##### Words: 7,412

March 16, 2004

##### DRAFT

##### Chapter 3. Reliability

**1. Introduction**

The Blackout of August 14, 2003 directly affected about 50 million
people in the United States and Canada, leaving millions of them without
power. Within a few months of that blackout, the U.S.-Canada Power
System Outage Task Force identified its proximate causes.[^1] But their
study did not address broad public policy questions about the
reliability of the electric power system.[^2] Reliability refers to the
power system's ability to deliver power of specified quality when and
where it is desired. Among the questions the Task Force did not address
are: (1) How reliable is the grid? (2) Is the grid becoming more or less
reliable over time? (3) Are necessary investments in reliability being
made, especially in transmission? (4) Do market incentives undermine
reliability? In particular, do voluntary approaches to reliability
management work in a market setting? (5) Are markets revealing new ways
to attain reliability at less cost? This chapter reviews the official
data and analytical tools available for answering such questions.

The Federal government's role in reliability management has been to
monitor outages and to require investor owned utilities to show their
plans are consistent with reliable operations.[^3] The Department of
Energy also sponsors reliability research, conducts investigations after
major outages and works with industry reliability groups to anticipate
reliability problems. The Federal Government does not determine
acceptable levels of reliability nor does it mandate how reliable
performance is to be obtained. That is left to the industry,
particularly the North American Electric Reliability Council (NERC).
This chapter examines the kinds of data the government needs to carry on
reliability oversight.

Since the September 11, 2001 terrorist attacks the government has
restricted access to certain grid data that were previously public. The
data needed to analyze reliability are a crucial part of the information
needed to identify the grid's vulnerabilities to physical attack.
Whether the terrorist threat will cause the government to take a more
direct role in reliability modeling, analysis and management is an open
question. If it does, the government's data needs would only grow.

After the East Coast Blackout of 1965, utilities formed the North
American Electric Reliability Council (NERC) to develop voluntary
reliability standards and guidelines. NERC encouraged its members in
each of its 10 regions (see chapter 2) to maintain enough reserve
generation and transmission in their exclusive franchise (service) areas
to keep the lights on despite equipment failures and exceptionally large
demand. State and Federal regulators generally approved those
investments and permitted investors to recover their costs by charging
their captive customers. NERC also encouraged its members to coordinate
their individual investment plans and responses to reliability threats.
Everyone generally cooperated in these efforts because reliable
operation is in everyone's best interest, no one lost customers to lower
cost competitors and because regulators underwrote their costs.

The growth of more competitive wholesale electricity markets since
FERC's 1996 Order 888 has created new challenges for reliability
management. In the past, utilities generally owned both generators and
transmission assets dedicated to serving customers in their exclusive
franchise area. Now, generation and transmission are often owned by
separate entities and neither bears sole responsibility for reliability
problems. Franchises are no longer exclusive: wholesale customers can
contract with whomever they want. Nor can regulators be counted on to
underwrite idle assets, especially those benefiting customers in other
states. Competition has also caused power to flow across system
boundaries and vary in amounts not seen before. These new operating
regimes have challenged engineers and system operators to develop new
ways of ensuring reliable operations in an increasingly dynamic market
environment.

The next section of this chapter discusses several reliability concepts
and identifies some of the measures these definitions imply. Measuring
reliability is akin to the problem of measuring good health. There is no
good summary metric; there are a host of useful indicators. Competition
and the August 14, 2003 blackout have highlighted the unstated role of
information, computation and communications in traditional reliability
concepts. Section 3 reviews some of the effects of markets on
reliability planning and management and identifies additional
reliability indicators. Section 4 reports the official reliability
information. The chapter concludes with a discussion of how data gaps
might be filled.

#### 2. Reliability Definitions and Indicators

Federal interests in reliability focus on the interstate, high voltage
power grid. State and local authorities have jurisdiction over the lower
voltage distribution system and substantial say in the building and
maintenance of the high voltage grid. Precisely where the high voltage
grid ends and the low voltage distribution system begin is a matter of
controversy. NERC's data and published analysis define the high voltage
grid as 230kV and above. FERC's Form 715's reporting threshold for the
high voltage grid is 100kV, but respondents generally include lines of
69kVand above. EIA's Form 412 defines the high voltage system as 132kV
and above and the EIA Form 411 uses 230kV as the high voltage threshold.
The differences matter because there are large areas of the country
where 69kV and 138kV lines deliver wholesale, bulk power. Moreover
limits on these lines may make it impossible to fully utilize much
higher voltage transmission lines. For those reasons this report
considers lines as small as 69kV.

When the demand for power (load) differs from generation net of losses,
an alternating current system is unbalanced. If the difference is large
enough the system will blackout-it will fail to operate in part or
total. If demand exceeds net generation by a lesser amount voltage and
frequency will drop, with possible damage to equipment. Likewise, net
generation in excess of demand but short of failure will cause voltage
and frequency to increase, again with possible damage to equipment. Any
sustained imbalance will lead to large deviations in frequency and
voltage.[^4] Most equipment is designed to withstand only small
departures from target voltage, frequency and power standards. Central
control of how much power is injected and with drawn from the
transmission grid is necessary to keep the lights on.

Operational control is mainly exercised at the level of the control
area, ISO and NERC reliability region. In rare instances, such as in the
case of the August 14 blackout, coordinated control across NERC regions
up to the boundaries of the relevant interconnection may be needed to
prevent blackouts. Federal oversight and data collection is focused on
control areas and NERC regions.

Conceptually the frequencies of blackouts and brownouts, their duration,
size and costs are fundamental measures of the grid's historical
reliability. Prospective improvements in reliability could, in
principal, be indicated by reduced probabilities of reliability problems
and reductions in their expected duration, size and cost.

Economists argue the *level* of reliability should be set so that the
marginal benefits of increased reliability (fewer outages, power quality
lapses, reduced economic loss) would equal marginal costs (additional
generation, transmission, or better system control). Utilities
traditionally evaluated investments in emergency generation by comparing
its cost with the cost of unserved energy. [^5] The costs of unserved
energy were those the utilities estimated on behalf of their customers
together with the utility's own costs. At the level of an individual
consumer, economists have defined reliability as the proportion of the
time power of sufficient quality costs less than she is willing to pay.
When marginal benefit from the consumer's perspective is less than
marginal cost (the price of power), she does not consume, i.e., she
chooses to black herself out.[^6]

The U.S-Canada Task force defined reliability as

> The degree of performance of the elements of the bulk electric system
> that results in electricity being delivered to customers within
> accepted standards and in the amount desired. Reliability may be
> measured by the frequency, duration, and magnitude of adverse effects
> on the electric supply. Electric system reliability can be addressed
> by considering two basic and functional aspects of the electric system
> Adequacy and Security.[^7]

Trends in experienced and expected frequencies of blackouts and
substandard power quality would give policy makers quantitative grounds
for concluding whether reliability is improving or deteriorating. For
reasons discussed below neither the Federal Government nor NERC
currently makes quantitative estimates of the future probabilities of
blackouts and brownouts.

