The Need for New Technology

The challenges to achieving a secure and sustainable energy future are both
large and urgent. An energy future that continues recent trends is projected
to result
in global demand that’s four times today’s level, entailing high
consumer costs for energy, greater oil-import dependence, worse local and regional
air pollution, and higher risks of climate change. Moreover, in the next two
decades, over half of global energy growth will be in developing and transitional
economies as these nations continue to improve their standard of living.

These realities call for changing the course of world energy development through
technology innovation. Without significant and global technology innovation,
such rapid growth in total world energy use will further compound the energy-linked
problems and challenges already of great concern today.

Therefore, we have before us a critical window of opportunity to move the world
off its current path and to embark on a trajectory that will at once enhance
energy security and economic growth, while significantly improving the environment.
Clearly, the choices that we make today relating to technology innovation and
policies to promote more efficient and cleaner technologies in the marketplace
will greatly influence energy security, energy costs, greenhouse gas emissions,
oil dependence, and public health and environmental impacts for the balance of
this century.

To address these realities and challenges, the United States has placed great
emphasis on technology innovation and deployment through international cooperation
and effective public-private partnerships. Over the last year, the US initiated
a number of major alliances that are structured to accelerate the development
and deployment of advanced energy systems through public-private engagement.

Innovation Is Critical

As a leader in technology innovation, the US is committed to develop and deploy
a continuum of breakthrough transforming technologies over time, informed by
better science and based on a diverse portfolio of energy sources. Over the last
year, President Bush’s administration initiated, as well as stepped up
participation in, several key international technology efforts that are dedicated
to revolutionizing the way we produce, deliver, and use energy.

The administration’s new Carbon Sequestration Leadership Forum (CSLF) has
brought together 14 countries and the European Commission to collaborate on developing
cost-effective methods to capture, store, and sequester carbon from coal, which
for many countries remains an abundant, economical energy option. The CSLF will
coordinate data gathering, R&D, and joint projects to advance the development
and deployment of carbon sequestration technologies worldwide. The related FutureGen
program is a $1 billion demonstration project to create the first coal-based,
zero-emissions electricity and hydrogen power plant.

To realize the promise of hydrogen, the US launched the International Partnership
for the Hydrogen Economy (IPHE) through which more than a dozen developed and
developing countries will advance cooperative R&D and commercial uses of
hydrogen production, storage, transport, and distribution. This multilateral
alliance also will facilitate the establishment of common codes and standards
and undertake activities to promote hydrogen and fuel cell programs. The US participation
in the IPHE will be advanced by the administration’s groundbreaking $1.7
billion Hydrogen Fuel Initiative that aims to commercialize hydrogen-powered
fuel cell vehicles and supportive infrastructure technologies by 2015.

With respect to nuclear energy, the 11-member Generation IV International Forum
is working on the next generation of safe, economic, emissions-free, and proliferation-resistant
nuclear reactor designs and fuel cycle technologies that could play a significant
role in hydrogen production. The US also rejoined the International Thermonuclear
Experimental Reactor Project. If successful, this $5 billion, internationally-supported
research project will further progress toward producing clean, renewable, commercially
available fusion energy by the middle of the century.

These major technology efforts are part of a wider array of cutting-edge technologies,
including bio-energy and nanotechnology, that the US is actively developing.
They comprise a portfolio of new 21st century technologies that hold out the
promise of offering all people access to affordable and abundant sources of energy
while lessening human impact on the environment.

International Cooperation

These major international initiatives that the US launched last year markedly
confirm the need and opportunity for enhanced international cooperation between
producing and consuming countries. Only through such multinational collaboration
between both developing and developed countries on energy technology innovation
and deployment can we expect to meet the concurrent challenges of economic growth,
energy security, and environmental quality.

The global dimensions of our 21st century energy challenges call for cooperative
efforts to:

  • Develop and deploy technologies that increase efficiencies in the production,
    delivery, and use of energy; increase the use of cleaner, lower carbon or no-carbon
    fuels, processes, and products; and that capture, store, and sequester carbon
    gases from energy systems;
  • Strengthen capacities for energy technology innovation through promoting
    institutional and market reforms, innovative financing, and pre-commercial
    private sector sponsored
    demonstrations of cleaner and more efficient energy technologies; and
  • Scale up demonstration projects to large-scale projects capable of providing
    cleaner energy to millions of people.

International cooperation clearly can help to accelerate global technology
innovation and deployment by reducing research, development, and deployment
(RD&D) costs, speeding and spreading knowledge and technology dissemination,
and increasing the economies of scale with respect to research and demonstration
efforts.

In joining forces, all of the participating countries have agreed to make substantial
long-term commitments to technology RD&D; shape well-defined visions and
national strategies to advance technology deployment and infrastructure development
in the marketplace; and undertake commitments to foster national policies that
will effectively attract, as well as address gaps in, private-sector investment.
These multilateral alliances also allow for collaboration that is more integrated,
systems-oriented, and responsive to market demands and values.

Agents of Change

Public-private partnerships are agents of change to leverage private resources
and share the risks of RD&D. All of the collaborative initiatives described
above are public-private partnerships that recognize the vital role of government
in mobilizing and leveraging critical private-sector investments through arrangements
that will capture the full range of public benefits. Public-private partnerships
can translate governmental policies into solid gains for sustainable development
by bringing together the skills and resources of the private sector and civil
society organizations with government resources and expertise.

