currently, ERCOT has three units under Reliability Must-
Run (RMR) contract in Laredo for a total capacity of 169 MW. Transmission line upgrades that
will allow releasing the RMR contract are planned to be completed in 2010. A 100-MW
Variable Frequency Transformer tie with Mexico has been installed. This device will not allow
releasing the RMR units but helps ensure that adequate capacity is available to restrict the
Laredo energy imports to acceptable levels that satisfy the Laredo area security criteria.

Two 140 MVAr dynamic reactive devices will be installed in the Houston area (Bellaire South
and Crosby 138 kV stations) by June 2008. These devices will provide reactive support
necessary to maintain voltages within the voltage ride-through requirements for generation in the
area during Category D contingencies32.

Operational Issues
Currently, there are about 30 minor unit outages planned during the assessment period; the
majority of these are scheduled for September, after the typical peak demand. One planned
outage for June, July and August will likely result in local congestion in the far south region of
Texas. Planned transmission upgrade projects in this area are expected to be completed before
the assessment period and should help this congestion. There are no environmental or regulatory
restrictions known at this time which are expected to impact reliability.

The continued increase in installed wind generation has the potential to lead to operating
challenges during the summer season. ERCOT has recently implemented a wind power
forecasting system to allow system operators to identify and take appropriate action when wind
resource schedules may not track expected changes in wind production, which was one
contributing factor to the EECP event on 2/26/2008.33 In addition, congestion management

32
     http://www.ercot.com/mktrules/guides/operating/2007/11/03/03-110107.doc
33
     http://www.ercot.com/meetings/ros/keydocs/2008/0313 /07._ERCOT_OPERATIONS_REPORT_EECP022608_public.doc

Page 36                                                           NERC 2008 Summer Reliability Assessment
                                                                          Regional Reliability Self-Assessments

associated with the increased wind generation is likely to require increased attention. Finally,
ERCOT recently completed a study of the impact of increased wind generation on ancillary
services requirements. At the level of wind generation that will be installed during this summer
season, the study found that ERCOT’s current ancillary services procurement methodologies are
appropriate; those methodologies will likely result in higher levels of some ancillary services.

Reliability Assessment Analysis
The reserve margin for the 2008 summer assessment period is currently projected to be 12.9%
which is 0.4% higher than the minimum reserve margin level for ERCOT of 12.5%. This
currently projected reserve margin for 2008 is 0.8% lower than the 13.7% reserve margin that
was projected for 2007 in last year’s Summer Assessment.

ERCOT has a minimum reserve margin target of 12.5%, based on Loss-of-Load Expectation
(LOLE) analysis of no more than one day in ten years loss of load. The last loss of load
probability (LOLP) study that was used to assess the adequacy of the 12.5% reserve margin
criteria in meeting a one-day-in-ten-years LOLP was performed in 2007.34

ERCOT does not have a formal definition of generation deliverability. However, 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 coincident system peak demand plus
operating reserves. Load data for this analysis is based on the non-coincident demands projected
by the transmission owners. Operationally, transmission operating limits are adhered to through
market-based generation redispatch directed by ERCOT as the balancing authority and reliability
coordinator. Operational resource adequacy is also maintained by ERCOT through market-based
procurement processes (See Sections six and seven of the ERCOT Protocols35).

ERCOT does not anticipate extreme summer weather to have an impact on fuel supply or fuel
delivery. If fuel supply issues become a potential problem they are reported to ERCOT by the
affected entity as a resource de-rating or a forced outage. ERCOT does not coordinate directly
with the fuel industry; independent generator owners and operators are responsible for their own
fuel supply. In the event of forecasted extreme weather and possible fuel curtailments, ERCOT
may request fuel capability information from qualified scheduling entities (QSE) that represent
generation to better prepare operationally for potential curtailments (See Section 5.6.5 of the
ERCOT Protocols36). Specific information that may be requested can be found in the ERCOT
Operating Guides.37

ERCOT has interconnections through DC ties with the Eastern Interconnect and with Mexico.
The maximum imports/export over these ties is 1,106 MW. These ties can be operated at a
maximum import and export provided there are no area transmission elements out of service. In
the event of a transmission outage in the area of these ties, studies will be run during the outage
coordination period for the outages to see if any import/export limits are needed.

34
   http://www.ercot.com/meetings/gatf/keydocs/2007/20070112-GATF/ERCOT_Reserve_Margin_Analysis_Report.pdf
35
    http://www.ercot.com/mktrules/protocols/current.html
36
   Ibid
37
    http://www.ercot.com/mktrules/guides/operating/index.html

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There are no known transmission constraints that are expected to significantly impact reliability
across the ERCOT region. 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.

ERCOT regularly performs transient dynamics and voltage studies. Small signal stability studies
were performed as part of the West-North stability study. There are no anticipated stability
issues that could affect reliability however ERCOT closely monitors a west-north stability limit
and a Rio Grande valley voltage limit.

In the operations planning horizon, ERCOT performs 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.

 Operating Procedure 2.4.3 VSAT (Voltage Stability Analysis Tool) describes the procedure to
monitor the system and to prevent voltage collapse using the online voltage stability analysis
tool. Different scenarios along with the MW safety margins are described and mitigation
procedures are prescribed based on VSAT results. Once the prescribed action is communicated,
taken and verified VSAT will be rerun with the new topology.

No explicit minimum dynamic reactive criteria exist, however reactive margins are maintained in
the major metropolitan areas. Areas of dynamic and static reactive power limitations are Corpus
Christi, Houston, Dallas/Ft. Worth, Rio Grande Valley, South to Houston generation, South to
Houston load, North to Houston Generation and North to Houston load. These areas and
mitigation procedures are found in Operating Procedure 2.4.3.38 ERCOT plans for a 5% voltage
stability margin for category A and category B contingencies and a 2.5% margin for category C
contingencies39. The UVLS program performs in up to three stages and is based on voltage trip
points, with time delays prior to trip and percentage of load at the specific bus.

The ERCOT region is expected to have more than sufficient resources to meet the 2008 summer
demand. ERCOT should have sufficient capacity even for a peak demand that is as high as the
90th percentile of the weather sensitivity in the load forecast, which could result in a peak
demand 5.5% higher than the expected peak demand. An extremely hot summer that results in
load levels significantly above forecast, higher than normal unit forced outage rates, or financial
difficulties of some generation owners that may make it difficult for them to obtain fuel from
suppliers are all risk factors that alone or in combination could result in inadequate supply. In
the event that occurs, ERCOT will implement its Emergency Electric Curtailment Plan (EECP)
(See Section 5.6.6.1 of the ERCOT Protocols)40. The EECP includes procedures for use of
interruptible load, voltage reductions, procuring emergency energy over the DC ties, ISO-
instructed demand response procedures and are in place and are described in the ERCOT
Operating Guides Section 4.5 Emergency Electric Curtailment Plan (EECP) 41.


38
   http://www.ercot.com/mktrules/guides/procedures/TransmissionSecurity_V3R89.doc
39
   http://www.ercot.com/mktrules/guides/operating/2007/07/05/05-070107.doc
40
   http://www.ercot.com/mktrules/protocols/current.html
41
   http://www.ercot.com/mktrules/guides/operating/current.html.

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Region Description
ERCOT is a separate electric interconnection located entirely in the state of Texas and operated
as a single balancing authority. ERCOT has 251 members that represent independent retail
electric providers; generators, and power marketers; investor-owned, municipal, and
cooperative utilities; and retail consumers. It is a summer-peaking region responsible for about
85 percent of the electric load in Texas with a 2006 peak demand of 62,339 megawatts. ERCOT
serves a population of more than 20 million in a geographic area of about 200,000 square miles.
Additional information is available on the ERCOT web site42.




42
     http://www.ercot.com


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FRCC
 2008 Projected Peak Demand                      MW
                                                                                       Relative Capacity by Fuel Mix
   Total Internal Demand                          47,364
     Direct Control Load Management                2,256
     Contractually Interruptible (Curtailable)       691                          Coal 17%
     Critical Peak-Pricing with Control                0
     Load as a Capacity Resource                       0                Hydro 0.1%
   Net Internal Demand                            44,417
                                                                        Nuclear 8%
                                                 MW      Change
 2007 Actual Summer Peak Demand                   46,676   -4.8%       Other 2%                                        Gas 52%

 All-Time Summer Peak Demand                      46,676   -4.8%

 2008 Projected Capacity                         MW      Margin
                                                                             Oil 21%
   Existing Certain and Net Firm Transactions     53,077   16.3%
   Net Capacity Resources                         53,552   17.1%
   Total Potential Resources                      54,606   18.7%




Introduction

FRCC expects to have adequate generating capacity
reserves with transmission system deliverability for the
2008 summer peak demand. In addition, existing uncertain
merchant plant capability of 1,053 MW is available as
potential future resources of FRCC members and others.

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

Demand

The Florida Reliability Coordinating Council (FRCC) is forecast to reach its 2008 summer peak
demand of 47,364 MW in August, which represents a projected demand increase of 1.5 % over
the actual 2007 summer demand of 46,676 MW. This projection is consistent with historical
weather-normalized FRCC demand growth and is 1.0% higher than last year’s summer forecast
of 46,878 MW. The increase in the 2008 summer peak demand is attributed to normal
temperatures and a sluggish economy.

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
summer takes into consideration the overall economy in Florida with emphasis on the price of
fuel and electricity. Each individual LSE within the FRCC Region develops a forecast that
accounts for actual peak demand. The individual peak demand forecasts are then aggregated by
summing these forecasts to develop the FRCC Region forecast. The 2008 net internal FRCC


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peak demand forecast includes the effects of 2,947 MW of potential demand reductions from the
use of direct control load management and interruptible load management programs composed of
residential, commercial and industrial demand. Projections also incorporate MW 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% confidence intervals on the projected or most likely load (90/10). The 80% confidence
intervals on peak demand can be interpreted to mean that there is a 10% probability that in any
year of the forecast horizon that actual observed load could exceed the high band. Likewise,
there is a 10% 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 summer’s forecast include a weaker Florida
economy and projected higher fuel prices.

Generation

The total existing generation in the FRCC region for this summer is 51,683 MW of which 50,629
MW (462 MW of biomass) are certain and 1,053 MW are uncertain. Since the beginning of the
year, a net capacity of 476 MW (11 MW of biomass) are planned to be online by September 30,
2008. 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.

Purchases and Sales
Currently, there are 2,448 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. These
purchases have firm transmission service to ensure deliverability into the FRCC region. The
FRCC Region does not consider non-firm, expected or provisional sales to other regions as
capacity resources. The FRCC Region does not rely on external resources for emergency
imports and reserve sharing.

Fuel
For the 2008 summer period, we do not anticipate any load serving concerns 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 is 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 summer.




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Transmission
Major additions to the FRCC bulk power system are mostly related to expansion in order to serve
the growing demand and therefore maintain the reliability of the transmission system. The most
notable transmission additions expected to be in-service for the summer of 2008 include a new
230kV transmission line and the rebuild of an existing 230kV in the Central Florida area. In
addition a new 138kV transmission line is expected to be in-service for the summer of 2008 in
the Southeast Florida area.

Operational Issues
No scheduled generating unit or transmission facility maintenance outages of any significance
are planned for the summer period. Scheduled transmission outages are typically performed
during seasonal off peak periods to minimize any impact on the bulk electric system. 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 2008 summer
period.

No unusual operating conditions are expected that could impact reliability for the upcoming
2008 summer. 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 Florida Public Service Commission to maintain a 15%
Reserve Margin. Presently, there are no requirements in the FRCC Region to plan for or
maintain a specific capacity margin. However, based on the expected load and generation
capacity, the calculated capacity margin for the summer of 2008 is 17.1% (Reserve Margin =
21%). This year’s calculated capacity margin is 0.5% lower than last year’s calculation for the
summer of 2007.

The expected Reserve Margin for this summer includes a total of 2,448 MW import from the
Southeastern Subregion of SERC to the FRCC. The total import into the FRCC Region consists
of 846 MW of generation that resides in the Southeastern Subregion of SERC owned by FRCC
entities and the remaining 1602 MW are firm purchases. These imports account for 5.0 % of the
total Reserve Margin, and have firm transmission service to ensure deliverability into the FRCC
region. During last year’s summer a total of 2,398 MW (firm transmission service) of external
resources were included in the Reserve Margin calculation for the Region. The increase in
imports over last year’s summer assessment is primarily due to a firm purchase of 50 MW from
the Southeastern Subregion of SERC.

The 15% Reserve Margin was established based on a Loss Of Load Probability (LOLP) analysis
that incorporated system generating unit information to determine the probability that existing
and planned resource additions will not be sufficient to serve forecasted loads. The objective of

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this periodic 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 2006 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 well below the 0.1 day per year criterion. The FRCC is planning to conduct
the next LOLP analysis by the end of 2008.

Given the FRCC fuel diversity as listed within the FRCC Load and Resource Database, it is
anticipated that fuel supply availability will be adequate during summer peak conditions. For
potential generating capacity constraints due to fuel delivery problems, 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. The recently revised FRCC Generating Capacity Shortage Plan
includes specific actions to address capacity constraints due to generating fuel shortages. 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.

The FRCC Region does not have an official definition for deliverability. However, the FRCC
Transmission Working Group (composed of transmission planners from FRCC member utilities)
conducts regional studies to ensure that all dedicated firm resources are deliverable to loads
under forecast conditions and other various probable scenarios to ensure the robustness of the
Bulk Electric System (BES). In addition, the FRCC Transmission Working Group evaluates
planned generator additions to ensure the proposed interconnection and/or integration is
acceptable to maintain the reliability for the BES within the FRCC Region.

Availability and deliverability of internal and external resources are ensured by firm transmission
service, purchase power contracts and transmission assessments. These internal and external
resources were included in the “2008 Summer Transmission Assessment” demonstrating the
deliverability of these resources and no deliverability concerns were identified.

Although the FRCC has reviewed various types of fuel supply issues in the past, the increased
reliance of generating capacity on natural gas has caused the FRCC to address this fuel type
specifically. The FRCC continues coordination efforts among natural gas suppliers and
generators within the region. The recently revised FRCC Generating Capacity Shortage Plan
includes specific actions to address capacity constraints due to natural gas availability constraints
and includes close coordination with the pipeline operators serving the Region. The FRCC
Operating Committee has also developed the procedure, FRCC Communications Protocols –
Reliability Coordinator, Generator Operators and Natural Gas Transportation Service

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Providers, to enhance the existing coordination between the FRCC Reliability Coordinator and
the natural gas pipeline operators and in response to FERC Order 698.

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 summer seasonal import capability of
3,600 MW into the region, and an export capability of 1,000 MW. These joint studies account
for constraints within the FRCC and/or the Southeastern Subregion of SERC.

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 two new 230kV
transmission lines and the rebuild of an existing 230kV transmission line have been identified
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.

Transmission constraints in the Northwest Florida area may occur under high imports into
Florida from the SERC Region. The FRCC Region and Southeastern Subregion of SERC
worked together to develop and approve a special operating procedure to address and mitigate
these potential constraints.

The FRCC Region is planned and operated such that NERC Reliability Standards are met
without the need to identify any specific criteria for minimum dynamic reactive reserve
requirements or transient voltage-dip criteria. Transient stability studies are performed by the
FRCC and no issues have been identified that would impact the summer 2008 season. Small
signal analysis is performed when damping issues are identified during transient stability studies.
Voltage stability studies performed in the Region involve identifying the worst case conditions
such as the unavailability of multiple units. These studies are normally load flow based using an
algorithm that can identify voltage limitations.

Under firm transactions, reactive power-limited areas can be identified during transmission
assessments performed by the FRCC. These reactive power-limited areas are typically localized
pockets that do not affect the bulk power system. The FRCC 2008 Summer Transmission
Assessment did not identify any reactive power-limited areas that would impact the bulk electric
system during the summer of 2008. The FRCC Region has not identified the need to develop
specific criteria to establish a voltage stability margin.

The FRCC Region has approximately 700 MW of load set for Under Voltage Load-Shedding
(UVLS) in localized areas to prevent voltage collapse as a result of a contingency event. The
UVLS system is designed with multiple steps and time delays to shed only the necessary load to
allow for voltage recovery.

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 summer peak demand. The results of the 2008 Summer Transmission Assessment, which
evaluated the steady-state summer peak load conditions under different operating scenarios,

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indicates that any concerns about 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 analyses 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 FRCC ensures resource adequacy by maintaining a minimum 15% Reserve Margin to
account for higher than expected peak demand due to weather or other conditions. In addition,
there are operational measures available to reduce the peak demand such as the use of
Interruptible/Curtailable load, DSM (HVAC, Water Heater, Pool Pump), Voltage Reduction,
customer stand-by generation, emergency contracts and unit emergency capability.

The FRCC is not anticipating any other reliability concerns for the 2008 summer conditions.
Unexpected potential reliability real-time issues identified by the Reliability Coordinator can be
resolved with existing operational procedures.

Region Description
FRCC’s membership includes 26 members, which is composed of investor-owned utilities,
cooperative systems, municipal utilities, power marketers, and independent power producers.
Historically, the region has been divided into 11 control areas. As part of the transition to the
ERO, FRCC has registered 79 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
     2008 Projected Peak Demand                          MW
                                                                                             Relative Capacity by Fuel Mix
       Total Internal Demand                              51,166
         Direct Control Load Management                    1,587
                                                                                                               Dual Fuel 9%
         Contractually Interruptible (Curtailable)         1,533
         Critical Peak-Pricing with Control                    0
         Load as a Capacity Resource                           0                                                              Gas 12%
       Net Internal Demand                                48,047
                                                                                                                                  Oil 4%
                                                         MW      Change                                                            Undeter-
                                                                                Coal 51%                                          mined 0.1%
     2007 Actual Summer Peak Demand                       47,629    0.9%
                                                                                                                                  Other 3%
     All-Time Summer Peak Demand                          47,629    0.9%
                                                                                                                                  Wind 1.0%
                                                                                                                              Nuclear 7%
     2008 Projected Capacity                             MW      Margin
       Existing Certain and Net Firm Transactions         55,109   12.8%
       Net Capacity Resources                             56,414   14.8%                                           Hydro 13%
       Total Potential Resources                          57,758   16.8%



Introduction

The Midwest Reliability Organization (MRO) is expected
to have sufficient generating capacity within the region to
maintain an adequate reserve margin for the 2008 summer
peak demand. The transmission system within the MRO
region is expected to perform reliably to meet firm
customer demand for the summer 2008. There are no
significant operational issues that may cause reliability
concerns expected in the MRO region during the upcoming
summer.

From the resource adequacy assessment viewpoint, the MRO membership consists of the
members of the MAPP Generation Reserve Sharing Pool (GRSP), members from the former
Mid-America Interconnected Network, Inc. (MAIN),43 and a Canadian member, Saskatchewan
Power Corporation (SaskPower). The assessment of transmission adequacy and identification of
operational issues are, however, conducted by areas in the MRO footprint: Iowa, Nebraska,
Northern MRO, and Wisconsin-Upper Michigan Systems (WUMS). The Northern MRO region
consists of the Dakotas, Minnesota, part of Montana, and the Canadian provinces of Manitoba
and Saskatchewan.

Demand

The MRO forecasted 2008 summer non-coincident peak total internal demand in the combined
MRO US and MRO Canada is 51,166 MW, assuming normal weather conditions. This forecast
is 4.2 percent above last summer’s forecasted total demand of 49,102 MW. The MRO 2008
forecast Net Internal Demand is 48,047 MW, which is 1.8 percent higher than the 2007
forecasted Net Internal Demand of 47,177 MW.


43
     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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Last summer’s actual peak demand was 47,629 MW. This actual peak value is not adjusted to
exclude any additional peak-demand reduction demand-side management programs that were not
implemented.

Direct control load management DSM (1,587 MW, or 3.1 percent) and contractually interruptible
demand (1,533 MW, or 3.0 percent), amounting to 6.1 percent of MRO’s projected Total Internal
Peak Demand of 51,166 MW, are used by a number of MRO members. A wide variety of
demand-side management programs may be used to reduce peak demand during the summer
season.

Each MRO member uses its own forecasting method. 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 significant
changes in this year’s forecast assumptions in comparison to last year.

Peak demand uncertainty and variability due to extreme weather and other conditions are
accounted for within the determination of adequate generation reserve margin levels, although
they are treated differently among the MRO groups, as follows.

The MAPP GRSP members and the former MAIN members within MRO use a Load Forecast
Uncertainty factor within the calculation for the Loss of Load Expectation (LOLE) and the
percentage reserve margin necessary to obtain a LOLE of 0.1 day per year or 1 day in 10 years.
The load forecast uncertainty considers uncertainties attributable to weather and economic
conditions.

For the Saskatchewan system, high and low demand forecasts were simulated using a Monte
Carlo method to reflect economic and weather uncertainties. This model considers each
uncertainty independently from other variables and assumes a probability distribution around the
expected demand forecast. Results are based on an 80 percent confidence interval, meaning
there is an 80% probability of the demand falling within the bounds created by the high and low
forecasts.

Generation

The MRO existing internal certain resources for the 2008 summer are 54,752 MW. The MRO
existing internal uncertain resources for the 2008 summer are 3,423 MW. Planned resources that
will be in service this summer are 1,428 MW. These values do not include firm or non-firm
purchases and sales.

New generation added before this summer includes generating facilities in Iowa and the
Northern MRO area. In Iowa, within the last year,

   •      The net generation output of the Louisa plant was increased from 730 MW to 755 MW;
   •      A 75 MW wind farm was added to the Charles City South 69 kV substation;
   •      The Wall Lake wind farm was expanded by 15 MW to bring the total generation to 200
          MW; and
   •      A 200 MW wind farm was added at the new Pocahontas County substation.

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A few wind farms have been installed in North Dakota this past year including 180 MW farm
near Ellendale, ND and a 159 MW farm near Langdon, ND. A second natural gas peaking unit,
rated at 120 MW, near Groton, South Dakota is scheduled to be online in June 2008 to help serve
load in northeastern South Dakota.

Significant generation additions at High Bridge (after decommissioning generation previously
installed, new net output will be 630 MW) in the Twin Cities and Colville (350 MW) near
Cannon Falls, MN are expected to be online before summer.

Among the resources expected to be in-service for the 2008 summer, there is 3,997 MW
nameplate capacity of wind generation. MISO allows a capacity credit of 20% for wind
generation. Assuming this 20% capacity value, 799 MW of wind capacity is expected to be
available to serve load at peak times. There is, however, 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. The biomass portion of resources
for the MRO region expected to be available at peak times is 346 MW.

The MRO region is not experiencing a drought that would limit thermal unit cooling.

While reservoir water levels continue to remain low in Montana, North Dakota, and South
Dakota, and will likely continue to reduce the magnitude and duration of power transfers out of
Northern MRO, they are sufficient to meet projected peak demand and energy requirements for
the 2008 summer season. The Manitoba water condition is normal and, therefore, normal
Manitoba-US power exports are likely.

Purchases and Sales

For the 2008 summer season, MRO is projecting total firm purchases of 1,192 MW. These
purchases are from sources external to the MRO region. MRO has approximately 835 MW of
total projected firm sales to load outside of the MRO region. The net transfers in and out of the
MRO region can vary at peak load, depending on system conditions and economic conditions.

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

MRO members do not count on any emergency imports or reserve sharing from outside of the
region to meet their target reserve margins.

Fuel

MRO considers known and anticipated fuel supply or delivery issues in its assessment and does
not foresee any significant fuel supply and fuel delivery issues for the upcoming 2008 summer
season. Because MRO has a large diversity in fuel supply, inventory management, and delivery
methods throughout the region, it does not have a specific mitigation procedure in place should
fuel delivery problems occur. If problems occur, they will be handled on a case-by-case basis.

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Transmission

Iowa

A 200 MW wind farm was added at the new Pocahontas County substation located on the Sac
County – Pomeroy 161 kV line. Network upgrades for the Pocahontas County wind farm were
completed in 2007 and included reconductoring the Clipper - Little Sioux 161 kV line and the
Pomeroy – Hayes 161 kV line.

In response to increasing load in the Fort Dodge area, MidAmerican Energy Company
constructed the new Tate & Lyle 161 kV substation and added a 125 MVA 161/69 kV auto-
transformer to improve load serving capacity and reliability. The new Tate & Lyle 161 kV
substation replaced the existing three-terminal Pomeroy – Webster – Sub T 161 kV line with
three independent 161 kV lines from Hayes – Pomeroy , Hayes – Webster, and Hayes – Tate &
Lyle - Sub T.

Nebraska

Phase I of Nebraska Public Power District’s Electric Transmission Reliability (ETR) Project for
east-central Nebraska is scheduled to be complete prior to the summer of 2008. Phase I of the
ETR Project entails conversion to 345 kV of an existing 230 kV transmission line from just north
of Norfolk to a point just north of Columbus, expansion of the Hoskins Substation near Norfolk,
and construction of the new Shell Creek substation north of Columbus. This phase of the project
is expected to improve local area voltage support during the summer months.

As a part of the Nebraska City Unit 2 power plant project, a 345 kV transmission line is being
built from the site of the Nebraska City 2 plant approximately 50 miles to a new substation
southeast of Lincoln. The new line is scheduled to be completed by mid-summer 2008 and is
expected to reduce the need for temporary operating guides during critical prior outages in and
around Lincoln.

Northern MRO

The Hensel - Langdon 115 kV line was added in 2007 in association with the 159 MW wind
farm near Langdon, ND.

The Arrowhead - Stone Lake - Gardner Park 345 kV line was energized January 23, 2008. The
line has been included in the new Minnesota-Wisconsin interface defined as MWEX. Studies
have shown the export limit for this interface to be 1,525 MW and that this line relieves
congestion on the Eau Claire-Arpin 345 kV line and the Alma - Elk Mound 161 kV line. The
new interface replaces the Minnesota-Wisconsin Stability Interface as the primary constraint for
bulk transfers between Minnesota and Wisconsin.

Significant transmission for wind generation has been completed in the Buffalo Ridge area in
southwestern Minnesota. The following transmission system upgrades are now in place:

   •      Nobles County - Lakefield Junction 345 kV

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       •    Chanarambie - Fenton-Nobles County 115 kV
       •    Buffalo Ridge - Yankee-Brookings County 115 kV
       •    Brookings County - White 345 kV
       •    Fieldon Series Compensation for Blue Lake - Wilmarth - LGS 345kV line

The final upgrade for this area, the Split Rock - Nobles 345 kV line, is expected to be energized
before the summer, which will then complete all the transmission improvements needed for the
825 MW of firm wind generation capacity in the Buffalo Ridge area.

Other facility additions needed to accommodate growing load for this coming summer include
minor projects such as capacitor additions and up-rating facilities.

Wisconsin-Upper Michigan Systems

The WUMS electric transmission system encompasses the service territories of five Balancing
Authorities: Alliant Energy-Wisconsin Power & Light, We Energies, Wisconsin Public Service
Corporation, Madison Gas & Electric Company, and Upper Peninsula Power Company. The
WUMS system consists of 345, 230, 161, 138, 115, and 69 kV transmission facilities and is
owned by American Transmission Company, LLC (ATCLLC). The operation of WUMS is
coordinated between ATCLLC and Midwest ISO.

Reliable operation of the WUMS transmission system is expected during the summer 2008
season.44

Major transmission projects with expected in-service dates between July 2007 and June 2008 are
listed below. These additions and upgrades strengthen the reliability of the WUMS system for
the summer 2008 season and subsequent years.