Instead of quantitative measures, the NERC uses a combination of expert
judgment, quantitative modeling and scenario ("what if") analysis to
assess qualitatively current and prospective reliability across and
within regions.[^8] NERC's qualitative evaluation hinges on two factors:

> "1. Adequacy-The ability of the electric system to supply aggregate
> electrical demand and energy requirements of customers at all times,
> taking into account scheduled and reasonably expected unscheduled
> outages of system elements.
>
> 2\. Security-The ability of the electric system to withstand sudden
> disruptions such as electric short circuits or unanticipated loss of
> system elements."[^9]

NERC's focus is on whether physical resources within a NERC region,
perhaps supplemented with emergency power imports, and operating
practices are sufficient to maintain electrical balance under expected
and emergency conditions. If they are, and there is a sufficient margin
of safety, the system is judged reliable. This evaluation does not say
how reliable the system is or whether additional investments would
increase reliability or would be worth their cost.

Determining generator "adequacy" amounts to adding up the capacity of
generators within the region, adjusting total capacity for maintenance
and unplanned outages, and comparing the total with the sum of demand
and losses less net imports. Likely and extreme values for outages,
demand and losses are derived from historical data. Base (net) imports
and emergency (incremental) imports appear to be derived from a
combination of historical experience and modeling results. Since imports
can replace the need for local generation, the selection of base imports
is important to the generation adequacy assessment. If the comparison
shows the amount of adjusted capacity exceeds that needed with a
sufficient margin of safety, usually on the order of 15-20% of peak
demand, generation is judged adequate. NERC does not document the basis
for specific margins of safety.

Electrical models in particular power flow models of the regional power
system are indispensable for determining whether the grid is "adequate"
to deliver power where needed. The input data for these power flow
models are extensive. The data include the impedance of all the branch
lines in the transmission system, the topology---a statement of the
connections between lines and buses\--of the system, the limits of all
the branches, the voltage control capabilities of the transformers,
generator capacity and availability, and demands at individual buses.
The results show the power flowing over all the different lines, its
voltage and whether any limits, such as thermal limits on lines, are
violated.[^10] Engineers rely on power flow models to confirm that power
flows under expected conditions do not exceed the grid's physical
capabilities and operating limits.

.........................................................................................

Text Box

Transmission Is Mysterious

1.  Life in an AC network

    a.  Electrons are not transported, shipped or otherwise moved from
        generators to consumers.

    b.  Less is more and more is less- sometimes, depending

        i.  Removing lines can increase delivery: increasing a line's
            capacity can decrease delivery.

        ii. Increasing consumption can relieve heavily loaded lines:
            decreasing consumption can overload lines.

    c.  Lightly loaded lines often cannot carry more power.

    d.  Fully loaded lines do not necessarily constrain delivery.

2.  Why?

    a.  Electrons in AC systems only move back and forth a small
        distance; they do not go from here to there.

    b.  In a network there are multiple paths from generators to
        customers.\* Electricity flows through a network along *all*
        possible paths following physical laws that favor those paths
        with "least resistance."

    c.  There are no valves for directing electricity along secure
        routes.

    d.  The entire system is limited by the weakest link

3.  What that means

    a.  Power flows, voltage and their control depend on the details of
        the network's physical configuration and on precisely how much
        is being generated and consumed at every location.

    b.  Mathematical models are indispensable for sorting out the
        complexity and accurately showing how the network can meet
        customers' power demands.

\* Electricity flows along more than one path (the scheduled, nominal,
or dominant path) from a source to a load is called "Loop Flow."

\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--..................................................................................

Engineers also need models of the region's connected neighbors to
determine if base imports are feasible and whether additional
(incremental) imports would be available to cover emergency imbalances.
If power from all sources can be delivered with a sufficient margin of
safety under the studied scenarios, then transmission is judged
adequate.

Security analysis is concerned with the regional system's continued
operation in the event of short circuits and equipment (generator and
line) failures. Stability analysis aims at ensuring that voltage and
system synchronization are kept within limits after a short circuit.
Contingency analysis is concerned with reliable operation after
generators and lines unexpectedly fail. The hypothetical events are
called contingencies: the ensemble of events is called a contingency
list.[^11] These analyses result in limits on "the maximum amount of
electricity that can be safely transferred over transmission
lines".[^12] These limits are imposed in adequacy analyses as if they
were physical limits.

System operators in each control area enforce security limits by
ordering generators within their systems to adjust their output, by
disconnecting users and by restricting the flows of power into and out
of their systems. Their actions are guided by real time metering data,
computer models of their system and experienced judgment. Intersystem
power flows are generally the result of specific scheduling agreements
between system operators in adjoining areas. Managing power flows across
control areas can be difficult simply because many parties must agree.

As documented in Section 4 below large blackouts and brownouts of the
high voltage grid in the US are common but infrequent enough that
statistically estimating regional probabilities and their trends is a
dubious enterprise. Estimating future probabilities based on detailed
electrical descriptions of regions, their experience of equipment
failures and similar information is conceptually possible but expensive
and of arguable accuracy.

Information relevant to indicating reliability as it relates to
transmission would include:

1.  Number, size, duration and cost of blackouts and brownouts.

2.  Trends and Status of grid adequacy and security

    a.  Peak demand, supply and power flows by control area

    b.  Line outages

    c.  Security limited lines, power curtailments and redispatch.

3.  Planning Data

    a.  Projected demand

    b.  Projected generation and transmission assets

    c.  Power transfer capabilities

4.  Analytical tools

    a.  Electrical models of regions, both as they currently exist and
        as described in planning documents.

    b.  Contingency lists

**3. Markets and Reliability**

Interregional and regional wholesale markets have significantly impacted
power line utilization and the volatility of power flows. NERC has noted
that

> "The transmission system is being subjected to flows in magnitudes and
> directions that were not contemplated when they were designed and for
> which there is minimal operating experience. New flow patterns result
> in an increasing number of facilities being identified as limits to
> transfers..."[^13] and
>
> "...operating experience shows that market conditions can, at times,
> cause volatile and unpredicted flow patterns that cannot be reliably
> accommodated by the transmission system."[^14]

NERC has not, however, released the data and statistical analyses
underlying these conclusions.