As UN Secretary-General Kofi Annan has said, “The most creative agents
of change may well be partnerships – among governments, private business,
nonprofit organizations, scholars, and concerned citizens.” Secretary
of Energy Spencer Abraham has remarked, “Partnerships that leverage scarce
resources, develop technology standards, and foster public-private technology
and infrastructure collaboration can more easily overcome the technological,
financial, and institutional barriers that inhibit the development and deployment
of cost-competitive, standardized, widely accessible advanced energy technologies.”

The US has not only developed public-private arrangements for the longer term,
but also for the near term as part of our president’s energy security
and climate change strategy. For example, in February 2003, the Department
of Energy launched the president’s Climate VISION (Voluntary Innovative
Sector Initiatives: Opportunities Now) program.

This is a public-private partnership between the federal government and 13
trade associations representing all of the major energy-intensive sectors.
Each association has made a commitment to make voluntary reductions in response
to the president’s national goal to reduce greenhouse gas intensity by
18 percent by 2012. The objectives of this program are to:

  1. Achieve cost-effective GHG reductions;
  2. Facilitate the development of effective tools for calculating and reporting
    emissions;
  3. Develop strategies to enable non-industrial sectors to reduce their GHG
    impacts; and
  4. Develop strategies to speed the development and deployment of more
    advanced energy technologies.

The US also is developing government and private-sector partnerships for technology
transfer. At the World Summit on Sustainable Development in Johannesburg, South
Africa, the US launched its Clean Energy Initiative that seeks to improve access
to clean, reliable, and efficient energy services in the developing world.

Accelerating efforts for technology innovation and deployment will require
the public and private sectors to move in better step with one another. The
private sector by itself cannot assure the delivery of “public goods.” Nor
can government act by itself to provide technology deployment.

Because most of the investment in new technologies will be coming from the
private sector, it is important to engage them from the beginning. We are in
the process of working with industry to structure more effective public-private
risk-sharing arrangements that can address the high incremental capital costs
of longer-term advanced technology development. Together, we are identifying
the critical risks to investment and determining which risks are best left
to industry to manage and which pose the greatest problems for industry and
require a government response.

This clarification of risk management will underpin the fashioning of more
risk-targeted government assistance and policy tools and incentives – structured
and timed to facilitate private investment flows.

Finally, the major international public-private partnerships that the US has
launched create exciting opportunities to stimulate collaboration among a wide
array of stakeholders through new structures that can be replicated globally.
The possibilities are enormous, and these alliances can draw upon smaller-scale
endeavors that have developed successful track records. For example, the establishment
of the Icelandic New Energy Ltd. has provided a platform from which different
government and private players have conducted hydrogen projects in Iceland.
A majority of the shares of the company belong to an Icelandic holding company
composed of key players from the country’s investment community, main
energy companies, research institutes, academics, and government. The remaining
shares belong to three multinational corporations.

In the US, the Sunline Transit Agency and Sunline Services Group have significantly
leveraged government seed money through a consortia of public and private-sector
entities to develop a hydrogen and clean energy public transit fleet and
to maintain a public hydrogen fueling station.

Conclusion

Taken together, the US technology initiatives, carried out through international
cooperation and public-private partnerships, are aimed at fostering
a long-term revolution in energy systems that will put us on a path to
stabilizing
greenhouse gas concentrations and ensuring secure, reliable, affordable,
and clean energy
to power economic growth and development across the globe.

Just Don”t Do It

The draft Energy Bill cobbled together in the fall of 2003 was justly excoriated
by everyone from actor Robert Redford to Sen. John McCain for the environmental
problems it would have created and the lavish, budget-busting pork it contained.
However, the subsequent version contained even more landmines for ratepayers
across the country.

The revised bill contained provisions that fundamentally upend the 70-year
balance between states and the federal government concerning how citizens are,
or are not, protected from exorbitant energy prices and over-reliance on fossil
fuels. Moreover, it would destroy one of the fundamental safeguards against
the globalization of US electricity companies and could prompt a merger frenzy
that further imperils electric reliability at a time when our nation is reeling
from recent electricity experiments that left wide swaths of the country in
the dark.

The bill included expanded deregulation of electricity markets. This deregulation
is accomplished by eviscerating the Public Utilities Holding Company Act of
1935 (PUHCA), a key component of the Federal Power Act (FPA), and by severely
limiting the ability of states to regulate the electric companies operating
within their borders.

Proponents promise that effective regulation will be carried out by the Federal
Energy Regulatory Commission. Californians, who experienced first-hand the
see-no-evil, hear-no-evil reality of FERC oversight during the California energy
crisis of 2000-2001, know how hollow and expensive ersatz FERC regulation can
be. More insidious, once California embarked on a dangerous deregulation experiment
and transferred effective control of electric prices to FERC, it stood helpless
as the precarious market it created morphed into all manner of manipulation.
California was reduced to pleading with FERC, which could not or would not
stop the manipulation, the profiteering, the withholding of electricity production,
and the resulting economic damage.

Congress enacted the FPA in 1935 to fill in the gaps in energy regulation where
states had not yet acted, but also to respect and work with states that were
already regulating their electricity systems. California had been regulating
its electric companies since the 1911 creation of the Public Utilities Commission
(CPUC). Then called the Railroad Commission, the CPUC was created by voter
initiative to regulate the prices and practices of the twin economic engines
fueling California’s growth: the railroads as the major transporter of
goods and the electric companies as the major producers and transporters of
the fundamental economic lifeblood – electricity.

At the start of the 20th century, when reliance on electricity was in its infancy,
policymakers knew how crucial an uninterrupted, reasonably priced electric
supply was to the well-being of each state’s economy. They found out
then, through bitter experience, that the free market alone cannot guarantee
a reliable supply of reasonably-priced electricity.