       •    Construct an Arrowhead – Stone Lake 345 kV line. In service in January 2008.
       •    Install an Arrowhead 345 kV substation including a 345/230 kV transformer and two 75
            MVAr capacitor banks. Available for service in January 2008.
       •    Install a 230 kV phase shifting transformer in series with the Arrowhead 345/230 kV
            transformer and the Arrowhead – Stone Lake 345 kV line at the Arrowhead 230 kV
            substation. In service in January 2008.
       •    Complete the Stone Lake 345 kV substation including installation of a 75 MVAr
            capacitor bank and a 75 MVAr shunt inductor. Available for service in January 2008.
       •    Install a Cypress 345 kV substation tapping into the Forest Junction – Arcadian 345 kV
            line. In service in December 2007.
       •    Increase ratings of N. Appleton – Fox River 345 kV line. In-service in April 2008.
       •    Construct an Eagle River – Conover 115 kV line. Expected to be in-service in June 2008.
       •    Construct an Ellinwood – Sunset Point 138 kV line. In service in November 2007.


44
     2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. Midwest ISO Summer
     2008 Assessment Studies (on-going), http://extranet.midwestiso.org/operations/seasonal.php. ReliabilityFirst Corporation
     (RFC) Summer 2008 Transmission Assessment Studies (on-going), http://www.maininc.org/. Eastern Interconnection
     Reliability Assessment Group (ERAG) Summer 2008 Inter-regional Transmission Assessment, MRO-RFC-SERC West-SPP
     (MRSWS) sub-group study (on-going), http://www.midwestreliability.org/.

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       •   Construct Rubicon – Hustisford - Hubbard 138 kV lines. Expected to be in-service in
           May 2008.
       •   A number of other major projects.

There is no anticipated delay of the expected in-service dates for those facilities planned for May
and June 2008.

Operational Issues

There are no known environmental or regulatory restrictions that could impact reliability during
the summer 2008 season.

Iowa

During the summer of 2008, East to West power transfers across Iowa are expected to be at more
moderate levels in comparison with the period from 2000-2006, due to operation of the Walter
Scott Energy Center Unit-4. This flow pattern is not expected to cause any significant
operational issues. Additionally, two 161 kV line flowgates in Central Iowa that used to be the
most affected facilities by the East to West flow pattern have been re-conductored.45

The addition of wind generation at Pocahontas and Charles City, as well as in southern
Minnesota will contribute better voltage control and less congestion associated with power
transfers. Single-event and double-event contingencies were simulated to evaluate steady-state
impacts of the Pocahontas and Charles City projects on system loading and bus voltages. None
of the simulated contingencies caused violation of emergency ratings. Operating studies
indicated that 161 kV facilities in the area are well designed to withstand any credible
contingency. However, prior outage conditions may cause limiting of the total wind farm output
of Clipper, Pocahontas and Buena Vista wind farms in order to protect underlying 69 kV
facilities. Operating guides will be implemented to protect the affected facilities. During
congestion, total output of the Charles City wind farm (75 MW) and combustion turbines (35
MW) will be limited to reduce loading on the Adams-Rochester 161 kV flowgate.

Summer operation of the Emery combined cycle gas generation near Mason City, Iowa and the
MidAmerican Energy Greater Des Moines Energy Center will have positive impacts on
reliability of the transmission system in the Waterloo area and in central Iowa, respectively. The
central Iowa system will be operated, most of the summer, without the 345/161 kV transformer
at the SE Polk substation that experienced an unrecoverable failure. The new transformer is
expected to be in service in late August. The Sycamore combustion turbines can be run if
necessary for transmission relief. A temporary operational guide is pending by MidAmerican
and will be in place for the 2008 summer season.

The Oak Grove-Galesburg Standing Operating Guide has been developed by MISO-Central to
document the operating procedures necessary to deal with heavy real-time loading on both
Galesburg 161/138 kV transformers and potential operating issues associated with a potential
loss of either the TSS940-Nelson 345 kV line or the Quad Cities-N.W.S&Q 345 kV line with
subsequent post-contingency overloading of the 161 kV line Oak Grove-Galesburg. The
45
     MEC-1. “2007 N-2 Contingency Analysis Studies”, MidAmerican Energy, System Planning Department, February 2008.

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Galesburg 161/138 kV transformers and the Oak Grove-Galesburg 161 kV line should be
adequately protected by this operating guide.

Standing operating guides for all Iowa flowgates have been reviewed and made available to the
transmission operators. In addition to the standing operating guides, temporary operating guides
will be issued in case of any unexpected change in system configuration due to forced outages or
for scheduled outages in which high transfer levels create operating conditions with a likelihood
of violating system operating limits. The Seams Operating Agreement between Midwest ISO and
MAPP will continue to be used for facilitating coordination of congestion management
procedures on Iowa flowgates.

Nebraska

Nebraska Public Power District (NPPD) and Omaha Public Power District (OPPD) currently
post six constrained paths on the MAPP OASIS which are located within or adjacent to the
NPPD and OPPD control areas. All of these interfaces have approved operating guides that have
historically proven effective in dealing with system conditions throughout the year.

During the summer peak and off-peak loading periods, two export interfaces are monitored
closely including the Cooper South Interface (COOPER_S) and the Western Nebraska to
Western Kansas Interface (WNE_WKS). Upgrades to the COOPER_S Interface are expected to
be completed prior to the 2008 summer season which should result in less frequent TLR events.
During peak loading periods with heavy exports to the south, NERC TLR is expected to be
implemented to limit the flows on the GGS-Red Willow 345 kV line to address system operating
limits associated with the WNE_WKS Interface.

With increased loads in the western Nebraska area during the summer months, stability
limitations associated with the Gerald Gentleman Station (GGS) Stability Interface are less
severe. High power transfers out of the western Nebraska area are typically less in the summer
months than in winter months.

In the past several years, there has been a large increase in the number of days the DC ties are
transferring power from east-to-west which reduces the west-to-east flows that are normally seen
across Nebraska. It is anticipated that this pattern of the DC ties flowing in the east-to-west
direction will continue this summer.




Northern MRO

No significant operational issues are expected this summer for the Northern MRO area. The
existing approved operating guides that are in use today have maintained a reliable transmission
system throughout the year.




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A number of bulk transmission outages are scheduled for maintenance in the US portion of the
Northern MRO area; however no operating problems are expected. Temporary operating guides
will be developed as necessary.

Wisconsin-Upper Michigan Systems

The completion of the Arrowhead – Stone Lake – Gardner Park 345 kV line provides needed
transmission reinforcement on the WUMS western interface with Minnesota and improves the
WUMS transmission reliability and transfer capability. Studies have demonstrated that with high
imports into WUMS from Minnesota, there is potential transient voltage recovery limit and
voltage instability limit and therefore determined the need for a new interface flowgate
comprised of Arrowhead-Stone Lake 345 kV line and King-Eau Claire 345 kV line, called the
Minnesota Wisconsin Export (MWEX) Interface. This interface is managed as a reciprocal
Interconnection Reliability Operating Limit (IROL) Flowgate of Midwest ISO and MAPP. The
existing Minnesota Wisconsin Stability Interface (MWSI) will be retained for prior outage
conditions and to gain operational experience with MWEX. The existing operating guides for
King – Eau Claire – Arpin 345 kV line and Arpin – Rocky Run 345 kV line will be accordingly
revised for summer 2008.

With high imports into WUMS through southwest Wisconsin, the Paddock 345/138 kV
transformer could be overloaded for loss of the Wempletown – Rockdale 345 kV tie-line. Also,
with high imports or exports through southeast Wisconsin, the Lakeview – Zion 138 kV line
could be overloaded for loss of either of the two 345 kV tie-lines, Pleasant Prairie – Zion or
Arcadian – Zion. Together, these southeast and southwest tie-lines comprise the ATC South Ties
Interface, which is thermally limited for critical N-1 contingencies and voltage stability limited
for critical N-2 contingencies during periods of heavy transfers across the interface. Operating
guides are used to monitor and manage the constraints during high imports into WUMS across
this southern interface. The ATCLLC has filed an application with the Public Service
Commission of Wisconsin to add a new 345 kV transmission line between the Rockdale and
Paddock 345 kV substations that will help to alleviate the southern interface constraints.

The eastern portion of the Upper Peninsula of Michigan (UP) is susceptible to changes from
generating to pumping mode at Ludington pumped storage station (in lower Michigan). As a
result, the eastern UP can experience flows in both directions — from east to west and west to
east. Heavy flows in either direction across the McGulpin – Straits 138 kV tie-line can cause
potential thermal violations in the eastern UP. Additionally, an east to west system bias can
result in low voltages or voltage instability in the eastern UP. Additions of the second 138/69 kV
transformers at Hiawatha (in-service January 2008) and at Straits (in-service December 2007)
have helped reduce the constraint level. This constraint continues to be managed by opening the
69 kV lines between the eastern UP and the rest of the WUMS system, as per the operating
guide. ATC has initiated an Eastern UP Strategic Assessment Team to review this situation.
ATC is working with the Michigan Transmission Owners and the Midwest ISO to evaluate this
operating challenge.

The pressure of power import into UP from northeast Wisconsin continues. The 138 kV corridor
consisting of the three 138 kV lines south of the Morgan and Stiles substations continues to be a
potential constraint that could lead to thermal and voltage violations under contingencies during

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periods of high flows towards UP. This constraint is monitored and managed by following an
operating guide. Completion of the Werner West – Highway 22 – Morgan and Gardner Park –
Highway 22 345 kV lines in late 2009 will help to alleviate this constraint.

Operating studies have been or will be performed for all scheduled transmission or generation
outages during the 2008 summer season. When necessary, temporary operating guides will be
developed for managing the scheduled outages to ensure transmission reliability.

Reliability Assessment Analysis

In December 2007, the MRO Board of Directors approved a regional standard, RES-501-MRO-
01, requiring all LSEs or their designated entity to annually perform a Resource Adequacy study.
This will be required by December 2008, one year after board approval.

Reserve margins are typically used as criteria for a target level, as opposed to capacity margins.
MRO’s projected 2008 summer Reserve Margin is 17.5% without uncertain resources.

For the MAPP GRSP members, resource adequacy is measured through the accreditation rules
and procedures. The MAPP GRSP requires a 15% reserve capacity obligation (RCO) for
predominantly thermal systems, and 10% reserve margins for predominantly hydro systems.46
The RCO is established by the MAPP Restated Agreement and its governing authorities, i.e.
MAPP Executive Committee and MAPP Pool Committee. This level of reserve requirements is
subject to periodic review based on reserve requirements studies conducted regularly by
MAPP.47 The RCO requires the MAPP GRSP members to maintain their respective minimum
reserve based on after-the-fact peak demand; i.e., the members are responsible for maintaining
adequate generation to account for load forecast uncertainty. When a new peak occurs, the
member will be required to maintain the minimum reserve based on that peak for the next 11
months, or until a new, higher peak takes place. Approximately 8,850 MW of generation in the
MAPP GRSP (15.7% of MRO net internal capacity) is associated with predominantly hydro
systems and only requires a 10% RCO. The projected MRO reserve margin of 17.5% for the
2008 summer season is in excess of the MAPP Reserve Capacity Obligation.

For the former MAIN members, generation resource adequacy is assessed based on LOLE
studies previously conducted by the MAIN region.48 Although conducted on a yearly basis,
MAIN’s LOLE studies consistently recommended a minimum short-term planning reserve
margin of 14%. The projected MRO reserve margin of 17.5% for the 2008 summer season is in
excess of the target Reserve Margin.




46
    The MAPP GRSP Handbook, http://www.mappcor.org/assets/pdf/GRSP_Handbook_20070116.pdf.
47
    The last MAPP reserve requirements study was conducted in 2003 by the MAPP Composite System Reliability Working
    Group. This study has not been posted on the MAPP website, but it is available upon request from Brian Glover, MAPPCOR
    (651-855-1715 or bp.glover@mappcor.org).
48
   In the former MAIN region, MAIN Guide 6 adopted a resource adequacy criterion of 0.1 days/year,
    http://www.maininc.org/bg/guide6.pdf. Studies concerning LOLE calculations for the former MAIN Region are available.
    The 2005 study is located at http://www.maininc.org/files/MG6GenerationReliabilityStudy2005_14.pdf. Other studies are
    found by navigating through http://www.maininc.org/files/files.htm.

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Saskatchewan's reliability criterion is based on annual expected unserved energy (EUE) analysis
and equates to an approximate 15% reserve margin requirement.49 The projected MRO reserve
margin of 17.5% for the 2008 winter season is in excess of the target Reserve Margin.

This summer’s projected capacity margin of 14.9%, which includes certain resources only and
net interchange, can be compared with last summer’s projected capacity margin of 17.2%
(considering committed resource and net interchange).

With uncertain resources included, the 2008 projected capacity margin is 19.7%, as compared to
17.4% in 2007 with uncommitted resources included.

There are several reasons for this difference. There are likely some differences in the way
members submitted their generation data due to the significant changes in generation definitions
implemented by NERC in 2008. Additionally, the difference between the nameplate value of
variable generation (wind in particular) and that portion considered as capacity was submitted as
Existing-Uncertain resources. Also, purchases and sales in 2007 included purchases from IPPs
within the MRO footprint, since that is how data was previously collected. For 2008, MRO staff
attempted to include all IPP MWs as an internal resource, not as a purchase. Most large IPPs
that are registered as Generator Owners within the MRO region were properly captured.
However, there are smaller IPPs within the MRO region 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; consequently, these firm generation resources are fully
deliverable to the load. There are no known deliverability concerns with the various methods
used within the MRO region for firm deliverability.

Generation deliverability is performed by Transmission Providers within the MRO region. Links
to deliverability criteria within the MRO region are:

          http://www.midwestiso.org/page/Generator+Interconnection
          http://www.mappcor.org/content/policies.shtml
          https://www.oatioasis.com/spc/

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.

Based on the MRO/RFC/SPP/SERC-W 2008 Summer Inter-regional Assessment, the non-
simultaneous Total Import Capabilities into MRO from RFC-W, SERC-W, and SPP Regions
are:50

49
   Studies concerning EUE and Loss of Load calculations on the Saskatchewan Power system are presently considered internal
   documents and are not publicly posted. Information regarding these studies may be obtained by contacting Wayne Guttormson,
   Saskatchewan Power (306-566-2166 or wguttormson@saskpower.com).
50
   Eastern Interconnection Reliability Assessment Group (ERAG) Summer 2008 Inter-regional Transmission Assessment, MRO-
   RFC-SERC West-SPP (MRSWS) sub-group study (on-going), http://www.midwestreliability.org/.

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                                TIC          The Total Import Capability (TIC) is equal to the net import
Transfer Direction
                               (MW)          into MRO (1,752 MW) in the base case plus the First
                                             Contingency Incremental Transfer Capability (FCITC)
 RFC West / MRO                2400
                                             obtained in the transfer analysis. These studies recognize
     SPP / MRO                 3300
                                             constraints internal and external to the MRO.

SERC West / MRO                   Transient, voltage and small signal stability studies are
                                  0
                                  performed as part of the near-term and long-term transmission
             51
assessments. Voltage stability is also evaluated in the Midwest ISO’s seasonal assessment.52
The results of the Midwest ISO summer assessment were not available prior to the due date of
this regional assessment. No transient, voltage, or small signal stability issues are expected that
impact reliability during the summer 2008 season.

Most subregional entities evaluate dynamic reactive reserve requirements on a case-by-case basis
if issues are identified. For example, 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 for NERC Category B contingencies.53

Manitoba Hydro maintains a 150 MVAr reserve on the Dorsey Substation synchronous
condensers at all times to cover for the loss of small and large synchronous condensers and
prevent voltage collapse from occurring. In addition, no less than 20 MVAr reserve per in-
service synchronous machine is permitted when the synchronous machines are taking in MVAr.
This is required to reduce the risk of system overvoltage for loss of HVDC-connected generation
or loss of a synchronous machine during light load periods.

Iowa, Nebraska, Northern MRO, and WUMS all have transient voltage dip criteria or guidelines
with varying requirements.54 As an example, the MAPP default criteria require voltage recovery
to be within 70 percent to 120 percent of nominal following the clearing of a disturbance.

The Operational Issues section above has identified potential voltage stability limitations.
Subregional entities evaluate voltage stability limitations and margins on a case-by-case basis.55
For example, voltage stability margin is part of the ATCLLC Planning Criteria. Under NERC
Category B contingencies, the steady state system operating point of selected areas for evaluation
is required to be at least 10 percent away from the nose of the P-V curve.

51
   2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. 2008 MAPP System
   Performance Assessment. MAPP Small Signal Stability Analysis Project Report, June 2007. Midwest ISO 2007 Expansion
   Planning, http://www.midwestiso.org/page/Expansion%20Planning.
52
    Midwest ISO Summer 2008 Assessment Studies (on-going), http://extranet.midwestiso.org/operations/seasonal.php.
53
    ATCLLC collects the generator maximum reactive capability information from the generator owners within ATCLLC
   footprint. For reactive reserve analysis, power flow cases would be created with a 5% or 10% simultaneous reduction in
   maximum reactive capability of all generators within ATCLLC footprint. Analysis of Category A and B contingencies would
   then be performed. Voltage violations are not acceptable in the case with a 10% reduction in generator maximum reactive
   capability under Category A contingencies. Voltage violations are not acceptable in the case with a 5% reduction in generator
   maximum reactive capability under Category B contingencies.
54
    2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. MAPP Members
   Reliability Criteria and Study Procedures Manual, November, 2004.
55
    2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. The MAPP Reliability
   Handbook, December 2004

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Several members within the MRO region have Undervoltage Load Shedding programs to prevent
localized low voltage conditions. These programs are not required to protect the bulk electric
system.

Assessment Process

The MRO Reliability Assessment Committee is responsible for this summer reliability
assessment.  The MRO Transmission Assessment Subcommittee, the MRO Resource
Assessment Subcommittee, the MAPP Transmission Operations Subcommittee, the ATCLLC,
and Saskatchewan Power Corporation all contribute to this MRO Summer Reliability
Assessment.

Region Description

The Midwest Reliability Organization (MRO) has 48 members which include Cooperative,
Canadian Utility, Federal Power Marketing Agency, Generator and/or Power Marketer, Small
Investor Owned Utility, Large Investor Owned Utility, Municipal Utility, Regulatory Participant
and Transmission System Operator. The MRO has 19 Balancing Authorities and 115 registered
entities. 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.




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NPCC
     2008 Projected Peak Demand                         MW
                                                                                             Relative Capacity by Fuel Mix
       Total Internal Demand                            111,226
         Direct Control Load Management                     378
                                                                                             Coal 10%
         Contractually Interruptible (Curtailable)        1,999                                                       Dual Fuel
         Critical Peak-Pricing with Control                   0                                                         18%

         Load as a Capacity Resource                      1,975
       Net Internal Demand                              106,874

                                                        MW      Change           Hydro 31%                                        Gas 13%
     2007 Actual Summer Peak Demand                     108,794   -1.8%
     All-Time Summer Peak Demand                        114,216   -6.4%

     2008 Projected Capacity                            MW      Margin                                                       Oil 8%
                                                                                                                                 Other 1.1%
       Existing Certain and Net Firm Transactions       133,225   19.8%
                                                                                                                               Wind 0.2%
       Net Capacity Resources                           136,331   21.6%
                                                                                                   Nuclear 16%                 Pumped
       Total Potential Resources                        150,849   29.2%                                                       Storage 3%


The non-coincident aggregate 2008 summer total projected
internal demand56 is 111,55757 MW (Canadian demand is
49,778 MW; U.S. demand is 61,779 MW). This forecast peak
demand is little changed (-0.2%) from last summer’s 111,83058
MW forecast aggregate demand. The forecast is based on
average weather conditions and is 2.4% higher than last
summer’s non-coincident aggregate actual 108,958 MW peak
demand.

All NPCC sub-regions (ISO New England (ISO-NE), the New
York Independent System Operator (NYISO), Hydro-Québec TransÉnergie, the Ontario
Independent Electricity System Operator (IESO) and the Maritimes) expect sufficient resources
to be available to meet projected demands during 2008 summer and have monthly projected net
capacity margins ranging from 15.6% to 53.0%. Québec and the Maritimes are predominately
winter peaking Areas, and therefore adequate resources, including the supply for firm external
sales, are expected to be available. Adequate transfer capability exists to transmit surplus
resources from these sub-regions to the others; however, a certain amount of bottling of
resources from Québec and the Maritimes to the rest of NPCC is normal and expected. In
general, in the NPCC region load projections show little increase, and very little new generating
capacity is coming on line for the summer 2008 period.

Wind capacity in NPCC and associated peak derates are highlighted in the table below.




56
   These figures differ from NPCC's May 1, 2008 Summer Assessment (http://www.npcc.org/documents/reports/Seasonal.aspx)
   as NPCC includes the month of May as part of the summer period in their non-coincident demand.
57
   This demand figure is the sum of sub-regional summer season forecast peaks, regardless of month. NERC’s Total Internal
   Demand is the greatest sum of sub-regional monthly forecast peaks. Therefore these figures may differ.
58
   This demand figure is the sum of sub-regional summer season actual peaks, regardless of month. NERC’s Total Internal
   Demand is the greatest sum of sub-regional monthly actual peaks. Therefore these figures may differ.

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Very little new generating capacity is                       Nameplate        Capacity after
                                             Sub-Region
expected to go into service for the 2008                     Capacity         Applied De-rating
summer period. Capacity additions in the     Maritimes       159.7 MW         43.7 MW
NPCC Areas include:        Maritimes (0
                                             New England     11.1 MW          4.3 MW
MW), New England (210 MW), New
York (65 MW), Ontario (371 MW),              New York        424 MW           42.4 MW
Quebec (489 MW).                             Ontario         471 MW           47 MW
                                             Québec          420 MW           0 MW
With regard to transmission, a new 345
kV transmission line between Point Lepreau, New Brunswick and Orrington, Maine went into
service during December of 2007. It has increased the New Brunswick - MEPCO Total Transfer
Capability (TTC) from 700 to 1000 MW and the MEPCO – NB TTC from 300 to 550 MW.

Just prior to the summer peak season, New England and New York expect to energize a
replacement set of 138 kV submarine cables in the 1385 (Norwalk Harbor-Northport 138 kV)
circuit connecting southwestern Connecticut to Long Island, NY. The original cables had
become highly unreliable due to a number of incidents where they had been damaged by marine
anchors.

Phase angle regulators (PARs) are installed on three of the four Michigan to Ontario
interconnections. One PAR, on the Keith to Waterman 230 kV circuit J5D has been in service
and regulating since 1975. The other two available PARs, on circuits L51D and L4D, which had
been bypassed pending completion of agreements between the IESO, the Midwest ISO, Hydro
One and the International Transmission Company, were placed in service on April 14, 2008, and
they are expected to start regulating before the summer. All parties have committed to
completing the necessary operating agreements to meet this schedule. The operation of the
phase angle regulators will assist in the management of system congestion and control of
circulating flows. The fourth PAR, responsible for controlling the tie flow on the 230 kV circuit
B3N, remains unavailable and is undergoing replacement. This PAR is located in Michigan at
the Bunce Creek terminal of circuit B3N.

Upgrades in the Rochester vicinity are continuing in preparation of the Russell Station retirement
this summer. A capacitor bank is scheduled to be added to Millwood 345 by June 1, 2008.

Detailed summaries of the expectations of each of the NPCC sub-regions follow:

Maritime Area

Demand
The actual peak for summer 2007 was 3,496 MW on July 27, 2007, which was approximately
242 MW (6.9 %) lower than last year’s forecast of 3,738 MW. Based on the Maritime Area
2008 demand forecast, a peak of 3,542 MW is predicted to occur for the summer period, June
through September. The 2008 demand forecast is lower by 196 MW (5.2 %) when compared to
the 2007 demand forecast. This reduction in demand is expected to be due to a combination of



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higher than normal temperatures forecast for 2008 summer and resulting in a lower electric
heating load in September 2008, and loss of industrial load due to plant closures.

The weekly Maritime Area load is the mathematical sum of the forecasted weekly peak loads of
each 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. If the total Maritime Area load included a coincidence factor, the
forecast load would be approximately 1-3% lower.

For the 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 30-year historical normal climate for the major load center,
along with analyses of sales history, economic indicators, customer surveys, technological and
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 using the previous year’s data. 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 used to reduce the forecast in the resource adequacy assessment for the
Maritime Area. In the Maritime Area there is between 445 and 487 MW of interruptible demand
available during the assessment period; there is 487 MW forecasted to be available at the time of
the Maritime Area seasonal peak.

Generation
The Maritimes Area resources will vary between 6,425 MW and 6,428 MW of existing capacity
plus 2.4 MW of planned wind generation scheduled to come on line during the summer period.
The uncertain portion of the existing capacity ranges from 367 MW to 457 MW. Of the existing
capacity there is 159.7 MW of wind expected on peak and 154.1 MW of biomass.

The Maritimes Area is forecasting normal hydro conditions for the summer 2008 assessment
period, and it is not presently, nor does it anticipate, a drought.

Purchases and Sales on Peak
There are no purchases from other regions or sub-regions that would affect the capacity margins
in the Maritimes Area. However, there is a firm sale of 205 MW to Hydro Quebec which is tied
to specific generators. The firm transmission to provide the sale at the Quebec-New Brunswick
border is also tied to this transaction.

The Maritime Area does have agreements in place for the purchase of emergency energy with
other sub-regions of NPCC as well as a reserve sharing agreement within NPCC. But the
Maritime Area does not rely on this assistance when doing the summer assessment.




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Fuel
The Maritime Area does not consider potential fuel-supply interruptions in the regional
assessment because the fuel supply in the Maritimes Area is very diverse and includes nuclear,
natural gas, coal, oil (both light and residual), Orimulsion, hydro, tidal, municipal waste, and
wood.

Transmission
A new 345 KV transmission line between Point Lepreau, New Brunswick and Orrington, Maine
went into service in December 2007. It has increased the NB to MEPCO Total Transfer
Capability from 700 to 1000 MW and the MEPCO to NB Total Transfer Capability from 300 to
550 MW.

Operational Issues
There are no major generating unit or transmission facility outages anticipated for the summer
that will impact reliability in the Maritime Area. Furthermore, there are no environmental or
regulatory restrictions that could impact reliability in the Maritime Area.

The Point Lepreau generation station will be out of service for 18 months and this will include
the entire summer assessment period. New Brunswick System Operator does not expect any
unusual operating conditions for the summer that will impact reliability in the Maritime Area.

Reliability Assessment Analysis
When allowances for unplanned outages (based on a discreet MW value representing an
historical assessment of the total forced outages typically experienced at the time of peak for the
given operating season) are considered, the Maritime Area is projecting more than adequate
surplus capacity margins above its operating reserve requirements for the summer 2008
assessment period. These surplus margins range from 35 to 53 % over the period from June
2008 through September 2008, meeting the NPCC once-in-10-year requirement for preventing
the disconnection of firm load due to a capacity deficiency. The Maritimes Area is a winter
peaking system and resource adequacy is generally not a concern during the summer operating
period. No external resources were used by the Maritimes Area to meet capacity margins during
2007 summer and none are used for the 2008 summer period.

To ensure seasonal resource adequacy, the Maritime Area conducts an 18-month load and
resource balance assessment in accordance with NPCC Document C-13, “Operational Planning
Coordination” (http://www.npcc.org/documents/regStandards/Procedure.aspx).

The projected capacity margin for summer 2008 period is 35 to 53 percent as compared to the
projected capacity margin for the summer 2007 of 29 to 52 percent. In the Maritime Area
deliverability of generation to load is not a concern, operationally, as there are no transmission
constraints or zonal issues within the area. The Maritime Area does not consider potential fuel-
supply interruptions in the regional assessment because the fuel supply in the Maritimes Area is
very diverse and it includes nuclear, natural gas, coal, oil (both light and residual), Orimulsion,
hydro, tidal, municipal waste, and wood.