Operators require good interregional models, precise data, rapid
computation and communications to successfully manage novel and
increasingly volatile power flows.[^15] The U.S.-Canada task force
concluded that two of the three basic causes for the August 14 blackout
relate to information technology; in particular, inadequate situational
awareness and failure of reliability organizations to provide effective
diagnostic support.[^16] They also found that neither NERC nor the
Federal Government maintained reference models of the directly affected
regions and of the Eastern Interconnection.

Although everyone benefits from reliable service its costs are borne by
specific generators and transmission owners. By bringing competition
into generation and encouraging free trade across regional markets,
FERC's restructuring has reopened the question of how to pay for
reliability. Free-riding beneficiaries of costly investments have always
been a feature of interconnected electrical systems. Under regulation,
utilities were assured they would recoup their investments and they had
no competitors to undercut their rates. Now their investments may
advantage competitors and raise their own costs. Competitive generators
cannot be faulted for resisting paying for idle or under-utilized assets
that benefit everyone else.

State regulators also question why their state's citizens should pay for
transmission investments that lower costs and improve reliability for
outsiders. Regulators cannot be counted on to underwrite transmission
investments, even those with significant local benefits. NERC notes
that:

> "With industry restructuring and the development of regional wholesale
> markets, new transmission lines may be beneficial to all parties,
> including the consumers of electricity, but their costs are incurred
> by only one or several entities. As a result, those entities may be
> reluctant to build the needed transmission facilities."[^17]

How to pay for reliability in a competitive environment is far from
settled. The Northern ISOs have had some success using markets to
provide mandated reserve generator capacity and various operating
reserves. No one has demonstrated a market-based way of deciding the
appropriate level of reliability and paying for it.[^18]

To the extent that restructuring encourages demand response to prices
(and distributed generation), markets may allow systems to operate
reliably with smaller safety margins, reducing reserves of idle
equipment. Numerous DOE studies have found price responsive demand can
be as important for reliability as generation reserves: reducing demand
is much like an increase in generation of the same amount and has the
additional benefit of reducing line loadings.[^19] Distributed
generators can potentially supply power to the grid and meet a share of
local demand, thereby directly relieving loaded lines.

Additional information relevant to assessing reliability in a market
environment as it relates to transmission would include:

1.  High quality, interconnection wide models

2.  Actual investment in the high voltage grid including specific
    investments in instrumentation, communications, computation and
    control.

3.  MWh metered to permit real time price responsive demand: MWh billed
    under real time pricing.

Credible interconnection models are necessary to manage reliability with
increasing and novel interregional commercial power flows. Trends in
investment in the high voltage grid together with information on who is
paying for it would both compliment planning projections and would give
policy makers a factual basis for re-considering how to pay for
reliability investments. Investment data showing investment in
instrumentation, computation and control would be consistent with
operators gaining more control over the grid. Increased information and
more precise control should allow for smaller safety margins in future
reliability assessments. Price responsive demand would be one more tool
operators could use to balance demand and supply. That could make it
possible for planners to reduce the need for reserve generation and new
transmission facilities. EIA recently began collecting considerable
information on distributed generation: there is no compelling reason to
collect more at this time.

### **4. Official Reliability Data**

***Reliability incidents, outage probabilities and costs:*** Federal
data on actual grid reliability is confined to the EIA --417, "Emergency
Incident and Disturbance Report." The EIA-417 incident data has mainly
been used as a starting point for grid security studies. This form must
be submitted to DOE's Operations Center if one or more of the following
apply:

1.  Uncontrolled loss of 300 megawatts or more of firm system loads for
    more than 16 minutes from a single incident

2.  Load shedding of 100 megawatts or more

3.  System wide voltage reduction of 3% or more

4.  Public appeals to reduce the use of electricity

5.  Actual or suspected physical attacks that could impact electric
    power system adequacy or reliability

6.  Actual or suspected cyber or communications attacks

7.  Fuel supply emergencies

8.  Loss of electric service to more than 50,000 customers for one hour
    or more

9.  Complete operational failure or shutdown of the transmission end or
    distribution system.

The types of data that appear on the Form EIA-417 include information
about the location, date, and time of the incident, as well as the
nature of the disturbance. Also, information about the cause of the
incident (if known) and the actions taken in response to the incident
are requested.

To illustrate, Table 3-1 shows a list of some typical disturbances and
unusual occurrences that were reported on the Form EIA-417 during the
year 2002.

  -------------- ------------------- ---------- ---------------- --------------- --------------- ------------ ---------------
  **Table 3-1**  **Major                                                                                      
                 Disturbances and                                                                             
                 Unusual                                                                                      
                 Occurrences, 2002**                                                                          

                                                                                                              

  **Date**       **Utility/Power     **Time**   **Area**         **Type of       **Loss          **Number of  **Restoration
                 Pool (NERC                                      Disturbance**   (megawatts)**   Customers    Time**
                 Region)**                                                                       Affected**   

  **January**                                                                                                  

  1/30/2002      Oklahoma Gas &      6:00 AM    Oklahoma         Ice Storm       500             1,881,134    2/7/2004 12:00
                 Electric                                                                                     

                 (SPP)                                                                                        

  1/29/2002      Kansas City Power & Evening    Metropolitan     Ice Storm       500-600         270,000      NA
                 Light (SPP)                    Kansas City Area                                              

  1/30/2002      Missouri Public     4:00 PM    Missouri         Ice Storm       210             95,000       2/10/2004 21:00
                 Service (SPP)                                                                                

  **February**                                                                                                 

  2/27/2002      San Diego Gas &     10:48 AM   California       Interruption of 300             255,000      2/27/2004 11:35
                 Electric (WSCC)                                 Firm Load                                    

  **March**                                                                                                    

  3/9/2002       Consumers Energy    12:00 AM   Lower Peninsula  Severe Weather  190             190,000      3/11/2004 12:00
                 Co. (ECAR)                     of Michigan                                                   

  **April**                                                                                                    

  4/8/2002       Arizona Public      3:00 PM    Arizona          Vandalism/      0               0            9-Apr
                 Service (WSCC)                                                                               

                                                                 Insulators                                   

  **July**                                                                                                     

  7/9/2002       Pacific Gas &       12:27 PM   California       Interruption of 240             1 PG&E       7/9/2004 19:54
                 Electric (WSCC)                                 Firm Power                                   

  7/19/2002      Pacific Gas &       11:51 AM   California       Interruption of 240             1 PG&E       7/19/2004 16:30
                 Electric (WSCC)                                 Firm Power                                   
                                                                 (Unit Tripped)                               

  7/20/2002      Consolidated Edison 12:40 PM   New York         Fire            278             63,500       7/20/2004 20:12
                 Co. of New York                                                                              
                 (NPCC)                                                                                       