At the start of this century, our elected officials are again faced with critical
policy choices about this fundamental building block of our economy and our
society. We should not be seduced by the rhetoric and the false promises of
the free market. As applied to electricity, theoretical free market models
fail in practice, resulting in inadequate investment in needed infrastructure,
less environmentally sound power options, and higher prices. If we ignore the
past, electric reliability and reasonable prices will become relics of the
20th century. If further deregulation is imposed on the states and FERC is
allowed to use the states as guinea pigs in ill-considered, unformed and ill-fated
experiments to shore up the shaky and unstable foundation of deregulation,
our states’ and our nation’s economies will founder all the more.

Virtually every state will be subjected to the vagaries of FERC’s deregulation
and enforcement whims, and its expensive experiments in enticing companies
to make needed investments and serve customers through providing them excessive
profits from ratepayers’ pocketbooks.

Three particularly dangerous elements found their way into the bill:

Federal Eminent Domain

First, the federal government should not hold the power to condemn land for
transmission lines. This power, disingenuously called “back-stop” siting
authority is right up front in allowing the federal government to use new powers
of federal eminent domain to condemn land in the path of a transmission line,
regardless of whether a state finds that line is needed to provide reliable
electric service in that state. Because the federal government also assesses
the costs of building that line, primarily local ratepayers, businesses, and
families in each state will not only bear the environmental and health burdens
of the transmission line but will also bear the costs, regardless of whether
that line is needed in that community or even in that state.

Proponents of expanding federal eminent domain authority to condemn private
property raise the specter of the August 2003 Northeast blackout for support.
But no evidence exists that state transmission siting processes had anything
to do with the blackout. Moreover, deregulation efforts, not the lack of federal
powers to condemn land for transmission projects, constitutes the primary driver
in the financial uncertainties surrounding transmission financing today.

Ultimately, the Northeast blackout and the California energy crisis were
used as cover for an unprecedented federal power grab from the states and
from state
laws that contain significant safeguards before condemnation can occur. As
the US Conference of Mayors, the League of Cities, and the National Association
of Regulatory Utility Commissioners have all noted, federal eminent domain
will not solve the infrastructure problems confronting the electric industry,
just as the granting of federal eminent domain authority for natural gas pipeline
siting did not solve any natural gas pipeline capacity problems.

Land use decisions, including transmission siting decisions, are best made
at local and state levels, which are more attuned to balance community, environmental,
and cost concerns, and to develop a public, evidentiary record to determine
the need for these major projects.

Indeed, once California began ordering its utilities to upgrade the transmission
infrastructure under a cost-of-service system, California utilities have invested
over $2.3 billion in transmission upgrades alone. The electric infrastructure
can and will be maintained at a reasonable cost, but only if the federal government
does not interfere by overbuilding and overpaying in its zealous pursuit of
making a market work.

Merger Mania

Perhaps the most pernicious aspect of the Energy Bill involves the removal
of the major impediment to go-go mergers and acquisitions of electricity companies
on the scale we saw with Internet and telecommunications companies in the 1990s.
The AOL-Time Warner merger provides but one example of high-flying companies
with no knowledge of how to run an old-economy business gobbling up those businesses
only to run them virtually into the ground through greed or incompetence. Imagine
what will happen to the backbone of our economy, our electric system, when
tomorrow’s darlings of the moment buy up newly unfettered electric companies
without a thought for service and an eye only for profits. Prices will shoot
through the roof, and reliability will drop through the floor.

Now envision layering on multinational and foreign ownership of America’s
electric companies. And of course, the same financial institutions that have
been embroiled in all manner of accounting tricks and fraudulent and preferential
practices for select customers are just itching to bring their style of business
to loot the utility cash cows. In both scenarios, the opportunities for mischief
are even more legion than opportunities for ineptitude. Even Fortune magazine
raised the question whether the blackout had something to do with First Energy’s
1990s buying spree of energy companies in anticipation of deregulation. What
more will like-minded energy companies do with ratepayers’ cash when
freed to launch risky new ventures in areas about which those energy companiesknow
nothing?

Standard Market Design

Third, FERC’s attempt to shoehorn all states’ electric systems
into the misnomer of a “standard market design” is a blatant attempt
to force states concerned about or opposed to energy deregulation into the
deregulated fold. Along the way, consumer and physical protections embedded
in a state-by-state electric system will be tossed aside in the name of free
markets so that all areas of the country can be subjected to the problems California
and the Northeast have experienced under deregulation. As just one example,
standard market design would eliminate the electric system’s “seams,” which
from a reliability standpoint help to compartmentalize outages. The issue concerning
the August 2003 blackout is not, “Did something go wrong in Ohio?,” but
instead, “Why was a problem in Ohio the cause of blackouts in New York,
Canada, and Maryland?”

California has experienced the weak-kneed enforcement of FERC which has bent
over backward not to find the blatant manipulation and market rigging that
cost California’s economy more than $30 billion and for which FERC is
settling purportedly on behalf of California consumers for cents on the dollar.
While FERC refuses to connect the dots, it continues to settle in private without
any coordination with state law enforcement authorities. California has been
barred from the back room where the deals are made with the same companies
that took California to the cleaners. And FERC tried every procedural move
it could to bar California’s appeals to a federal court to examine FERC’s
untoward behavior and settlements.

For the past century, states have proven far more effective in ensuring just
and reasonable electricity prices and in ensuring reliable supplies of electricity
so that businesses and families do not have to wonder, much less worry, if
the lights will turn on when needed. Thus, expanding FERC jurisdiction, at
the direct expense of state protections, subjects businesses and families to
needless risk and unnecessary costs.