As indicated in the Transmission section above, a new 345 KV transmission line between Point
Lepreau, New Brunswick and Orrington, Maine went into service in December 2007. It has


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increased the NB to MEPCO Total Transfer Capability from 700 to 1000 MW and the MEPCO
to NB Total Transfer Capability from 300 to 550 MW.

Because of the characteristics of the power system, the Maritimes Area does not have any
transmission constraints that could impact reliability. Furthermore, this assessment did not use
steady state or dynamic simulation analysis. The Maritimes Area does not use specific criteria
for minimum dynamic reactive requirements or margins or voltage dip as reactive resources are
based on local needs. The Maritimes Area system does not have stability or voltage-limited
interfaces and has no need to apply voltage stability margins. Currently, no Under Voltage Load
Shedding systems are installed in the Maritimes. In summary, no significant reliability concerns
are expected for summer 2008.

The Maritime Area participates in the NPCC Summer and Winter Reliability Assessment
operations planning studies.

The Maritimes Area is a winter peaking system. This area covers approximately 57,800 square
miles serving a population of around 1,910,000. It includes New Brunswick, Nova Scotia, Prince
Edward Island, and the area served by the Northern Maine Independent System Operator (parts
of northern and eastern Maine).

New England

Demand
The ISO New England’s Balancing Authority area actual 2007 summer peak load, which
occurred on August 3, 2007, was 26,145 MW. The reference peak load forecast for the summer
of 2007 was 27,360 MW. The 2008 summer peak load forecast is 27,970 MW which is 610 MW
(2.2%) higher than the 2007 forecast. The key factors leading to this change in the forecast are
underlying population and economic growth.

The reference case forecast is the 50/50 forecast (50% chance of being exceeded), corresponding
to a New England 3-day weighted temperature-humidity index (WTHI) of 80.1 which is
equivalent to a dry bulb temperature of 90 degrees Fahrenheit and a dew point temperature of 70
degrees Fahrenheit. The 80.1 WTHI is the 95th percentile of a weekly weather distribution and is
consistent with the average of the WTHI value at the time of the summer peak over the last 30
years. The reference demand forecast is based on the reference economic forecast, which reflects
the economic conditions that “most likely” would occur.

ISO New England develops an independent load forecast for the Balancing Authority area as a
whole, and does not use individual members’ forecasts of peak load in its load forecast.

A total of 1,352 MW of demand resources that could be interrupted during times of capacity
shortages is assumed available for the summer of 2008. These resources, which are in ISO New
England’s Real-Time 30-minute, Real-Time 2-Hour, and Profiled Demand Response programs,
are instructed to interrupt their consumption during specific actions of Operating Procedure No.
4 (OP 4) Action during a Capacity Deficiency59. Some of the assets in the Real-Time Demand
Response programs are under direct load control. The direct load control involves the
59
     http://www.iso-ne.com/rules_proceds/operating/isone/op4/index.html

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interruption of central air conditioning systems in residential, commercial and industrial
facilities. These direct load control resources are not reported separately from the other assets in
the Real-Time Demand Response program.

In addition to demand response resources, ISO New England considers energy efficiency to be a
capacity-side resource. New energy efficiency programs are projected to amount to 331 MW in
summer 2008.

Not included in this assessment, is voluntary load that will interrupt based on the price of energy.
As of February 29, 2008, there were approximately 97 MW enrolled in the price response
program. The actual value of the load that responded is captured in collected demand response
data; at the time of the peak in 2007, this figure was about 50 MW.

ISO New England addresses peak demand uncertainty in two ways:

   •      Weather — peak load distribution forecasts are made based on 37 years of historical
          weather which includes the reference forecast (50% chance of being exceeded), and
          extreme forecast (10%chance of being exceeded);
   •      Economics — alternative forecasts are made using high and low economic scenarios.

ISO New England reviews the 2008 summer conditions using the extreme, 90/10 peak demand
based on the reference economic forecast. For summer 2008, that value is 29,895 MW.

Generation
The ISO New England Balancing Authority area Existing-Certain generating capacity amounts
to approximately 30,900 MW based on summer ratings. None of the existing capacity is in the
Existing-Uncertain category.

Approximately 4 MW of the Existing-Certain capacity is wind generation, all of which is
expected to be available on peak. The total nameplate capability of those wind facilities is 11
MW. An additional 24 MW (nameplate) of wind capacity is projected to begin commercial
operation in September. The expected on-peak capacity of that facility has not yet been
determined. A total of 210 MW of Planned capacity resources, not including the aforementioned
wind plant, are expected to become commercial by the end of the summer.

Also included in the Existing-Certain capacity is 765 MW of variable hydro resources. The full
765 MW is expected to be available on peak. A hydro uprate planned for completion by the
beginning of the summer is expected to be able to produce an additional 16 MW on peak.

Biomass capacity totals 888 MW, all of which is considered to be in the Existing Certain
category. A Planned biomass facility with a capacity rating of 17 MW is expected to be in
commercial operation by the summer, and another 5 MW project has a September projected
commercial date.

Hydro generation contributes to approximately 5% of the total New England generation, and
hydro conditions are anticipated to be sufficient to meet the expected capability of these plants


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this summer. The New England area is not experiencing a drought, and reservoir levels are
expected to be normal for the upcoming summer.

Purchases and Sales on Peak
The forecast of summer firm external capacity purchases is 401 MW. This includes 310 MW
from Hydro-Québec and 91 MW from New York. Only firm, Installed Capacity (ICAP)
purchases that are known in advance are included as capacity.

While the entire 401 MW of ICAP purchases 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 it wishes to use for the delivery of
energy associated with ICAP, but the market participant bears the associated risk of ICAP
market penalties if it chooses to use non-firm transmission. The 310 MW purchase from Hydro-
Québec is a Liquidated Damage Contract (LDC) that is not a “make-whole” contract. The 91
MW purchase from New York is not an LDC.

For the summer period, ISO-New England expects a firm sale to New York (Long Island) of 343
MW via the Cross Sound Cable. Although this sale is backed by a firm contract for generation,
if past practice is indicative of future actions, the energy and capacity will be considered to be
recallable by New England. This means that it can be cut earlier than non-recallable exports in
the case of a transmission import constraint into Connecticut. The sale across the Cross Sound
Cable is based on a make-whole contract.

Based on experience, ISO New England assumes that it has 2,000 MW of emergency assistance,
also referred to as tie-line benefits, available from other areas within the NPCC region. This is
about 50% of New England’s total import capability. ISO New England 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.

Fuel
ISO New England (ISO-NE) routinely gages the impacts that fuel supply disruptions will have
upon system or sub-region reliability. Because natural gas is the predominant fuel used to
produce electricity in New England, ISO-NE continuously monitors the regional natural gas
pipeline system to ensure that emerging gas supply or delivery issues can be incorporated into
the daily operating plans.

Transmission
During the upcoming Summer Operating Period, data provided by the New England
Transmission Owners indicates that few new facilities are expected to be placed in service.

A new autotransformer will be added at the Barbour Hill Substation in Connecticut. This
autotransformer will provide a new supply from the 345 kV network into the existing radial 115
kV network which serves north central Connecticut. Addition of this transformer also removes
load from the existing Manchester auto transformers which provide supply to the Middletown
area and therefore eases operating constraints in this area.


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A new 345/115 kV autotransformer will be added at the existing Scobie Substation in New
Hampshire in order to provide additional supply into the southern New Hampshire 115 kV
network.

Projects that have already been placed in service include the Northeast Reliability
Interconnection (NRI), which is a new 345 kV line between Orrington, Maine and Pt. Lepreau in
New Brunswick. This area inter-tie improves the stability performance between New England
and New Brunswick and also allows for increased transfers in both directions between the areas.
The NRI became operational in December 2007. In addition, a new 115 kV line was built
between the Scobie and Hudson substations to eliminate thermal overloads in the southern
Manchester area of New Hampshire.

Just prior to the summer peak season, New England and New York expect to energize a
replacement set of 138 kV submarine cables connecting southwestern Connecticut to Long
Island, NY. These cables replace an older set of cables that had become highly unreliable due to
a number of incidents where they had been damaged through contact with marine anchors. The
new cables will be buried, reducing the likelihood of future outages caused by external forces.

Operational Issues
There are no significant anticipated unit outages, variable resource, transmission additions or
temporary operating measures that would adversely impact reliability during the summer. As
stated in the Transmission section, new transmission upgrades have been placed in service or are
expected to soon be placed in service which will improve the reliability of various portions of the
New England transmission system.

During extremely hot days and low river flow conditions, there may be environmental
restrictions on generating units due to water discharge temperatures. Over the past four years,
such conditions have occurred three times, resulting in reductions ranging from 150 MW to 200
MW. These reductions are reflected in our forced outage assumptions. The ISO monitors the
situation and expects adequate resources to cover such forced outages or generator reductions.

At this time, there are no unusual operating issues or concerns that are anticipated to impact the
reliable operation of the New England transmission system for the coming summer.

Reliability Assessment Analysis
ISO New England bases its capacity requirements on a probabilistic loss-of-load-expectation
analysis that calculates the total amount of installed capacity needed to meet the NPCC once-in-
10-year requirement for preventing the disconnection of firm load due to a capacity deficiency.
This value, known as the Installed Capacity Requirement (ICR), was calculated for the
2008/2009 capability year. The ICR is approximately 32,160 MW during July and August,
which results in reserves of 15.0%.

The model used for conducting the 2008/2009 system-wide ICR calculations for New England
accounts for all known external firm purchases and sales, which in 2008/2009 amount to a net
value of 58 MW. This value is essentially the same as the 55 MW of net purchases and sales
assumed in 2007/2008. In addition, 2,000 MW of tie-line benefits from neighboring systems
were included in the ICR modeling for both summer 2007 and summer 2008.


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ISO-New England’s latest resource adequacy studies are detailed in the report, “ISO New
England Installed Capacity Requirements for the 2008-2009 Capability Year60.”

For this summer reliability assessment, ISO-NE projects an installed capacity margin of
approximately 4,844 MW (15.6 percent) under the reference economic forecast at the 50/50 peak
load level forecast, and about 2,919 MW (9.4 percent) under the reference economic forecast at
the 90/10 peak load level during the peak load period (July and August 2008). The net margin is
based on known outages, anticipated generation additions and retirements, projected firm
purchases and sales, and the impact of expected demand response programs. The margin does
not include allowances for any unplanned outages or for operating reserve.

The summer 2007 and 2008 projected                               2007 Margin 2008 Margin
capacity margins are summarized in the                               (MW)           (MW)
table. The projected margins are Reference
sufficient to cover the New England (50/50 Forecast)                  4250          4844
operating reserve requirement, which is Extreme
approximately 1,800 MW; however, (90/10 Forecast)                     2445          2919
higher than expected unit outages and/or
higher than anticipated load could adversely affect the forecasted margin. During the 2007
summer peak load period, the projected capacity margin under the 50/50 peak load forecast was
approximately 4,250 MW, and the capacity margin under the 90/10 forecast was about 2,445
MW. The 50/50 and 90/10 margins forecasted for the 2008 summer are about 594 MW and 474
MW higher, respectively, than the 50/50 and 90/10 margins forecasted for 2007.

ISO New England currently addresses generation deliverability through a combination of
transmission reliability and resource adequacy analyses. Detailed transmission reliability
analyses of sub-areas of the New England bulk power system confirm that reliability
requirements can be met with the existing combination of transmission and generation. Multi-
area probabilistic analyses are conducted to verify that inter-sub-area constraints do not
compromise resource adequacy. The ongoing transmission planning efforts associated with the
New England Regional System Plan, support compliance with NERC Transmission Planning
requirements and assure that the transmission system is planned to sufficiently integrate
generation with load.

No deliverability concerns for summer 2008 have been identified. In previous years, studies
indicated that without additional resources or transmission improvements, Connecticut would
experience a negative Net Margin if the 90/10 forecasted demand were to occur. However,
analyses of the situation in 2008 have shown that the Net Margin in Connecticut is expected to
be positive this year. No capacity shortage is expected in Connecticut this summer. The primary
reasons for the improved situation are additional capacity as well as 130 MW of additional
demand response resources in Connecticut.

Reliability has also previously been a concern in the Boston area. However, transmission
upgrades completed in the spring 2007 increased the import capability into the Boston area by
60
     The draft report “ISO New England Installed Capacity Requirements for the 2008-2009 Capability Year” may be found on
     ISO-NE’s website at http://www.iso-ne.com/genrtion_resrcs/reports/nepool_oc_review/index.html.

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1,000 MW, to a total of 4,600 MW. As a result of those improvements, the Net Margin was
forecasted to be positive in 2007 and is expected to remain so in 2008.

Summer period fuel supply and delivery has not been an issue within New England.

ISO-New England, through regular meetings with regional stakeholders and state and federal
regulatory agencies, has established both formal and informal communications links with
regional fuel suppliers. For example, membership on the ISO’s Electric/Gas Operations
Committee (EGOC) routinely informs ISO-New England of the status of regional natural gas
(and LNG) supply and delivery issues. In addition, ISO-New England has recently developed an
Operating Procedure 21 (http://www.iso-ne.com/rules_proceds/operating/isone/op21/index.html)
designed to help mitigate the impacts to the bulk power system reliability resulting from regional
fuel supply deficiencies.

The import capabilities to New England and the studies on which they are based are listed below.
The studies are reviewed and updated as necessary on a regular basis. All of the studies are
based on simultaneous transfer capability, and recognize transmission and generation constraints
in systems external to New England.

New England does not have any new transmission constraints that could significantly impact
reliability for the summer of 2008. New England has identified existing transmission constraints
within the regions and has developed extensive guides and procedures for operating within these
limitations to ensure no System Operating Limit (SOL) or Interconnection Reliability Operating
Limit (IROL) violations occur.

     Interface                                 Transfer Capability (MW)                Basis for Interface Limit
     New Brunswick-New                         1,000                                   Second New Brunswick
     England                                                                           Tie Study
     Hydro-Quebec-New                          1,200-1,40061                           PJM and NYISO Loss of
     England Phase II                                                                  Source Studies
     Hydro-Quebec-Highgate                     200                                     Various Transmission
                                                                                       Studies
     New York — New England                    1,350                                   NYISO Operating Study,
                                                                                       Winter 2005-06
     Cross Sound Cable                         34662                                   Cross Sound Cable
                                                                                       System Impact Study

The impact of new generator interconnections or changes/additions to transmission system
topology on transient performance and voltage or reactive performance of the bulk power system
is analyzed. In the event that an adverse impact is discovered, either the project must be revised

61
   The Hydro-Quebec Phase II interconnection is a DC tie with equipment ratings of 2,000 MW. Due to the need to protect for the
   loss of this line at full import level in the PJM and NY Control Areas’ systems, ISO-NE has assumed its transfer capability for
   capacity and reliability calculation purposes to be 1,200 MW to 1,400 MW. This assumption is based on the results of loss of
   source analyses conducted by PJM and NY.
62
   The transfer capability of the Cross Sound Cable is 346 MW. However, losses reduce the amount of MWs that are actually
   delivered across the cable. When 346 MW is injected into the cable, 330 MW is received at the point of withdrawal.

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in some manner to eliminate the concern or operational guides must be developed and
implemented to mitigate the adverse impact. Operating studies to develop operating guides are
generally performed under light load conditions to assess the impact on transient performance
and under both peak and light load conditions to assess the impact on voltage/reactive
performance. Therefore each and every change to the generation/transmission system is either
implicitly or explicitly evaluated from a transient and voltage/reactive perspective. There is
nothing particular about the summer of 2008 which would introduce any new concerns in these
areas.

New England has specific criteria to manage minimum dynamic reactive reserve requirements.
ISO Operating Procedure (OP #17) defines acceptable Load Power Factor requirements for
various subregions within New England. The procedure is designed to ensure adequate reactive
resources are available in the subregion by managing the reactive demand. Furthermore, when
transfer limits are developed for voltage or reactive constrained subregions, the ISO will develop
detailed operating guides that cover all relevant system conditions to ensure reliable operation of
the bulk power system. In determining the acceptable transfer limits, a 100 MW reserve margin
is typically added to each limit to ensure that adequate reactive reserves are maintained. In some
areas, such as Boston and Connecticut, where specific reactive compensation concerns exist,
specific operating guides have been developed to ensure that the areas are operated reliably.

New England has a specific guideline for voltage sag which states that the minimum post-fault
voltage sag must remain above 70% of nominal voltage and must not exceed 250 milliseconds
below 80% of nominal voltage within 10 seconds following the fault. This guideline is applied
when developing transfer limits for the bulk power system in New England.

There are no known reactive power-limited areas in the New England transmission system for
the summer of 2008. Transmission planning studies have ensured that adequate reactive
resources are provided throughout New England. In instances where dynamic reactive power
supplies are needed, devices such as STATCOMs, Dynamic VAR Systems (D-VARs) and
additional generation commitment have been employed to meet the required need. Additionally
the system is reviewed in the near-tem via operating studies to develop operating guides to
confirm adequate voltage and reactive performance. New England in creating transfer limits
based on the dynamic performance of the system, does apply a 100 MW margin to the transfer
limits.

Northern New England has the potential to arm approximately 600 MW of load as part of Under
Voltage Load Shedding. However, it is important to recognize that a significant portion of these
relays are normally not armed and are only armed under severe loading conditions with a facility
already out of service.

As previously noted, ISO New England conducts operable capacity analyses for the current year
using both the 50/50 and the 90/10 forecasts. Those analyses are updated on a monthly basis to
reflect the latest information on new generation, purchases/sales and outages.




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New York

Demand
The New York Balancing Area peak load forecast for this summer is 33,809 MW, which is 362
MW higher than the forecast of 33,447 MW reported in the 2007 Summer Assessment and 1,639
MW more than the 32,169 MW 2007 summer actual. The 2007 summer actual demand was
lower than forecast because of moderate weather. This forecast load is 0.4 % lower than the all-
time summer peak load of 33,939 MW that occurred on August 2, 2006. The daily peak demand
observed by New York during the Summer Operating Period occurs in the mid to late afternoon.
The forecast is developed by the NYISO using a Temperature-Humidity Index (THI) value of
84.2 degrees, which is representative of weather conditions during peak load conditions. At
forecast load levels, a one-degree increase in the THI will result in approximately 610 MW of
additional load. Under extreme conditions the peak load could reach 35,000 MW.

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. In addition to examining the load forecast uncertainty on a
combined basis, the NYISO performs a separate analysis of the uncertainty for summer peak
demand forecast due to weather alone. While the NYISO constructs upper and lower bounds for
energy for both seasonal peaks, additional analysis is performed for summer peaks only. The
NYISO develops error bounds at a total of 7 weather conditions, 3 below and 3 above the
expected load.

The NYISO introduced two load response programs for the New York Market in May 2001.
The Special Case Resource (SCR) and Emergency Demand Response Program (EDRP) are
programs in which Customers are paid to reduce their consumption by either interrupting load or
switching to emergency standby generation when requested by the NYISO.

The EDRP is continuing for summer 2008, and NYISO estimates that 301 MW of load relief
during peak conditions is considered to be available. This load relief will be available to support
the New York State power system during capacity emergency periods. This program is in
addition to the relief obtained through the emergency procedures for Operating Reserve Peak
Forecast Shortage (Section 4.4.1 NYISO Emergency Operations Manual) or in response to the
major emergency state (Section 3.2 NYISO Emergency Operations Manual). Additionally, SCR
is expected to provide 1,287 MW of load relief under peak conditions.

Generation
For 2008 the New York Balancing Area expects 39,770 MW of existing capacity. Of the
existing capacity, 424 MW are from wind generation and 357 MW from biomass generation.
Capacity classified by the NERC RAS as “Existing-Certain” total 38,716 MW; the breakdown of
“Existing Certain” energy from various generation types is as follows: 42 MW from wind
generation, 5,152 MW from hydro generation, and 333 MW from biomass generation. Capacity
classified by the NERC RAS as “Existing Uncertain” totals 1,054 MW; the breakdown of
“Existing Uncertain” energy from various generation types is as follows: 381 MW from wind
generation, 652 MW from hydro generation, and 24 MW from biomass generation. Capacity
classified by the NERC RAS as “Planned” total 130 MW; the breakdown of “Planned” energy
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from various generation types is as follows: 100 MW from wind generation and 30 MW from
hydro generation. Solar energy as capacity in the New York Balancing Area is negligible.

Since the summer of 2007, 65 MW of additional resources have been added to the New York
system. Planned capacity resources for the 2008 summer period include the Munnsville wind
project (35 MW wind farm) and the Gilboa 2 up-rate (30 MW).

For wind generation the NYISO derates all wind generators to 10% of rated capacity in the
summer operating period. With 424 MW of wind generation capacity for this summer, the
expected on-peak capacity counted is 42.4 MW from wind generators classified as “Existing
Certain” capacity according to the NERC RAS. The 90% applied wind de-rate equates to 381
MW of wind capacity classified as “Existing Uncertain” capacity.

For the summer 2008 water levels are normal and no drought exists. Hydro generation consists
approximately 14% of the total capacity in the New York Balancing Area. NYISO applies a
45% de-rate factor for non-NYPA hydro generation for the expected peak months of July and
August. The 45% de-rate factor is applied to the total available non-NYPA hydro generators
totaling 1,040 MW. The large NYPA projects (St. Lawrence and Niagara) have specific de-rate
factors based on the probability the unit will be at certain percentages of its rated capacity output.
Adding all the hydro generation derates values in New York totals 652 MW classified as
“Existing Uncertain” generation according to the NERC RAS.

Hydro conditions are anticipated to be sufficient to meet the expected demand this summer. The
New York area is not experiencing a drought, and reservoir levels are expected to be normal for
the upcoming summer.

Purchases and Sales on Peak
The NYISO projects capacity backed energy net purchases into the New York Balancing Area
backed by 2,802 MW of generating capacity. 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 as the NYISO does
not use firm transmission concept, however, adequate transmission rights must be available to
assure delivery to NY when scheduled. External capacity is also subject to external availability
rights. External availability on import interfaces is available on a first-come first-serve basis.
The total capacity purchased for this summer operating period may increase since there remains
both time and external rights availability.

No portion of the purchases or sales to/from the New York Balancing Area is Liquidated
Damage Contracts (LDCs). Thus, no portion of the purchases or sales to/from the New York
Balancing Area is “make-whole” contracts as defined by FERC in order #890.




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Fuel                                                                  Fuel Type           Percentage
New York State 2008 capacity percentages by fuel type are
listed in the table. Traditionally, the New York Area generation      Gas & Oil           37 %
mix has been dependent on fossil fuels for the largest portion        Gas                 17 %
of the installed capacity. Recent capacity additions or
enhancements now available use natural gas as the primary             Hydro               14 %
fuel. While some existing generators in southeastern New              Nuclear             13 %
York have “dual-fuel” capability, use of residual or distillate
                                                                      Oil                 9%
oil as an alternate may be limited by environmental
regulations. Adequate supplies of all fuel types are expected to      Coal                8%
be available for the summer period.
                                                                      Wind63              1%
Transmission Assessment                                               Other64             1%
Upgrades in the Rochester vicinity were made to accommodate
the Russell Station retirement this summer. A capacitor bank is scheduled to be added to
Millwood 345 by August 2008, for added voltage support in the lower Hudson Valley; the
Athens Special Protection System (SPS) will also be added. Also planned for this summer (June
or July) is the re-conductor of the Northport – Norwalk Harbor 138 kV cable. The new cable
will have three circuits and operate at the same ratings as the current cable.

Operational Issues
There are no significant anticipated unit outages, variable resource, transmission additions or
temporary operating measures that would adversely impact reliability in New York during 2008
Summer.

All generating units in New York are required to operate with limits established in various
permits. Limits apply to many operating parameters including water discharge temperatures,
reservoir drawdown rates, and rates of exhaust gas emissions. In addition, on an annual basis
and seasonal basis, fossil fueled generators are required to surrender emission allowances
equivalent to their respective emissions of SO2 and NOx. The NYISO monitors the supply and
use of NOx allowances during the Ozone Season for selected units to detect impending shortages
and take action to guard against generation shortfalls.

At this time, there are no unusual operating issues or concerns that are anticipated to impact the
reliable operation of the New York transmission system for the coming summer.

Reliability Assessment Analysis
NYISO conducts semi-annual and monthly Installed Capacity (ICAP) auctions. Based on the
forecast load for 2008, the ICAP requirement is 38,879 MW based on a 15% Installed Reserve
Margin (IRM) requirement. Last year the IRM requirement was 16.5%. On February 29, 2008,
the Federal Electric Regulatory Commission issued an order accepting the New York State
Reliability Council's (NYSRC’s) filing of a 15% IRM for the State of New York. In addition to
the generation resources within the New York Area, generation resources external to the New
York Area can also participate in the NYISO ICAP market. An external ICAP supplier must

63
     Wind is listed at full nameplate capacity
64
     Includes methane, refuse, solar, and wood

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declare that the amount of generation that is accepted as ICAP in NY will not be sold elsewhere.
The external Area in which the supplier is located has to agree that the supplier will not be
recalled or curtailed to support its own loads; or will treat the supplier using the same pro rata
curtailment priority for resources within its Balancing Area. The energy that has been accepted
as ICAP in NY must be demonstrated to be deliverable to the NY border. The NYISO sets a
limit on the amount of ICAP that can be provided by suppliers external to NY. Resources within
the New York Balancing Area that provide firm capacity to an external Area are not qualified to
participate in the NYISO ICAP market. With net capacity resources of 41,272 MW, a capacity
margin of 22.1% is projected for the summer peak.

For 2008, the NYISO forecasts 3,075 MW of available transmission for import of external
capacity into the New York Balancing Area. In last summer’s peak operating period, the NYISO
purchased 3,085 MW of external capacity.

The NYISO performs a resource adequacy study to help the New York State Reliability Council
determine the required Installed Reserve Margin for the upcoming capability year. This study
specifies the margin required for the New York Balancing Area. The NYISO conducts the
Locational Capacity Requirements study which determines the amount of capacity that must be
physically located within specific zones such as New York City and Long Island. This study
also helps demonstrate the deliverability of internal and external ICAP capacity among the load
zones within New York. The NYISO currently requires that a value of capacity equal to 80% of
the New York City peak load be secured from within its zone and 94 % of Long Island peak load
be secured from capacity within that zone, for the 2008-2009 capability years. The NYISO also
performs an LOLE analysis that determines the maximum amount of ICAP contracts that can
originate from Balancing Authorities external to the New York Balancing Authority.

NPCC requires that New York perform a comprehensive resource adequacy assessment every
three years. This assessment uses an LOLE analysis to determine resource needs five years into
the future. A report is required showing how the NYISO would meet any projected shortfalls.
In the two intervening years between studies, the NYISO is required to conduct additional
analysis in order to update the findings of the comprehensive review.

Presently, the New York State Reliability Council (NYSRC) Reliability Rules are implemented
such that the electric system has the ability "to supply the aggregate electrical demand and
energy requirements of their customers at all times, taking into account scheduled and reasonably
expected unscheduled outages of system elements.” Compliance is evaluated probabilistically,
such that the loss of load expectation (LOLE) of disconnecting firm load due to resource
deficiencies shall be no more than an average of 0.1 days per year. This evaluation gives
allowance for NYS Transmission System transfer capability documented in NYSRC Rules,
Installed Reserve Margin (IRM), and Locational Capacity Requirements (LCR) reports.
Currently all known deliverability concerns are captured in the evaluation and there are none
identified needing mitigation. A multi area reliability simulation capturing the significant
limitations of the NYS Transmission System is performed every year to demonstrate compliance.
IRM Requirements are developed annually to satisfy resource adequacy requirements. The
NYISO establishes installed capacity requirements (ICAP), including LCRs, recognizing internal
and external transmission constraints.


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New York Balancing Area import capability for this summer is summarized in the table below.