  **August**                                                                                                   

  8/2/2002       Central Illinois    12:43 PM   Illinois         Interruption of 232             53,565       8/2/2004 18:36
                 Light Co. (MAIN)                                Firm Power                                   

  8/9/2002       Lake Worth Utils    8:23 AM    Florida          Interruption of 51              25,000       8/9/2004 12:13
                 (SERC)                                          Firm Power                                   

  8/25/2002      Pacific Gas & Elec. 3:41 AM    California       Interruption of 120             1 PG&E       8/25/2004 9:17
                 (WSCC)                                          Firm Power                                   

  8/28/2002      Lakeworth Utils     2:09 PM    Florida          Severe Weather  67.6            25,000       8/28/2004 15:38
                 (SERC)                                                                                       

  **October**                                                                                                  

  10/3/2002      Entergy Corporation 3:33 AM    Coastal Areas of Hurricane Lily  NA              242,910      10/4/2004 9:00
                 (SPP)                          Southern                                                      
                                                Louisiana                                                     

  **November**                                                                                                 

  11/6/2002      Pacific Gas &       10:00 PM   Northern and     Winter Storm    270             939,000      Noon November
                 Electric Co. (WSCC)            Central                                                       10
                                                California                                                    

  11/17/2002     Long Island Power   3:48 PM    Northport, NY    Cable Tripped   0               0            Unknown
                 Authority (NPPC)                                                                             

                                                Norwalk, CT                                                   

  11/17/2002     Northeast Utilities 6:00 AM    Northwest and    Ice Storm       NA              224,912      11/21/2004 8:00
                 (NPCC)                         North Central                                                 
                                                Connecticut                                                   

  **December**                                                                                                 

  12/3/2002      Entergy Corporation 6:30 PM    Arkansas         Ice Storm       NA              43,000       12/5/2004 8:00
                 (SPP)                                                                                        

  12/11/2002     Dominion-Virginia   1:09 PM    Northern         Winter Storm    63              130,000      12/11/2004
                 Power/North                    Virginia to                                                   13:45
                 Carolina Power                 Fredericksburg                                                
                 (SERC)                                                                                       

                                                Staunton to                                                   
                                                Harrisonburg                                                  

  12/14/2002     Pacific Gas &       11:00 AM   Northern and     Winter Storm    180             1.5 million  12/18/2004
                 Electric (WSCC)                Central                                                       16:00
                                                California                                                    

  12/19/2002     Pacific Gas &       6:00 AM    Northern and     Winter Storm    56              385,000      12/20/2004
                 Electric (WSCC)                Central                                                       17:00
                                                California                                                    

  12/25/2002     PPL Corporation     5:00 PM    Eastern          Winter Storm    250             106,000      12/26/2004 5:00
                 (MAAC)                         Pennsylvania                                                  

  12/25/2002     Metropolitan Edison 10:00 AM   Reading, York,   Winter Storm    NA              95,630       12/27/2004 8:30
                 Co./First Energy               Hanover, Hamburg                                              
                 (MAAC)                         Pennsylvania                                                  

                                                                                                               

  Note: North                                                                                                 
  American                                                                                                    
  Electric                                                                                                    
  Reliability                                                                                                 
  Council region                                                                                              
  acronyms are                                                                                                
  defined in the                                                                                              
  glossary.                                                                                                   

  Source: Form                                                                                                
  EIA-417,                                                                                                    
  \"Electric                                                                                                  
  Emergency                                                                                                   
  Incident and                                                                                                
  Disturbance                                                                                                 
  Report\"                                                                                                    
  -------------- ------------------- ---------- ---------------- --------------- --------------- ------------ ---------------

Seven of the reported twenty-three incidents were in the California and
two were in Florida. Oklahoma experienced the largest blackout in terms
of numbers of people affected. Assuming complete reporting of qualifying
events, it is clear that major reliability failures are fairly common
but spread around the country and involve a very small percent of
delivered power nationwide. At the regional level of aggregation the
historical data suggests that the frequency of failures is very low.

*Outage probabilities*. John Doyle of the California institute of
Technology and others used NERC data to show outage frequencies for
North America 1984-1997.[^20] Figure 3-1 is an example of that body of
research. Similar displays can be constructed from EIA data. Their work
shows that the frequency of large outages is significant. The frequency
of large outages follows a power law. That would imply the probability
of outages does not vanish as its size increases: very large outages
cannot be ruled out as a practical matter. There are, however, too few
large outages to be confident that observed frequencies are accurate
estimates of underlying probabilities at the regional level. Empirical
estimates of changes in outage probabilities are of unknown accuracy for
the same reason.

![](media/image1.png){width="3.7493055555555554in"
height="3.0097222222222224in"}Figure 3-1. North American Power System
Outages, 1984 -- 1997

Source: Adapted from John Doyle, California Institute of Technology,
"Complexity and Robustness," 1999. Data from NERC.

*Costs*. There are no official data on the cost of reliability
incidents. The Federal government does not collect customer expenditures
for backup generators, power quality protection, equipment damage and
insurance. Consequently it is not possible to identify trends in actual
losses or peoples' perception of the potential for loss.

The Electric Power Research Institute (EPRI), the insurance industry and
researchers have attempted to compute annual costs due to power
incidents. There efforts were not restricted to official data. Recent
estimates of the annual national cost of blackouts and poor power
quality range from about \$20 billion to over \$400 billion.[^21]
Researchers under contract to EPRI, however, concluded after an
exhaustive review of the literature that

> There are few estimates of the aggregate cost of unreliable power to
> the U.S. economy. Documentation for existing estimates is either
> absent or based on assumptions that need additional review[^22].

The lack of cost data makes vacuous policies, such as those followed by
Electricite de France (EDF), to balance the costs of reliability
investments against their cost savings.

*Trends in Status of Grid Adequacy and Security:* Since outage and power
quality data do not support estimates of near term and regional
reliability, it is natural for government oversight groups to examine
data on recent and current conditions that bear on grid adequacy and
security.

The FERC 714, the Annual Electric Control and Planning Area Report, is
the major official source of recent data on reliability management.
Control areas identify their interconnections with adjacent control
areas and their scheduled and actual annual interchange (net power flows
into and out of the area) in the context of showing the adequacy of
their generation and transmission resources. Each control area collects
monthly generating capability, net generation and net interchange for
the reporting year. Importantly for reliability assessment, the form
also records how the control area met the peak hourly demand occurring
in each month.