And those costs are substantial. As the color-coded map of the United States
in Figure 1 shows, those states that deregulated or started down the deregulation
path now endure much higher electricity costs than those states that never
deregulated. This map contains price data only for 2002 and thus does not reflect
the price increases experienced by many of the deregulated states in 2003,
increases that widen the disparity between the deregulated and regulated states
and that bring home the divergence in the costs of doing business state by
state. While deregulation is not the sole reason for energy prices within a
state, analyzing the national map by this factor shows important differences
that policymakers should consider before ordering deregulation nationwide.

Instead of coercing states to follow FERC’s pied piper of energy deregulation,
Congress should expand the tools that FERC needs to protect consumers when
gouging and manipulation occur. Expanded remedial authority for FERC is necessary,
but not sufficient to get FERC to do its job. Congress should also expand its
direction to FERC to work with state and federal law enforcement agencies to
bring full redress to victims of market malfeasance in the future.

As even free-market observers of California have realized, the structure
of the energy markets is such that before we can authorize market-based
pricing
and rates, we have to eliminate oligopoly and the structural imbalances caused
by the specific ways that California and every other state have divested
their power plants. More importantly, before electricity markets can
work, if in
fact they can ever work, Congress and FERC must shut down the modern forms
of conspiracy and collusion played out through new styles of market-rigging
and market information trading such that regional market power can be exercised
by pivotal suppliers in critical regions.

In the absence of action on these issues, Congress should not set states
on the roller coaster ride of electricity deregulation that went so far
off track
the first time.

Europe”s New Retail Market

The European Union plans to accelerate the pace of electricity and gas market
liberalization and has introduced dates for the phased introduction of full
retail competition (FRC) in both these markets. Some member states have already
implemented FRC arrangements that meet the requirements of the revised directives.

Many, however, have not. For the transmission and distribution systems operators
(TSOs and DSOs) of these member states, the dates for market opening are looming
large.

Experience around the world shows that implementation of arrangements for FRC
is a complex undertaking. Successful implementation can take years to complete.
Those states that have implemented partial competition, and even those that
have full competition but where there has been little interest in the mass
market by external retailers, face a significant task in scaling up their systems
and processes to meet the transaction volumes seen in fully competitive markets.

Based on IBM’s involvement in the successful implementation of FRC in
many jurisdictions, we’ll address:

  • Challenges facing TSOs and DSOs around Europe;
  • Models for FRC already implemented
    around the world; and
  • Key factors that ensure a successful implementation for regulators, TSOs,
    and DSOs, including critical market design concepts, implementation approaches,
    and systems and technology options for retail markets.

European Challenges

The progress of implementing retail competition across Europe to date has been
mixed. Some markets are fully opened and have experienced fierce competition,
e.g., the UK electricity and gas markets and the Nordic electricity market.
There are some markets that are still only partially open, such as France,
and some that are theoretically fully open, but where fierce competition between
retailers has yet to take hold for all customer classes. For these countries,
current processes and systems may only have to cope with registering the switching
of a few thousand customers. Over the next two to three years, we’ll
see a significant change with far-reaching implications for those charged with
implementing new market arrangements.

There are four key factors that will lead to a very active mass retail market:

  • Nondiscriminatory, cost-reflective arrangements for access by third parties
    to all network voltage or pressure levels;
  • Competitive, transparent, and liquid markets in wholesale energy (either
    national markets, or regional markets with non-discriminatory arrangements
    for international
    interconnector or pipeline access);
  • Clear rules and processes for changing retailers that minimize the transaction
    costs involved; and
  • Sufficient scale (again, either nationally or regionally) to encourage
    entry by global mass market retail players.

New EU directives require the designation of a regulator charged with approving
the commercial terms for third-party network access and for the provision of
balancing energy or flexibility services, legal and financial separation of
all distribution and transmission network operations, and phased moves toward
full market opening by 2007.

In addition, the new regulation in the electricity market, and its expected
equivalent in gas, will start to address the issue of charging for international
interconnectors and the allocation of capacity on those interconnectors. This
will increase the extent to which Europe will be regarded as a single market
in electricity and should encourage players to think of regional rather than
national wholesale and retail markets. This may encourage retail players to
participate in markets that would, otherwise, have been below an efficient
scale.

Finally, given the legal mandate for full retail competition, regulatory institutions
are likely to start considering the rules and processes put in place to allow
customers to change retailer, and the extent to which they provide a framework
for an active market.

TSOs and DSOs in either partially open markets, or in markets that are as yet
only theoretically open, will need to consider their response to questions
that are likely to arise, such as:

  • Can existing processes and systems ensure that delivered energy is appropriately
    accounted for and that customers can still be billed with churn rates
    of 10 to 20 percent?
  • Given the requirement for a two-stage market opening (2004 for nondomestic
    and 2007 for full market opening), can the 2004 arrangements be future-proofed
    or will there need to be two separate programs of work?
  • What are the potential costs of creating a fully liberalized market, and
    how will these be recovered?
  • How will a significant internal and cross-industry work program be
    managed?
  • Which market design options will be most appropriate?

International Models

The two broad models that have been implemented around the world – distribution-centric
retail settlement, and direct wholesale market settlement – differ
in the way retail participants interact with the wholesale market.

Distribution-Centric Retail Settlement

The distribution-centric retail settlement model shown in Figure
1 has been implemented in a number of electricity markets in North
America.
This model
is based on a mandatory wholesale market (as is typical in the
North American electricity sector).

In this model, retailers receive their bills for wholesale energy
from the distribution system operator rather than directly interfacing
with
the wholesale
market operator. Retailers (and the DSO to the extent they have
a retail business) strike financial hedges with producers to reduce
exposure
to volatile wholesale
energy prices.