These transfer capabilities are not          Import Area               Transfer Capability
determined based on simultaneous
transfers, how-ever they do take into        PJM                       3,000 MW
account known limitations in adjacent        Neptune Cable             660 MW
systems.                                     Quebec                    1,825 MW
                                             New England               1,200 MW
The Beck-Packard BP76 230kV line is out
of service for this summer and scheduled     Cross Sound Cable         330 MW
to return August 29, 2008.                   Ontario                   1,710 MW

The NYISO performs transient dynamics and voltage studies. Small signal stability studies are
not performed. There are no stability issues anticipated that could impact reliability during the
2008 summer. The NYISO does not have criteria for minimum dynamic reactive requirements.
Transient voltage-dip criteria, practices or guidelines are determined by individual Transmission
Owners in New York State.

The Central-East interface is a reactive power-limited transfer interface. Mitigation plans
include re-dispatch of generation and switching of reactive power equipment. There are a certain
number of internal and external contingencies monitored by the EMS in real-time at regular
intervals to check against post-contingency transfer limits on Central-East. Criteria for voltage
stability margins are outlined in the NYISO Transmission Planning Guidelines. Post-
contingency transfer levels have a 5% voltage stability margin.

As required by NPCC Document A-03, “Emergency Operation Criteria,” New York maintains
an automatic underfrequency load shedding program which trips demand at two frequency set
points. Automatic load shedding of ten percent of load occurs at a nominal set point of 59.3
Hertz; automatic load shedding of an additional fifteen percent of load occurs at a nominal set
point of 58.8 Hertz. With the underfrequency load shedding program in place in New York,
there is no implementation of under voltage load shedding in New York.

The NYISO performs seasonal operating planning studies to calculate and analyze system limits
and conditions for the upcoming operating period. The operating studies include calculations of
thermal transfer limits of the internal and external interfaces of the New York Balancing Area.
The studies are modeled under seasonal peak forecast load conditions. The operating studies
also highlight and discuss operating conditions including topology changes to the system
(generators, substations, transmission equipment or lines) and significant generator or
transmission equipment outages. Load and capacity assessment are also discussed for forecasted
peak conditions.

Ontario

Demand
Ontario’s forecast summer peak demand is 24,892 MW based on Monthly Normal weather and
taking into consideration the impacts of planned conservation and modest economic growth. The
forecast peak for summer 2008 is 3.3% lower than the 25,737 MW actual peak demand which

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occurred on June 26th, 2007. The 2008 forecast is 0.3% higher than last summer’s weather-
corrected peak demand of 24,820 MW.

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 Ontario Power
Authority to provide demand response under tight supply conditions. The combined amount of
these demand measures has been steadily increasing and now amounts to approximately 818
MW in total of which 541 MW is included for seasonal capacity planning purposes, with 249
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 summer peak of 24,892 MW,
the LFU is 1,288 MW.

Generation

The total capacity of existing installed resources connected to the IESO controlled grid is
31,297 MW, of which the amount of ‘certain’ capacity is 27,139 MW for June 2008. The
remainder, 4,158 MW, is ‘uncertain’ capacity for June 2008 which includes the on-peak resource
deratings, planned outages and transmission-limited resources. The certain capacities for July,
August and September 2008 are 28,194 MW, 27,920 MW and 25,643 MW respectively. The
variations in certain capacity arise primarily from monthly variations in hydroelectric capability
and planned outages to large thermal units. In particular, the large variation for September 2008
results from generators beginning scheduled maintenance outages for their units after the peak
summer period.

More than 280 MW of dependable new supply (371 MW installed) is scheduled to come into
service by June 1, 2008. All of this new supply is gas-fired generation, including 340 MW
generation (250 MW under contract and considered dependable) in downtown Toronto from the
first, simple cycle phase of a 550 MW combined cycle energy centre to be completed by
summer 2009 and 31 MW of Combined Heat and Power projects in several locations around the
province.

A hydroelectric project with an installed capacity of 23 MW will come into service by July 1,
2008 MW. An additional 13 MW of hydroelectric is scheduled by September 1. Eighty percent
of this new installed hydroelectric capacity is assumed to be available at the time of weekly peak.

The existing installed capacity of wind generation connected to the IESO controlled grid is
471 MW. Ten percent of the installed wind capacity is assumed to be available at the time of
weekday peak, thus, 47 MW of wind is considered certain for capacity planning purposes. Of
the 75 MW of installed biomass generation in the province, 45 MW is assumed certain. The
generation output of some biomass units has been reduced as a consequence of reductions in
steam demand primarily from pulp and paper operations.

IESO resource adequacy assessments include hydroelectric generation capacity contributions
based on median historical values of hydroelectric production plus operating reserve provided

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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. In particular hydroelectric conditions are highly dependent on snow melt and
spring rains occurring in April and May. 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. Most hydro storages are energy
limited. An energy-limited hydroelectric facility has insufficient storage capability and stream
flows to deliver full generator capacity for each and every hour of the day. Hydro operators
identify weekly and daily limitations for near-term planning in advance of real-time operations.

The province is not experiencing a drought at present. This is evident from the monthly water
levels report published by Environment Canada. It is stated in the report that “Water supplies to
each of the Great Lakes except Lake Superior were above average during February (2008). As a
result, water levels increased on each of the lakes except Lake Superior during the month.”65

Purchases and Sales
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.

The IESO is not aware of any firm purchase or sale contracts with other areas for the summer
season. However, market participants may arrange limited external purchases of capacity to
avoid deferral or cancellation of generator outages in the event that operating reserve
deficiencies are forecast in the near-term.

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.

Fuel
The Ontario fuel supply infrastructure is judged to be adequate during the summer peak demand
period, and there is no fuel delivery problems anticipated for this summer. Gas pipeline
capacity, historically, has not limited the summer energy or capacity capability of Ontario
generation fuelled solely by natural gas and is not expected to be a problem for this summer.
Similarly, no fuel delivery concerns have been identified for coal-fired or nuclear generating
stations. In its market manuals, the IESO requires generator market participants in Ontario to
provide specific information regarding energy or capacity impacts if fuel-supply limitations are
anticipated. No limitations have been reported for the summer months.

Transmission
The supply to central Toronto will be improved for the summer with the John TS to Esplanade
TS link, built by Hydro One, which provides an additional 90 MW of load transfer capability
within the city core. This project was completed in December 2007 ahead of schedule.


65
     http://www.on.ec.gc.ca/water/level-news/ln200803_e.html?CFID=9615995&CFTOKEN=96650156

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Since last summer, Hydro One has installed a new 230/115kV autotransformer at Cambridge and
a 245 MVAR shunt capacitor at Orangeville, both in southwestern Ontario. These transmission
projects are among a number under various stages of development to improve local area
deliverability over the next few years.

Phase angle regulators (PARs) are installed on three of the four Michigan to Ontario
interconnections. One PAR, on the Keith to Waterman 230 kV circuit J5D has been in service
and regulating since 1975. The other two available PARs, on circuits L51D and L4D, which had
been bypassed pending completion of agreements between the IESO, the Midwest ISO, Hydro
One and the International Transmission Company, were placed in service on April 14, 2008, and
they are expected to start regulating before the summer. All parties have committed to
completing the necessary operating agreements to meet this schedule. The operation of the
phase angle regulators will assist in the management of system congestion and control of
circulating flows. The fourth PAR, responsible for controlling the tie flow on the 230 kV circuit
B3N, remains unavailable and is undergoing replacement. This PAR is located in Michigan at
the Bunce Creek terminal of circuit B3N.

Operational Issues
There are no unusual operating condition, environmental, or regulatory restrictions that are
expected to affect capacity availability for this summer. All known planned generator outages
and forecast energy limitations have been included in the IESO’s adequacy assessment.

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.”66

The IESO assumes that the planned resource additions meet their stated in service dates and the
forecast amount of conservation is achieved. The generator planned outages submitted by
Market Participants are inputs to the studies, as well.

Reserve requirements are established in conformance with NPCC regional criteria. The IESO
doesn’t consider external resources in the calculation of resource adequacy. The resource
adequacy studies are done during the last month of every quarter for the subsequent 18 months.
The latest study results are published in the March 12, 2008 18-Month Outlook.67
Planning reserves, determined on the basis of the IESO’s requirements for Ontario self-
sufficiency, are above target levels for all weeks in this period. On average, the projected
capacity margins for the upcoming summer are 1.5% higher than for the summer of 2007.

The IESO reviews its system operating limits on an ongoing basis, as warranted by system
configuration changes on the grid. In advance of each summer peak season, the IESO analyzes
the forecast demand for Ontario, and forecast transmission and generation availability, and
assesses the ability of the planned generation to supply the forecast load (in essence its
deliverability). Where transfer limits are expected to restrict available generation, these
restrictions, in addition to zone-to-zone system operating limits, are factored into the reliability
66
     http://www.ieso.ca/imoweb/monthsYears/monthsAhead.asp
67
     http://www.ieso.ca/imoweb/pubs/marketReports/18MonthOutlook_2008mar.pdf

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analysis for the season, to determine IESO’s resource adequacy. IESO, as the Reliability
Coordinator, and via its authority to direct the operation of the IESO-administered market and
the IESO-controlled grid, can ensure that generation dispatch does not violate system operating
limits. Where resources are expected to be insufficient to satisfy established criteria68, the IESO
can deny final approval for planned outages, and can rely on emergency procedures in the
operational time frame to address shortfall conditions.

Fuel supply is forecast to be adequate to meet the summer peak demands, with no delivery
problems anticipated. IESO obtains fuel supply information directly from market participants as
required. At times, extreme weather conditions may affect hydroelectric and wind supply since
hot, dry calm conditions often elicit peak demands. Allowance for these factors is developed
through IESO review of historic performance every three months. Specifically related to the
convergence of the natural gas and electricity sectors, the IESO is jointly working with the
Ontario gas transportation industry to identify and address issues.

With partial phase angle (PAR) control of the Ontario – Michigan interconnection, the coincident
import/export capability is unlikely to equal the arithmetic sum of the individual flow limits. At
best, the total transfer capability is the sum of the interconnection flow limits. At worst, the total
transfer capability will equal the minimum of the New York (St. Lawrence plus Niagara) or
Michigan interconnection flow limit, plus all other interconnection flow limits. In the summer,
the interconnections can carry coincident exports from 2,765 MW up to 4,915 MW, and
coincident imports from 3,734 MW up to 5,284 MW. In the winter, the interconnections can
carry coincident exports from 3,512 MW up to 5,912 MW, and coincident imports from
4,115 MW up to 5,915 MW.

The IESO regularly conducts transmission studies that include results of stability, voltage,
thermal and short-circuit analyses in conformance with NPCC criteria. Since the implementation
of the NERC TPL standards in June 2007, the IESO’s comprehensive 2007 transmission studies
have been conducted to comply with these standards, in addition to NPCC criteria.

There are no transmission constraints, stability based limits or reactive power deliverability
constraints that are expected to significantly impact reliability based on the forecast availability
of generation and transmission facilities for the upcoming season, although there are many
transmission limits on the IESO-controlled grid that the IESO manages on a day-to-day basis
(e.g. through constrained-dispatch, and occasional use of Transmission Loading Relief
procedures).

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.
68
     NPCC Criteria A-02, ”Basic Criteria for Design and Operation of Interconnected Power Systems” and IMO_REQ_0041, “Ontario Resource
     and Transmission Assessment Criteria”

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There are currently no Under-Voltage Load Shedding systems installed in Ontario for the
purpose of controlling the voltage on the bulk power system portion of the IESO-controlled grid
in response to bulk power system events. There are several systems used for localized voltage
control in the event of an outage to local supply facilities.

Although energy supplies available within Ontario are expected to be adequate overall, energy
deficiencies could arise as a result of higher than forecast forced outage situations, prolonged
extreme weather conditions and other influencing factors. Interconnection capability and
available market and operational measures have been evaluated as sufficient to ensure summer
energy demands can be met for a wide variety of conditions. The IESO uses a measure of
forecast uncertainty in a probabilistic analysis to account for variations in demand due to weather
volatility. This uncertainty is used in conjunction with the normal weather demand forecast to
determine resource adequacy. As well, the IESO creates a demand forecast based on extreme
weather and uses it in further assessing system adequacy.


Québec

Demand
Québec’s forecasted internal peak demand for the 2008 summer NERC RAS reporting period ─
June to September ─ is 21,344 MW. The actual peak demand for the 2007 summer NERC RAS
report period was 21,411 MW. This occurred on August 2, 2007 at 17h00 EDT. The all-time
summer peak for the NERC RAS report period was 21,614 MW on June 28, 2005.

Hydro-Québec Distribution is the only Load Serving Entity in Québec, and its load forecast is
conducted for the entire Area. HQD’s load forecast is based on the average climatic conditions
observed from 1971 to 2006 adjusted for a global warming of 0.30 °C per decade starting in
1971. The latest forecast – based on economic, demographic and energy-use assumptions – was
presented in the Hydro-Québec Distribution Procurement Plan submitted to the Québec Energy
Board in October 2007 (available on the Québec Energy Board web site).

HQD has developed a method to estimate the impact of climatic uncertainty on peak demand
based on 252 simulations of the hourly load forecast under the 36 years of the climatic period
1971-2006. Each year of climatic data is shifted up to ± three days to gain information on the
effect of the climatic conditions on each days of the week. Since Québec has a winter peaking
load profile, the uncertainty – measured by a standard deviation analysis – is lower during the
summer than during the winter. As an example, at the summer peak, weather conditions
uncertainty is about 300 MW, equivalent to one standard deviation. During winter, this
uncertainty is approximately 1,500 MW. Extreme weather deviations can be quantified at about
900 MW for the summer peak and at about 4,700 MW for the winter peak.

The following table summarizes and compares actual and forecasted demands in Québec for
2007 and 2008.




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   Demand in MW                    June           July            August          September
   A) Observed 2007                21,272         20,919          21,411          21,255
   B) Forecasted 2007              21,487         21,606          21,769          21,750
   Difference (A-B) 2007           -215           -687            -358            -495
   C) Forecasted 2008              20,971         21,078          21,344          21,297
   Difference (C-B)                -516           -528            -425            -453

The shutting down of certain industrial loads, such as sawmills and paper mills, has reduced the
forecasted demand by 400 to 500 MW for the next summer months.
Since Québec is a winter peaking system, no interruptible load programs are available for the
summer period.

Generation
For the 2008 Summer Operating Period, total installed capacity in Québec is projected to be
42,111 MW, up 605 MW from last summer’s installed capacity of 41,506 MW. This includes
firm capacity purchases from Churchill Falls Labrador Co., from Québec private producers, from
Alcan in Québec, and from wind farm generation.

Hydro-Québec Production’s (HQP) main hydro project ─ the Péribonka generating station ─ will
be completely in service for the Summer Operating Period. Commissioning has begun in fall
2007 and will be through in early spring 2008. The total capacity is 340 MW. Two more hydro
generating stations ─ Chute-Allard and Rapide-des-Coeurs ─ are being partially commissioned
during the Summer Operating Period and will add 64 MW of capacity to the system. A number
of small capacity adjustments, derates, etc. in many hydro generating stations account for the rest
of the 2007-2008 capacity differences.

The following table summarizes the anticipated ‘existing certain’, ‘existing uncertain’ and
planned resources in Québec during the 2008 summer season.

   Capacity (MW) in 2008             June           July          August          September
   Existing Certain                  32,732         32,776        32,742          32,133
   Existing Uncertain                9,110          9,066         9,100           9,709
   Planned                           237            269           269             291
   Total Internal                    42,079         42,111        42,111          42,133

The present Québec wind power installed capacity is 420 MW. Wind power is completely
derated for reliability assessments, so it is reported as capacity that is treated as “Existing
Uncertain” in the submission of data for the 2008 summer analysis. The present Québec biomass
installed capacity is 298 MW (derived from forest biomass), and this capacity is reported as
capacity that is treated as “Existing-Certain” in the submission of data for the 2008 summer
analysis.

Presently, there are no drought conditions in Québec. Reservoir levels are expected to be more
than sufficient to meet both peak demand and energy demand throughout the summer. To

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demonstrate its energy reliability, HQP ─ Québec’s reservoirs’ manager ─ presents an energy
reliability assessment to the Québec Energy Board three times a year. Its energy criterion states
that Hydro-Québec Production must maintain a sufficient energy reserve to protect against a
possible hydraulic deficit of 64 TWh for two consecutive years and 98 TWh for four consecutive
years. The last assessment (November 2007) shows that Hydro-Québec Production complies
with this energy reliability criterion. The next assessment will be presented to the Québec
Energy Board in May 2008.

Purchases and Sales on Peak
HQP does not require any external purchases for the 2008 summer peak period in terms of
resource adequacy. Also, no firm sales affect the Québec sub-regional capacity margins. During
summer periods, Québec does not need external purchases due to its winter peaking
characteristic.

Fuel
Fuel supply vulnerability does not apply to Québec since about 95 % of resources are hydro-
electric. The only natural gas generating station in Québec (507 MW) will be out of service
(mothballed) for the entire year 2008. This capacity is considered to be “Existing Uncertain –
Inoperable”.

Transmission
Since summer 2007, no new Bulk Power System transmission projects have been commissioned
in Québec.

Operational Issues
There are no anticipated unit outages, variable resource, transmission addition or temporary
operating measure issues that may impact reliability during the summer. Internal generating unit
and transmission outage plans are assessed to meet internal demand, firm sales, expected
additional sales and additional uncertainty margins. They should not impact internal reliability
and inter-area capabilities with neighboring systems. In addition, there are no environmental or
regulatory restrictions that could impact Quebec reliability.

There are no unusual operating conditions anticipated on the system that could impact reliability
for summer 2008. All scheduled interconnection installation maintenance is to be done outside
the summer operating period.

Reliability Assessment Analysis
In the “Québec Control Area 2007 Interim Review of Resource Adequacy” report approved in
March 2008 by the NPCC, the projected capacity margins for the next three winter periods are
between 14 and 16 % of the peak demand forecasts. These percentages are higher than those
required to respect the NPCC and Québec Energy Board reliability criteria. In the 2007 Interim
Review of Resource Adequacy, the required reserve expressed as a percentage of winter peak
demand is about 11 %.

A description of the various assumptions used to assess the resource adequacy of Québec is
available in the 2005 and 2007 Québec Area Review of Resource Adequacy. The major
assumptions of the 2007 Interim Québec Review are consistent with Hydro-Québec


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Distribution’s Procurement Plan 2008-2017 filed with the Québec Energy Board in November
2007. No external resources were considered, as Québec is generally a resource exporter.

Moreover, each year, Québec produces resource adequacy assessments for NPCC and the
Québec Energy Board. These assessments are conducted during fall for the next winter peak
period and the years thereafter. The conclusions show that Québec is more reliable than the
NPCC resource adequacy criterion.

As shown in the next table, for August the capacity margin is 1,500 MW lower than last year’s.
The main factor explaining this difference is the firm sales in August 2008, which are 2,000 MW
higher than last year.


       Projected Capacity Margin Comparison for Summer Assessments in August
                                2008 Versus 2007 (MW)
                                         2007      2008     Difference
             Existing Capacity                41,474     41,842        368
             Planned Additions                32         269           237
             Total Internal Capacity          41,506     42,111        605

             Maintenance/Hydro Derates        -8,338     -8,654        -316
             Wind Derates                     -322       -420          -98
             Internal Capacity                32,846     33,037        191

             Purchases                        200        200           0
             Sales                            -1,335     -3,383        -2,048

             Net Capacity Resources           31,711     29,854        -1,857

             Net Internal Demand              21,770     21, 344       -426

             Margin (MW)                      9,941      8,510         -1,431
             Margin (%)                       45.7       39.9




TransÉnergie conducts a yearly peak-demand period assessment for the Québec system to assess
generation deliverability. However, this is done for the winter peak period. For the summer
period, when the greater part of system maintenance is done, weekly generation deliverability
studies are conducted to assure not only deliverability to internal load but also to
interconnections so as to fill in neighboring Area requirements. When deliverability concerns to
interconnections are identified in summer, maintenance is usually rescheduled so as to maintain
scheduled deliveries.

Hydro-Québec Production plans its summer generating unit maintenance so that enough
resources are available for internal load and any scheduled exports to neighboring Areas with a
sufficient capacity margin to allow for demand forecast uncertainty and unscheduled short term

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exports. Summer capacity margins in Québec are usually between 4,000 and 9,000 MW.
TransÉnergie, through the weekly generation deliverability studies mentioned above, assures
maximum access to internal and external markets.

Fuel supply is not a concern in Québec since about 95 % of the resources are hydroelectric.
Thermal generation is used for peaking purposes in winter.

Transmission capabilities from and to the Eastern Interconnection are revised periodically with
Québec’s neighboring systems to assess interconnection limits. Transfer capabilities vary from
peak to non peak periods.

These are the Québec import capabilities in summer:

     From Maritimes: 685 to 735 MW
     From New England: 1,600 MW
     From New York: 1,100 MW
     From Ontario: 712 to 880 MW

The summer demand in Québec is historically lower than the winter demand. Summer peak is
approximately 60% of the winter peak. During summer, the Québec Area does not expect to
need external assistance.

These are the Québec export capabilities in summer:

     To Maritimes: 921 to 991 MW
     To New England: 1,460 MW
     To New York: 1,825 to 1,980 MW
     To Ontario: 1,465 to 1,540 MW

The capacity margin available in Québec during summer period ranges from 4,000 to 9,000 MW
approximately so that a certain amount of bottling of resources from Québec to the rest of NPCC
is expected due to the rated transfer capabilities of Québec interconnections compared to the
available resources. Also, due to system configuration, capacity may not be available
simultaneously to New York and Ontario. However, maximum capacity is made available in
July and August for Ontario, New York and New England, with due regard to system constraints
concerning exports.

There are no transmission constraints that could impact reliability in Québec for summer 2008.
Transient and voltage stability studies are performed continuously by TransÉnergie to establish
the system transfer limits on all possible system configurations. No particular issue has been
found to impact the summer 2008 season.

TransÉnergie has a criterion for minimum dynamic reactive requirements. Due to system
geography and configuration (Generation centers are remote from load centers and system is
made up of long 735-kV lines) this is not applied to generators but to synchronous condensers
and Static Var Compensators distributed along the system. There are 20 SVCs and synchronous
condensers on the system, each with a nominal reactive power range of -100 to +300 MVAR.

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The steady state operating range is -50 to +50 MVAR per compensator, so that a 250 MVAR
margin per compensator is available as dynamic reactive reserve. (Up to 5,000 MVAR total).
Moreover, a significant amount of 735-kV 330 MVAR reactors may be switched on and off to
continually keep the compensators within their operating range. The SVC and synchronous
condenser operating range is strictly monitored.

The following table shows the voltage-dip criteria applicable to the Bulk Power System and
guidelines after a system contingency.

                          Voltage Limits on the Transmission System

                             Normal Limits                       Emergency Limits
Nominal
Voltage               Low limit          High limit         Low Limit           High Limit
                     kV       p. u.     kV       p. u.     kV       p. u.       kV       p. u.
735 kV             725       0.985    760      1.034     698       0.95      765        1.04
315 kV             299       0.95     331      1.05      284       0.90      347        1.10
230 kV             219       0.95     242      1.05      207       0.90      253        1.10
Interconnections             0.95              1.05                0.90                 1.05

The emergency limits must be respected five minutes after a contingency. This is done
automatically by voltage regulation on the system, with the adequate amount of reactive capacity
built into the system. However, the 735-kV Emergency Low Limit is quite stringent and the use
of MAIS (Automatic Shunt Reactor Switching System) is permitted after the contingency to re-
establish 735-kV voltages. On the 735-kV system, the transient limit is 0.80 p. u. voltage for two
seconds after fault clearing and the mid-term limit is 0.90 p. u., from two seconds up to five
minutes after fault clearing. All transient and long term voltage stability analyses must respect
these criteria.

There are no dynamic and static reactive power-limited areas on the Québec Bulk Power System.
TransÉnergie is a winter peaking area, and as such, does not expect to encounter voltage collapse
problems (or any kind of low voltage problem) during the summer. On the contrary, controlling
over voltages on the 735-kV network during off-peak hours is the concern. This is accomplished
mainly with the use of shunt reactors. Typically, about 15,000 MVAR of 735 kV shunt reactors
may be connected at any given time during the summer, with seven to ten 735-kV lines out of
service for maintenance. Most shunt capacitors, at all voltage levels, are disconnected during the
summer.

Under Voltage Load Shedding is installed in Québec. It has been designed to operate following
extreme contingencies involving the loss of two or more 735-kV lines tripped out in the load area
of the system. UVLS operates on a pre-defined pool of load located in the Montréal area. The
amount of load shed is proportional to the length and severity of the measured under voltage. A
total load shedding of 2,500 MW can be ordered. UVLS is used as an effective countermeasure
against voltage instability.

Operational planning studies are being continuously conducted by TransÉnergie, the Québec
Area controller. These studies lead to the implementation of procedures to safely operate the

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system. For example, the Québec system being asynchronous with the rest of NPCC ─ and
being an Interconnection in its own right ─ has procedures for maintaining spinning reserve to
guard against post-contingency frequency drops. Also, TransÉnergie conducts a yearly peak
demand period study to assess system conditions during the winter peak period.

Extreme weather conditions in Québec translate into very low temperatures during the Winter
Operating Period. Through a transmission planning criterion, transmission planning and
operational planning studies must take into account a 4,000 MW load increase on the system
during such extreme weather conditions. This is equivalent to 110 % of system winter peak load.
The Load Serving Entity relies on both internal and external resources to serve this additional
load and transmission capacity is available.

Québec System Information

Peak season: winter.
Winter to summer peak ratio: 1.7
Population served: Around 7 million
Area: approximately 1,668,000 km2

Regional Description

The Northeast Power Coordinating Council, Inc. (NPCC) is the cross-border regional entity and
criteria services corporation for Northeastern North America. It is the NPCC mission to
promote and enhance the reliable and efficient operation of the international, interconnected
bulk power system in Northeastern North America pursuant to its agreement with the Electric
Reliability Organization, which designates NPCC as a regional entity and delegates authority
from the U.S. Federal Energy Regulatory Commission, and by Memoranda of Understanding
with applicable Canadian Provincial regulatory and/or governmental authorities. The
geographic area covered includes New York, the six New England states, and Ontario, Québec,
and Maritimes provinces in Canada. The total population served is approximately 56 million,
and the total geographic area is approximately one 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. Additional information can be found
on the NPCC Web site (http://www.npcc.org/).




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RFC
2008 Projected Peak Demand                      MW
                                                                                 Relative Capacity by Fuel Mix
  Total Internal Demand                         184,000
    Direct Control Load Management                  900
    Contractually Interruptible (Curtailable)     5,400
    Critical Peak-Pricing with Control                0                                                          Gas 25%
    Load as a Capacity Resource                       0
  Net Internal Demand                           177,700

                                                MW      Change        Coal 47%
2007 Actual Summer Peak Demand                  181,700   -2.2%                                                            Oil 8%
All-Time Summer Peak Demand                     190,213   -6.6%
                                                                                                                       Other 0.4%
2008 Projected Capacity                         MW      Margin                                                        Wind 0.8%
  Existing Certain and Net Firm Transactions    213,400   16.7%                                                      Pumped
  Net Capacity Resources                        213,400   16.7%                                     Nuclear 15%     Storage 2%
                                                                                    Hydro 1.1%
  Total Potential Resources                     216,300   17.8%



Introduction
All ReliabilityFirst Corporation (RFC) members are
affiliated with either the Midwest ISO (MISO) or PJM RTO
(PJM) for operations and reliability coordination. Ohio
Valley Electric Corporation (OVEC), a generation and
transmission cooperative located in Indiana, Kentucky and
Ohio, is not affiliated with either RTO market; however
OVEC’s Reliability Coordinator services are performed by
PJM. Duquesne Light Co. has recently announced its
intention to withdraw from PJM and join MISO later this
year. For this assessment, Duquesne Light continues to be
included within the PJM RTO.