FERC 714 is a double entry account, so that net transactions between
adjacent control areas are reported directly. As control areas are
associated wholly and uniquely with NERC regions, estimates of regional
interchange could in principle be made by aggregating individual
reports.[^23] Unfortunately, discrepancies in reporting are significant.
While many of the receipts and deliveries match exactly on both sides of
the ledger, there are some modest differences in delivery and receiving
area reports, possibly attributable to losses or differences in
metering. More unsettling are gaps in reporting- one control area
reports a delivery, but the named recipient does not report a receipt.
The information on power flows between control areas is not sufficiently
accurate, complete or at a high enough frequency to be useful in
assessing the grid's ability to deliver power to control areas that need
it, when they need it.

The EIA 411 collects somewhat similar information for NERC regions. The
interchange information, however, is an annual total and does not
identify power flows. That data are not useful for monitoring grid
adequacy and security; their main use is for planning.

Line outages, both scheduled and unscheduled, obviously limit how
operators can affect power flows but they do not necessarily limit the
grid's ability to deliver power. An increase in outages over time
complicates the task of delivering power and can point to underlying
problems, such as neglected maintenance, which could eventually affect
grid adequacy.

Data on transmission line availability are collected by the ten regional
reliability councils and by many transmission-owning utilities. For
example, the East Central Area Reliability (ECAR) region reported
several interesting trends recently.[^24] Availability of the 345 kV
system in ECAR in 2001 was the second lowest in twenty years, primarily
because scheduled outage time increased by 95 percent. The report notes
that several of the longer outages in 2001 were attributable to work to
connect independent generators to the grid.[^25] The data are not
reported in a standard form across NERC regions and is not readily
available for lines of 69kV and above.

Increases or decreases in line loadings on a heavily loaded transmission
path, corridor, or interface can indicate change in grid adequacy.
During a time period when grid capability is fixed, increased
transmission loading is a direct indication of reduced adequacy. The
direction of these flows is usually well known at peak times, and the
total corridor loading is equal to the sum of the loadings on a
relatively small set of lines. Such data are maintained by NERC but are
not publicly released.

A more direct measure of adequacy would be number of hours n-1, n-2 and
higher level constraints are actually binding within a control area and
region. It would be useful to know which lines are at a security limit,
when the constraint became effective, how much power was curtailed and
the cost of re-dispatching the system to meet demand. This information
is generally not available.

One publicly available indicator of grid adequacy is NERC's Transmission
Loading Relief (TLR) Database. The information is unique to the Eastern
Interconnection. [^26] This "Log" contains information on instances of
transmission inadequacy at flow gates (major pieces of transmission
equipment) and on major lines. In particular, it documents the
requirement to implement NERC TLR procedures on specified days to
protect major parts of the transmission system.[^27] Similar information
is not available for either the Western Interconnection or ERCOT. The
Northern ISOs do not experience TLRs because they use prices rather than
priorities to ration transmission resources.

There are nine TLR levels. Level "0" is normal operation, level 2
indicates that further increases would violate security limits and the
higher levels all require curtailments. The curtailments start with low
priority nonfirm point-to-point service and continue up to curtailments
of firm point to point service. Figure 3-2 is a plot of TLR level 2
events by month of the year. Not surprisingly it shows TLRs increase
significantly during the peak demand months of July and August.

# Table 3-2. Level two or higher TLRs by Month

NERC does not report the volumes of power that are curtailed by TLRs.
NERC did, however, provide that information to FERC staff writing the
previously cited December, 2001, curtailment study.

![](media/image2.png){width="5.989583333333333in"
height="3.5833333333333335in"}

**Planning Data.** The starting point for establishing prospective
adequacy is estimates of future demands, especially peak demand. The
FERC 714 requires planning areas to report their actual hourly demand.
Planning areas are also required to provide their forecasts of summer
and winter peak demand ten years into the future. The historical data
could provide a benchmark for projections as well as important data for
modeling future demand.

NERC submits the EIA 411 on behalf of its 10 regional councils. The data
includes five-year projections of supply and demand by NERC region.
Supply means generation, but the form identifies existing transmission
lines and proposed lines. The data can be used to indicate whether
projected generation within a NERC region exceeds projected demand.
However the form does not contain the kinds of information necessary to
determine whether intra and interregional transmission is sufficient to
deliver power where it is demanded under peak or other definable
conditions.

The coverage and relevance of the data collected on the EIA 411 to
NERC's short-term and long-term reliability assessments are unclear. The
form is voluntary and may or may not include entities that are not
members of NERC. The instructions do not require that the projects are
consistent with those used in NERC's reliability assessments or with
planning area projections contained on the FERC 714.

As mentioned in Section 2 of this chapter, NERC assesses power transfer
capability between interconnected regions and sub-regions and publishes
the "base" power transfers between regions and the incremental transfer
capabilities in each direction. Such data provide a measure of the
additional power that could be transferred from one region to a
neighboring region, if the latter region experienced a sudden need for
support. High levels of incremental capability indicate adequacy; low
levels indicate potential for shortages to spread from one region to
neighboring regions Table 3-2 gives the transfer limits from MAIN to
MAPP, SERC and TVA under conditions NERC expected in the summers between
2000 and 2003.

![](media/image3.wmf){width="7.116666666666666in"
height="1.0569444444444445in"}**Table 3-2. Base Transfers and
Incremental Transfer Limits between Select NERC Reliability Regions and
Subregions**

Source: North American Electric Reliability Council, Summer Assessments
2000 - 2003

Generally the capabilities are substantial. However, the values are for
non-simultaneous conditions, that is, these limits could not all be
approached at the same moment. Further, the limits assume that all
transmission facilities are in service, all facilities are loaded within
normal ratings, and voltages are within normal limits.

The limits are also subject to supply and demand conditions that can
cause base and incremental levels to change. Time series and econometric
projections would be unlikely to anticipate the changes in base and
incremental transfer capability shown in Table 3-2. The annual
variations in base and incremental flows are sufficiently large that
they can only be estimated with the help of models.

***Analytical Tools:*** The planning data is one input to reliability
assessments. In order to independently evaluate adequacy and security
government officials and their experts require electrical models (power
flow models) that accurately represent the relevant systems, whether
control area, NERC region or interconnect.

The FERC Form 715, *Annual Transmission Planning and Evaluation Report*,
is the major official source of the information required to build power
flow models used to evaluate transmission adequacy and security.[^28]
Transmitting utilities that operate networks at or above 100 kilovolts,
or their agents, submit the form to FERC annually. Normally NERC
Regional Councils submit the Form 715 on behalf of their members. The
required data includes:

1.  Power flow base cases for its transmission system, or if the
    transmitting utility belongs to a regional or subregional
    transmission planning or reliability organization, power flow bases
    cases for that region or subregion;

2.  System maps;

3.  Descriptions of reliability criteria; and

4.  Evaluations of the current and future performance of the
    transmission system.

The power flow cases are intended to be forward looking. FERC suggests
that the cases include summer and winter peak conditions one, two and
five to ten years in the future. FERC also suggests that respondents
include an analysis of light and heavy transfers one year in the future.

