Issues Affecting the Electricity Transmission and Distribution System in North America

Executive Summary

After more than two decades of underinvestment, the North
American electricity delivery infrastructure is struggling to meet
today’s changing and ever-growing demands. This was made
evident to the public on August 14, 2003, a warm, calm summer
day when large portions of the Midwest and Northeast United
States and Ontario, Canada, experienced a massive electric power
blackout. The outage affected an area with an estimated 50
million people and 61,800 megawatts (MW) of electric load in the
states of Ohio, Michigan, Pennsylvania, New York, Vermont,
Massachusetts, Connecticut, New Jersey and the Canadian
province of Ontario. The result of this event was to raise the
profile of electricity delivery issues to a place of prominence on the
political agendas of both the United States and Canada.

The North American transmission system, or “Grid,” is a complex
network of interconnected power lines that has evolved over the
last 100 years, delivering needed electricity from more than
950,000 MW of generating stations to well over 100 million
customers. This must be accomplished by constantly keeping the
supply and demand absolutely in balance at all times while
ensuring that customers can flip a switch and be certain that the
electricity they need will be available.

Creating policies to keep the system working is based on striking
a balance between three key drivers: adequate and reliable supply,
acceptable electricity prices and environmental sustainability.

Historically, as the system was developed, vertically integrated
regulated utilities were focused on delivering adequate supply and
reliability, building a system of generating stations and
transmission lines that would support the evolving needs of
electricity consumers. Over the last two decades, there has been
a trend toward deregulation of the sector, meaning the
unbundling of generation, transmission and distribution. The
objective was to develop efficiencies through competition and to
provide broader access to lower-cost electricity generation. In this
model, managing the operation of the grid has become the
purview of Independent System Operators (ISOs) and Regional
Transmission Organizations (RTOs).

Reliability of the system has been managed through adherence to
voluntary reliability standards established through the North
American Electric Reliability Corporation. The cascading events of
the 2003 blackout and the recognition that failure to meet these
voluntary standards was at fault made it clear that this is no
longer sufficient to meet the needs of the system. The major
recommendation of the United States/Canada Blackout Task Force
was to create the Electricity Reliability Organization (ERO), which
would make compliance with reliability standards mandatory, with
penalties for utilities that fail to meet these standards. This was
legislated in the US Energy Policy Act (EP Act) of 2005, and the
new ERO came into being earlier this year.

Improving the reliability of the system must also address its future
needs. Electricity consumption is forecast to grow by more than
40% by the year 2030. In the United States alone, spending on
transmission is growing, with an estimated $31.5 billion to be
spent by 2009. Opposition to new lines makes siting extremely
difficult, and, in many cases, primarily in the United States, cost
allocation is also a major issue. These two issues can and often
do cause delays in transmission projects. The US government has
identified a strong electricity infrastructure as essential to the
country’s economy. As a result, the EP Act of 2005 has put
measures in place to ensure that transmission is built when
needed. These measures include defining a process for the
establishment of national transmission corridors and offering
more attractive financial incentives to investors.

Delivering resolution of the above issues is a daunting task, and to
add to the challenge, this must all be accomplished in a changing
world. Environmental requirements are now causing every aspect
of how electricity is generated, delivered and consumed to be
questioned. Climate change is at the top of the political agenda,
and electricity generation through the use of fossil fuels is a major
source of greenhouse gases. The result is a strong push for new
energy efficiency and demand response programs to reduce
overall use and to shave the peak, while also driving the use of
more environmentally friendly “green” technologies for new
generation. Many of these renewable energy sources, such as
wind or solar energy, have technical characteristics very different
from the more traditional forms of generation. These sources
tend to be non dispatchable, meaning that their contribution to
the grid is intermittent and not easily controllable by the system
operator. This is creating new challenges for the system moving

Addressing many of these issues and moving toward the system
of the future requires the use of new enabling technologies. The
implementation of “smart” meters to enable time-of-use billing
and remote control devices to enable system-controlled demand
response is underway and is changing the very nature of the grid.
This will be followed by the implementation of a number of other
new technologies in the years to come.

This century-old system is experiencing a period of transition
unlike any that has been seen before. Improving the reliability of
the system, while meeting the requirements for growth, all in an
environment of enormous structural and technical change, is a
great challenge for the future. Achieving these goals will be
dependent upon having a well-trained and highly motivated
workforce. Yet the current work force is aging, with about 50%
eligible to retire in the next decade. Therefore, increased
pressures to meet reliability standards, build new transmission and
implement the technologies of the future will make workforce
management much more important.


“On August 14, 2003, large portions of the Midwest and
Northeast United States and Ontario, Canada, experienced an
electric power blackout. The outage affected an area with an
estimated 50 million people and 61,800 megawatts (MW) of
electric load in the states of Ohio, Michigan, Pennsylvania, New
York, Vermont, Massachusetts, Connecticut, New Jersey and the
Canadian province of Ontario. The blackout began a few minutes
after 4:00 p.m. eastern daylight time (16:00 EDT) and power was
not restored for four days in some parts of the United States. Parts
of Ontario suffered rolling blackouts for more than a week before
full power was restored.”1