ReliabilityFirst does not have officially-designated subregions; however, about one-third of the
RFC load is within MISO and nearly all remaining load is within PJM, except for about 100 MW
of load within the OVEC Balancing Authority area. From the perspective of the RTOs,
approximately 60% of the MISO load and 85% of the PJM load is within RFC. The PJM RTO
spans into the SERC region, and the MISO RTO also spans into the MRO and SERC regions.
The PJM RTO operates in total as one Balancing Authority area. MISO has recently received
approval to begin operation as a single Balancing Authority area however operation as a BA is
not expected to occur until after this summer.

This assessment provides information on projected resource adequacy for the upcoming summer
season across the ReliabilityFirst region. The RFC Resource Adequacy Standard BAL-502-
RFC-01 requires Planned Reserve Sharing Groups (PRSGs) to identify the minimum acceptable
reserves to maintain resource adequacy for their respective areas of RFC. PJM operates as the
PRSG for its members. The Midwest PRSG consists of a consortium of MISO members that
includes about 95% of the MISO load in the RFC regional area. Since nearly all ReliabilityFirst
area demand is in either Midwest ISO or PJM, the reliability of these two RTOs will determine
the reliability of the RFC region. This report assesses the resource adequacy of each RTO based
on the reserve margin requirements applicable to each RTO. PJM determines the reserve margin


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requirement for all demand within PJM. The Midwest PRSG and MAPP determine reserve
requirements for most of the demand in MISO. MISO uses a 12% default reserve requirement for
demand not included in the Midwest PRSG and MAPP. The combination of reserves from the
Midwest PRSG, MAPP and the default reserve calculation was used by RFC as the MISO
reserve margin target for assessing resource adequacy.

Demand
The analysis of the demand data for the summer assessment focuses on three factors, Total
Internal Demand (TID), Net Internal Demand (NID) and Demand-Side Management (DSM).

TID represents the entire forecast electric system demand. This demand forecast is based on
“50/50” or average summer weather (a 50% chance of the weather being warmer and a 50%
chance of the weather being cooler). The ReliabilityFirst Region identifies the various programs
and contracts designed to reduce system demand during the peak periods as DSM. Individual
companies may implement DSM through a demand response program, a direct-controlled load
program, an interruptible load contract or other contractual load reduction arrangement. Since
DSM is a contractual management of system demand, the reserve margin requirement for the
RTO includes DSM. NID is total internal demand (TID) less DSM. Reserve margin requirements
are based on NID.

Demand-Side Management can be addressed in different ways, reflective of its operational
impact on peak demand and reserve margins. DSM offers the companies that have these
programs and contracts a way to mitigate adverse conditions that the individual companies may
experience during the summer. The total demand reduction of each RTO is the maximum
controlled demand mitigation that is expected to be available at the time of the peak system
demand. For the summer of 2008, the ReliabilityFirst RTOs have identified the following types
of DSM programs:

          DIRECT-CONTROLLED LOAD MANAGEMENT
          There are a number of load management programs under the direct control of the system
          operators that allow interruption of demand (typically residential) by controlling specific
          appliances or equipment at the time of the system peak. Radio controlled water heaters
          or air conditioners would be included in this category. Direct controlled load
          management is typically used for “peak shaving” by the system operators.

          INTERRUPTIBLE DEMAND
          Industrial and commercial customer demands that can be contractually interrupted at the
          time of the system peak, either by direct control of the system operator (remote tripping)
          or by the customer at the request of the system operator, are included in this category.


PJM RTO DEMAND DATA
The estimated Net Internal Demand (NID) peak of the entire PJM RTO for the 2008 summer
season is 134,000 MW and is projected to occur during July. This value is based on the Total
Internal Demand (TID) forecast prepared by PJM staff with the full utilization of the load
management placed under PJM coordination. The forecast is dated January 2008, and is based on
economic data from late 2007.


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Emergency Load Management placed under PJM coordination is PJM’s program for Demand-
Side Management (DSM). PJM identifies two types of DSM, Direct Control, and Interruptible.
Direct control amounts to 400 MW during the summer for PJM with an additional 3,500 MW of
Interruptible Demand.

The estimated Total Internal Demand (TID) of PJM RTO for the 2008 summer season is 137,900
MW and is projected to occur during July. This value is based on an independent demand
forecast prepared by PJM staff for each PJM zone, region and the total RTO. This compares to
the 2007 metered peak demand of 139,568 MW, and a weather normalized peak demand of
136,095 MW. The 2008 forecast TID is 1,805 MW (1.3%) higher than the weather normalized
2007 peak TID, and 1,668 MW (1.2%) lower than the actual 2007 metered peak demand.

MISO DEMAND DATA
The estimated Net Internal Demand (NID) coincident peak of the entire Midwest ISO (MISO)
Market Area for the 2008 summer season is 100,000 MW and is projected to occur during July.
This value is based on the Total Internal Demand (TID) demand forecast prepared by the MISO
market participants and the expected peak reduction from various DSM programs. The MISO
market participants developed their demand forecasts at different times throughout the last half
of 2007, so the economic basis for each company forecast reflects the specific economic data of
that company’s planning area at the time of their forecast.

The amount of MISO market participant demand response or load management expected at the
time of the peak is 4,800 MW. This is categorized as 1,700 MW of Load Management with an
additional 3,100 MW of Interruptible Demand.

The estimated coincident Total Internal Demand (TID) of MISO for the 2008 summer season is
104,800 MW and is projected to occur during July. This value is based on information provided
by the market participants. This compares to the 2007 peak demand of 103,891 MW. The 2008
forecast demand is 909 MW (0.9%) higher than the actual 2007 peak demand.

RFC DEMAND DATA
In this assessment, the data related to the RFC areas of PJM and MISO is combined with the data
from the Ohio Valley Electric Corporation (OVEC) to develop the RFC regional data. The RFC
demand forecast also accounts for expected demand diversity among these entities. RFC uses the
minimum diversity from the past 5 years which is 2.0% in July.

Approximately 85% of the PJM RTO demand and approximately 60% of the MISO market load
is within the RFC region. Since OVEC is not a member of either RTO, the 88 MW of OVEC
demand was added to the non-coincident demand of the PJM and MISO areas; a 2.0% diversity
factor, the minimum diversity in July over the past five years of history, was applied; and the
result rounded to the nearest 100 MW. The resulting coincident peak for the RFC region is
177,700 MW NID and 184,000 TID. The forecast NID peak is 3,000 MW (1.7%) lower than the
forecast demand for 2007. This lower forecast is the result of lower expected economic growth at
the time of the demand forecasts, and 2,800 MW of additional DSM. The forecast TID peak is
2,300 MW higher than the actual peak demand of 181,700 MW that occurred on August 8, 2007
for the ReliabilityFirst regional area.



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DEMAND SENSITIVITY
Although the demand forecasts used in this assessment were collected in recent months, these
forecasts were prepared months earlier. Both weather and economic conditions have significant
influence on the peak demands. Any deviation from the original forecast assumptions for those
parameters could cause the aggregate 2008 summer peak to be significantly different.

For the summer of 2008, a 90/10 TID forecast was prepared by PJM for its load zones as a
sensitivity for extreme weather. A 90/10 demand forecast includes weather related demand for
weather that has a 10% chance of being warmer and a 90% chance of being cooler. The PJM
load zones that are in RFC have a non-coincident 90/10 demand of 129,600 MW, a 4.43%
increase. The MISO performs a statistical analysis with the participants 50/50 TID forecast and
historical demand data to calculate a 90/10 demand forecast. From this analysis there is a 4.97%
increase in the demand of the RFC area of MISO to 66,800 MW for 90/10 weather. For the
summer of 2008, the NID forecast based on 90/10 weather for the MISO and PJM areas,
including OVEC and a 2% demand diversity, was used to calculate the sensitivity of the reserve
margin to extreme weather in RFC. The results of this demand sensitivity are included in the
Reliability Assessment Analysis section of this report.

Generation
The generating capacity in this assessment represents the rated capability of the generation in
OVEC and in the PJM and MISO market areas. The category of Existing Capacity listed as
“certain” represents existing resources in PJM’s Reliability Pricing Model (RPM) and
Designated Network Resources (DNR) in the MISO market.

The “uncertain” resources are the existing generation that represents wind/variable resource
deratings, and other existing capacity resources within the region that are not included in the
“certain” category or the reserve margin calculations. Also included in “uncertain” capacity
would be generating capacity that has not been studied for delivery within the region, and
capacity located within the region that is not part of PJM committed capacity or MISO DNR.

“Planned” capacity additions are those additions expected to go in-service during the summer
period and are included in the determination of the reserve margins. Any “proposed” capacity
additions have an uncertain in-service status for this summer and are not included in the reserve
margins.

The recent emphasis on renewable resources is increasing the amount of wind power capacity
being added to systems in the ReliabilityFirst Region. In this assessment, the amount of available
wind power capability included in the reserve calculations is less than the nameplate rating of the
wind resources. PJM uses a three year average of actual wind capability during the summer daily
peak periods as the expected wind capability. Until three years of operating data is available for a
specific wind project, that project is assigned a 13% capability of the name plate rating. In
MISO, wind power providers may declare up to 20% of nameplate capability as DNR. The
difference between the nameplate rating and the expected wind capability is accounted for in the
existing “uncertain” category.

Scheduled maintenance and any existing capacity that is inoperable for this summer is not
included in this assessment of reserve margins. Generally, scheduled maintenance is minimized

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during the peak demand periods. This inoperable capacity listed during the summer peak (July)
is expected to be zero for PJM and about 1,000 MW for MISO.

PJM GENERATION
The whole PJM RTO has 164,700 MW of capacity for this summer that is identified as “certain”
in this assessment. Under the Reliability Pricing Model (RPM), all capacity that has cleared in
the capacity market has to be in service prior to June 1. Therefore, there is no “planned” capacity
included for this summer. There is also 1,600 MW of generation related to capacity deratings of
wind generators and generators that are energy-only participants in the PJM market. Since these
resources are not in the RPM market, the deliverability and availability 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.

MISO GENERATION
The whole MISO RTO has 115,300 MW of DNR capacity for this summer that is identified as
“certain” in this assessment. This includes 4,400 MW of expected DNR capacity that does not
have final contracts at the writing of this report. No additional capacity is expected to go in
service during the summer. However, there are 6,600 MW of capacity in the MISO RTO that is
“uncertain” capacity, consisting of uncommitted resources and the derated amount of wind
energy capacity. None of this uncertain capacity is included in the reserve margin calculation.

RFC GENERATION
The RFC analysis includes only generation physically located within the ReliabilityFirst Region,
although generating capacity outside the regional area owned by member companies may be
included with the scheduled power imports.

The amount of “certain” OVEC, PJM and MISO capacity in RFC is 212,900 MW. No additional
capacity is expected to go in service during the summer. All of the “certain” capacity in each
RTO is determined to be fully deliverable by PJM and MISO within their respective RTOs.
There is also 2,900 MW of capacity in the RFC region that is “uncertain” capacity, which is not
included in the reserve margin.

Deliverability of capacity between the RTOs is not addressed in this report. However, each of the
reserve requirement studies conducted has assumed limited or no transfer capability between
these RTOs. Studies by the RFC Transmission Performance Subcommittee indicate there is
additional inter-RTO transfer capability. The limited use of transfer capability in the reserve
requirement studies provides a level of conservatism in this resource assessment.

Included in the total of “certain” generation is 225 MW of wind power expected at the peak. An
additional 1,565 MW of wind power is categorized as “uncertain” due to the variable nature of
wind. Other renewable categories make up an addition 400 MW of generation within the RFC
region.

If there are any known adverse weather conditions or fuel supply concerns expected to affect
available generating capacity this summer, those deratings have been applied to the existing
capacity and included in the uncertain capacity category. If any specific adverse conditions are
expected to exist this summer they will be addressed in the Fuel section.


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Purchases and Sales
PJM and MISO have reported expected firm purchases and sales across their RTO boundaries at
the time of the peak. This net interchange is due to member ownership interest in generation
outside the RTO boundary, and contracted transactions. Specific transactions identified by PJM
and MISO as interchange that supports the reserve margins in RFC are firm transactions with
firm transmission reservations.

Some of the total interchange reported by PJM and MISO 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 in PJM and MISO comes from OVEC entitlements.
Since the jointly owned generation and the OVEC generation is all within RFC, the jointly
owned and OVEC generation is included in RFC’s generation and not in the RFC net
interchange. Other transfers between the RTOs may have been reported. Since these transfers
originate and terminate within the RFC region, they will also not be included in the RFC
interchange. Therefore, the total net interchange for the RFC region is not a simple summation
of the PJM and MISO RTO interchange.

Since both the MISO and PJM balancing authority areas span into neighboring regions, the
values shown below for each RTO are for the total of the respective RTO footprint. The RFC
net interchange below only includes that portion of the respective RTOs within the
ReliabilityFirst regional area.

PJM NET INTERCHANGE
Firm power transfers into all of PJM are reported to be 2,700 MW. Firm power transfers out are
reported to be 4,200 MW. Net interchange is a 1,500 MW power export flowing out of the PJM
RTO.

MISO NET INTERCHANGE
MISO has reported net interchange (purchases) of 6,300 MW into the whole MISO market at the
time of the peak demand. There are no projected firm power sales.

RFC NET INTERCHANGE
The combined net interchange transactions for OVEC, MISO and PJM at the time of the peak
that cross the RFC regional boundary are projected to be a 500 MW import into ReliabilityFirst.
These include only firm transactions. Other transactions may occur this summer, but they are
not considered to be firm transactions and are not included in this analysis.

For both MISO and PJM, any firm capacity from outside the region would be used as any other
market resource and, therefore, could be used for emergency and reserve sharing purposes.

Fuel
Severe weather conditions or fuel supply and delivery problems can adversely affect available
generating capacity. Droughts, like the current drought in the Southeastern U.S. can affect coal
barge traffic on some rivers. Droughts can also impact the cooling water needed for steam
generating plants, by lowering intake channel depths, or by thermal discharge limitations. Rail
bottlenecks or other limitations on rail transportation would be expected to cause significant coal
delivery problems. Generation that depends on a single natural gas pipeline can become


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unavailable during a pipeline outage. Insufficient natural gas in storage during high use periods
can create a regulatory prohibition of gas usage for electric generation.

The RFC area is not currently experiencing a drought. Two thirds of the hydro resources in the
ReliabilityFirst Region are pumped storage units and the remaining are conventional hydro units.
These conventional impoundment or run-of-river units only account for about 1% of the capacity
resources within the region, limiting the region’s exposure to adverse water conditions.

RFC is dependent on natural gas as a fuel for the demand peaks, particularly in the summer time.
Over 64,000 MW (29%) of the regional capacity is fueled by gas. Natural gas in storage at the
middle of March is near the 5-year average of gas in storage at this time of year according to the
Energy Information Administration. Although natural gas usage for electric generation in the
summer has increased significantly in recent years, the peak gas usage is during the winter
heating season. ReliabilityFirst does not expect any problem with gas availability this summer.

Coal is a plentiful fuel within the region, and a potential concern is the dependence on rail
transport for much of the coal supply. However, RFC is not aware of any major railroad
reporting rail transportation limitations or concerns for this summer.

ReliabilityFirst expects each member to be ready to mitigate any fuel supply disruption that may
occur. Although ReliabilityFirst has not compiled a list of mitigation actions that could be taken,
some members may resort to fuel switching for those units with dual-fuel capability, if it
becomes necessary to maintain reliable fuel supplies. Data available to ReliabilityFirst indicates
that at least 25% of the regional capacity has dual-fuel capability. ReliabilityFirst has not
verified with individual members the ease or difficulty involved with switching to alternate fuels.
PJM is investigating firm gas supply contracts. There are significant financial consequences
within the PJM market structure for generators not supplying output when called upon. PJM
does not have a policy for on-site coal or back-up fuel storage.

Transmission
Historically, ReliabilityFirst (including the heritage regions) has experienced widely varying
power flows due to transactions and prevailing weather conditions across the region. As a result,
the transmission system could become constrained during peak periods because of unit
unavailability and unplanned transmission outages concurrent with large power transactions.
Generation redispatch has the potential to mitigate these potential constraints. Notwithstanding
the benefits of this redispatch, should transmission constraint conditions occur, local operating
procedures as well as the NERC transmission loading relief (TLR) procedure may be required to
maintain adequate transmission system reliability.

Certain critical flowgates that have experienced TLRs in previous summers continue to be
identified as heavily loaded in various reliability assessments and may require operator
intervention to ensure reliability is maintained. No major changes have been identified that
would adversely impact reliability this summer.

Many new additions to the bulk-power system have been placed in-service since last summer and
include a total of 85 miles of transmission line at 230 kV and above, plus ten transformers with a
total capacity of about 6,000 MVA. An additional total of 30 miles of transmission line at 230

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kV and above is projected to be placed in-service by this summer, plus six transformers with a
total capacity of about 3,000 MVA. These system changes are expected to enhance reliability of
the bulk-power system.

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 flow from RFC to NPCC. The Michigan-Ontario PARs have not yet achieved long-term
operation of all four units. The B3N PAR that previously failed will still be out-of-service this
summer. An operations agreement for controlling the interface is expected to be completed by
the summer, after which the remaining three PARs are expected to control flows (i.e. will be
regulating).

Operational Issues
During normal operations and for typical operations planning scenarios, there may be some
transmission constraints within both the PJM and MISO areas of ReliabilityFirst. All of these
constraints may be alleviated with generation redispatch or other operating plans/procedures with
minimal impact on reliability. ReliabilityFirst does not anticipate any significant impact on
reliability from scheduled generating unit or transmission facility outages.

In addition to the NERC TLR procedure, other operating procedures are available to maintain
reliability. These include a multiregional agreement involving balancing authorities around Lake
Erie, to use generation redispatch and phase angle regulator adjustment to mitigate emergency
TLR procedures and curtailments in situations where the affected system(s) is about to curtail
firm demand. Both MISO and PJM will need to continue to use a transmission constrained
economic dispatch.

The output of one power plant in the Washington, DC area is still restricted due to environmental
issues. However, the restriction may be lifted for emergency operating conditions. Recent
transmission enhancements have relieved any local deliverability issues related to this
restriction. No other unusual operating conditions that could impact reliability are foreseen for
this summer.

No unusual operating conditions that could impact reliability are foreseen for this summer.

Reliability Assessment Analysis
The ReliabilityFirst 2008 summer assessment relies on the reserve margin requirements
determined for the PJM and MISO areas. Analyses were conducted by PJM and the Midwest
PRSG at the end of 2007 or early in 2008 to satisfy the ReliabilityFirst Loss of Load Expectation
(LOLE) criterion of not exceeding one occurrence in ten years on an annual basis. These
analyses include demand forecast uncertainty, outage schedules, and other relevant factors when
determining the probability of forced outages exceeding the available margin for contingencies.
The assessment of PJM resource adequacy was based on reserve requirements determined from
their analysis. To assess MISO resource adequacy, RFC calculated a combined reserve target
based on the reserve requirement for demand in the Midwest PRSG, the remaining MRO area of
MISO that uses the MAPP reserve requirement, and a small amount of other MISO demand that
uses a MISO default reserve requirement. This RFC calculated reserve target may be different
than the MISO calculated reserve requirement, based on provisions in the Energy Markets Tariff.


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Therefore, the assessment for the entire ReliabilityFirst regional area is derived from the results
of the PJM and MISO assessments. It is not meaningful to try and calculate a specific reserve
margin requirement for all of RFC since each RTO has slightly different demand characteristics,
capacity resource availabilities and calculated reserve requirements. However, since PJM and
MISO each operate as single entities, it follows that when each RTO has adequate resources
based on satisfying their respective reserve requirements, then the RFC reserves can be
considered to be adequate.

It is important to note that the capacity resources identified as “certain” in this assessment have
been pre-certified by either PJM or MISO as able to be used within their RTO market area. This
means that these resources are considered to be fully deliverable within and recallable by their
respective markets. Both PJM and MISO only include in the certain category those generator
resources determined to satisfy their respective deliverability requirements. In both RTOs, there
are additional resources identified as uncertain that may be available to serve load.

PJM RESERVE MARGINS
The reserve margin requirement for all of PJM is 15.0%. This was determined from a study
performed by the PJM planning department, and approved by the PJM Board of Managers. Study
criteria used in the evaluation can be found in the PJM Planning Manual M-20, “PJM Resource
Adequacy Analysis”.

The 15.0% reserve margin requirement in this assessment is based on NID and Net Capacity
Resources. The reserve margin for the PJM RTO is 21.8% of the NID, which is 29,200 MW and
is greater than the reserve requirement of 15.0%, which is 20,100 MW.

MISO RESERVE MARGINS
Under the current Resource Adequacy section of the MISO’s Energy Markets Tariff (Module E),
reserve margins are established by the States and NERC Regional Entities. There are two groups
within the MISO that have established reserve requirements consistent with the Regional Entity
standards.

The Midwest PRSG (MPRSG) has approved planning reserve requirements for three zones
(East, Central, West) within the MISO Market Footprint.69 MAPP also has an approved planning
reserve requirement for MRO regional demand within the MISO market. A 12% default
requirement is applicable to the small amount of demand not included in MAPP or the MPRSG.
RFC used these applicable reserve margins in the Midwest ISO for the 2008 planning year to
calculate a reserve target for MISO in this assessment of 15,900 MW or a 14.1% reserve margin.

The reserve margin target in this assessment is based on NID and Net Capacity Resources. The
projected reserve margin for MISO is 21.6% of the NID (21,600 MW). Therefore, the reserves
are adequate within the Midwest ISO since the available reserves are greater than the target of
15,900 MW.




69
     www.midwestmarket.org/page/Regulatory+and+Economic+Standards

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RFC RESERVE MARGINS
The reserve margin for ReliabilityFirst is 35,700 MW, which is 20.1% based on NID and Net
Capacity Resources. PJM and MISO each have sufficient resources to satisfy their respective
reserve margin requirements. Therefore, the 20.1% calculated reserve margin this summer in the
ReliabilityFirst region is adequate. This compares to a 20.7% reserve margin in last year’s
assessment. While it is not essential for either PJM or MISO to have access to external resources
to satisfy this summer’s reserve requirements, both RTOs use resources that are not within the
ReliabilityFirst boundary.

RESERVE MARGIN SENSITIVITY
For the summer of 2008, a higher demand forecast was used to prepare a reserve margin
sensitivity for extreme weather across the ReliabilityFirst region. This high demand forecast was
developed by combining the 90/10 demand forecasts of PJM and MISO with the OVEC demand
and applying a coincidence factor. This is not a true 90/10 demand forecast for the
ReliabilityFirst regional area. However, it is being used to evaluate sensitivity to extreme
weather. This forecast amounts to a potential demand increase of about 8,700 MW in July under
this weather scenario. On an NID basis, the reserve margin would be 27,000 MW or 14.5%.

This illustrates that high demand due to extreme weather can significantly reduce the reserve
margin available (from 20.1% to 14.5%) to cover potential generator outages. As load increases
due to the weather conditions, system operators closely monitor the available generator status
and attempt to maintain reserves above the minimum by purchasing additional power from the
Interconnection. Curtailment of the interruptible and other DSM program loads would precede a
public appeal for conservation and any alerts and warnings that would be issued as reserves
become lower. Such procedures are designed to minimize the potential for curtailing firm load.
However, a high level of generator outages coupled with high loads from extreme weather and a
lack of additional power available from the Interconnection could result in the curtailment of
firm demand. Such a curtailment is considered to be a low probability event for this summer.

There are two automatic under voltage load shed (UVLS) schemes within RFC. One is located in
the northern Ohio/western Pennsylvania area and the other is in the northern Illinois area. These
schemes have the capability to automatically shed a combined total of about 2,300 MW and
provide an effective method to prevent uncontrolled loss-of-load following extreme outages in
those areas.

ReliabilityFirst is not aware of any coordinated activities with the fuel supply or delivery
industries by the RTOs or other groups within the region. Fuel supply and delivery is the
responsibility of the generation owner/operator.

Through regional and interregional transmission transfer capability analyses, ReliabilityFirst has
not identified any dynamic or static reactive power-limited areas. ReliabilityFirst also does not
currently have regional criteria for dynamic reactive reserves or margins, voltage dip, or stability
margin; as each individual transmission owner or RTO would develop their own. Voltage
stability margin is not a foreseen concern for this summer.

PJM performs voltage stability analysis (including voltage drop) as part of all planning studies
and also as part of a periodic (every five minutes) analysis performed by the EMS. Results are

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translated into thermal interface limits for operators to monitor. Transient stability studies are
performed as needed and are part of the Regional Transmission Expansion Plan (RTEP) analysis
(see http://www.pjm.com/planning/rtep-baseline-reports/baseline-report.html).         Small signal
analysis is performed as part of long-term studies, but not for seasonal assessments.

ReliabilityFirst actively participated in all three of the Eastern Interconnection Reliability
Assessment Group (ERAG) interregional seasonal transmission assessment efforts and also
conducted      its    own      transfer     capability   analyses     and     assessment      (see
http://www.rfirst.org/Reliability/ReliabilityHome.aspx). Transfer capability results are included
in each of the regional and interregional seasonal reports. ReliabilityFirst regional analyses do
recognize facility constraints external to its boundary. ReliabilityFirst members also conduct
their own seasonal assessments. Simultaneous import capabilities are projected to be adequate
for this summer.

Region Description
ReliabilityFirst currently consists of 44 Regular Members, 21 Associate Members, and 4 Adjunct
Members operating within 12 NERC balancing authorities, which includes over 360 owners,
users, and operators of the bulk-power system. They serve the electrical requirements of more
than 72 million people in an 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 ReliabilityFirst area
demand is primarily summer peaking. Additional details are available on the ReliabilityFirst
website (http://www.rfirst.org).




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SERC
2008 Projected Peak Demand                      MW
                                                                                     Relative Capacity by Fuel Mix
  Total Internal Demand                         203,320
    Direct Control Load Management                  958                                                      Dual Fuel
    Contractually Interruptible (Curtailable)     4,977                                                        15%

    Critical Peak-Pricing with Control              221
    Load as a Capacity Resource                     125
  Net Internal Demand                           197,040
                                                                       Coal 39%

                                                MW      Change                                                           Gas 18%
2007 Actual Summer Peak Demand                  209,108   -5.8%
All-Time Summer Peak Demand                     209,108   -5.8%
                                                                                                                          Oil 2%

2008 Projected Capacity                         MW      Margin                                                           Other 0.3%
  Existing Certain and Net Firm Transactions    236,328   16.6%                                                       Pumped
  Net Capacity Resources                        237,006   16.9%                   Hydro 6%                           Storage 4%
                                                                                                     Nuclear 16%
  Total Potential Resources                     238,335   17.3%



Introduction
The SERC Reliability Corporation (SERC) is the Regional
Reliability Organization for all or portions of 16 central
and southeastern states. SERC is divided into five sub-
regions: Central, Delta, Gateway, Southeastern, and
VACAR, that together supply power to approximately 23%
of the electric customers in the United States. Most electric
utilities within SERC have traditional vertically integrated
corporate structures with planning philosophies based on
an obligation to serve ensuring that designated generation
operates under optimal economic dispatch to serve local area customers. A few SERC members,
however, have selected or 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 or a Regional Transmission Organization that manages
transmission flows to customers over a broader regional area through congestion-based
locational marginal pricing. Companies within SERC are closely interconnected and the region
has operated with high reliability for many years.