Retailers can opt to bill their end customers directly (direct
retailers), or have the distribution system operator bill the customers
for energy
on their behalf (indirect retailers). DSOs will also charge retailers
for network
access.

In terms of payments to the DSO, direct retailers simply pay the
wholesale price on their estimated consumptions. Indirect retailers
receive the
difference between their retail contract price and the wholesale
energy price.

Because retailers don’t interface and settle directly with the wholesale
energy market, their consumption doesn’t have to be estimated immediately
for the purposes of settling that day’s consumption. The wholesale
market can be settled between producers and distributors, and then
retailers can settle
with distributors through a separate process. For example, their
consumption could be settled on a monthly basis. Depending on typical
meter reading frequency,
this can help to remove the need to continually refine estimates
of consumption as more recent meter reads are collected.

The model is based around a single, mandatory market. It is this
that makes it possible for the distributor to bill retailers for
the energy
consumption
of their registered customers, as it provides a single independently
determined market price. Hence it is most applicable to electricity
markets. However,
in Europe (in contrast to the US), even electricity markets are
typically bilateral in nature, and do not involve centralized mandatory
markets.
Within such a
context, it would be difficult for distributors to bill retailers
for the energy consumption of their registered customers.

Direct Wholesale Market Settlement

Figure 2 shows the broad market mechanics for direct wholesale
market settlement. This model has been implemented in a numberof
European
markets, including
the UK electricity and gas markets, the Nordic electricity market,
and in a number
of states in Australia. It is being implemented in the Irish gas
and electricity markets.

This model is shown in the context of a bilateral contract market
for wholesale energy, but could equally well be implemented alongside
a
mandatory market.

In this model, retailers interface directly with the arrangements
for imbalance settlement, either by themselves or as part of a
balancing
wholesale circle.
Customer consumption needs are estimated under the same timescales
as those used for the imbalance settlement process.

If the imbalance settlement arrangements are based on a rolling
settlement process a given number of days after delivery, customer
consumption
needs to be estimated daily and well within the defined timescale.
Reconciliation
of
imbalance amounts among retailers will be required as actual meter
reads become available. Depending upon the approach to profiling
noninterval metered data
and typical meter reading frequencies, this reconciliation process
may
run for over a year after the settlement day.
All retailers bill customers directly, rather than having the option
of allowing the DSO to carry out billing on their behalf.

Key Factors for Success

Implementing FRC is no small undertaking. The total cost across
all participants of implementing FRC in the UK has been estimated
at €1.5
billion. This cost is attributed to complex market arrangements
and a high degree of systems
development to implement the arrangements.

Today a number of package solutions exist to meet the requirements
of FRC. Coupled with advances in the use of Internet technology
for market
communication,
this has reduced the cost of implementing a competitive retail
market. However, even where simpler arrangements have been implemented
using
configured off-the-shelf
solutions, costs have been significant. For example, central costs
of around €20
million in some Australian states, and company-specific costs in
Canada and Australia of around €20 million. The cost and complexity
of
these programs remains high, and FRC implementations around the
world continue to be characterized
by delays and cost overruns. The risks presented by these programs
can be minimized through careful consideration of the following
four
factors.

Market Design Features

The failure to make appropriate decisions on critical market design
features upfront in an FRC program often comes back to haunt the
program during
its implementation. The procurement and configuration of systems
will be dependent
upon these design features, as will be the interactions required
between participants to effect market transactions. An ill-defined
design is
likely to change during
the life of the program, resulting in increased costs to change
the design being implemented by some or all participants involved.
Even
if the design
does not change, there is still the risk of misinterpretation between
participants that will require change on behalf of one or all parties.
Therefore it
is of critical importance to the success of the program that a
number of design
features
are defined early and with sufficient authority. This will ensure
that systems design decisions can be made with confidence.

Approach to Program Management

Given the size, complexity, and number of participants and stakeholders
involved in implementing FRC, strong and effective central program
management is critical
to the success of the implementation. The key features of such
program management are:

  • Appropriate governance arrangements;
  • Industry-wide clarity on roles and responsibilities;
  • Resource planning;
  • Design control;
  • Systems and processes trialing; and
  • Stakeholder management and communication.

Systems Selection

For those markets that have successfully implemented FRC to date, systems
costs have been a significant part of overall expense. Fully
automated systems solutions
have replaced the simpler systems and manual processes that were
used to support initial market opening. However, as international experience
of FRC implementations
has grown, so have the range of package system solutions that
are available.
It is now possible to avoid significant build and implement FRC
using off-the-shelf
solutions (using either single packages with a wide range of
functionality or best-of-breed integrated solutions).This has dramatically
reduced
the costs of implementing FRC, while also improving the quality of
the solution.

The UK recently began reviewing the systems and processes that support
FRC in gas and electricity in the belief that they were too expensive
to operate
and produced too many exceptions.

The nature of the systems solution will depend upon the overall
market design chosen, and on the approach taken to separation
of network and
competitive activities (and hence the use of legacy applications).

However, in general, the implementation of FRC will have implications
for systems performing the following functions:

  • Customer registration and transfer;
  • Meter data handling;
  • Retailer settlement and billing; and
  • Communications hub.

In defining a systems solution for FRC, the capabilities and constraints of
the existing legacy systems form a key consideration. While many of the package
solutions will claim to meet all FRC requirements fully, the final solution
architecture will typically include a number of legacy systems in one form
or other.