Modern society has come to depend on reliable electricity as an
essential resource for national security; health and welfare;
communications; finance; transportation; food and water supply;
heating, cooling and lighting; computers and electronics;
commercial enterprise; and even entertainment and leisure—in
short, nearly all aspects of modern life. Customers generally know
little about the system that provides them with their electricity, but
they do expect that electricity will be available when needed at
the flip of a switch. While most customers have experienced local
outages from time to time caused by an accident or severe
weather, what is not expected is the occurrence of a massive
outage on a calm, warm summer day. Widespread electrical
outages, such as the one that occurred on August 14, 2003, are
rare, but they can happen if multiple reliability safeguards break

The North American transmission system is a complex network
that has evolved over the past century to meet the ever-growing
power-hungry needs of society. The system was developed on a
regional basis and expanded on a piecemeal basis, not planned in
an integrated fashion across the continent. The last 20 or 30
years have seen chronic under investment in new transmission, far
below investment in generation. The result is an aging
infrastructure that is falling apart at the seams. With current
environmental requirements and electricity deregulation changing
the rules of the game, the system is being challenged as never
before. And with projections of continuing growth and rapidly
changing technology, huge investments are required to improve
the reliability of the system today and to meet the needs of the
future. Unfortunately, it can take an extreme event such as the
2003 blackout to bring this issue to the forefront and drive
needed action.

In response to a request from ClickSoftware, this white paper will
examine the issues faced by the electricity transmission and
distribution system, including those related to the workforce, as it
struggles to move forward and keep the lights on for the people
of the United States and Canada.

North American Transmission System

The electricity delivery infrastructure represents the culmination of
100 years of development and growth to create a complex system
that must always be in balance while delivering the necessary
electricity from the source of supply to the end user. This
electricity infrastructure represents more than $1 trillion (U.S.) in
asset value, more than 200,000 miles (or 320,000 kilometers) of
transmission lines operating at 230,000 volts and greater,
950,000 megawatts of generating capability, and nearly 3,500
utility organizations serving well over 100 million customers and
283 million people.2

The system is built of a large number of generators of different
types – fossil, hydro, nuclear, wind, biomass and others –
producing electricity at low voltage. This electricity is then
“stepped up” to high voltage for delivery over a network of
interconnected bulk power lines, and then the voltage is once
again lowered for distribution to final customers. This system is
known as the “Grid.”

While customers are used to electricity always being available at the
flip of a switch, in reality, maintaining the grid is a very complex
undertaking that requires a real-time assessment, control and
coordination of the thousands of generators, high-voltage
transmission system and final distribution to customers. This is
because, in comparison to all other forms of energy, electricity
cannot be economically stored, so at all times, supply and demand
must be in complete balance.

The North American grid is largely interconnected but is not one
system. It is actually made up of three major systems. The Eastern
Interconnection includes the eastern two-thirds of the continental
United States and Canada, from Saskatchewan east to the Maritime
Provinces. The Western Interconnection includes the western third
of the continental United States (excluding Alaska), the Canadian
provinces of Alberta and British Columbia, and a portion of Baja
California Norte, Mexico. The third interconnection comprises most
of the state of Texas. In general, these three systems are completely
independent of one another, with only some minor DC connections
between them.

Even though the grids are primarily interconnected in a north /
south flow from Canada to the United States, there remain many
differences in policies between the two countries. In the United
States, electricity policy is established at the federal level and is
regulated by the Federal Energy Regulatory Commission (FERC). The
systems are then managed on a regional and local level by
individual utilities and market operators, which must meet the
requirements of public utilities commissions. In Canada, electricity
is the responsibility of the provinces and each province has its own
policies and regulations. There is little to no federal involvement in
the electricity sector.

Key Drivers Affecting
the Electricity System

Electricity policy is generally determined as a result of striving to
satisfy three key drivers: adequate supply and reliability (technical),
acceptable prices for customers (commercial) and environmental
concerns (social).

This was achieved in the past through the use of relatively large,
vertically integrated utilities that were responsible for all aspects of
electricity supply: generation, transmission and delivery to
customers. These companies operated in a defined service territory
and had an obligation to serve. The objective was to build a strong,
stable system that would assure adequate, reliable electricity supply
at the lowest possible cost. Consumers would pay regulatorapproved
prices based on cost of service. Environmental
requirements were met through adherence to regulations regarding
discharges of pollutants to air and water.

Keeping a balance between these drivers is an ongoing challenge
for policy makers and regulators, as often, these drivers can be in
conflict with one another. Overall, in North America, the low cost
of electricity has been a major contributor to industrial and
commercial development. Supply and reliability can always be
improved by increased investment, but at a higher cost to
consumers. Reducing environmental impacts also drives the system
to add higher cost, but lower emitting sources of supply.

Keeping a balance between these drivers is an ongoing challenge
for policy makers and regulators, as often, these drivers can be in
conflict with one another. Overall, in North America, the low cost
of electricity has been a major contributor to industrial and
commercial development. Supply and reliability can always be
improved by increased investment, but at a higher cost to
consumers. Reducing environmental impacts also drives the system
to add higher cost, but lower emitting sources of supply.

Traditionally, the emphasis has been on meeting technical
requirements to ensure an adequate and reliable system. More
recently, commercial requirements have become more important
and have resulted in deregulation to promote competition and
provide broader access to lower supply costs. Currently,
environmental issues are now having far-reaching effects on the
system as a whole that are driving major changes which will
dramatically affect the way the grid looks in the future.


More recently, to make the system more efficient and lead to lower
costs, many jurisdictions have decided to introduce competition
through deregulation. This was achieved by unbundling the services
into generation, transmission and distribution and by allowing
customers to chose their provider, at both the wholesale and retail
levels. The system is then managed by Independent System
Operators (ISOs), which operate the market.