The EIA Form EIA-411, *Coordinated Bulk Power Supply Program Report*,
requires power flow data similar to that provided in the Form 715 for
newly planned transmission facilities.[^29] Specifically, the Form 411
requires that respondents

> "... submit a single annual peak load power flow case that includes
> all prospective facilities to be energized in the next two years.
> Alternatively, the respondent may provide a copy of any annual peak
> load power flow case that includes the new facility for the year it is
> to be energized. If more than one facility is to be energized in a
> given year, it is acceptable to provide a single annual peak load
> power flow case that includes all the new facilities added in that
> year."

Neither the FERC nor the EIA power flow data are publicly available
because of the Federal Government's concern with national security. The
data are available for official government purposes, including policy
analysis.

Neither the EIA 411 nor the FERC 714 require that the planning data
control areas and NERC regions submit are consistent with the assumed
facilities, grid configuration or demands assumed in the FERC 715
demonstration of reliability. It would not be a violation of reporting
instructions for regions to submit EIA 411 and FERC 715 data that refer
to significantly different visions of how reliability is to be achieved.

The utility of the FERC 715 is diminished by the uneven quality of
reporting. In particular many of the submitted cases violate line
loading and voltage limits. Contrary to specific instructions some
respondents do not identify generators with EIA names, making it
expensive to merge EIA and FERC data. Contingency lists are unavailable,
though the instructions would seem to require them. And the information
provided on service areas is not sufficient to locate demand centers
(load buses).

The FERC 715 does not require power flow cases of the respondent's
system as it currently exists; the data are for a hypothetical system
that the respondent expects will exist in the future. This has two
consequences. First it is not possible to use the 715 data to compare
actual with calculated power flows as a means of validating the basic
power flow model. Second, it is not possible to show how planned
investments would provide for *additional* transmission capability and
security of the existing system.

Because of the latitude respondents have for picking planning horizons,
models of neighboring regions may refer to different years. That makes
it difficult, if not impossible, to use the regional power flow models
to confirm NERC's estimates of base and incremental transfer capacity.
In fact, the cases do not specifically identify new transmission
facilities; that information is available on the EIA Form 411.

The electrical models that can be constructed directly from this data
only include the reporting area and some of the lines connecting it to
outside areas. Most of the EIA-411 and FERC-715 data is at the NERC
region level. In assessing reliability and security, imports from
outside the reporting region can make the difference between normal
operation and blackout. One way to bridge this information gap is with
estimates of how much power can be brought into a region facing
temporary shortages. That is what NERC does with its incremental
transfer limits mentioned earlier.

Another way to account for the reliability consequences of imports and
exports is to model the interconnections in their entirety. FERC does
not require that be done. For many years NERC has sponsored committees
to piece together their individual FERC 715 filings into a description
of the Eastern and Western Interconnects. This is an arduous, error
prone and expensive process. The resulting models, while useful, reflect
the problems of joining electrical descriptions that reflect different
assumptions, reference dates, aggregation conventions and nomenclature.
Currently, there are limited tools for assessing reliability from a
multi-region and interconnect wide perspective.

As demonstrated in the August 14, 2003 Eastern blackout, reliability
problems cannot be managed or confined to a single utility, control area
or NERC region. Preliminary analyses of the blackout's progress have
repeatedly pointed to the fragmentary information available to system
operators.[^30] As the gird becomes increasingly integrated the need for
interconnect spanning electrical models and supporting data will only
grow.

***Response to Markets:*** The growing importance of interregional power
flows and regional markets requires tighter control over the grid than
is customary in most of the country. High quality electrical models of
the regions and the relevant interconnection are critical to achieving
enough control to allow commercial flows with minimal arbitrary
restrictions.

The incentives facing many market participants are to push the costs of
reliability, information and system control on to others. That way they
keep their costs low and can offer better terms than can "good
citizens." Data on actual investment in the high voltage grid and
information on how those investments were financed and who paid for them
are necessary to quantify the extent of the free rider problem and to
craft solutions. Investments in instrumentation, computation,
communication and other elements of system control are particularly
important. As discussed in Chapter 4, the FERC Form 1 reports more
aggregate investments and does not sharply separate distribution from
high voltage transmission.

The advent of real time pricing would make it possible for customers to
respond to prices. As discussed in Chapter 6 there is little data on how
much load is currently metered to allow real time pricing or of the
amount of power that is being sold at real time rates.

**5. Filling the Information Gaps**

In a regulated, cost-of-service world each utility could reasonably be
held accountable for reliable service within its exclusive service area.
Transmission was secondary to generation; it was cheap by comparison and
utilities simply built lines as needed to serve their customers. With
restructuring some utilities have divested generation and all are seeing
power flowing across utility and regional boundaries in response to
commercial opportunities. That together with the entry of independent
generators supplying local and distant markets, means reliability is
increasingly dependent on building and managing transmission.

Data collections that the government relies on to monitor reliability
have not kept pace with the ascendancy of transmission in a
restructuring industry. The government does not have the power flow
models necessary to verify the efficacy of the industry's reliability
plans as they relate to transmission within a region. The industry's
reported plans are not necessarily those imperfectly analyzed in the
power flow analyses that industry does submit to FERC. Data for
monitoring investments in the high voltage grid, including those to
improve grid control, and indicators of reliability trends are not
routinely available to government. Neither the industry nor the
government has data adequate to allow rigorous cost-benefit analyses of
transmission related investments to enhance reliability.

Much improvement in the government's capability to oversee reliability
could be achieved without new data collections. Instead, were FERC to
modify the FERC 715 and rigorously monitor the quality of responses,
government engineers could construct the power flow models necessary to
confirm current reliability and to examine the efficacy of reliability
plans. The FERC 715 power flow models frequently show electrical
violations, reporting errors, and do not necessarily describe the
existing grid. The government's oversight would be enhanced if the
planning regimes described in the FERC 714 and EIA 411 and 860 were
among the cases evaluated in the FERC 715. FERC and EIA could accomplish
that by first requiring the planning data on the FERC 714, EIA 411 and
EIA 860 to describe the same "plan".[^31] Then FERC could, for example,
require that the FERC 715 power flows show how well the plan provides
for "adequacy" and "security" one year, three years and five years into
the future.

Table 3-3 exhibits many of the specific changes that would be required
to existing FERC and EIA forms.