A number of vendors provide solution components for FRC. They include: Excelergy
Corporation, ICF Consulting, ITRON, Lodestar Corporation, SAP, and SPL WorldGroup.

While some of the packages can claim to meet the full scope of FRC requirements,
the specifics of a particular market, key design aspects and the use of legacy
systems (and associated constraints) will typically drive the solution chosen.
In this context, compatibility and ease of integration need to be considered
when selecting components from one or several package solutions.

As Figure 3 shows, the operation of the UK arrangements is split over
four roles:

The Registration Service, which is at the center of
the change-of-retailer process, is operated by the DSOs and maintains
a range of details for each eligible metering point, including the retailer,
the data collector and data aggregator, and the meter registers from
which data is to be collected.

The Data Collector, who is an agent of the retailer,
collects data from interval metered and noninterval metered metering
points. For non-interval metering the data collector provides an estimated
annual consumption where a reading is not available, or an annualized
meter advance where a meter reading has been made.

The Data Aggregator calculates aggregated cumulative
advance meter readings (or estimated annual consumptions where no meter
advance has been collected) by each
profile class.

A Central Agent, who:

  • Calculates and applies profiles to the aggregated data for each
    retailer;
  • Receives data on total transmission system off-takes for each distribution
    area and adjusts profiled estimates to ensure that the aggregated estimates
    are consistent with this top-down figure;
  • Aggregates retailers profiled consumptions nationally;
  • Carries out initial wholesale market imbalance settlement using
    this data as an input; and
  • Carries out subsequent reconciliations among retailers to update
    imbalance settlement calculations as improved estimates of retailer
    consumption (based on actual meter reads) become available.

There is a private data network to manage the flow of information between
all the relevant parties involved in the end-to-end processes of calculating
each retailer’s total demand. While the wholesale settlement arrangements
are, to a great extent, unaffected by the arrangements for retail competition,
it is worth noting that final settlement for retailers does not occur
until around 14 months after the energy has been delivered. This elapsed
time allows a greater proportion of retailer consumption to be based
on profiles applied to actual non-interval meter readings, rather than
on the estimates of the readings used for initial settlement.

The arrangements put in place in the UK electricity market to facilitate
retail competition probably lie at the extreme end of the spectrum of
complexity. For example:

  • Each DSO operates their own registration database, and this is typically
    implemented as a physically separate
    system to the databases that the DSOs’ retail businesses
    use for customer care and billing purposes.
  • The roles of interval meter operator and data collector
    were specified separately and open to competition from
    the start of operation of the new arrangements, with
    their non-half hourly counterparts opened to competition shortly thereafter.
  • There are eight separate regression profiles, depending on customer
    class.

Similarly, while the UK gas market arrangements were simpler initially
(with the majority of the process being managed centrally within Transco)
progressive regulatory moves to increase competition have added to complexity.
Equally, the unbundling of the distribution networks within Transco may
complicate the arrangements further.

Finally, the technology underpinning the UK arrangements reflects the
fact that they were designed and implemented in 1998-1989. For example,
nowadays we would expect Internet technology and communication hub applications
to be used in place of the UK’s centrally managed private data
network. This sort of technology has been implemented in a number of
North American markets and has recently gone live in the Belgian electricity
and gas markets. A similar technology solution is being considered for
the Irish gas market.

 

Implementation and Testing

In addition to the definition of a solution architecture, there are a number
of other key factors in the detailed implementation program itself, which,
in IBM’s experience, are key to success. Two such important factors are
legacy data migration and cleansing, and market testing.

Legacy Data Migration and Cleansing

Existing meter and customer data may need to be migrated from the DSO’s
legacy customer information system (CIS) to the new systems which support FRC.
Alternatively, if the legacy CIS is to support FRC, the structure of the data
may need to be modified. An appropriate data structure is central to the implementation
of FRC. Retailers should be associated with metering points, and metering points
with customers

A retailer may serve many metering points, and an individual customer may be
associated with many metering points. However, this basis of customer registration
may not be consistent with the way in which data is stored in legacy systems.
Equally, the data in legacy systems may not be of the quality required to ensure
accurate accounting for energy delivered post-FRC. Many retail participants
in mature markets continue to have problems billing customers directly as a
result of data quality issues that were not resolved prior to the market going
live.

Market Testing

Sufficient time should be allowed in the overall implementation program for
individual system testing (the usual factory, site and user acceptance testing
processes) and also for end-to-end market testing with market participants.
Given the nature of FRC implementation, it is particularly important to ensure
that all existing participants in the market prior to FRC are able to continue
their operations after go-live. Failure to ensure this could, in the extreme,
result in a failure to account appropriately for energy that has been delivered
and the risk of utilities’ statutory accounts being qualified.

Robust market testing is the key to mitigating this risk. This allows those
participants already operating in the market to test their systems and business
processes against the central systems in order to ensure that end-to-end
market processes operate as intended, and that central and participant
systems can
communicate with each other. The most appropriate approach to market testing
will need to be considered against the specific situation of each country,
and the way in which eligible customers supplied by third-party retailers
will be treated under post-FRC arrangements.

For example, if existing eligible customers will continue to be managed under
existing systems and processes and only migrated on new FRC systems at
a later date (for example, when they next switch), then testing of the
new
systems
and processes may have to involve fewer parties.

Closing the Renewable Energy Gap

The US depends on large, centralized power plants that run on
fossil fuels and nuclear power. As a result, it has an electricity system that
is increasingly vulnerable to volatile fuel prices, supply disruptions, and
dependency on foreign imports. Fossil fuels also pose serious risks to health,
air quality, water supplies, and the earth’s climate.