As part of this restructuring, transmission systems have remained
regulated, due to the recognition that there is a need to make sure
the infrastructure is capable of delivering the electricity. This is being
done by the creation of Independent System Operators.
Wholesale access to transmission grids enables local distribution
companies, or other large buyers, to use the grid to purchase
electricity from the most competitive generation sources. Since the
issuance of Order 2000 in 1999, the FERC has promoted the
formation of Regional Transmission Organizations (RTOs) as the
mechanism to achieve wholesale access, thus enabling US
consumers to obtain lower-cost power from other regions. Finally,
retail access could economically benefit consumers as a result of
their having choice among suppliers.

British Columbia Energy Plan
Zeros in on New Greenhouse Gases

The new BC Energy Plan: A Vision for Clean Energy Leadership
puts British Columbia at the forefront with aggressive targets for
zero net greenhouse gas emissions, new investments in
innovation and an ambitious target to acquire 50% of BC
Hydro’s incremental resource needs through conservation by
2020. Among the highlights:

Environmental Leadership:

  • All new electricity projects developed in BC will have zero
    net greenhouse gas emissions.
  • Existing thermal generation power plants will reach zero
    net greenhouse gas emissions by 2016.
  • Achieve zero greenhouse gas emissions from coal-fired
    electricity generation.
  • Clean or renewable electricity generation will continue to
    account for at least 90% of total generation, placing
    the province’s standard among the top jurisdictions in
    the world.
  • Eliminate all routine flaring at oil-and-gas-producing wells
    and production facilities by 2016 with an interim goal to
    reduce flaring by half (50%) by 2011.
  • Achieve the best coalbed gas practices in North America.
    Companies will not be allowed to surface dischargeproduced
    water, and any reinjected produced water must
    be injected well below any domestic water aquifer.

Energy Conservation and Efficiency

  • An ambitious target to acquire 50& of BC Hydro’s
    incremental resource needs through conservation by 2020.
  • New energy efficiency standards will be determined and
    implemented for buildings by 2010.

Source: BC Ministry Web Site Feb 27, 2007

Deregulation has been successful in jurisdictions with adequate
supply, primarily by increasing the efficiency of existing assets.
However, one of the major issues associated with deregulation is
that there is no longer an obligation to serve since the assumption
is that market-pricing mechanisms would ensure adequate supply.
The result has been somewhat less success in creating appropriate
and timely incentives to build new generation. This has had an
adverse effect on meeting adequacy of supply and reliability
requirements. Markets continue to evolve to meet the ongoing
needs of the system.

Global Warming

Concerns about the environment and pollution have long affected
the choice of generation options and have increased the costs of
generation, such as coal, as pollution abatement equipment has
been added to plants.

At the present time, there is no greater driver to change in the
electricity system than the environment. Environmental issues and,
in particular, global warming have leapt to the top of the global
agenda. A Movie and presentations on global warming have made
former US Vice President Al Gore into a modern cult icon. Recent
reports by Stern in the UK and the IPCC have removed any doubt
as to the importance to the planet of global climate change and the
need to take immediate and decisive action.

Global warming is a result of greenhouse gases entering the
atmosphere from burning fossil fuels. This comes primarily from
two major industries: transportation and electricity generation.
Since it is feasible to generate electricity without burning fossil fuels
through the use of renewable energy sources, including wind,
hydro and biomass and nuclear power, there is considerable
pressure on the electricity industry to reduce its emissions of
Greenhouse Gases (GHGs).

Both the International Energy Agency World Energy Outlook 2006
(WEO) and the US Department of Energy’s Energy Information
Administration (DOE EIA) Annual Energy Outlook 2007 (AEO)
Reference Case clearly show that continuing down the current
policy path will lead to increased use of fossil fuels over the next 25
years, with resultant accelerating increases in carbon dioxide
emissions. The WEO then goes on to state that this result is not set
in stone and that in an alternate policy scenario, the policies and
measures that governments are currently considering to mitigate
carbon emissions are assumed to be implemented. The result is
significantly reduced fossil fuel demand and associated emissions.

It would seem that almost every day, a government or government
agency is announcing new measures to protect the environment.
California has already introduced measures to reduce greenhouse
gases. More recently, the government of British Columbia
announced its “zero emissions” energy plan (see box). And many
more announcements are imminent.

Security of Supply

The need for oil imports from the Middle East has shown how
vulnerable America is to what it considers very unstable political and
potentially anti-American regimes. Since September 11th 2001,
this has added the issue of security of supply to energy
considerations. The result of this concern has been policy incentives
in the EP Act of 2005 by the administration that emphasize energy
independence. These include renewal of the use of nuclear power
and considerable emphasis on continued use of coal, a dirty but
domestically plentiful resource. Considerable research funds are
being invested in new coal technologies, such as “clean coal” and
carbon sequestration, to enable coal to continue to be used, but in
a more environmentally friendly manner.

On the other hand, Canada has been blessed with almost limitless
energy resources, and the current government is very focused on
developing Canada as an “energy superpower,” in part to help
meet the ever-growing needs of the United States. The multitude
of energy choices available in Canada has led to significant regional
differences; Alberta is moving forward with research into new clean
coal technologies while Ontario is committing to shutting down all
coal-burning facilities at the earliest opportunity.