Table 3-3. Modify Existing Data Collections

+----------------+---------+---------------------+-----+-------------+
| **Information  | *       | **Needed Changes**  |     | **Comment** |
| Need**         | *Form** |                     |     |             |
+----------------+---------+---------------------+-----+-------------+
| 1.High quality | FERC    | 1.Identify load     | The |             |
| power flow     | 715     | buses by MSA.[^32]  | q   |             |
| models         |         |                     | ual |             |
|                |         | 2\. Power flow      | ity |             |
|                |         | cases of existing   | of  |             |
|                |         | system.             | rep |             |
|                |         |                     | ort |             |
|                |         | 3\. Model planning  | ing |             |
|                |         | data for 1, 3 and 5 | is  |             |
|                |         | years in future.    | of  |             |
|                |         |                     | ten |             |
|                |         | 4.Provide           | po  |             |
|                |         | contingency lists   | or. |             |
|                |         |                     | Su  |             |
|                |         | 5\. Explain line    | bmi |             |
|                |         | and voltage         | ssi |             |
|                |         | violations          | ons |             |
|                |         |                     | of  |             |
|                |         |                     | ten |             |
|                |         |                     | do  |             |
|                |         |                     | not |             |
|                |         |                     | use |             |
|                |         |                     | E   |             |
|                |         |                     | IA/ |             |
|                |         |                     | EPA |             |
|                |         |                     | na  |             |
|                |         |                     | mes |             |
|                |         |                     | and |             |
|                |         |                     | c   |             |
|                |         |                     | ont |             |
|                |         |                     | ain |             |
|                |         |                     | s   |             |
|                |         |                     | eri |             |
|                |         |                     | ous |             |
|                |         |                     | e   |             |
|                |         |                     | lec |             |
|                |         |                     | tri |             |
|                |         |                     | cal |             |
|                |         |                     | v   |             |
|                |         |                     | iol |             |
|                |         |                     | ati |             |
|                |         |                     | ons |             |
+----------------+---------+---------------------+-----+-------------+
| 2\. Data on    | FERC    | 1\. Actual hourly   |     |             |
| the recent     | 714     | demand, generation, |     |             |
| adequacy,      |         | inter-control area  |     |             |
| security       |         | power flows         |     |             |
| status of      |         | experienced in      |     |             |
| control areas. |         | control regions for |     |             |
| Data to verify |         | 715 cases (2 above) |     |             |
| power flow     |         |                     |     |             |
| models of      |         | 2\. Experienced     |     |             |
| existing       |         | line and voltage    |     |             |
| system.        |         | violations.         |     |             |
|                |         |                     |     |             |
|                |         | 3.Use EIA/EPA       |     |             |
|                |         | generator names and |     |             |
|                |         | same line/bus       |     |             |
|                |         | identifiers as on   |     |             |
|                |         | the FERC 715        |     |             |
+----------------+---------+---------------------+-----+-------------+
| 3\. A          | FERC    | 1\. Require EIA 411 | Th  |             |
| consistent set | 714,    | and 860 data to     | ese |             |
| of reference   | EIA 411 | describe the same   | pl  |             |
| reliability    | and EIA | plan                | ans |             |
| plans.         | 860     |                     | sho |             |
|                |         | 2\. Require FERC    | uld |             |
|                |         | 714 (Part 111,      | be  |             |
|                |         | Schedule 2. and EIA | the |             |
|                |         | 411 demand          | ba  |             |
|                |         | projections are     | sis |             |
|                |         | consistent.         | for |             |
|                |         |                     | the |             |
|                |         |                     | po  |             |
|                |         |                     | wer |             |
|                |         |                     | f   |             |
|                |         |                     | low |             |
|                |         |                     | an  |             |
|                |         |                     | aly |             |
|                |         |                     | ses |             |
|                |         |                     | 1,  |             |
|                |         |                     | 3   |             |
|                |         |                     | and |             |
|                |         |                     | 5   |             |
|                |         |                     | ye  |             |
|                |         |                     | ars |             |
|                |         |                     | i   |             |
|                |         |                     | nto |             |
|                |         |                     | the |             |
|                |         |                     | f   |             |
|                |         |                     | utu |             |
|                |         |                     | re. |             |
+----------------+---------+---------------------+-----+-------------+
| 4\. Monitor    | EIA 861 | Add a schedule      | To  |             |
| Demand         |         | showing total MWh   | qu  |             |
| Response       |         | metered hourly (or  | ant |             |
|                |         | higher frequency)   | ity |             |
|                |         | and number of MWh   | ext |             |
|                |         | billed by time of   | ent |             |
|                |         | consumption         | of  |             |
|                |         |                     | pr  |             |
|                |         |                     | ice |             |
|                |         |                     | r   |             |
|                |         |                     | esp |             |
|                |         |                     | ons |             |
|                |         |                     | ive |             |
|                |         |                     | d   |             |
|                |         |                     | ema |             |
|                |         |                     | nd. |             |
|                |         |                     | See |             |
|                |         |                     | c   |             |
|                |         |                     | hap |             |
|                |         |                     | ter |             |
|                |         |                     | 6.  |             |
+----------------+---------+---------------------+-----+-------------+
| 5\. Quantify   | FERC 1  | 1\. Adopt NIA       | See |             |
| investment in  |         | definition of       | c   |             |
| the high       |         | investment.         | hap |             |
| voltage grid   |         |                     | ter |             |
| and in its     |         | 2\. Report line and | 4.  |             |
| metering and   |         | associated          |     |             |
| control        |         | equipment           |     |             |
|                |         | investment by       |     |             |
|                |         | voltage level.      |     |             |
|                |         |                     |     |             |
|                |         | 3\. Report          |     |             |
|                |         | investment in       |     |             |
|                |         | metering,           |     |             |
|                |         | communication,      |     |             |
|                |         | software and        |     |             |
|                |         | control of the high |     |             |
|                |         | voltage grid        |     |             |
+----------------+---------+---------------------+-----+-------------+

At such time as reference power flow models are available for regions it
would be appropriate for the Federal government and NERC to build
interconnection wide models.

The government's ability to monitor trends in reliability could be
substantially improved were NERC and FERC to build a time series data
base on security limits experienced on high voltage lines and flowgates,
curtailments, denied service and power flows across the 230kV and above
grid. That would require a formal agreement between FERC and NERC.

Finally, data on the costs of blackouts and substandard power quality,
including what people spend to protect themselves, would be useful.
Given the other needs that data are of relatively low immediate
priority.