Fortunately, this growing reliance on fossil fuels and nuclear power can be
reduced with clean renewable energy sources such as solar, wind, geothermal,
and bio-energy. These safe, homegrown energy sources are readily available,
increasingly cost effective, and highly popular with consumers. Recent studies
have shown that increasing America’s use of renewable resources would
create a more diverse
and secure energy system that pollutes less, creates jobs, benefits consumers,
and stimulates rural economies.

Despite the benefits, there exists an enormous “renewable energy gap” in
the United States. Significant market and commercialization barriers force
renewable energy to compete
on an uneven playing field with fossil fuels. As a result, renewable energy
sources (not including hydropower) generate about 2 percent of our electricity
today. Worse, there is no significant national
policy to help renewable energy overcome these barriers. Without new policy
support, the US Energy Information Administration
(EIA) forecasts renewable energy generation will increase to just
3 percent of the nation’s electricity by 2025.

The good news is that a few states are taking the clean energy lead by setting
an example for other states and the nation to follow. These states have adopted
policies like renewable electricity standards and funds, which are designed
to remove barriers and establish long-term markets for renewable energy. But
do they go
far enough to put us on the path toward energy sustainability and independence?

Boundless Potential

Of all the barriers that face renewable energy, an adequate resource base
is not one of them. The United States is blessed with a wealth of diverse renewable
resources. Combined, the major non-hydroelectric renewable technologies (wind,
solar, geothermal, and bioenergy) have the technical potential to provide more
than five times the amount of electricity this country currently uses.1

Renewable resources are well-dispersed throughout the country. Every state
has enough renewable energy technical potential to generate at least one-quarter
of its electricity needs. Thirty states have the technical potential to generate
all of their electricity from renewable energy.

Of course, not all of the technical renewable energy potential will
be tapped, due to economic, physical, and other limitations. But these resources
are certainly sufficient to support a gradual increase in renewable energy
use of 1 percent per year, to at least 20 percent by 2020 or 2025. This level
has been advocated by a growing number of environmental and consumer groups,
and energy companies as an achievable and appropriate mid-term goal in the
transition to a more sustainable energy system.

Despite the boundless potential and strong interest from consumers, only a
few states are currently generating electricity from renewable energy at meaningful
levels. In 2001, renewable energy provided more than 5 percent of total electricity
use in just seven states – Alabama, California, Hawaii, Maine, Nevada,
New Hampshire, and Vermont – and less than 1 percent in 23 of the states.
Sadly, most of the states with low penetrations of renewable energy also have
significant renewable energy potential.

State Leadership

A growing number of states have recently implemented policies to increase the
use of these clean, homegrown resources. Renewable electricity standards (RES),
for example, have emerged in the past several years as an effective and popular
tool for reducing existing market barriers and creating new markets for renewable
energy.

The RES (sometimes called a renewable portfolio standard or RPS) is a simple
market-based policy that increases power supply diversity
by establishing a minimum commitment to generate electricity from renewable
resources. RES requirements and design varies from state to state, but the
policy essentially requires electricity providers to gradually increase the
share of renewable energy in their electricity mix. To date, 13 states have
established minimum renewable electricity standards.

Renewable electricity funds, often referred to as public benefits funds,
also emerged as a popular policy tool for supporting renewable power during
restructuring
of the electric industry. Funds are collected through a small fee on consumers’ monthly
electricity bills. Funding is then distributed to support programs promoting
renewable energy development, with the focus varying from state to state based
on local priorities and interests. To date, 15 states have implemented renewable
electricity funds that, cumulatively, are projected to collect more than
$4 billion to promote clean, sustainable energy by 2017. Eight states – Arizona,
California, Connecticut, Massachusetts, Minnesota, New Jersey, Pennsylvania,
and Wisconsin – have implemented both funds and renewable electricity
standards.

Together, state standards and funds have created significant new markets
for renewable energy that will provide important economic
and environmental benefits well into the future. We estimate that these state
policies will lead to the development of 17,310 MW of new renewable energy
capacity by 2017 – enough to meet the electricity needs of 11.7 million
typical homes (see Figure 1). An additional 7,325 MW of existing renewable
energy capacity receives ongoing support from these policies, for a total of
24,635 MW. Though there are 20 states with standards and/or funds contributing
to this total, it is important to note that more than 80 percent of the development
is supported by policies in just five states.

By 2017, the new development resulting from states with standards and funds
could reduce annual carbon emissions from fossil fuel plants by an estimated
14.3 million metric tons (MMT). This is equivalent to taking 7.8 million cars
off the road.

Renewable electricity standards and funds are not the only policies that states
have adopted to stimulate the growth of the renewable energy industry. States
policies such as net metering, generation disclosure, financial incentives,
and state government purchase requirements have been effective at removing
some market barriers
and promoting some renewable energy development. In addition,
energy consumers in every state now have the opportunity to support renewable
energy directly through voluntary green power purchases. However, the development
from these policies and voluntary approaches has been relatively small and,
in many cases, difficult to attribute to specific policies. For example, a
recent National Renewable Energy Laboratory Study found that voluntary programs
may add only enough renewable generation to equal 0.1 percent of US electricity
sales by 2010, while we project that existing state standards and funds will
add 11.6 times as much by that date.

National Policy

Significant renewable energy commitments
by a handful of states
are a laudable start, but it is not nearly enough
to ensure a national
shift toward a cleaner, more sustainable
energy system. Poor performances and the lack of commitment by most states
to date speak to the need for a comprehensive national renewable energy policy.