Reliability – Keeping the Lights On

Electric reliability means continuity of service and acceptable power
quality. North Americans have come to expect a very high level of
reliability from the electricity system. Occasional blackouts and / or
brownouts are unacceptable to consumers. The expectation is that
when the switch is turned on, the lights will come on, all the time.

Poor system reliability imposes significant economic consequences
on society. Estimates of the total costs of the 2003 blackout in the
United States range between $4 billion and $10 billion (US dollars).
In Canada, gross domestic product was down 0.7% in August,
there was a net loss of 18.9 million work hours and manufacturing
shipments in Ontario were down $2.3 billion (Canadian dollars).3

Public safety is at risk, as without power, controls of essential
systems (e.g. Traffic lights, public transit, hospital emergency
services, etc) are lost. A large outage in the cold winter months can
leave many freezing in the dark. Many industries are dependent
upon large-volume, reliable power to drive their factories and
processes. Concern over the reliability in a given area can drive
businesses to locate to areas that have more reliable systems, thus
greatly impacting local economies.

Reliability has two key aspects. The first is adequacy of supply,
which means having enough generation and transmission capacity
to meet system need. The second is short-term or operating
reliability, which requires the system to withstand disturbances or
contingencies and be able to continue to operate when there are
problems with the infrastructure or interconnected systems.

The National Electricity Reliability Corporation (NERC) is an industry
organization that draws upon the technical expertise of its
members. NERC has ten regional councils, comprising about 140
control areas in Canada, the US and the northern Baja region of
Mexico. Most Canadian electric utilities/system operators that have
interconnections with other regions are members of NERC’s
regional councils.

Why must there be a crisis to improve reliability?

Prior to the August 2003 blackout, much of the attention
being paid to the electricity industry was related to
generation and the alternatives available to meet demand.
The emphasis was on deregulation as a means to create
competition to both increase efficiency and bring down

The blackout created the crisis necessary to get political
focus on the deficiencies in the grid. And it made it clear
that the system must be improved. A joint US/Canada task
force studied the event for one year and concluded that lack
of adherence to voluntary reliability standards by operators
working to manage the aging infrastructure was the
primary cause.

Its major recommendation was to create an Electricity
Reliability Organization (ERO), which would make
compliance with reliability standards mandatory, rather than
voluntary, as is currently the case with NERC standards.
One year later, in 2005, this recommendation was enacted
in legislation in the EP Act of 2005. And now, after
approving NERC as the ERO in July 2006, the new ERO has
started operations as of January 2007, some four years after
the event.

It is interesting to note that it was another crisis, the big
blackout of 1965, that resulted in the creation of NERC (in
1968) and management of the reliability of the system.

NERC’s stated mission is “to ensure that the bulk electric system in
North America is reliable, adequate and secure.” Toward that end,
the organization develops planning standards and operating
policies, which are the main methods it employs to achieve
reliability. However, in the past, its standards and policies were
voluntary and were enforced by peer pressure.

In July 2006, FERC designated NERC as the ERO under section 215
of the Federal Power Act, a new provision added by the Energy
Policy Act of 2005 to establish a system of mandatory, enforceable
reliability standards under the Commission’s oversight. The ERO will
manage reliability by proposing standards, which are to be
approved by FERC, and then to enforce these standards and levy
fines for non-compliance, subject to FERC approval. Most
Canadian provinces have negotiated participation so that there will
be clear, continent-wide reliability standards and enforceability.

On average, most customer outage incidents are due to distribution
system problems. Some of the most common causes of distribution
outages include scheduled outages, loss of supply, tree contact,
lightning, defective equipment, adverse weather and the human
element. These results suggest that, from the consumer viewpoint,
the reliability of the bulk power system is somewhat higher than
that of the distribution system.

This is consistent with the general view that the flexibility in the bulk
delivery system enables system operators to compensate for
contingencies. For example, if a generating unit experiences a
technical problem and must shut down, the system operator can
call on reserve margins to meet demand. If a transmission line trips
off, the power can flow across different lines so that demand is still
satisfied in each area. In the absence of exceptional circumstances,
consumers will not be aware of the disturbance. However, when
larger bulk system outages occur, they affect more people and tend
to last longer, as demonstrated by the 2003 blackout.

Distribution systems, on the other hand, have less flexibility because
they have less redundancy built into them. The cost of duplicating
the infrastructure would be high and as disturbances on these
systems do not affect as many people, the benefits would be small.
A lack of redundancy and generally longer distribution lines also
mean that rural consumers experience lower reliability than urban
consumers do. This puts added pressure on distributors to be able
to respond to outages and take corrective actions quickly.

So how is reliability enhanced? Primarily through investment in new
generation and transmission to build a stronger system or by
reducing demands on the system in some other manner.

Enhancing and Expanding the Power Grid – Building New Transmission

System improvements and expansion are required to continue
improving the reliability of the existing system, replace aging
infrastructure and accommodate electricity demand growth. The
US DOE EIA Annual Energy Outlook 2007 Reference Case forecasts
an annual growth rate in electricity consumption of 1.5% per year,
for a total increase of 43% by 2030. Growth rates in the Canadian
provinces are projected to be somewhat similar. And all of this
increase cannot be accommodated without increased transmission

As a result, investment in transmission is continuing to increase at a
very rapid rate. Looking across the continent, major plans to add
transmission and distribution infrastructure is universal.