It should be noted that the generation capacity figures provided here are based generally on the
data submitted for the current EIA 411 report. SERC collects generation data for the upcoming
season from its members in addition to the collection of data in accordance with NERC’s
prescribed definitions. This data identifies on generation which is constructed, but not
necessarily dedicated or committed to serving load. Such generation performs a merchant
function, operating when it is economic to do so. Therefore, even though a significant amount of
merchant generation has been developed within SERC in recent years, not all of that generation
is reflected in the capacity margins calculated by NERC. It is estimated that there is over 28,000
MW of such generation in the SERC region in addition to what is reported in the EIA 411 report.

Some companies wait to finalize some of their arrangements until close to the peak season,
knowing that adequate capacity will be available. Another factor that should be recognized is an
expansion of efforts in efficiency and demand side management (DSM) programs. Sub-regions

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in SERC, for example Central, are committing to very aggressive programs that provide, in
addition to consumer benefits, further means to reduce or curtail demand when needed to ensure
reliability. Thus the region members anticipate no difficulties in meeting their respective goals
for capacity margin during the 2008 summer peak.

SERC members invested approximately $1.161 billion in transmission system upgrades 100 kV
and above in 2007 and plan to invest approximately $1.478 billion in 2008 and $1.681 billion in
2009.

Demand
The SERC total internal demand for the 2008 summer is forecast to be 203,320 MW which is
5,788 MW (2.8%) lower than the all-time peak of 209,108 MW that occurred in August 2007,
but is 2,666 MW (1.3%) higher than the forecast 2007 summer peak of 200,654 MW. This
projection is based on average historical summer weather. There were no significant changes in
weather and economic assumptions since last year except for considerations related to the
southeast drought which have been incorporated into the operational planning for the upcoming
season. However, small adjustments are made to better match current economic and weather
outlooks.

The SERC region has significant demand response programs. These programs allow demand to
be reduced or curtailed when needed to maintain reliability. 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 demand-side management
capabilities for 2008 summer are 7,040 MW as compared with the 5,702 MW reported last
summer. Traditional demand response programs include monetary incentives to reduce demand
during peak periods. Some examples are real time pricing programs and voluntary curtailment
riders.

Temperatures that are higher or lower than normal and the degree to which interruptible demand
and demand-side management is used, result in actual peak demands that vary from the forecast.
Although SERC does not perform extreme weather or load sensitivity analyses at the region
level, SERC members consider these issues. These member methodologies are documented and
subject to audit by SERC.

While member methodologies vary, many commonalities exist. Common considerations
include:

•   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 utilizing these forecasts

In addition, many SERC members use sophisticated, industry accepted methodologies to
evaluate load sensitivities in the development of load forecasts


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Regarding the influence of weather, the 90th percentile peak temperature relates to an extreme
weather peak of about 6% higher than the regular forecast for the region. An extreme peak for
2008 summer equates to 215,520 MW of peak demand for the region. The capacity margin for
this scenario is estimated to be over 9.5%, which, although reduced from the expected margin
under normal forecast conditions remains at an adequate level for the extreme case condition.
This analysis assumes the load response to temperatures in this extreme range is linear.
However, historical evidence indicates that at some point saturation occurs as temperatures rise,
so the capacity margin is likely to be better even under this extreme case. The SERC region as a
whole is not expected to have any difficulty serving customers in a 90/10 outcome relative to the
load forecast.

Generation
SERC members report 237,966 MW of Existing-Certain generating capability in the region for
2008 summer. This generation alone exceeds the forecast summer total peak demand by 33,686
MW and does not include the un-contracted merchant generation connected to the SERC
member systems.

SERC has had significant merchant generation development. SERC member responses to the
annual SERC Reliability Review Subcommittee’s Generation Development Survey indicate in
excess of 28,000 MW of un-contracted merchant generation is connected to the member systems.
This merchant generation has not been contracted to serve load within SERC and its
deliverability is not assured. For these reasons, only merchant generation expected to serve
SERC load is included in the capacity margins reported for SERC. However, 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 are deliverable during certain system
conditions.

Purchases and Sales
Planned firm purchases across the SERC electrical borders total 1,548 MW and are comprised of
908 MW from RFC and 640 MW from SPP. These firm purchases have been included in the
capacity margin calculations for the region.

Planned firm sales across the SERC electrical borders total 3,186 MW and are comprised of
1,551 MW to FRCC, 1,247 MW to RFC, 13 MW to MRO, and 375 MW to SPP. These firm
sales have been accounted for in the capacity margin calculations for the region.

Fuel
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 SERC members to reduce risks due to fuel supply
problems. SERC entities with large amounts of gas-fired generation connected to their systems
have conducted electric-gas interdependency studies. In-depth studies have simulated pipeline
outages for near and long-term study periods as well as both summer and winter forecast peak
conditions. Also included, for each of the major pipelines serving the service territory, is an
analysis of the expected sequence of events for the pipeline contingency, replacing the lost
generation capacity, and assessment of electrical transmission system adequacy under the
resulting conditions. Other SERC entities with less dependence on gas generation have mapped
generators to their respective pipelines from which they are served. Dual fuel units are tested

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and back-up fuel supplies are maintained and positioned to ensure immediate availability. Some
generating units have made provisions to switch between two separate natural gas pipeline
systems, reducing the dependence on any single interstate pipeline.

Current projections indicate that the fuel supply infrastructure and fuel inventories for the
summer period are adequate even considering unexpected extreme conditions. New international
gas supplies are continuing to enter the U.S. market. While fuel deliverability problems are
possible for limited periods of time due to weather extremes, assessments indicate that this
should not have a significant negative impact on reliability. The immediate impact will likely be
economic as some production is shifted to other fuels. Secondary impacts could involve
increased deliveries from alternate fuel suppliers and impacts to emission levels.

SERC members recognize that planning for variability in resource availability is necessary.
Many SERC members typically provide for this variability through capacity margins, demand
side management programs, fuel inventories, diversified fuel mix and sources, and transfer
capabilities. Some SERC members participate in Reserve Sharing Groups (RSG). In addition,
emergency energy contracts are used within the region and with neighboring systems to enhance
recovery from unplanned outages. Emergency sales and purchases and activation of shared
reserves have been used in the region during the past year. However, the frequency of their use
has not increased relative to previous years.

Transmission
The SERC region has extensive transmission interconnections between its sub-regions. 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 134 miles of 161 kV, 230 kV, 345 kV, and 500 kV transmission lines and several
station reliability improvement projects were completed from Fall 2007 to Spring 2008 with
approximately 228 more miles of 161 kV, 230 kV, 345 kV, and 500 kV additions scheduled for
completion prior to or during the 2008 summer season. SERC members spent approximately
$1.161 billion in new transmission lines and system upgrades (includes transmission lines 100
kV and above and transmission substations with a low-side voltage of 100 kV and above) in
2007 and plan to spend approximately $1.478 billion in 2008 and $1.681 billion in 2009.

Coordinated interregional Eastern Interconnection Reliability Assessment Group (ERAG)
transmission reliability and transfer capability studies for the 2008 summer season were
conducted involving all the SERC sub-regions and neighboring regions. These studies indicate
that the bulk transmission systems within SERC and between adjoining regions generally can be
expected to provide adequate and reliable service over a range of system operating conditions.
No significant limits to transfers were identified except for the Delta-SPP interface which is
discussed later in the Delta subregional report.

Operational Issues – Special Drought Assessment
All sub-regions of SERC experienced drought effects during 2007. This provided a valuable
basis for evaluation of 2008 conditions. SERC conducted a special assessment including an
extreme hydrological scenario more severe in terms of water availability to forecast 2008


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summer conditions. Based on the assessment, if the drought continues through 2008, the
hydrological conditions leading into 2009 could be more severe. However, at the present time
hydrological conditions in 2008 are improving in many areas.

No sub-region identified significant concerns that might threaten reliability for summer 2008. At
most, some redispatch, modest increases in imports, or operating guidelines will be required.
Individual Transmission Planners and Planning Coordinators are continuing drought
preparedness initiatives already underway and operational representatives continue to provide
opportunities for coordination and sharing of system conditions.

Environmental restrictions are not expected to significantly impact operations. No major
generator outages are planned for the summer that could impact reliability. With the exception
of dams being repaired, hydro reservoirs are mostly at normal levels as the drought conditions
have improved. Current projections are for normal rainfall this summer, although in some areas
rainfall to date has been below normal. Reservoir levels are expected to be sufficient to meet
forecast peak demands and daily energy demands for the summer period. Several hydro
facilities in the region are continuing major rehabilitation such as rewinding of generators,
turbine replacements, switchyard work, and dam repairs, but the outages are being coordinated
so reliability and contractual commitments will not be impacted.

Reliability Assessment Analysis
Capacity resources in SERC are expected to be able to supply the projected firm summer
demand with adequate margin. Although SERC does not specify a regional capacity margin
requirement, members adhere to their respective state commission regulations, RTO
requirements and/or internal business practices as applicable. The projected 2008 summer
capacity margin for SERC is 16.9%, which is higher than last year’s projected capacity margin
of 13.9% although on a significantly different definition basis for generation classification.

While there are no common sub-region wide criteria to address transient dynamics, voltage and
small signal stability issues, some members have noted that they adhere to voltage schedules and
voltage stability margins. In addition to static reactive compensation, some members employ
dynamic 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 electric system cascading events.


Sub-regional Details
This section of the report describes highlights of reliability issues in each SERC sub-region.
While details are not provided here, companies throughout the region work closely with each
other, with NERC, inter-regionally through the ERAG, and other associations, to ensure
continued reliability. In general the SERC sub-regions have negligible amounts of renewables
(except for hydro resources) with many sub-regions reporting zero for the renewable categories.

Central
Demand - Projected total internal demand for the 2008 summer season is 43,866 MW based on
normal weather conditions. This is 720 MW (1.7%) higher than the forecast 2007 summer peak
demand of 43,146 MW. The projected total internal demand for 2008 is 921 MW (2.1%) lower
than the actual 2007 summer peak of 44,787 MW, which was higher than expected due to higher

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temperatures. The 2008 summer demand forecast is based on normal weather conditions and
economic data from population, employment, energy sales, and gross regional product increases.
To assess variability, some members within the sub-region use forecasts assuming normal
weather, and then develop models for milder and more extreme weather to create optimistic and
pessimistic scenarios. Others within the sub-region use historical peaks, and demand models to
predict variance.

The sub-region has a mix of various demand response programs including interruptible demand,
new energy efficiency programs, customer curtailing programs, and direct load management
including an air conditioner control program.

Generation - Members in the Central sub-region reported approximately 49,582 MW of existing
certain resources and zero MW of existing uncertain resources available during June 1 through
September 30, 2008. Capacity expected on peak includes approximately 4,961 MW of hydro,
560 kW of solar and 15 MW of biomass. As noted below, additional firm capacity will be in
place to ensure normal margins for the peak.

The sub-region experienced a severe drought through 2007 which is expected to continue into
2008, and some members have seen a reduction in their power supply from Southeastern Power
Administration due to repair work on the Wolf Creek Dam which is likely to continue for several
more years. Hydro operations are constantly monitored and evaluated for potential changes and
mitigation plans are formed to minimize any threats to reliability. While the continuing drought
and dam repairs will affect hydro energy and capacity and cause some thermal de-rating no
problems are foreseen in meeting normal margins and maintaining normal reliability.

If unexpected capacity shortages occur, multi-step mitigation plans such as firm replacement
contracts, alternative fuel generation, voluntary curtailment, and out of schedule dispatching are
used as necessary.

Purchases and Sales - Firm Sales of 66 MW are external to the Region and 143 MW are
external to the sub-region. Firm Purchases of 266 MW are external to the Region.

The majority of these sales/purchases are backed by firm contracts and very few are associated
with liquidated damages contracts (LDC). The firm purchases and sales have been included in
the capacity margin for the sub-region.

Fuel - Fuel vulnerability is not considered to be a concern. Central sub-region members have a
highly diverse mix of suppliers, transportation, supply contracts, on-site storage and fuel
alternatives to supply generation. Coal is responsible for over 50% of generation in the sub-
region and coal stocks and transportation systems are considered strong. While gas supplies
have been disrupted in the past by hurricanes, this would affect only a small percentage of
generation.

Operational Issues - No major generating unit outages, generation additions,
environmental/regulatory restrictions or temporary operating measures are expected to affect the
reliability of the Central sub-region this summer.


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Transmission - Members within the sub-region reported several 161 kV, 345 kV and 500 kV
transmission line and substation projects including a new Davies County 345 kV interconnection
between Big Rivers and E.ON U.S. and TVA’s 500 kV Cumberland-Montgomery line, are
expected to be in-service for the upcoming season.

Resource Assessment Analysis - Projected summer peak capacity margin in the sub-region as
reported in January 2008 was 17.0% compared to 13.4% at the same time last year. However, as
a consequence of the continuing drought effects, the schedule to finalize firm resource contracts
for the summer has been extended to the end of April, but plans are in place to ensure firm
resources with at least a 15% capacity margin for the summer peak.

Resource adequacy analyses are performed on a regular basis, and no significant changes have
been reported from last year. Some members use reserve margins, resource and supplier
contracts as criteria to ensure resources are adequate to meet demand. Members also use
planning studies to ensure generation deliverability. Studies are coordinated with neighboring
systems to incorporate imports and unit outages.

Members within the sub-region rely on quarterly OASIS studies. For example the SERC Near
Term Study Group assesses transfer capability issues.

Studies show that Western Kentucky and Southern Indiana continue to experience transmission
constraints that limit regional power transactions; and. north-to-south power transfers through the
state of Kentucky introduce loading concerns due to parallel flows in several transmission
facilities within the northern Central sub-region and neighboring control areas. Transmission
Loading Relief procedures are expected to be used this summer. No other constraints to the bulk
electric system for the 2008 summer season has been identified that could impact reliability.

Companies within the sub-region maintain individual criteria to address any problems with
stability issues. UVLS systems have been installed to prevent voltage collapse at Philadelphia,
Miss., and Knoxville, Tenn. All other systems are expected to be secure with no anticipated
stability issues.

Delta
Demand - Total internal demand for the 2008 summer season is forecast to be 28,440 MW based
on normal weather conditions. This forecast is 710 MW (2.6%) higher than the forecast 2007
summer peak demand of 27,730 MW and is 666 MW (2.3%) lower than the actual 2007 summer
peak demand of 29,106 MW. Uncertainty and variability is assessed through load scenario
development, based on historical temperature probabilities. Peak load scenarios are also
performed to assess conditions due to extreme weather found in historical records.

While certain parts of the sub-region are expecting increases in demand due to load growth, the
overall decrease between the actual 2007 summer peak demand and forecasted 2008 summer
peak demand is primarily due to Entergy experiencing a 2007 summer peak that occurred when
Entergy’s system above average temperature was 101°F. The 2008 forecast assumes a 10-year
system average temperature of 96°F.




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Members within the Delta sub-region reported that they have a mix of demand response
programs which consists of interruptible load programs for larger customers and a range of
conservation/load management programs for all customer segments.

Generation - Companies within the sub-region expect to have approximately 31,569 MW of
Existing-Certain resources and 389 MW of existing uncertain resources available during June 1
through September 30, 2008. Approximately 79 MW of this generation is hydro expected on
peak during this time period. Hydro conditions for the summer 2008 are expected to be normal
based on current reservoir levels and anticipated rainfall. The sub-region expects no significant
changes or assumptions and expects to have adequate capacity to meet peak demand.

Purchases and Sales - Sales of 600 MW are external to the region and 1,145 MW is external to
the sub-region. Purchases of 541 MW are external to the region and a max of 1,404 MW is
external to the sub-region. These firm purchases and sales have been accounted for in the
capacity margin calculations for the sub-region. Overall, the sub-region is not dependent on
outside purchases, transfers, or contracts to meet the demands of its load.

Fuel - Delta sub-regional members reported that they purchase a significant amount of fuel in
short-term markets. The entities ensure that they are in constant communication with pipelines,
storage facilities and suppliers in the region resulting in continuous up-to-date knowledge of
supply and transportation issues. Agreements have been set in place to purchase supply,
transportation, balancing, flexibility and peaking services to serve anticipated generation needs.

Delta sub-regional members reported that fuel supplies and infrastructure are more than adequate
for summer peak demands. Members also 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, natural gas at a company-owned natural gas storage facility,
and short-term purchases of firm natural gas. This mix of resources provides diversity of fuel
supply and minimizes the likelihood and impact of potentially problematic issues on system
reliability. Other measures include aggressive maintenance of coal delivery infrastructure.

Resources - Projected capacity margin in the sub-region is 11.6% as compared to 13.9% last
year. This decrease is primarily due to some generation previously reported as certain now being
reported as uncertain. Because of the large amount of non-firm generation available within Delta
sub-region, primarily within the Entergy System, additional resources could be procured in the
short-term to meet any expected shortfalls in generation capacity. New combined cycle and
wind generation, totaling about 580 MW are expected online for 2008 summer to serve sub-
region load. The Delta sub-region has over 4,000 MW of firm purchases scheduled for 2008
summer. However, the resources are primarily from merchant generation located within the sub-
region with only about 2,000 MW of that coming from outside the sub-region. Capacity in the
sub-region should be adequate to supply forecast demand.

Operational Issues - No reliability concerns are anticipated for the upcoming peak season.
There are no major generating unit outages or transmission facility outages planned which would
impact bulk system reliability for the 2008 summer season. There are also no local


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environmental, regulatory restrictions or unusual operating conditions expected that might
impact reliability.

Transmission - Several transmission projects to increase system reliability are scheduled for
completion prior to or during summer 2008 in the Delta sub-region. New transmission lines
Gobbler Knob-Cox Creek 161 kV, Brookline-Springfield 161 kV, and a new 345/161 kV
transformer have all been reported to be available for the summer of 2008 on the Associated
Energy Cooperative, Inc. system.

Other recently completed transmission projects on the Entergy System include construction of
the Sterlington-Perryville 500 kV transmission line (May 2007), the Yandell Road-Bozeman 230
kV transmission line (September 2007), and the Hammond-Amite 230 kV transmission line
(December 2007).

The preliminary results from the ERAG sponsored 2008 Summer MRO-RFC-SERC West-SPP
inter-regional study indicate potential transmission transfer issues between the Delta sub-region
and some neighboring regions involved in the study. The areas of interest from this preliminary
study indicate that the First Contingency Incremental Transfer Capability (FCITC) from the
Delta sub-region to some neighboring interfaces, including SPP and MRO, as “zero”. These
transfers are primarily limited by 161 kV transmission facilities on the Entergy-SPP interface for
the outage of the ANO-Ft. Smith 500 kV line, which is a tie line between Entergy and OG&E.
Previous reliability studies indicate that power flows on these 161 kV transmission lines are
extremely sensitive to Entergy and SPP generation dispatch in the local area, as well as
transactions modeled across Entergy’s northern interface. While Entergy and other SPP
members have committed to upgrading one of these interface constraints (i.e., Danville-
Magazine 161 kV line), Entergy is also evaluating other long-term transmission solutions for this
limit. However, Entergy does not expect any reliability concerns for the upcoming summer.

Reliability Assessment Analysis - As noted above, Delta sub-regional members projected an
11.6% capacity margin in the sub-region as compared to 13.9% last year. Even though there is a
slight decrease in margins predicted for the upcoming season as compared to last year’s margins,
capacity should be adequate to meet demand for the upcoming summer season. While the sub-
region’s generation capacity is adequate for supplying its load, it also has access to reserve
sharing programs, fuel diversification, fuel policy contracts and other firm resource network
contracts and power agreements to ensure supply in times of catastrophic events. Several
analyses (Loss-of-Load Expectation, etc.), coordinated with neighboring regions and other SERC
sub-regions, indicate that transmission transfer capability will be adequate on all interfaces this
summer to support reliable operations. From the results of these analyses, no bulk electric
system constraints are expected that would need to be addressed. Studies have been performed
to assess transient dynamics, voltage and small signal stability issues for summer conditions in
the near-term planning horizons as required by NERC Reliability Standards. For certain areas of
the sub-region, the 2009 assessment from the study was chosen as a proxy for the near-term
evaluation. No critical impacts to the bulk electric power system were identified. While there
are no common sub-region wide criteria to address transient dynamics, voltage and small signal
stability issues, some members have noted that it adheres to voltage schedules and voltage
stability margins. In addition, some members employ static var compensation devices to provide
reactive power support and voltage stability. Under-voltage load-shedding (UVLS) programs are

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also used to maintain voltage stability and protect against bulk electric system cascading events.
It was reported that the maximum load that can be shed by the UVLS program is approximately
300 MW.

Gateway
Demand - Total internal demand for the 2008 summer season is forecast to be 19,233 MW based
on normal weather conditions. This is 349 MW (1.8%) lower than the actual 2007 summer peak
demand of 19,582 MW, but is 249 MW (1.3%) higher than the forecast 2007 summer peak
demand of 18,984 MW. The increase in forecast load compared to 2007 summer is due to
normal load growth. The decrease in forecast load compared to the 2007 actual peak is because
the forecast is based on normal load and temperature patterns. The 2007 summer peak load was
caused by hotter than normal temperatures. In order to assess the uncertainty and variability in
projected demand some members within the sub-region use regression models, multiple forecast
scenario models, and econometric models. Economic assumptions and historical temperature
and weather pattern information are considered individually by each sub-region member. The
sub-region has only 128 MW of direct control load management or contractual interruptible load.

Generation - Companies within the Gateway sub-region expect to have approximately 23,979
MW of existing certain and 875 MW of uncertain existing resources during June 1 through
September 30, 2008. The sub-region has 368 MW of hydro expected to be on peak during this
time period. The generation resources to serve these retail loads are predominantly located
within the Gateway sub-region for this summer. Hydro conditions within the sub-region are
expected to be normal for the upcoming season, but represent less than 2% of the total capacity
in the sub-region. Cooling water reservoirs are expected to be adequate and return to their full
pool levels due to heavy precipitation in 2008.

Purchases and Sales - Firm Sales - 869 MW are external to the region. Firm Purchases - 136
MW are external to the region 250 MW is external to the sub-region. These firm purchases and
sales have been accounted for in the capacity margin calculations for the sub-region. Overall,
the sub-region is not dependent on outside purchases or transfers to meet the demands of its load.

Fuel - Gateway sub-region members reported various fuel policies and some members have
reevaluated fuel inventories as a result of fuel delivery issues. Some members have developed
Integrated Resource Plans to help ensure fuel reliability within the sub-region. These 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.

Resources - Projected capacity margin in the Gateway sub-region is 18.7% as compared to
24.3% last year.

Operational Issues - No reliability problems are anticipated on the transmission systems of the
Gateway sub-region members for this summer. The City of Springfield-CWLP reported that its
Dallman generator unit 1, which experienced an explosion last year that compromised 86 MW,
will not be available this upcoming summer season. Several members within this sub-region
have noted that there are limitations with emissions stipulations, thermal discharge or lake
temperature limitations that can have an impact on peak energy needs. Many of these issues

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would be alleviated with the above normal precipitation received in late 2007 and early 2008.
These limitations or any unusual operating conditions are not expected to have a major impact on
reliability. The Taum Sauk pumped storage facility in the AmerenUE control area remains
unavailable but this is not a reliability concern as adequate resources are available in the sub-
region. The Taum Sauk plant is expected to return to service in late 2009.

Transmission - An eleven-mile 345 kV line between the Loose Creek switching station and the
Mariosa Delta 345/161 kV substation in central Missouri should be completed by AmerenUE for
the summer 2008. All transmission owners reported that they are steadily making capacity
improvements to upgrade and enhance the bulk electric power system in the sub-region.

Reliability Assessment Analysis - The projected capacity margin in the Gateway sub-region is
18.7% as compared to 24.3% last year. The decline can be attributed to data reporting at a time
when not all resources were identified to serve the Illinois load for 2008 summer. Based on past
experience it is expected that by summer, adequate resources and reserves could be secured from
the market to reliably supply the load in the Gateway sub-region.

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.
Deliverability testing studies are performed on an ongoing basis throughout the sub-region to
ensure that transmission capacity is sufficient to make the generation deliverable. No concerns
for deliverability have been reported for the upcoming year. No significant issues within the
Gateway sub-region have been identified. Transmission constraints within the sub-region are
minimal and are not expected to impact reliability. Sub-regional studies involving power flow,
short-circuit, and stability analyses are not performed on a regular basis involving the entire sub-
region, but joint studies are performed by the members as needed to address sub-regional needs.

Southeastern
Demand - Total internal demand for the 2008 summer season is forecast to be 50,122 MW based
on normal weather conditions. This is 598 MW (1.2%) higher than the forecast 2007 summer
peak demand of 49,524 MW and 772 MW (1.5%) lower than the actual 2007 summer peak
demand of 50,894 MW. The 2007 summer was much hotter than normal and so demand was
higher than anticipated. The 2008 summer demand forecast is based on normal weather
conditions and uses normal/median weather, normal load growth and conservative economic
scenarios. The sub-region has a mix of various demand response programs including
interruptible demand, customer curtailing programs, direct load control (irrigation, A/C and
water heater controls) and distributed generation to reduce the effects of summer peaks. To
assess variability, some sub-region members develop forecasts using econometric analysis based
on approximately 30 year (normal, extreme and mild) weather, economics and demographics.
Others within the sub-region use the analysis of historical peaks, reserve margins and demand
models to predict variance.

Generation - Companies within the Southeastern sub-region expect to have approximately
59,517 MW of Existing-Certain resources and over 5600 MW of uncommitted resources
available during June 1 through September 30, 2008. Approximately 4,058 MW of this is hydro
generation. Various areas within the sub-region are experiencing drought conditions, but these
conditions have improved considerably with January - March rainfall and are not predicted to

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affect reliability. Reservoirs and reserve margins are expected to be sufficient in 2008.
Mitigation plans such as firm replacement contracts, alternative fuel generation, and dispatching
operations are available if necessary.

Purchases and Sales - Firm Sales - 1,551 MW are external to the Region and max 986 MW is
external to the sub-region. Firm Purchases - None are external to the Region and 408 MW are
external to the sub-region. The majority of these sales/purchases are backed by firm contracts,
but none are associated with Liquidated Damages Contracts (LDC). These firm purchases and
sales have been included in the capacity margin calculations for the sub-region. Overall, the sub-
region is not dependent on outside purchases or transfers to meet the demands of its load.

Fuel - Southeastern sub-regional members reported that fuel vulnerability is not an expected
reliability concern for the summer reporting period. The members have a highly diverse fuel mix
to supply its demand, including nuclear, PRB coal, Eastern coal, natural gas and hydro. Some
members have implemented fuel storage and coal conservation programs, and various fuel
policies to address this concern. These tactics help to ensure balance and flexibility to serve
anticipated generation needs.

Resources - Projected capacity margin in the Southeastern sub-region is 16.1% compared to
13.5% last year. In addition to the resources included in the capacity margin calculation, demand
side options are available during peak periods along with large amounts of merchant generation
in the sub-region. Capacity in the sub-region should be adequate to supply forecast demand.
Additionally, the preliminary results of the SERC Summer Reliability Study indicate assistance
can be imported into the Southeastern sub-region during the upcoming summer peak, if needed.
No local deliverability problems are anticipated.

McIntosh unit 1 (110 MW Compressed Air Energy Storage) experienced a forced outage during
summer 2006. It is expected to be unavailable until March 2008. Two 48 MW Combustion
Turbine units at Sowega were made operational in January 2007.

Operational Issues - No reliability problems due to unit outages, additional/temporary operating
measures or environmental regulations are anticipated to negatively affect the transmission
systems of the Southeastern sub-region members this summer. The sub-region routinely
experiences significant loop flows due to transactions external to the sub-region itself. However,
all transmission constraints identified in current operational planning studies for the 2008
summer can be mitigated through generation adjustments, system reconfiguration or system
purchases.