While important to the renewable energy industry, national tax incentives
alone are not a comprehensive enough policy. The federal PTC helps level the
playing
field for new renewable energy facilities that otherwise would have to pay
higher taxes than competing fossil fuel
and nuclear plants. It does not, however, create new long-term market demand,
which is critical for an industry with high up-front capital costs. The PTC
has contributed to significant wind power development in
the past few years. But this growth has mostly occurred in states with standards
and/or funds, effectively demonstrating how well these policies can work together.

A national standard would address the fact that the majority of states have
yet to make any specific commitments to renewable energy either through funds
or standards. It would also provide an opportunity to create a more level playing
field among states that have already enacted standards, by enforcing a minimum
standard that states could still choose to exceed.

In the past two years, the Senate has twice passed a comprehensive energy
bill that included a national renewable electricity standard. This standard
would
require major electric companies to increase sales of renewable electricity
by an average of 0.6 percent a year starting in 2005, reaching 10 percent by
2019. A recent study by the Union of Concerned Scientists (UCS) found that
by adopting the Senate standard – along with extending the PTC through
2006 – the US can meet a significant portion of its electricity needs
with renewable energy while generating substantial economic and environmental
benefits. 2

Under a 10 percent standard, the US would increase its total homegrown renewable
power to nearly 80,000 MW by 2020 – which would provide enough generation
to meet the needs of 57 million typical homes. While wind power would provide
most of the new development, bio-energy and geothermal would also make important
contributions. The new power generated by this development would be 3.4 times
as much as the new generation supported by state standards and funds (see Figure
2).

A national RES of 10 percent would stimulate significant economic benefits
through 2020, including:

  • $18 billion in new capital investment;3
  • $1.2 billion in new property tax revenues for local communities; and
  • $430 million in wind-power-related lease payments to farmers and rural
    landowners.

UCS also found that the Senate RES and tax credits would reduce long-run energy
costs to consumers. Increased competition from renewable energy would reduce
natural gas use for generating electricity, which in turn would lead to slightly
lower natural gas and electricity prices. As a result, total annual consumer
energy bills would be $8.3 billion or 1.5 percent lower in 2020. The present
value of total consumer savings would be $17.6 billion between 2002 and 2020.

In addition, increasing renewable energy use in the United States would help
reduce air pollution. Power plant carbon emissions would be reduced by approximately
38 MMT nationwide by 2020 with a national RES of 10 percent. Other pollutants
that harm human health would also be reduced, as would the damage to water
and land resulting from extraction, transport, and use of fossil fuels.

Congress has also introduced several bills over the past few years proposing
a national renewable electricity standard of 20 percent by 2020 or 2025. While
neither the Senate nor the House has yet supported a 20 percent RES, a UCS
study found that doubling the RES requirement is achievable and affordable,
and would substantially increase economic and environmental benefits.

For example, under a 20 percent standard, total renewable capacity would increase
to more than 170,000 MW by 2020. The new renewable generation supported by
this standard would be 3.3 times as much as the Senate-passed 10 percent RES
and tax credits, and 11.3 times as much as existing state standards and funds.

Between 2002 and 2020, a 20 percent national renewable standard would produce:

  • $80 billion in new capital investment;4
  • $5 billion in new property tax revenues for local communities;
  • $1.2 million in wind-power-related lease payments to farmers and rural
    landowners;
  • $4.5 billion in consumer energy bill savings; and
  • 150 MMT of annual carbon emission reductions by 2020.

Recent RES analyses by EIA have reached similar results, despite using pessimistic
renewable energy assumptions and low natural
gas prices. A 2002 EIA study showed that an RES of 10 percent by 2020 would
result in slightly lower electricity and natural gas prices, generating savings
for energy consumers of $13.2 billion through 2020.5 EIA also found that increasing
the standard to 20 percent
by 2020 would reduce natural gas prices enough to offset nearly all of a modest
4 percent increase in electricity prices, resulting in virtually no net cost
increase to consumers.6

A robust commitment to renewable energy in the US
can provide many economic, environmental, health, and security benefits. A
few states recognize this and have become clean energy leaders. But the bigger
picture is one of inaction and wasted opportunities. A strong national policy
with specific targets for making renewable energy a key element of the US electricity
system
is needed.

Endnotes

1 Deyette, J., S. Clemmer, and D. Donovan. 2003. “Plugging In Renewable
Energy: Grading the States.” Cambridge, Mass: Union of Concerned Scientists.
May. Online at www.ucsusa.org/clean_energy/ renewable_energy/page.cfm?pageID=1180.
2 Union of Concerned Scientists. 2002. “Renewing Where We Live:
A National Renewable Energy Standard Will Benefit America’s Economy.” Cambridge,
Mass: Union of Concerned Scientists. September.
Online at www.ucsusa.org/documents/National_Senate_RWWL__2003_ September_Update.pdf.
3 Results presented are in 2000 dollars. Cumulative results are in net present
value using an 8 percent real discount rate.
4 Results presented are in 1999 dollars. Cumulative results are in net present
value using a 5 percent real discount rate.
5 Energy Information Administration. 2002. “Impacts of a 10 Percent Renewable
Portfolio Standard.” SR/OIAF/2002-03. February. Online at www.eia.doe.gov/oiaf/servicerpt/rps/pdf/sroiaf(2002)03.pdf.
6 Energy Information Administration. 2001. “Analysis of Strategies for
Reducing Multiple Emissions from Electric Power Plants: Sulfur Dioxide, Nitrogen
Oxides, Carbon Dioxide, and Mercury and a Renewable Portfolio Standard.” SR/OIAF/2001-03.
June. Online at www.eia.doe.gov/ oiaf/servicerpt/epp/pdf/sroiaf(2001)03.pdf.