US EP Act of 2005 Designates National Corridors

The EP Act of 2005 directed the secretary of energy to conduct
a nation-wide study of electric transmission congestion by
August 8, 2006. Based upon the congestion study, comments
thereon and considerations that include economics, reliability,
fuel diversity, national energy policy and national security, the
secretary may designate “any geographic area experiencing
electric energy transmission capacity constraints or congestion
that adversely affects customers as a national interest electric
transmission corridor.”

Now that this study is complete, the DOE expects to open a
dialogue with stakeholders in areas of the nation where
congestion is a matter of concern, focusing on ways that
congestion problems might be alleviated. Where appropriate in
relation to these areas, the department may designate national
interest electric transmission corridors.

Source: US DOE National Electric Transmission Congestion
Study, August 2006

In the United States, spending reached $5.8 billion in 2005, an 18%
increase from the previous year. And spending is anticipated to
continue to grow, with $31.5 billion planned to be spent by 2009.
In addition to transmission, accommodating both the significant
replacement needs of the aging distribution infrastructure and
continued growth will require that $14 billion be spent on average
over the next ten years.

In Canada, Ontario has issued a draft plan showing a need for
spending in excess of $4.5 billion in transmission and distribution,
and British Columbia is planning to spend $3.2 billion over the next
ten years. Both jurisdictions have identified that transmission
investment is the highest priority to protect the integrity of the
system in the short to medium term.

Building new transmission lines is anything but easy. Lines can
cover long distances and pass through many communities, which all
have a say in their approval. Although the objective is to minimize
the impact on the community, explaining the benefits and necessity
of the project to community members is complex, and in many
cases the benefits of the project can be outside of the community
being impacted. Therefore, project delays are almost inevitable
during the planning stages as transmission companies work to
address the issues of siting and cost Allocation. This can create
considerable pressure to reduce build times once approvals are


In most cases, building transmission is more difficult than building
new generation as there are frequently several alternatives for
routing (siting) the line. When it comes to transmission projects,
there is a very strong NIMBY (Not in My Back Yard) factor. In fact,
there is a whole industry associated with working with communities
to fight new projects of this type. It has become increasingly
difficult to site new projects, as many opponents are now working
according to the BANANA (Build Absolutely Nothing Anywhere
Near Anyone) principle.

Since these power lines pass over long distances, many
communities are affected. It is thus not always simple to
demonstrate the benefit of a new transmission line to a local
community. Often the benefit is construed to be too far away for
communities that are in need of this new system link.

Many regulators in the United States have clear siting rules and
policies in place. This, coupled with strong utility community
relations programs, definitely helps to get approvals in a more
timely fashion. And new policies in the EP Act of 2005 are also
designed to facilitate new build transmission projects (see section
on strengthening interconnections below).

In Canada, siting issues can be even more difficult, as distances can
be even longer and most transmission projects will pass through
aboriginal lands. The project sponsor must then secure an
agreement with each band whose land the project will impact. In
some projects, this can mean 50 or more agreements, any one of
which can stop the project.

Cost Allocation

In the United States, new projects often go beyond the territory of
one regulator. Regulators frequently have no hard and fast rules on
cost allocation and usually address these issues on a case-by-case
basis. This can create delays in project implementation, and
unpopular rulings may make a project not viable.

In Canada, since most transmission does not cross regional lines,
cost allocation is not an issue. It is within the responsibility of the
provincial regulator to approve the costs and allocate them to the
rate base.

Strengthening Interconnections

Historically, the electric systems in North America were vertically
integrated and each was responsible for a given territory. Whether
companies were public or private, they focused on providing service
to their customers in their regulated service territories. External
trade and energy transfers were of secondary concern.

One of the factors influencing electricity sector deregulation was
that many customers in the higher cost regions of the United States
had no access to lower-cost electricity from other areas. To address
this issue, since the issue of Order 2000 in 1999, the US Federal
Energy Regulatory Commission (FERC) has promoted the formation
of Regional Transmission Organizations (RTOs) as the mechanism to
achieve this wholesale access. The structure is intended to promote
competition by providing non-discriminatory access to transmission
within the RTO area and to eliminate excessive transmission use
charges to reduce costs.

It is generally accepted that increasing interconnections also
increases system reliability, as it makes the system more flexible to
accommodate faults. On the other hand, as seen in the 2003
blackout, the risks can also be higher, hence the need for more
stringent reliability standards, as the system will only be as strong as
its weakest link.

Improvements in interconnections will also result in less congestion.
While congestion is not a result of deregulation, the unbundling of
the system has highlighted the need to address it. In the EP Act of
2005, the US government acknowledged the importance of a
strong national grid, and therefore mandated regular congestion
studies and created the opportunity to create national electric
transmission corridors (see box) to enable new transmission in areas
where there is a need to reduce congestion. In addition, the EP Act
has directed FERC to establish, by rule, an incentive-based rate
treatment for the transmission of electricity in interstate commerce
by public utilities to benefit customers through increased reliability
and reduced congestion.

In Canada, regulating and authorizing the construction and
operation of international power lines and designated interprovincial
lines under federal jurisdiction is the responsibility of the
National Energy Board.

An East-West Grid in Canada?

Regional integration of the electric transmission grid is relatively
strong, with most Canadian electricity connected and flowing in
a north-south direction. In Canada, electricity is under provincial
jurisdiction and the amount of interconnection across provinces
is relatively weak.

Following the 2003 blackout there has been considerable
interest in improving the east-west connections and further
integrating the Canadian grid. This has substantial difficulties,
as the distances are very long, meaning that integration would
be costly and stability would be difficult.