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 Southeastern sub-region than on
loading within. Significant changes in gas pricing dramatically impact dispatch patterns.
Adjustments to total transfer capability will be made as needed based on actual flows. Local
procedures will be used as needed, but no delivery problems are anticipated. Utilizing the TLR
process is not anticipated, but available if necessary.




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Various areas are currently experiencing drought conditions; however recent weather
assessments show that the drought conditions have improved significantly and this trend is
expected to continue throughout spring 2008. The sub-region members participated in the SERC
regional drought assessment which did not identify significant reliability impacts from the
drought. Although hydro generation is predicted to be lower than normal for the upcoming
season, reliability will not be affected due to ready access to other generation sources.

Transmission - Numerous 230 kV and 500 kV additions are scheduled for the Southeastern sub-
region to serve load and address contingency loadings and voltages for the upcoming season. A
new 161 kV interconnection between SMEPA and TVA entered service on July 3, 2007 to
increase reliability in portions of both the Southeastern and Central sub-regions. An existing
SMEPA – Entergy interconnection will be upgraded, doubling its capacity, for summer 2008
operation. Several 230 kV and 500 kV transmission lines additions, re-rates and station
reliability improvement projects are expected to be completed by the 2008 summer season.

Reliability Assessment Analysis - The projected capacity margin in the Southeastern sub-region
is 19.9% compared to 13.5% last year. Resources are expected to come from within the region
and through external resources as well. Capacity in the sub-region should be adequate to supply
forecast demand. There are no significant changes to LOLP, EUE, generation resource models
and other resources adequacy studies that will affect margins. Various tactics are being used to
ensure these resource adequacy measurements are within an acceptable range. Annual
Transmission Transfer Capability, System Impact and Facility studies are performed jointly with
various members within the sub-region to determine external generation deliverability.
Operating guides are developed as necessary to ensure acceptable transfer levels are reached.
Some entities perform annual contingency analysis (studies typically covering up to ten future
years) and biannual stability studies to ensure internal generation deliverability. Current studies
have identified no deliverability concerns expected to impact reliability. The fuel supply
infrastructure, fuel delivery system, and fuel reserves are all adequate to meet peak gas demand.
Various companies within the sub-region have firm transportation, gas storage, firm pipeline
capacity, and on-site fuel oil and coal supplies to meet the peak demand. Transfer capability
studies are routinely performed with neighboring companies both within and outside the SERC
region. No major transmission constraints have been identified for the upcoming season that
would impact existing firm transmission service. The Southeastern sub-region does not have
sub-regional criteria for dynamics, voltage and small signal stability; however, various
companies within the sub-region perform individual studies and maintain individual criteria to
address any stability issues. All systems are expected to be secure for the upcoming season.

VACAR
Demand - Total internal demand for the 2008 summer season is forecast to be 63,130 MW based
on normal weather conditions. This is 799 MW (1. 3%) higher than the forecast 2007 summer
peak demand of 62,331 MW and 1,610 MW (2.5%) lower than the actual 2007 summer peak
demand of 64,740 MW The 2007 actual peak exceeded the forecast because of temperatures
which exceeded the statistically normal values used in the forecast. The 2008 summer demand
forecast is based on averages of the latest 20 to 35 years of historical weather, forecast economic
growth, and regressing demographics against system load. These tools are used to develop
weather variables for forecasting peak demands. Some members reported that the demand
forecast is based on a 50-50 weather projection. The sub-region has a mix of various demand

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response programs including interruptible demand, customer curtailing programs, Standby
Generator Control, Residential Time-of-Use, General Service and Industrial Time-of-Use, and
Hourly Pricing for Incremental Load Interruptible programs to reduce the affects of summer
peaks. To assess variability, some members within the sub-region use forecasts that are
developed using assumptions through economic models, historical weather conditions, energy
consumption and demographics. Others assess variability of forecast demand by accounting for
reserve margins instead.

Generation - Companies within the VACAR sub-region expect to have approximately 72,656 of
existing certain resources and 0 MW of existing uncertain resources available during June 1
through September 30, 2008. Approximately 3,740 MW of this generation is hydro expected on
peak and 225 MW of this generation is biomass expected on peak during this time period.
Members within the sub-region report that it has experienced a drought and is expecting
conditions to continue for the upcoming season. These conditions have caused substantial
constraints on hydro operations. However, coupled with other resources, projected hydro
generation and reservoir levels are expected to be adequate to meet both normal and emergency
energy demands for the 2008 summer. Members within the sub-region are also monitoring
drought conditions through studies to assess the expected severity and its impact on the system.

Purchases and Sales - VACAR sub-regional members reported 100 MW of firm sales external
to the region and 200 MW external to the sub-region. Firm purchases from entities were 605
MW external to the region and 1,149 external to the sub-region. Of these sales/purchases, very
few are associated with Liquidated Damage Contracts (LDC). Outside purchases or transfers of
capacity from other regions or sub-regions are not expected to be relied on to meet emergency
imports and reserve sharing requirements for the upcoming season.

Fuel - Fuel vulnerability is not a concern within this sub-region. The members have a highly
diverse mix of options which consist of on-site storage, transportation alternatives and fuel
contracts to ensure supply to its resources. Other mitigation plans generally involve tiered
strategies that are invoked depending on the severity of the situation. This guidance on
managing fuel in short supply has been formalized in procedures as required by NERC
Reliability Standards. These tactics help to ensure balance and flexibility to serve anticipated
generation needs for the upcoming season.

Resources - Projected capacity margin in the subregion is 17.5%, compared to 13.1% last
summer. Capacity in the subregion should be adequate to supply forecast demand.

Operational Issues - For the upcoming summer season, no major outages, additions, or measures
are anticipated. It was noted that the output of Potomac River generating plant located within
Pepco, a member of ReliabilityFirst Corporation (RFC), in Washington, DC is still restricted
because of environmental concerns. However, Potomac River may be dispatched during
emergency conditions. Other members reported that the minimum flow, fish passage, and 401
water quality requirements may restrict available pooling of water for generation. There are also
concerns of the limitations on generation due to the installation of scrubbers. Even though there
are environmental/regulatory concerns within the sub-region, the members anticipate no
restrictions that could potentially impact reliability for this summer.


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Transmission - Several improvements to transmission facilities within VACAR have been
completed or planned to be completed by the summer of 2008. The Brambleton to Greenway
230 kV line will complete the Brambleton – Beaumade – Pleasant View 230 kV loop and will
address several contingency loading concerns in the Northern Virginia area for the upcoming
season. A number of Bennettsville 230 kV Transmission Lines (TL) and upgrades are expected
to be completed by the summer of 2008 on the Progress Energy Carolinas system. A new 230
kV interconnection with SCPSA at the Bennettsville Substation will be a part of this construction
to Bennettsville, SC. Other 230 kV lines (Cross-Aiken 230 kV TL, Cross-Carnes Crossroads
230 kV TL rating upgrade, and the Cross-Jefferies 230 kV TL rating upgrade) are expected to be
completed by the upcoming season as well.

Reliability Assessment Analysis - The projected capacity margin in the sub-region is 17.5%,
compared to 13.1% last summer. Capacity in the sub-region should be adequate to supply
forecast demand. Members within this sub-region do not have an established target margin level
to benchmark margins. To assess resource adequacy, some members have conducted studies for
the upcoming summer and have determined that LOLP, LOLE and EUE figures are comparable
to those for the previous summer. These studies may include estimates of the impacts of forced
and planned outages on the system operation. Other members use reserve margins to account for
worse-case scenarios with unavailability. However, members have reported that there are no
significant changes from last year’s assessment that will impact reliability. To ensure generation
deliverability, some members use deliverability load test as a requirement for new generation
that will serve load in their system. These tests ensure that all new generation is accessible for
the supply of load. Other members within the sub-region rely on contracts for fuel and
transportation, operating limits and security constraints to ensure their deliverability. Fuel
supplies are expected to be adequate for the upcoming season. Members have a very diverse mix
of suppliers, transportation contracts, fuel switching plants and on-site storage to ensure
adequacy of fuel supply. No fuel supply or delivery issues are expected for this summer.

Members within the VACAR sub-region are involved in studies performed by SERC Study
Groups and interregional reliability assessments conducted under the direction of the ERAG
Management Committee. These studies analyze transfer capability problems and constraints
throughout the sub-region. No constraints to the bulk electric system for the 2008 summer
season has been identified that could impact reliability. The VACAR sub-region does not have a
sub-regional criterion for dynamics, voltage and small signal stability. Various companies
within the sub-region perform individual studies in accordance with NERC Reliability Standards
and maintain individual criterion to address any problems with these stability issues. The sub-
region does not predict any stability issues that will impact 2008 summers season reliability.

Region Description
The SERC Region is a summer peaking region covering all or portions of 16 central and
southeastern states. Owners, operators, and users of the bulk power system in these states cover
an area of approximately 560,000 square miles. The SERC Reliability Corporation (SERC) is the
regional entity for the region and is a nonprofit corporation responsible for promoting and
improving the reliability, adequacy, and critical infrastructure of the bulk power supply system.
SERC membership includes 63 member entities consisting of publicly owned (federal, municipal
and cooperative), investor owned operations. In the SERC Region there are 31 balancing
authorities and over 200 registered entities under the NERC functional model.

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SERC serves as a regional entity with delegated authority from NERC for the purpose of
proposing and enforcing reliability standards within the SERC Region. SERC is divided
geographically into five sub-regions that are identified as Central, Delta, Gateway,
Southeastern, and VACAR. Additional information can be found on the SERC Web site
(www.serc1.org).




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SPP
 2008 Projected Peak Demand                      MW
                                                                                    Relative Capacity by Fuel Mix
   Total Internal Demand                          43,571
     Direct Control Load Management                   36                                             Dual Fuel 6%
     Contractually Interruptible (Curtailable)       487
     Critical Peak-Pricing with Control               35
     Load as a Capacity Resource                     187
   Net Internal Demand                            42,827
                                                                         Coal 39%

                                                 MW      Change
 2007 Actual Summer Peak Demand                   43,165   -0.8%                                                    Gas 40%
 All-Time Summer Peak Demand                      43,165   -0.8%

                                                                       Hydro 4%
 2008 Projected Capacity                         MW      Margin
   Existing Certain and Net Firm Transactions     48,993   12.6%   Nuclear 2%                                         Oil 2%
   Net Capacity Resources                         58,096   26.3%       Pumped
                                                                     Storage 0.7%                                   Undeter-
   Total Potential Resources                      59,379   27.9%                    Wind 0.5%
                                                                                                   Other 1.9%       mined 3%




Introduction
Based on the evaluated contingency events and taking into
consideration transmission operating directives, Southwest
Power Pool is not expecting any reliability issues for the
upcoming summer. The resources available for the region
are adequate to meet the expected peak demand.

Demand
The non-coincident total internal demand forecast for the
upcoming summer peak is 43,571 MW, which is 1% higher than the 2007 actual summer peak
monthly non-coincident total internal demand of 43,167 MW. The actual 2007 summer demand
of 43,165 was 0.4% higher than the 43,007 summer forecasted projection for 2007. Last year,
SPP experienced a slight increase in demand from the normal forecast due to higher temperatures
in the summer and the modest load growth throughout the SPP footprint.

Although actual demand is very dependent upon weather conditions and typically includes
interruptible loads, forecasted net internal demands are based on 10 year average summer
weather, or 50/50 weather. This means that the actual weather on the peak summer day is
expected to have a 50% likelihood of being hotter and a 50% likelihood of being cooler than the
weather assumed in deriving the load forecast. SPP does not anticipate 90/10 weather scenario
this year but has a 12% capacity margin requirement to address this.

Forecast data is collected from individual reporting members as monthly non-coincident values
and then summed up to produce the total forecast for SPP. Each SPP member also provides their
demand response programs and then subtracts those values from their load forecasts to report the
net load forecast. Based on the SPP member inputs, currently 487 MW of interruptible demand,
36 MW of load management, 35 MW of critical peak pricing and 187 MW of load as a capacity
resource are reported.




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Generation
SPP expects to have 58,141 MW of total internal capacity for the upcoming summer season. This
consists of Existing Certain Capacity of 47,754 MW, Existing Uncertain Capacity of 9,271 MW,
and Planned Capacity of 1,116 MW

The expected on peak capacity from the variable generation plant (predominantly wind) is 169
MW. SPP do not have any biomass-fueled generation reported at this time.

The hydro capacity within SPP region represents a small fraction of the total resources
(Approximately 1%). SPP monitors potential fuel supply limitations for hydro and gas resources
by consulting with its generation owning/controlling members at the beginning of each year.
There are no anticipated issues concerning the reservoir levels being sufficient enough to meet
the peak and daily energy demands during the summer season. The SPP region is experiencing
normal rainfall and is not expected to experience drought like conditions during the summer
season that would that would prevent the region from meeting their capacity needs.

Purchases and Sales
SPP has a total of 2,789 MW of projected purchases of which 2,684 MW is firm and 105 MW is
firm delivery service from WECC administered under Xcel Energy’s OATT. None of the
purchase contracts are Liquidated Damage Contracts.

SPP has a total of 1,550 MW of firm sales, and 145 MW of non-firm sales for the 2008 summer
by regions external to SPP. None of the sales contracts are Liquidated Damage Contracts.

SPP members along with some members of the SERC region have formed a Reserve Sharing
Group. The members of this group receive contingency reserve assistance from other SPP
Reserve Sharing Group members. The SPP’s Operating Reliability Working Group will set the
Minimum Daily Contingency Reserve Requirement for the SPP Reserve Sharing Group. The
SPP Reserve Sharing Group will maintain a minimum first Contingency Reserve equal to the
generating capacity of the largest unit scheduled to be on-line.

Fuel
All fuel supplies throughout the summer are expected to be adequate. SPP monitors potential
fuel supply limitations for hydro and gas resources by consulting with its generation
owning/controlling members at the beginning of each year. Predicting and managing the energy
output from intermittent resources like run-of-river hydro and wind farms are more challenging.
Wind resources are not expected to provide a significant portion of the region’s capacity during
the upcoming peak load conditions. Although dispatched to serve during high peak periods,
hydro capacity represents a small fraction of the total resources (Approximately 1% of total MW
sources) in SPP. Regarding adequacy, the coal supply of the Powder River Basin (PRB) is not
considered to be a high-risk issue by SPP members at this time. Natural gas sources are abundant
in the SPP region and are not considered to be at high risk regarding supply adequacy or security.

Transmission
American Electric Power West (AEPW) is scheduled to complete the installation of the new 14-
mile 345 kV line from Chamber Springs to Tontitown expected to be in service in June 2008.


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This will improve reliability in the Northwest Arkansas are by providing an additional EHV
source into the area.

Operational Issues
There are no scheduled maintenance outages of operational concern within the SPP region that
will impact reliability during the summer months. The SPP operations staff does not anticipate
any environmental and/or regulatory restrictions that could potentially impact reliability. As a
result of Flowgate assessment analysis, there are no unusual operating conditions expected for
the upcoming summer months.

Reliability Assessment Analysis
Currently, a SPP criterion requires that its members maintain a minimum capacity margin of
12%, unless their system is primarily hydro-based and then the required minimum capacity
margin is 9%. This is adequate to cover a 90/10 weather scenario. The SPP capacity margin
based on certain resources is expected to be 14.1% for 2008 summer, which is slightly lower
than the 2007 margin of 15.7%. On a total potential resources basis, SPP has sustained around a
26.4% capacity margin

The total amount of external resources that were used by SPP to meet its criteria for the 2007 and
upcoming 2008 summer is 2,789 MW of firm purchases.

SPP is currently performing Loss-of-Load Expectation and Expected Unserved Energy studies.
The preliminary results of these studies are expected in early Summer 2008. Historically, SPP
has adhered to a 12% regional capacity margin to ensure the minimum LOLE of 1 day in 10
years is met. Presently the 12% capacity margin requirement is checked annually in the EIA-411
reporting as well as through supply adequacy audits of regional members. The last supply
adequacy audit was conducted in 2007.

SPP defines firm deliverability as electric power intended to be continuously available to the
buyer even under adverse conditions; i.e., power for which the seller assumes the obligation to
provide capacity (including SPP defined capacity margin) and energy. Such power must meet
standards of reliability and availability as that delivered to native load customers. Power
purchased can be considered to be firm power only if firm transmission service is in place to the
load serving member for delivery of such power. SPP does not include financial firm contracts
towards this category

There are no significant deliverability problems expected due to transmission limitation at this
time, SPP will continue to closely monitor the issue of deliverability through the Flowgate
assessment analysis in the Spring 2008 and address any reliability constraints. This analysis
validates the list of flowgates that SPP monitors on a short term basis using various scenario
models developed by the SPP Staff. These scenario models reflect all the potential transactions
in various directions being requested on SPP system. The results of this study are reviewed and
approved by SPP’s Transmission Working Group prior to summer. Although this study is not
completed yet, SPP is not expecting significant constraints in the upcoming summer operating
conditions.




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Due to the diverse generation portfolio in SPP, there is no concern of the fuel supply being
affected by the extremes of summer weather during peak conditions. If there is to be a fuel
shortage, it is communicated to SPP operations staff, in advance, so that they can take the
appropriate measures SPP would assess if capacity or reserves would become insufficient due to
the unavailable generation. If so, we would declare either EEA (Energy Emergency Alert) or
OEC (Other Extreme Contingency) and post as needed on the RCIS (Reliability Coordinator
Information System).

As a part of the interregional transmission transfer capability study, SPP participates in the
ERAG seasonal study group (MRO-RFC-SERC West and SPP) which produces an upcoming
summer, and winter operating condition transfer limitation forecast. Simultaneous transfers are
also performed as part of this study. The preliminary results of this study will be available in late
spring.

SPP develops an annual SPP Transmission Expansion Plan (STEP) with regional group of
projects to address system reliability needs for the next 10 years (2008 through 2017). The latest
STEP that was approved by SPP Board Of Directors is available on SPP website70. During the
STEP process, SPP also performs a dynamic stability analysis. The latest dynamic study that
was completed for the 2008 operating conditions did not indicate any dynamic stability issues for
the SPP region. In addition, SPP also performs an annual review of reactive reserve
requirements for load pockets within the region. Currently, SPP does not have specific criteria
for maintaining minimum dynamic reactive requirement or transient voltage dip criteria.
However, according to reactive requirement study scope, which is completed as a STEP process
each load pocket or constrained area was studied to verify sufficient reactive reserves are
available to cover the loss of the largest unit. The annual STEP process conducted by SPP did
not indicate dynamic and static reactive power limited areas on the bulk power system. .

SPP has an under-voltage load shedding (UVLS) program in the western Arkansas area within
AEP-West footprint. This program targets about 180 MW of load shed during the peak summer
conditions to protect bulk power system against under-voltage events.

SPP does not conduct operation planning study to evaluate the extreme hot weather condition.
The current capacity margin criteria are intended to address the load forecast uncertainty.

Other Region-Specific Issues
SPP continues to see a surge in wind development in the western part (Oklahoma, Texas
Panhandle, and Western Kansas) of its system. Because wind–generated capacity is currently
such a small fraction, less than 1 percent, of the total SPP capacity, wind farm operational issues
is not expected to affect reliability for the upcoming summer. Should the capacity grow to a
significant amount, near the capacity reserve margin, additional criteria, such as that requiring
voltage support, will be added to handle issues native to unstable wind farm operations.




70
     http://www.spp.org/publications/2007%20SPP%20Transmission%20Expansion%20Plan%2020080131_BOD_Public.pdf

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Region Description
Southwest Power Pool (SPP) region covers a geographic area of 255,000 square miles and has
members in eight states: Arkansas, Kansas, Louisiana, Mississippi, Missouri, New Mexico,
Oklahoma, and Texas. SPP manages transmission in seven of those states. SPP’s footprint
includes 17 balancing authorities and 52,301 miles of transmission lines. SPP has 49 members
that serve over 4.5 million customers. SPP’s membership consists of 13 investor–owned utilities,
11 generation and transmission cooperatives, 11 power marketers, 7 municipal systems, 3
independent power producers, 2 state authorities, and 2 independent transmission companies.
Additional information can be found on the SPP Web site (www.spp.org).




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WECC
2008 Projected Peak Demand                      MW
                                                                                    Relative Capacity by Fuel Mix
  Total Internal Demand                         162,052
    Direct Control Load Management                3,053
    Contractually Interruptible (Curtailable)     1,054                                                    Dual Fuel
                                                                             Coal 18%
                                                                                                             14%
    Critical Peak-Pricing with Control                0
    Load as a Capacity Resource                       0
  Net Internal Demand                           157,945

                                                MW      Change
2007 Actual Summer Peak Demand                  157,526    0.3%
                                                                                                                          Gas 29%
All-Time Summer Peak Demand                     161,131   -2.0%
                                                                        Hydro 29%
2008 Projected Capacity                         MW      Margin
                                                                                                                     Oil 0.4%
  Existing Certain and Net Firm Transactions    189,829   16.8%
                                                                                                                    Geothermal
  Net Capacity Resources                        196,956   19.8%          Nuclear 5%                                    1.3%
  Total Potential Resources                                                            Pumped
                                                213,507   26.0%                                                        Other 1.3%
                                                                                      Storage 2%    Wind 0.5%



Demand
The aggregate WECC 2008 summer total internal demand is
forecast to be 162,052 MW (U.S. systems 142,032 MW, Canadian
systems 17,797 MW, and Mexican system 2,223 MW). The
forecast is based on normal weather conditions and is 2.9 percent
above last summer’s actual peak demand, which was established
under normal to somewhat above normal temperatures in the
region. The 2008 summer total internal demand forecast is 3.2
percent greater than last summer’s forecast peak demand of
156,988 MW for the 2007 summer period.

The internal demand forecast includes 3,053 MW of direct control demand-side management
capability and 1,054 MW of interruptible demand capability. The 2008 summer period direct
control load management and interruptible demand capability has increased by about 560 MW
compared to last year. The direct control demand-side management capability is located mostly
in California. The interruptible demand capability includes industrial interruptible demand and
water pumping demand.

The peak demand forecasts are non-coincident sums of balancing authority forecasts and are
consistent with the balancing authority actual-year hourly demand data. Comparisons with
hourly demand data indicate that the WECC non-coincident peak demands generally exceed
coincident peak demands by two to four percent. WECC has not established a quantitative
analyses process for assessing the variability in projected demand due to the economy.
However, balancing authority forecast processes generally include assumptions regarding
economic conditions but those assumptions may not fully reflect current economic expectations
due to the inherent lag between forecast preparation dates and the assessment publication date.
WECC has not published a weather sensitivity analyses for the 2008 summer peak period.




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Generation
WECC has not established an interconnection-wide process to address the issue of planning for
variability in resource availability due to fuel and other conditions. The gross hydroelectric
resource capability used for this assessment is approximately 63,662 MW with an associated de-
rate (existing uncertain) amount that is roughly 6,890 MW to reflect river flow limitations and
other factors leaving approximately 56,772 MW available for peak periods (existing certain).
There is 6,918 MW of installed wind capability, of which only 1,205 MW is considered existing
certain capacity after it has been reduced by about 5,713 MW to reflect expected available
capability during the peak summer period. WECC’s biomass capacity is 239 MW, of which 236
MW is considered existing certain. There could be an additional 133 MW of peak planned wind
generation after a reduction of approximately 789 MW. Transmission limitations that restrict
generator access to the power grid are largely associated with wind farm interconnections. These
limitations, however, do not exceed the wind derates referenced above. Transmission limitations
for other generation sources are reported at 4 MW.

WECC is not experiencing a drought and does not expect significant adverse hydroelectric
generation conditions during the 2008 summer period.

Purchases and Sales on Peak
Net firm imports at time of peak are 467 MW, composed of 614 MW of gross imports and 147
MW of gross exports. The gross imports are scheduled across three back-to-back DC ties with
SPP and four of the five back-to-back DC ties with MRO. The gross exports are scheduled
across the back-to-back DC ties with MRO. WECC’s summer assessment forecasted net
capacity resources include only firm capacity commitments.

Fuel
WECC has not implemented a formal fuel supply interruption analysis method. 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 were historically
located near major load centers and relied on relatively abundant western gas supplies. Some 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, increasing the region’s exposure to interruptions to that
fuel source.

A survey of major power plant operators indicates that their natural gas supplies largely come
from the San Juan and Permian Basins in western Texas, from gas fields in the Rocky
Mountains, and from the Sedimentary Basin of western Canada.

It is not expected that extremes of summer weather during peak load conditions would have any
impact on the fuel supply infrastructure and Powder River coal deliveries are not expected to be
an issue. Dual-fuel capability is not a significant issue within the Western Interconnection. Only
a nominal amount of generation outside of the Southwest has dual fuel capability and almost all
of the Southwest dual-fueled plants are subject to severe air emission limitations that make
alternate fuel use prohibitive for anything other than very short term emergency conditions.



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Transmission
WECC and regional entities have several processes in place that relate to generation
deliverability. For example, 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.71 WECC prepares an annual power supply assessment that
is designed to identify major load zones within the region that may experience load curtailments
due to physically-constrained paths and internal resource limitations. Major power grid
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 to reflect deliverability constraints identified by
transfer capability studies, interconnection agreement studies, etc.

The southern California area imports significant amounts of power and it is expected that the
transmission into that area of the Western Interconnection will be used much of the time. As in
the past; any unplanned major transmission, generation outages or extreme temperatures may
cause resource constraints in the southern California area. 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.

While WECC has eight back-to-back direct current ties to the Eastern Interconnection with a
combined transfer capability of almost 1,500 MW, only about 470 MW of net capacity imports
are planned for the 2008 summer period. The net non-simultaneous capacity imports for the
2007 summer period were about 690 MW. It has been reported that the capacity imports have
firm resource and associated firm transmission commitments.

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
generation and transmission projects that may impact the interconnected system. These
processes identify potential deliverability issues that may result in actions such as the
implementation of system protection schemes designed to ensure deliverability and to mitigate
possible adverse power system conditions.

Transmission Facilities
Transmission projects for all of WECC’s subregions that have been installed during the time
from October 2007 – February 2008 or that are projected to come on line during the time period
of March 2008 – September 2008 are indicated in the tables at the back of WECC’s section.

Operational Issues
The WECC region is spread over a wide geographic area with significant distances between load
and generation areas. In addition, the northern portion of the region is winter peaking while the
southern portion of the region is summer peaking. Consequently, systems within the Western
Interconnection may seasonally exchange very significant amounts of electric power but
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transmission constraints between the subregions are a significant factor affecting economic
utilization of surplus power. Due to the inter-subregion transmission constraints, reliability in
the Western Interconnection is best examined at a subregional level. WECC does not expect
major generating unit outages, transmission facility outages, or unusual operating conditions that
would adversely impact reliable operations this summer. No environmental or regulatory
restrictions have been reported that are expected to adversely impact reliability.

Other Items
The Northwest Power Pool72 and California ISO73 have publicly available document on their
websites that address 2008 summer conditions.

Reliability Assessment Analysis
WECC prepares an annual power supply assessment74 of generation resource capacity margins
for the summer and winter peak hours over a 10-year planning horizon. The intent of the
assessment is to identify subregions within the Western Interconnection that have the potential
for electricity supply shortages based on reported demand, resource, and transmission data.

For the peak summer month of July, WECC expects a capacity margin of 19.8 percent, which
corresponds to a 24.7 percent reserve margin. WECC’s capacity margin last summer was 17.4
percent. The forecast margin of approximately 38,300 MW significantly exceeds WECC’s
power supply assessment planning margin of about 23,900 MW.