[^1]: U.S.-Canada Power System Outage Task Force, *Interim Report:
    Causes of the August 14^th^ Blackout in the United States and
    Canada*, November 2003

[^2]: For examples of differing views see, Richardson, Bill, *Drunk on
    Power*, Barabasi, Albert-Laszlo, *We're all on the Grid Together*,
    and Kuttner, Robert, *An Industry Trapped by a Theory*, all in the
    New York Times, Saturday, August 16, 2003, page A25

[^3]: The EIA Form 417 collects data on outages and power quality
    problems. The EIA Form 411 and the FERC Form 715 collect facility
    and electrical data needed in reliability studies.

[^4]: As mentioned in Chapter 2, the approximately 140 control areas in
    the United States are the basic unit for balancing power flows and
    maintaining power quality within their area.

[^5]: Schweppe, Fred et al, *Spot Pricing of Electricity*, Klur Academic
    Publishers, 1988, pages 137-145

[^6]: See, Chao, Hung-Po and Wilson, Robert, *Priority Service: Pricing,
    Investment, and Market Organization*, American Economic Review,
    Vol.77 No.5, December 1987, pages 899-916.

[^7]: Ibid, see Glossary.

[^8]: NERC's summer, winter and multi-year assessments are available at
    their website www.nerc.com

[^9]: North American Electric Reliability Council, *NERC Reliability
    Assessment 2002-2011: The Reliability of Bulk Electric Power Systems
    in North America*, October 2002, page 7

[^10]: Thermal limits are imposed to prevent overheating of lines due to
    excessive power flows. An accessible discussion of kinds of line
    limits is contained in U.S.-Canada Power System Outage Task Force,
    *Interim Report: Causes of the August 14^th^ Blackout in the United
    States and Canada*, November 2003, pages 5-6.

[^11]: In a contingency analysis, engineers present a power flow model
    of the electrical system with hypothetical demand conditions and a
    base case of operating generators and lines. Large generators and
    major lines are then taken off line one at a time to mimic unplanned
    outages. This is called an n-1 contingency analysis: all but 1 of
    the n pieces of major equipment in the electrical system is assumed
    to operate normally. The analysts note those operating regimes that
    cause failure of other large lines, potentially resulting in
    cascading blackouts. Through a planning procedure, they preclude
    catastrophic failures, essentially "outlawing" failed operating
    regimes, by de-rating vulnerable power lines. The line limits that
    are imposed to ensure that the system continues to operate after a
    failure are called n-1 limits, contingency limits, reliability
    limits or some similar term. If a major piece of equipment has
    already failed, the n-2 limits become the relevant constraints.

[^12]: U.S.-Canada Power System Outage Task Force, *Interim Report:
    Causes of the August 14^th^ Blackout in the United States and
    Canada*, November 2003, page 6.

[^13]: NERC, *NERC Reliability Assessment 2002-2011: The Reliability of
    Bulk Electric Power Systems in North America*, October 2002, page 20

[^14]: NERC, 2003 Summer Assessment: Reliability of the Bulk Electricity
    Supply in North America, page 8

[^15]: Another alternative is to increase safety margins. That would
    require more investment in transmission assets and would lead to
    higher redispatch costs

[^16]: Op. cite, page 23.

[^17]: NERC, *NERC Reliability Assessment 2002-2011: The Reliability of
    Bulk Electric Power Systems in North America*, October 2002, page
    28.

[^18]: Academic economists have proposed market mechanisms for
    determining reliability and paying for it. See, Chao, Hung-Po and
    Wilson, Robert, *Priority Service: Pricing, Investment, and Market
    Organization*, American Economic Review, Vol.77 No.5, December 1987,
    pages 899-916.

[^19]: Oak Ridge National Laboratory, *Load as a Reliability Resource in
    Restructured Electricity Markets*, ORNL/TM2001/97, June 1, 2002. See
    also, Goldman, Charles, Barbose,G., Eto, J., *California Customer
    Load Reductions during the Electricty Crisis: Did they Help to Keep
    the Lights On?*, Journal of Industry, Competition and Trade, 2:1/2,
    113-142, 2002.

[^20]: See Carreras, Benjamin A., Newman, David E., Dobson, Ian, and
    Poole, A. Bruce, *Evidence of Self-Organized Criticality in a Time
    Series of Electric Power System Blackouts*, submitted to the IEEE
    Transactions CAS-1 May, 2002, available at Dobson@engr.wisc.edu

[^21]: Eto, Joseph et al, Scoping Study on trends in the Economic Value
    of Electricity Reliability to the U.S. Economy, Lawrence Berkeley
    National Laboratory, LBNL-47911, June 2001. , page 14.

[^22]: Ibid. page x.

[^23]: "Dynamically-scheduled load" is not included in net interchange.
    Dynamic resources are sources, usually generators, located outside a
    region or control area whose output is dedicated to that control
    area. Since exchanges are explicitly balanced on the FERC 714, no
    distortion should be introduced by the exclusion.

[^24]: ECAR, ***2001 Transmission Line Outages Summary Report***
    (02-TFP-46), December 2002.

[^25]: Ibid, see p. 5.

[^26]: The Federal Energy Regulatory Commission has endorsed the use of
    transmission loading relief orders to individual generators to keep
    line flows below area interchange limits. These orders are based on
    a transaction\'s \"priority\" and not on its economic value. In
    addition, those generators who have a priority cannot sell it to
    others who are willing to pay. A summary of recent curtailments
    appears in Transmission Constraint Study, Presentation of FERC Staff
    to the Commission, December 19, 2001.

[^27]: NERC's website (www.nerc.com) states "the NERC TLR procedure is
    an Eastern Interconnection-wide process that allows reliability
    coordinators to mitigate potential or actual operating security
    limit violations while respecting transmission service reservations
    priorities."

[^28]: This description is taken from the form's instructions which can
    be obtained at
    www.ferc.gov/docs-filing/eforms/form-715/instructions.asp

[^29]: The Form EIA-412 for municipal, State, Federal and generation and
    transmission cooperatives requires reporting of existing and new
    lines. It does not require them to submit power flow cases.

[^30]: See for example, Lipton, Eric, Perez-Pena,R. and Wald, M.,
    *Overseers Missed Big Picture as Failures Led to Blackout*, New York
    Times (National), Vol.CL11....No. 52,605, September 13, 2003, pages
    A1 and A10.

[^31]: The EIA 860 does require that identified planned power plants and
    generators be taken from "planning data." Planning data is not
    defined on the form.

[^32]: MSA stands for Metropolitan Statistical area. An MSA is a
    geographic entity defined by the U.S. Office of Management and
    Budget. Qualification of an MSA requires the presence of a city with
    50,000 or more inhabitants, or the presence of an Urbanized Area
    (UA) and a total population of at least 100,000 (75,000 in New
    England).