However, there has been good progress in the consideration of
new, broader east-west regional connections. Ontario and
Quebec are improving their interconnection, and there are
proposals to greatly improve the interconnections between BC
and Alberta.

In March 2007, the federal government announced that more
than $500 million of investment through its eco trust is
earmarked to support Ontario’s initiative to create an
interconnection with Manitoba.

Non-Wire solutions

Not all solutions for improving reliability and increasing the flexibility
of transmission systems require new investment in transmission.
Transmission is only one corner of a triangle in which all elements
have to be in balance to create a strong, reliable system. The others
are generation and demand management.

When looking at the need for a new transmission project,
consideration must be given to alternative solutions. One is to
provide new generation closer to the loads. This is becoming
increasingly difficult in the deregulated environment, as locating
generation facilities is not easily accomplished. However, even in
open markets, market operators do have the flexibility to offer
incentives to generators that locate in areas that improve the
reliability of the overall system.

Of increasing interest is the ability to control demand. It is
becoming widely accepted that the lowest-cost KWh is the one not
generated. In the past, demand-reduction programs have been
difficult to implement, as utilities saw little benefit in spending
money to reduce their overall revenues. Therefore, it has become
increasingly important to ensure that programs are well defined so
that regulators will allow the cost of these programs into the rate

The benefit of demand-reduction programs is that they tend to
satisfy all three key drivers affecting the electricity system. Demand
reduction increases supply adequacy and reliability, reduces total
cost to consumers and positively impacts the environment. In fact,
it is the environmental benefits that are driving strong interest in
these programs today. Increased efficiency is the only source of
supply that has zero environmental impact. The US EP Act of 2005
places significant importance on energy efficiency through
mandating improved standards and providing incentives for energy
efficiency programs.

There are two types of demand reduction. In Demand
Management (or efficiency) programs, the total usage of electricity
is reduced, and in Demand Response programs, the emphasis is on
reducing usage during peak times through either temporary
reductions in load or shifting loads to off-peak hours.

It is interesting to note that in Canada, the term “conservation”
continues to be used, while in the United States the term
“efficiency” is more prevalent. While they have the same
objectives, the connotations are considerably different.
“Conservation” still has the connotation of some level of sacrifice
or doing without – as in turning down the thermostat and wearing
a sweater. On the other hand, “efficiency” is all about technology
and achieving the same level of comfort with less. In any case,
there are as many efficiency programs in place as there are
jurisdictions. In fact, lack of uniformity and local and regional
differences in programs are cause for concern as they have the
potential to dilute the benefits of these programs and, in some
cases, cause customer confusion. Most programs to reduce usage
are focused on improving energy efficiency standards for various
types of equipment and then providing incentives to encourage
their rapid assimilation into society.

What is new is the increased emphasis on demand response, or
peak shifting. This has the most impact on transmission issues, as
reducing demand at peak times reduces congestion so that new
transmission can be deferred or cancelled altogether. Deregulated
markets have provided new ways to address this concern. For the
first time, pricing mechanisms are being used to try to change
customer behavior.

This is now possible due to the availability of technology to
implement these programs. For example, implementing time-ofuse
pricing to encourage time shifting of load requires metering
that can provide the data to utilities on time of use. Other
programs, in which automatic controls are put on large appliances
such as air conditioners so that utilities can cycle them off remotely
at times of peak demand, are also possible. Customers who opt for
such programs are offered pricing benefits. In the past, there were
no technologies in place to enable programs such as these.

New Challenges to the Transmission Infrastructure

The requirements for new transmission to replace aging
infrastructure, improve reliability and meet the ever-increasing
growth in electricity demand are certainly enough to stress the
system in terms of resources, both financial and human. However,
this is not all. From deregulation causing uncertainty in generator
type and location, to increased use of renewables with inherent
characteristics that have not been experienced on the grid before,
to the rapid change and requirement for new technologies, the key
strategies in place to address the key drivers in Section 3 place new
and previously unknown challenges on the system.

Independent Power Producers

In the many deregulated markets throughout North America, there
are many independent power producers. Generators build and
connect to the grid depending upon the type of fuel and the nature
of their generation. In some markets, they may be totally merchant
plants, and in others long-term Power Purchase Agreements may
be acceptable.

Different generators can connect to the grid from different
locations. This puts added stress on transmission planning, as
planners do not know the locations of all the future generation in
advance. This means that more robust transmission is required to
accommodate the many possible generating locations. Of course,
the price of connecting to the grid will have to be included in the
costs of the generator, making poor locations more expensive than
good ones. But on the other hand, there is no certainty that
locations very important to the system will end up with appropriate

There is also no certainty in the type of generation being added to
the grid. A nuclear plant’s technical operation characteristics differ
from those of a gas-fired plant or a wind farm. The new grid must
take all these things into consideration.

Growth of Wind Generation in North America

Wind generation continues to grow in both Canada and the
United States.

By more than doubling its total installed capacity to 1,460 MW
by year end 2006, Canada became the world’s 12th largest
nation in terms of installed wind energy capacity. Provincial
governments are currently seeking to put in place a minimum of
10,000 MW of installed wind energy capacity.

The US wind energy industry installed 2,454 (MW) of new
generating capacity in 2006, an investment of approximately $4
billion, making wind one of the largest sources of new power
generation in the country – second only to natural gas – for the
second year in a row. New wind farms boosted cumulative US
installed wind energy capacity by 27% to 11,603 MW.