Subregions

Northwest Power Pool (NWPP) Area

The Northwest Power Pool (NWPP) is a winter peaking area. The 2008 summer peak total
demand forecast of 55,922 MW is 0.3 percent greater than last summer’s actual peak demand of
55,737 MW and is 4.6 percent greater than last summer’s forecast peak demand of 53,479 MW.
Last summer’s peak demand was higher than expected due to warmer temperatures. The
forecast peak demand includes 347 MW of interruptible demand and load management
capability. The subregion’s combined (Canadian and United States portion) projected capacity
margin for their summer peak month (July) is 29.0 percent which equates to a 40.9 percent
reserve margin.

Resources — Over 60% of the Power Pool resource capability is from hydro generation. In
addition, generation is produced from conventional thermal plants and miscellaneous resources,
such as non-utility owned gas-fired cogeneration or wind. Under normal weather conditions, the
Power Pool area does not anticipate dependence on imports from external areas during summer
peak demand periods.

Hydro Capability — Northwest 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

72
   http://www.nwpp.org/publications.html
73
   http://www.caiso.com/docs/2003/04/25/200304251132276595.html
74
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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
carrying capability, when reservoirs start full. Under Average water year conditions, the
additional non-firm energy available is approximately 3,000 average megawatts.

The 2008 March early bird forecast for the January through July Columbia River flows at The
Dalles, Oregon is 103 million acre-feet, or 96 percent of the thirty-year average. Last year, the
Coordinated System hydro reservoir refilled to approximately 94 percent by July 31.

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, as well as 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 2008 summer 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 capacity margin at time of peak can be calculated to be greater than 20%, 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 capacity 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 hydro-electric generation.

The Power Pool 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 at least 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 relative to the
Northwest in the winter: however, under summer extreme low water conditions, it impacts
summer conditions.

Thermal Generation — 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 summer peak period.

Transmission — Constrained paths within the Power Pool area are known and operating studies
modeling these constraints have been performed and operating procedures have been developed
to assure safe and reliable operations.




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The Northwest Operational Planning Study Group (NOPSG) coordinates seasonal inter-area and
intra-area transmission transfer capability studies. Daily studies to determine transfer
capabilities during planned outage conditions are coordinated by the operators of the individual
operating paths.

Operations — Balancing Authorities within the Power Pool use a fully automated system of
sharing resources, when requested, to meet the NERC Disturbance Control Standard for loss of
generation in the Pool area. The system has the ability to automatically move generation over a
2-Province, 7-State area while taking into consideration transmission constraints within the area.
This system assures adequate resources are available over a broad area; an adequate response is
delivered within the prescribed time; and the impact of the disturbance to internal as well as
neighboring systems is mitigated.

The Northwest 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 (ER) Response Process to address
immediate power emergencies. The ER Team (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 Power Pool.

In view of the present overall power conditions, including the forecasted water condition, the
area represented by the Power Pool is estimating that it will be able to meet firm loads including
the required reserve. Should any resources be lost to the area beyond the required forced outage
reserve margin and or loads are greater than expected as a result of extreme weather, the Power
Pool area may have to look to alternatives which may include emergency measures to meet
obligations.

California–Mexico Power Area

This is a summer-peaking area. The 2008 summer peak demand forecast of 62,691 MW75 is 0.3
percent greater than last summer’s actual peak demand of 62,508 MW and is 1.6 percent greater
than last summer’s forecast peak demand of 61,687 MW. The areas’ 2007 summer peak demand
occurred during a period of generally normal to slightly warmer than normal temperatures. The
forecast peak demand includes 2,967 MW of interruptible demand and load management. The
subregion’s combined (California and Mexico) projected capacity margin for their summer peak
month (August) is 13.6 percent which equates to a 15.8 percent reserve margin.

The California ISO has reported that its 49,071 MW forecast peak demand could increase by
about 3,000 MW under a 1-in-10 hot weather condition which could reduce the capacity margin
to 9.3% if no additional purchases were procured. As noted earlier, any unplanned major

75
   Details regarding the California ISO portion of the subregion’s forecast may be found at:
http://www.energy.ca.gov/2007publications/CEC-200-2007-015/CEC-200-2007-015-SF2.PDF

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transmission and/or generation outages coupled with lower import levels, or extreme
temperatures coupled with lower import levels, may cause resource constraints in the southern
California area. The California ISO’s April 28, 2008 summer assessment76 presents
deterministic and probabilistic analyses for its portion of southern California. The assessment
states that “…voluntary conservation and on-call interruptible loads could be needed more
frequently than normal.” The assessment also references a 10% probability that its portion of
southern California may experience reserves declining to 3%.

The California ISO performed an exhaustive generation deliverability study in 2006 of all
existing generation. All new generation added since that time has been demonstrated to be
deliverable along with the existing generation and imports. Although several major constrained
transmission paths have been upgraded in recent years, path constraints still exist. Operating
procedures are in place to manage any high loading conditions that may occur during the
summer. 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.

Rocky Mountain Power Area

The Rocky Mountain Power Area’s peak demand may occur in either summer or winter. The
2008 summer peak demand forecast of 12,285 MW is 3.0 percent greater than last summer’s
actual peak demand of 11,931 MW and is 6.4 percent greater than last summer’s forecast peak
demand of 11,547 MW. Last summer’s peak demand was higher than expected due to warmer
temperatures. The forecast peak demand includes 242 MW of interruptible demand and load
management capability. The projected capacity margin for the peak month (July) is 12.5 percent
which equates to a 14.2 percent reserve margin.

Hydro conditions for the 2008 summer period are expected to be near normal, except for the
Bighorn Basin drainage area, and reservoir releases will be similar to last year. The area has
experienced several years of below normal runoff on the Colorado River, causing significant
draw-down at Lake Powell (behind Glen Canyon dam). However, current run off forecasts are
favorable and Lake Powell is expected to partially refill with a fifty-foot increase in reservoir
elevation. The Glen Canyon power plant is operating under environmental impact restrictions
that limit water releases. The release limitations reduce peaking capability by about 450 MW,
but under normal hydro conditions the plant is able to respond to short-term emergency
conditions.

The transmission system is expected to be adequate for all firm transfers and most economy
energy transfers. Although slightly different flow patterns from past years are expected on major
bulk system transmission, no significant changes in flow patterns are expected. The transmission
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path between southeastern Wyoming and Colorado often becomes heavily loaded, as do the
transmission interconnections to Utah and New Mexico. Consequently, the WECC Unscheduled
Flow Mitigation Procedure may be invoked on occasion to provide line loading relief for these
paths.

Arizona-New Mexico-Southern Nevada Power Area

This is a summer-peaking area. The 2008 summer peak demand forecast of 31,551 MW is 3.0
percent above last summer’s actual peak demand of 30,642 MW and is 4.0 percent greater than
last summer’s forecast peak demand of 30,338 MW. Last summer’s peak demand was slightly
higher than expected due to slightly higher temperatures. The forecast for the area includes 555
MW of load management and interruptible demand capability. The projected capacity margin
for the peak month (July) is 14.4 percent which equates to a 16.8 percent reserve margin,
excluding four megawatts of transmission limited resources.

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 summer peak demand conditions. The
physical gas commodity and pipelines that supply this area have proven very reliable. In
addition, firm coal supply and transportation contracts are in place, and sufficient coal
inventories are anticipated for the summer season.




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           WECC Scheduled Transmission Facility Additions, Retirements, and Re-ratings

                              Additions and Upgrades (230 kV and Above)
                                October 2007 through February 2008

 Control                                                       Type of Expected           Actual
                                    Length Capacity Voltage
 Area or           Facility                                    Change Operating          Operating
                                    (Miles) (MVA)    (kV)
Company                                                        (Action)  Date              Date
CA/MX
            Metcalf-Hicks Varona
            (previously as Monta
                                                                 In-
 PG&E       Vista) #1 and #2 230      27    1714     230                   12 2007        10 2007
                                                               Service
            kV Reconductoring
            (T-647A)
            Tracy-Westley 230 kV                                 In-
TID/MID                              0.1     650     230                   11 2007        02 2008
            Line                                               Service
            Westley 230 kV                  2000                 In-
TID/MID                              N/A             230                   11 2007        02 2008
            Substation - Breakers           AMPS               Service
NWPP
            John Day Substation                      500/        In-
  BPA                                N/A    1300                                          10 2007
            - Transformer                            230       Service
            Rock Creek
                                                     500/        In-
  BPA       Substation -             N/A    1300                                          10 2007
                                                     230       Service
            Transformer
            Benewah ID to                                        In-
  AVA                                 60     797     230                   12 2006        11 2007
            Shawnee WA                                         Service
            A. A. Lambert -                                      In-
  FBC                                N/A     90      230                   12 2006        12 2007
            Transformer                                        Service
            Evander Andrews                                      In-
  IPC                                 6      550     230                                  01 2008
            Generation-                                        Service
            Evander Andrews
                                                                 In-
  IPC       Generation- Step-up      N/A     230     230                                  01 2008
                                                               Service
            Station
            Evander Andrews
                                                     230/        In-
  IPC       Generation – Auto-       N/A     300                                          01 2008
                                                     138       Service
            Transformer
RMPA
            Peetz Logan-Pawnee                                   In-
 PSCo                                 70     800     230                   3Q 2007        10 2007
            230kV Line                                         Service
            Denver Terminal –                                    In-
 PSCo                                 7      495     230                   05 2007        11 2007
            Arapahoe                                           Service
            Cedar Creek-
                                                                 In-
 PSCo       Keenesburg 230kV          72     414     230                   4Q 2007        12 2007
                                                               Service
            Line



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                Initial Service, Retirement, or Re-rating (230 kV and Above)
                            March 2008 through September 2008

                                                                                       Projected
Control Area                           Length    Capacity    Voltage      Type of
                      Facility                                                         Operating
or Company                             (Miles)    (MVA)       (kV)        Change
                                                                                         Date
AZ/NM/SNV
               KS 230 kV line Loop
    IID                                  5         150          230                     05 2008
               into Ave 42
               Southeast Valley
   SRP                                   51       1405          500                     06 2008
               Project
               Pinal West
    TEP                                  1         925          345                     06 2008
               Interconnection
               Diamond – Mead 230                                         Can-
    VEA                                  44        640          230                     06 2008
               kV # 2                                                     celled
               Capacitors (Navajo –               136
    APS                                 N/A                     500                     05 2008
               Crystal 500 kV line)               MVAr
               Palo Verde – Pinal
   SRP                                  N/A        800          500                     05 2008
               West Project
               Palo Verde – Pinal
   SRP                                  N/A        800          345                     05 2008
               West Project
               Palo Verde – Pinal
   SRP         West Project –           N/A        800          500                     05 2008
               Transformer Bank
               Southeast Valley
   SRP                                  N/A        280          230                     05 2008
               Project
               Southeast Valley
   SRP         Project – Transformer    N/A        280          230                     05 2008
               Bank
               Reactor replacement
    APS                                 N/A      83 MVAr        500                     06 2008
               (Reactor #4)
CA/MX
               Westley – Rosemore
   MID                                   17        650          230                     06 2008
               230 kV Line
               Westley 2nd
    TID                                 N/A        167       230/115                    04 2008
               Transformer
               Lone Tree Substation
   PG&E                                 N/A        45           230                     05 2008
               Interconnection
               Silvergate-New 230kV
   SDGE                                 N/A                     230                     06 2008
               Substation




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Control Area /                             Length    Capacity   Voltage     Type of        Projected
                         Facility
 Company                                   (Miles)    (MVA)      (kV)       Change         Op. Date
NWPP
                 Caribou Sub: 345kV          1
    PAC                                               1396        345                      06 2008
                 line loop-in
                 Three Peaks Sub:            1
    PAC                                               1163        345                       06 2008
                 345kV line loop-in
                 East Tracy – Emma           20
    SPR                                               1076        345                      08 2008
                 345 kV Line
                 Rocky Ford 230/115
  GCPUD          kV auto-transformer        N/A                 230/115                    05 2008
                 project
                 Brownlee East                        182
     IPC                                    N/A                   230                      05 2008
                 Capacity Increase                    MVAr
     IPC         Mora Substation            N/A        300      230/138                    05 2008
                 Copperfield –
     IPC                                    N/A      1200 A       230                      06 2008
                 Capacitors
                 Brownlee East
     IPC                                    N/A      75 MVAr      230                      06 2008
                 Capacity Increase
                 Mill Creek Phase
   NWMT                                     N/A        350        230                      06 2008
                 Shifter
                 TOT 4AVoltage
    PAC          Support Project -          N/A      30 MVAr      230                       06 2008
                 Riverton
                 TOT 4AVoltage
    PAC          Support Project -          N/A      25 MVAr      230                       06 2008
                 Latham
                 Edmonton Area                        110
   AESO                                     N/A                 240 DC                     06 2008
                 Capacitor Banks                      MVAr
                 Edmonton Area                        110
   AESO                                     N/A                 240 DC                     06 2008
                 Capacitor Banks                      MVAr
                 Edmonton Area
   AESO                                     N/A      30 MVAr    240 DC                     06 2008
                 Capacitor Banks
                 Edmonton Area
   AESO                                     N/A      36 MVAr    240 DC                     06 2008
                 Capacitor Banks
                 Edmonton Area
   AESO                                     N/A      54 MVAr    240 DC                     06 2008
                 Capacitor Banks
                 TOT 4A Voltage
    PAC          Support Project -          N/A      15 MVAr      230                       06 2008
                 Atlantic City
RMPA
                 Chambers 230/115 kV
                 Interconnection Project
                                            N/A        280        230                      05 2008
                 – Substation &
                 Autotrans.

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Regional Description
WECC’s 209 members, including 35 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).




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                                                       Abbreviations Used in This Report




Abbreviations Used in This Report
    AZ-NM-SNV   Arizona-New Mexico-Southern Nevada (Subregion of WECC)
    CA-MX-US    California-Mexico (Subregion of WECC)
    dc          Direct Current
    DOE         U.S. Department of Energy
    EECP        Emergency Electric Curtailment Plan
    ERO         Electric Reliability Organization
    ERCOT       Electric Reliability Council of Texas
    FERC        U.S. Federal Energy Regulatory Commission
    FRCC        Florida Reliability Coordinating Council
    GHG         Greenhouse Gas
    GRSP        Generation Reserve Sharing Pool
    GTA         Greater Toronto Area
    GWh         Gigawatthours
    ICAP        Installed Capacity
    IESO        Independent Electric System Operator (in Ontario)
    IROL        Interconnection Reliability Operating Limit
    ISO         Independent System Operator
    ISO-NE      New England Independent System Operator
    kV          Kilovolts (one thousand volts)
    LFU         Load Forecast Uncertainty
    LNG         Liquefied Natural Gas
    LOLE        Loss of Load Expectation
    LSE         Load-serving Entities
    LTRA        Long-Term Reliability Assessment
    MAPP        Mid-Continent Area Power Pool
    MISO        Midwest Independent Transmission System Operator
    MRO         Midwest Reliability Organization
    MVA         Megavoltamperes
    Mvar        Megavars
    MW          Megawatts (millions of watts)
    NERC        North American Electric Reliability Corporation
    NIETC       National Interest Electric Transmission Corridor
    NPCC        Northeast Power Coordinating Council
    NWPP        Northwest Power Pool Area (subregion of WECC)
    NYISO       New York Independent System Operator
    OVEC        Ohio Valley Electric Corporation
    PAR         Phase Angle Regulators
    PC          NERC Planning Committee
    PJM         PJM Interconnection
    PRB         Powder River Basin
    PRSG        Planned Reserve Sharing Group

Page 129                                       NERC 2008 Summer Reliability Assessment
                                                     Abbreviations Used in This Report


    RAS     Reliability Assessment Subcommittee of NERC Planning Committee
    RCC     Reliability Coordinating Committee
    RFC     ReliabilityFirst Corporation
    RFP     Request For Proposal
    RMPA    Rocky Mountain Power Area (subregion of WECC)
    RMR     Reliability Must Run
    RRS     Reliability Review Subcommittee
    RTO     Regional Transmission Organization
    SCR     Special Case Resources
    SERC    SERC Reliability Corporation
    SOL     System Operating Limit
    SPP     Southwest Power Pool
    SPS     Special Protection System
    TRE     Texas Regional Entity
    THI     Temperature Humidity Index
    TLR     Transmission Loading Relief
    TVA     Tennessee Valley Authority
    VACAR   Virginia and Carolinas (subregion of SERC)
    WECC    Western Electricity Coordinating Council




Page 130                                     NERC 2008 Summer Reliability Assessment
                                                           Capacity & Demand Definitions in this Report




Capacity & Demand Definitions in this Report
Capacity Categories

Existing
        a. Certain — Existing resources reasonably anticipated to be available to operate and
           deliver power to or into the region.
        b. Uncertain — Includes mothballed generation and portions of intermittent generation
           not included in “Certain”
Planned — This category includes generation that has achieved one or more of these milestones:
        a. Construction has started
        b. Regulatory permits approved
               • Site permit
               • Construction permit
               • Environmental permit
        c. Approved by corporate or appropriate senior management
               i. Included in a capital budget
               ii. BOD approved
Announced/Proposed — This category includes generation that is not in a prior listed category,
but has been identified through one or more of the following sources:
    a. Corporate or appropriate senior management announcement
    b. Included in integrated resource plan
    c. Generator Interconnection Queues

Bulk Power System Transactions

Capacity Purchases and Sales – the following categories may be applied to existing and future
capacity calculations. Purchases are negative values, sales are positive values. Each interregional
purchase/sale should be reported.

       a)   Firm – contract signed
       b)   Non-Firm – contract signed
       c)   Expected – no contract executed, but in negotiation, projected, or other.
       d)   Provisional – transactions under study, but negotiations have not begun.

Demand

Internal Demand: Is 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 includes
adjustments for 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).
Page 131                                                   NERC 2008 Summer Reliability Assessment
                                                         Capacity & Demand Definitions in this Report

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.

Demand Response
The figure below provides an overview of NERC’s Demand-side management categories.
               Demand-Side Management and NERC’s Data Collection




Information about demand response categories in Phase 1 were collected for the 2008 Summer
Reliability Assessment. Each of these is defined below:
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
   Dispatchable: demand-side resource curtails according to instruction from a control center
       Controllable: dispatchable demand response, demand-side resources used to supplement
       generation resources resolving system and/or local capacity constraints
             Capacity: demand-side resource displaces or augments generation for planning
             and/or operating resource adequacy; penalties are assessed for nonperformance
                  Direct Control Load Management: demand-side management that is under
                  direct remote control of a control center. It is the magnitude of customer
Page 132                                                  NERC 2008 Summer Reliability Assessment
                                                         Capacity & Demand Definitions in this Report
                demand that can be interrupted at the time of the Regional Council seasonal
                peak by direct control of the System Operator by interrupting power supply to
                individual appliances or equipment on customer premises.
                Contractually Interruptible (Curtailable): 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 Council’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.
                Critical Peak Pricing (CPP) with Control: demand-side management that
                combines direct remote control with a pre-specified high price for use during
                designated critical peak periods, triggered by system contingencies or high
                wholesale market prices.
                Load as a Capacity Resource: demand-side resources that commit to pre-
                specified load reductions when system contingencies arise
           Energy-Voluntary: demand-side resource curtails voluntarily when offered the
           opportunity to do so for compensation, but nonperformance is not penalized
                Emergency: demand-side resource curtails during system and/or local capacity
                constraints
           Ancillary: demand-side resource displaces generation deployed as operating reserves
           and/or regulation; penalties are assessed for nonperformance
                Non-Spin Reserves: demand-side resource not connected to the system but
                capable of serving demand within a specified time
                Spinning/Responsive Reserves: 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.
                Regulation: demand-side resources responsive to Automatic Generation
                Control (AGC) to provide normal regulating margin




Page 133                                                 NERC 2008 Summer Reliability Assessment
                                                                      Reliability Assessment Subcommittee




Reliability Assessment Subcommittee
 Chairman   William O. Bojorquez          Electric Reliability Council of Texas, Inc.   (512) 248-3036
            Vice President of System      2705 West Lake Drive                          (512) 248-6560 Fx
            Planning                      Taylor, Texas 76574                           bbojorquez@
                                                                                        ercot.com

 Vice       Mark J. Kuras                 PJM Interconnection, L.L.C.                   (610) 666-8924
 Chairman   Senior Engineer, NERC and     955 Jefferson Avenue                          (610) 666-4779 Fx
            Regional Coordination         Valley Forge Corporate Center                 kuras@pjm.com
                                          Norristown, Pennsylvania 19403-2497

 ERCOT      Dan Woodfin                   Electric Reliability Council of Texas, Inc.   (512) 248-3115
            Director, System Planning     2705 West Lake Drive                          (512) 248-4235 Fx
                                          Taylor, Texas 76574                           dwoodfin@
                                                                                        ercot.com

 FRCC       Vince Ordax                   Florida Reliability Coordinating Council      (813) 207-7988
            Transmission Planning         1408 N. Westshore Boulevard                   (813) 289-5646 Fx
            Engineer                      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.    (212) 840-1070
            AVP-System Operations         1515 Broadway                                 (212) 302-2782 Fx
                                          43rd Floor                                    jmosier@npcc.org
                                          New York, New York 10036-8901

 RFC        Jeffrey L. Mitchell           ReliabilityFirst Corporation                  (330) 247-3043
            Director - Engineering        320 Springside Drive                          (330) 456-3648 Fx
                                          Suite 300                                     jeff.mitchell@
                                          Akron, Ohio 44333                             rfirst.org

 RFC        Bernard M. Pasternack, P.E.   American Electric Power                       (614) 552-1600
            Managing Director -           700 Morrison Road                             (614) 552-2602 Fx
            Transmission Asset            Gahanna, Ohio 43230-8250                      bmpasternack@
            Management                                                                  aep.com

 SERC       Hubert C. Young               South Carolina Electric & Gas Co.             (803) 217-9129
            Manager of Transmission       1426 Main Street                              (803) 933-7264 Fx
            Planning                      MC 034
                                          Columbia, South Carolina 29201

 SPP        Mak Nagle                     Southwest Power Pool                          (501) 614-3564
            Manager of Technical          415 North McKinley                            (501) 666-0376 Fx
            Studies & Modeling            Suite 140                                     mnagle@spp.org
                                          Little Rock, Arkansas 72205-3020



Page 134                                                     NERC 2008 Summer Reliability Assessment
                                                                        Reliability Assessment Subcommittee




 WECC           James Leigh-Kendall         Sacramento Municipal Utility District       (916) 732-5357
                Regulatory Compliance       Mail Stop D113                              (916) 732-7527 Fx
                Officer                     P.O. Box 15830                              jleighk@smud.org
                                            Sacramento, California 95852-1830

 WECC           Christopher S Smart         Western Electricity Coordinating Council    (801) 883-6865
                Staff Engineer              615 Arapeen Drive                           (801) 824-0129 Fx
                                            Suite 210                                   csmart@wecc.biz
                                            Salt Lake City, Utah 84108-1262

 IOU &          K. R. Chakravarthi          Southern Company Services, Inc.             (205) 257-6125
 DCWG Chair     Manager, Interconnection    13N-8183                                    (205) 257-1040 Fx
                and Special Studies         P.O. Box 2641                               krchakra@
                                            Birmingham, Alabama 35291                   southernco.com

 ISO/RTO        John Lawhorn, P.E.          Midwest ISO, Inc.                           (651) 632-8479
                Director, Regulatory and    1125 Energy Park Drive                      (651) 632-8417 Fx
                Economic Standards          St. Paul, Minnesota 55108                   jlawhorn@
                Transmission Asset                                                      midwestiso.org
                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
 Canadian-At-   Daniel Rochester, P. Eng.   Independent Electricity System Operator     (905) 855-6363
 Large          Manager, Reliability        2635 Lakeshore Road, West                   (905) 403-6932 Fx
                Standards and Assessments   Mississauga, Ontario L5J 4R9                dan.rochester@
                                                                                        ieso.ca

 FERC           Sedina Eric                 Federal Energy Regulatory Commission        (202) 502-6441
                Electrical Engineer         888 First Street, NE, 91-11                 (202) 219-1274 Fx
                                            Washington, D.C. 20426                      sedina.eric@
                                                                                        ferc.gov

 FERC           Dean Wight                  Federal Energy Regulatory Commission        (202) 219-2675
                Energy Industry Analyst     ,                                           Dean.Wight@
                                                                                        ferc.gov

 DOE            Patricia Hoffman            Department of Energy                        (202) 586-1411
                Acting Director Research    1000 Independence Avenue                    patricia.hoffman@
                and Development             SW 6e-069                                   hq.doe.gov
                                            Washington, D.C. 20045

 LFWG Chair     Yves Nadeau                 Hydro-Quebec                                (514) 879-6228
                Manager, Load and           Complexe Desjardins, Tour Est               nadeau.yves@
                Revenue Forecasting         25 etage -- Case postale 10000              hydro.qc.ca
                                            Montreal, Quebec H5B 1H7

 Alternate      Herbert Schrayshuen         SERC Reliability Corporation                (704) 940-8223
 SERC           Director Reliability        2815 Coliseum Centre Drive                  (315) 428 5114 Fx
                Assessment                  Charlotte, North Carolina 28217             hschrayshuen@
                                                                                        serc1.org


Page 135                                                      NERC 2008 Summer Reliability Assessment
                                                                     Reliability Assessment Subcommittee

 Alternate    John E. Odom, Jr.           Florida Reliability Coordinating Council   (813) 207-7985
 FRCC         Manager of System           1408 N. Westshore Blvd.                    (813) 289-5646 Fx
              Planning                    Suite 1002                                 jodom@frcc.com
                                          Tampa, Florida 33607

 Alternate    Christopher Plante          Wisconsin Public Service Corp.             (920) 433-1290
 MRO          Director, Transmission      700 N. Adams Street                        (920) 433-1176 Fx
              Analysis                    Green Bay, Wisconsin 54307                 CTPlante@
                                                                                     wisconsinpublicser
                                                                                     vice.com

 Alternate    Jeffrey L. Mitchell         ReliabilityFirst Corporation               (330) 247-3043
 RFC          Director - Engineering      320 Springside Drive                       (330) 456-3648 Fx
                                          Suite 300                                  jeff.mitchell@
                                          Akron, Ohio 44333                          rfirst.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@
                                          Akron, Ohio 44333                          rfirst.org

 Alternate    Jay Caspary                 Southwest Power Pool                       (501) 614-3220
 SPP          Director, Engineering       415 North McKinley                         (501) 666-0376 Fx
                                          Suite 140                                  jcaspary@spp.org
                                          Little Rock, Arkansas 72205




NERC          Dave Nevius                 North American Electric Reliability        (609) 452-8060
              Senior Vice President and   Corporation                                (609) 452-9550 Fx
              Director of Reliability     116-390 Village Boulevard                  dave.nevius@
              Assessment and              Princeton, New Jersey 08540-5721           nerc.net
              Performance Analysis

NERC          Kelly Ziegler               North American Electric Reliability        (609) 452-8060
              Communications Specialist   Corporation                                (609) 452-9550 Fx
                                          116-390 Village Boulevard                  kelly.ziegler@
                                          Princeton, New Jersey 08540-5721           nerc.net

NERC          Christopher Lada            North American Electric Reliability        (609) 452-8060
Analyst       Technical Analyst           Corporation                                (609) 452-9550 Fx
                                          116-390 Village Boulevard                  chris.lada@
                                          Princeton, New Jersey 08540-5721           nerc.net

NERC          Mark G. Lauby               North American Electric Reliability        (609) 452-8060
Coordinator   Manager of Reliability      Corporation                                (609) 452-9550 Fx
              Assessments                 116-390 Village Boulevard                  mark.lauby@
                                          Princeton, New Jersey 08540-5721           nerc.net




Page 136                                                    NERC 2008 Summer Reliability Assessment

				
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