Source: American and Canadian Wind Energy Associations

Renewables and Distributed Generation

Environmental concerns have led to a very significant political
commitment to new renewable resources. The EP Act of 2005 and
the energy plans of the individual states and Canadian provinces all
provide renewable incentives, either through the tax system (such
as production tax credits) or through incentives by use of either (or
both) renewable obligations and feed-in tariffs. The US DOE EIA
Annual Energy Outlook Reference Case forecasts that renewable
generation will increase by 1.5% per year to 2030, or by 45%.
However, it acknowledges that new strategies to address global
warming will likely put pressure on this number to increase. In its
World Energy Outlook, the IEA recommended that the United
States increase its share of renewables to achieve the alternative
policy scenario.

Specifically, the US EP Act promotes renewable energy resources,
including hydropower. It extends through the end of 2007 the tax
credit for wind, closed-loop and open-loop biomass facilities,
geothermal, small irrigation power, landfill gas and trash
combustion facilities. There are increased tax credits for solar
energy, and new tax credits for fuel cells and distributed generation.

The main renewables being implemented are wind, solar, biomass
and hydro. Of these, only large hydro and biomass are the
traditional dispatchable type of generation that can be controlled as
required by the system. Renewables such as wind, solar and, in
some cases, small hydro, are non-dispatchable or “intermittent”
resources. This means that they are not necessarily available when
needed by the system, but rather when the resource is available,
such as when the wind blows or the sun shines. This has profound
effects on the management of the bulk electric transmission
system. It has effects on system stability and changes the
requirements for system reserve allowances and standby capacity.
In most systems, these forms of generation are run as “base load,”
meaning that they are dispatched first, or, in this case, whenever
available. This may displace more economic generation, thus
increasing electricity costs. ISOs are now starting to understand
how to integrate this form of generation into the grid. Many
studies have been done to investigate the impact of this on the
system and to set targets for maximum tolerable amounts of this
type of generation.

In addition to their intermittency, these resources are not
transportable to a specific site, i.e, the generation facility must be
built where the resource is. Once again, this places new challenges
on the system, as often the best wind can be long distances from
the required load. And given that it can come on and off the grid
at somewhat unpredictable rates, this will have an impact on the
system design and management.

The above applies to larger-scale facilities, such as wind farms.
Renewable generation is also more amenable to more local or
distributed generation. For example, individual homes or
businesses can install solar panels or small wind turbines on their
roofs, which would contribute electricity to the grid at some times;
at other times their homes would be required to use grid-based
power. This means new challenges for the distribution systems as
customers can now also be generators.

Smart Meters and Other Technology Advancements

As discussed earlier, there are many changes in the ways that
electricity is being generated, controlled and paid for. All of these
changes require technology to enable them.

In order for prices to be used to influence behavior, it is essential to
monitor electricity usage as a function of time. Only then can
policies be put in place to charge for time of use. The technology
to achieve this objective is known as “smart metering.” This
requires a large-scale change from the current mechanical bulk
meters that are used to measure electricity usage to new electronic
“smart” meters. There is no one specification for these meters. In
general, they can measure, maintain and transmit usage data to the
utility automatically on a frequency of interest to that utility.

Smart meter implementation is now rampant. The EP Act of 2005
requires each electric utility to provide each of its customer classes,
and individual customers at their own request, a time-based rate
schedule. In addition, the Act goes on to specify that each electric
utility shall provide each customer requesting a time-based rate
with a time-based meter capable of having the utility offer this rate
structure. As a result, most jurisdictions within the United States are
either implementing or have plans to implement smart meters. In
Canada, Ontario has mandated that all consumer bulk meters be
changed to smart meters by 2010 (4.3 million meters), with the first
800,000 meters to be installed before the end of 2007.

Smart meters themselves do not change behavior. Achieving the
desired result is a function of the program design. The cost of
implementing the new meters is significant, and the demonstrated
net cost savings to the consumer must be real and measurable
within a reasonable time frame. There are as many programs as
there are utilities, and a large number of papers describing how to
go about and how not to go about offering time based rates. The
extent to which prices must vary from time to time to encourage
behavioral change remains unclear. While there is considerable
hope for this program, at this stage of its implementation, the level
of success remains uncertain.

The grid is a complex, interconnected system, but it is one where
there is a one way flow – from generation to final users. This is no
longer the case as small generators are added to customer locations
so that at some times of the day they can be users, and other times,
producers. This is the case when customers install their own small
generation so they can either send electricity to the grid or accept
electricity from the grid, depending upon circumstances at the time.
Smart meters are also required to enable this “net metering.”

Other technologies are now being implemented for the purpose of
demand response. For example, utilities are installing remote
controlling technology so that the utility can control equipment and
take it out of service during times of peak demand if supply is at

A typical demand-response system would have a peak-saver switch
installed on a central air conditioner. During critical times (typically
on hot summer days), a signal can be sent to cycle the system down
to reduce the amount of electricity it uses. No change in
temperature would have been noticed. Typical activation would
occur when the electricity supply was reaching its peak, usually on
hot summer weekdays between 2 p.m. and 6 p.m. The activation
period would not exceed four hours. Yet the benefit to the system
is dramatic. Since air conditioning loads are the largest contributor
to the summer peak, widespread use of this technology would
reduce congestion and the need for additional generation and

As the grid evolves into the grid of the future, two-way
communication will be required to remotely control loads to help
manage the system. High-quality up-to-the-minute information will
assist customers, generators and utilities in taking the necessary
actions to keep the system running smoothly.

There are also several new technologies on the horizon for future
implementation to the transmission network. The US EP Act of
2005 provides incentives for a large range of technologies: from
high temperature lines to underground cables, from new
transmission component materials to wireless power transmission
and new electricity storage technologies.

Workforce Issues

Underinvestment in the transmission and distribution system over
the last 20 years has led to an equivalent loss of opportunity to
develop and maintain the work force.

The work force is aging and retirements are looming. A 2004 study
by the Canadian Electricity Association4 noted that workers
between the ages of 40 and 54 make up nearly two-thirds of the
total workforce. For trade-related occupations, over one-quarter of
employees were 50 years of age or older. And of more concern,
only about 7% of the workers were less than 30 years old. The
transmission sector had the most employees eligible to retire, with
almost 30% eligible within five years, and 50% within the next ten
years. This is two-thirds higher over the next 5 years than the total
electricity sector average.

This would be the case if the sector were expected to be stagnant.
But as has already been seen, investment in new infrastructure is
expected to grow significantly over the next 25 years, meaning that
there is a looming shortfall in workers on the horizon unless
immediate action is taken.

Retirement is seen as the number-one work force issue by electricity
sector companies. Retirement has implications much broader than
simply a worker shortage. As workers retire, they take experience
and knowledge with them that, without planning and training, can
be lost to the utility.

Previous sections of this report have discussed the transformation in
technologies in the electricity sector. Application of these new
technologies will put added pressure on the field workforce. New
skills will be required to meet the needs of the technology. Working
on renewable technologies, such as wind or solar, requires new and
more multidisciplinary capabilities to keep them running reliably.

More complex interactive systems will mean that more worker
knowledge will be required to work on these systems. Training will
have to be increased and workers with new and different skills will
have to be added to the mix.

Implications for the workforce

The implications for the workforce are clear. New mandatory
reliability standards will impose more rigorous requirements on field
maintenance and times required to return system faults to service.
This, coupled with a shrinking work force and added technical
requirements, means that there will be a need to ensure that the
right workers are at the right place to do the right work in the
shortest period of time. Therefore, powerful workforce
management will be a necessity to keep the system up and running

Appendix: Glossary of Terms

The following are terms used throughout this document.

Annual Energy Outlook (AEO) – Report prepared by the US
Department of Energy’s Energy Information Administration on an
annual basis to project the trends in energy in the United States.
The AEO 2007 predicts trends to 2030.

BANANA (Build Absolutely Nothing Anywhere Near Anyone) – Term used to define opposition to projects.

Demand Management – Program to reduce electricity usage
through conservation, improved efficiency or other means.

Demand Response – Program to reduce demand during peak
periods through a signal by the system to the customer. Reduction
can be automated or manual.

Electricity Policy Act of 2005 (EP Act 2005) – US legislation
passed in 2005 defining current United States energy policy.

Electricity Reliability Organization (ERO) – Organization to
manage reliability by proposing standards, which are to be
approved by FERC, and then to enforce these standards and levy
fines for non-compliance, subject to FERC approval.

Energy Information Administration (EIA) – Department with
the US Department of Energy (DOE) that is responsible for collecting
official energy statistics from the US government.

Federal Energy Regulatory Commission (FERC) – The agency
that regulates and oversees energy industries in the economic,
environmental, and safety interests of the American public.

Grid – The electricity transmission and distribution delivery system.

Independent System Operator (ISO) – The market operator in
deregulated markets.

International Energy Agency (IEA) – This agency acts as energy
policy advisor to 26 Member countries in their effort to ensure
reliable, affordable and clean energy for their citizens. The IEA
conducts a broad program of energy research, data compilation,
publications and public dissemination of the latest energy policy
analysis and recommendations on good practices.

Intergovernmental Panel on Climate Change (IPCC)
Recognizing the problem of potential global climate change, the
United Nations established the Intergovernmental Panel on Climate
Change to assess on a comprehensive, objective, open and
transparent basis the scientific, technical and socio-economic
information relevant to understanding the scientific basis of the risk
of human-induced climate change, its potential impacts and
options for adaptation and mitigation.

National Electricity Reliability Corporation (NERC) – NERC’s
mission is to improve the reliability and security of the bulk power
system in North America. To achieve that, NERC develops and
enforces reliability standards; monitors the bulk power system;
assesses future adequacy; audits owners, operators, and users for
preparedness; and educates and trains industry personnel.

National Energy Board (NEB) – This is an independent Canadian
federal agency that regulates several aspects of Canada’s energy
industry. Its purpose is to promote safety and security,
environmental protection, and efficient energy infrastructure and
markets in the Canadian public interest within the mandate set by
Parliament in the regulation of pipelines, energy development and

NIMBY (Not in My Back Yard) – A term used for public opposition
to projects within or close to the opponents’ community.

Regional Transmission Operator (RTO) – Regional Transmission
Organizations were created in the United States as the mechanism
by which to achieve wholesale access to transmission in
deregulated markets.

Siting – Term used for selecting routing for new transmission and
distribution and then securing the required approvals for building in
that location.

Smart Meters – Smart meters can measure, maintain and transmit
electricity usage data to a utility automatically on a frequency of
interest to that utility.

World Energy Outlook (WEO) – The WEO is an analysis prepared
by the IEA of the impact of current energy policies, projecting a
vision of how energy markets are likely to evolve. An alternative
scenario analyzes the potential impact of a number of additional
measures to impact energy security and climate change and their