Report from New England: Lessons Learned on the Road to Competition

This white paper reviews the restructuring experiences in three New England
states – Massachusetts, New Hampshire, and Maine – and their trials and
successes. Additionally, the paper considers the role of the New England
Independent System Operator in establishing free and open power markets
and the disconnect between the development of the retail and wholesale
electric markets in the region. The New England experience demonstrates
the difficulty in creating competitive markets for an essential commodity
that has historically been subject to command and control regulation and
used as a vehicle to support numerous social programs. The tension between
the popular desire to create a free market and the political will to shield
consumers from the risks inherent in such markets has created distorted
price signals and dampened the growth of a once promising retail electric
market in the region.

Three Different Approaches

By 1997 a number of New England states were fully engaged in the race
to restructure their electric utilities and provide consumers with retail
access to third-party suppliers of electricity. The discrepancy between
low wholesale electric prices and high retail electric rates spurred state
utility regulatory commissions and legislators to find a way to bridge
the gap. States competed to be the first to create new markets that would
hopefully reduce the traditionally high New England energy rates and make
their state more attractive to economic development. The California experiment
with retail access, the Federal Energy Regulatory Commission’s action
to provide open access transmission and competitive wholesale markets,
and the desire to attract new competitors and capture a “first-in” premium,
quickly produced an almost unanimous political groundswell for electric
industry restructuring.

Before any markets were opened and the rules established, eager marketers
from all parts of the country converged upon New England in hopes of capturing
market share and getting a jump on the learning curve that could be used
in other regions opening up their retail electric markets. Three years
later, after the scheduled “customer choice” dates have come and gone
in all three states, many retail energy sellers have abandoned New England.
In several states, retail customers granted “customer choice” in open
access states have no options to choose a third-party supplier because
the marketers have fled, unable to compete with the mandated standard
offers or transition service made available through electric distribution
utilities. All three of the New England states discussed here adopted
distinctively different approaches to introducing competition, and each
achieved varying success in attracting new market entrants.


Massachusetts was one of the first states in the nation to embark on
electric industry restructuring when the Massachusetts Department of Public
Utilities opened an investigation into the matter in February, 1995. In
a number of decisions over the next two years the Department announced
its general principles for restructuring and concluded that there is a
strong public policy basis for providing electric utilities a reasonable
opportunity for recovery of non-mitigatable stranded cost. While the Department
did not accept the utilities’ legal arguments that they were absolutely
entitled to such recovery, based upon exclusive franchises, it recognized
that lengthy litigation over the matter could derail efforts to introduce

While developing rules and requiring utilities to file restructuring
plans, the Department encouraged stakeholders to negotiate settlements
as the most efficient means of moving forward. In October, 1996, Massachusetts
Electric Company (MECo) filed a settlement with the Attorney General and
numerous other parties, under which MECo agreed to provide retail access
to its customers, divest its generating assets, and implement an immediate
10 percent discount in its rates. The parties also agreed that MECo should
be allowed to recover all of its non-mitagatable stranded costs through
a Contract Termination Charge over a 12-year period.

The MECo settlement provided a framework for the Department’s Electric
Industry Restructuring Plan issued in December 1996. The Department concluded
that it required legislative authorization to implement its plan, which
would provide immediate consumer benefits through mandatory rate reductions,
allow utilities an opportunity for full-stranded cost recovery, and prevent
vertical market power by encouraging voluntary divestiture of utility-owned
generation. The Plan also provided that distribution service would remain
a monopoly service and postponed consideration of whether to allow competition
in metering, billing, and information services (MBIS).

After the filing of several other utility restructuring settlements,
and approval by the Department of the MECo proposal, the Massachusetts
Legislature enacted restructuring legislation in November 1997. The legislation
embodied most of the principles in the Settlements and the Department’s
Plan, and mandated rate decreases of 10 percent in 1998 and 15 percent
in 1999. The Legislation also included adders to distribution rates for
energy efficiency programs and to support renewable sources of generation.

The compromise reached by the legislature on stranded cost recovery and
rate reductions produced an immediate barrier to market entry entitled
Standard Offer Service. All customers would be eligible to continue to
take service through the standard offer which would include three parts:
the stranded cost recovery charge, the distribution charge, and the Standard
Offer for generation. In order to ensure the mandated discounts, utilities
were to price their “standard offer” at a rate below wholesale prices
and could defer for collection in later years, the difference between
the wholesale price and the artificially deflated Standard Offer.

All of the Massachusetts electric distribution companies filed restructuring
plans or settlements and opened up to competition on March 1, 1998. Unfortunately,
the below-market standard offer made it extremely difficult for new market
entrants to offer a “competitive” price without taking the risk of a large
loss leader in the early years and gambling that the new markets would
eventually reduce wholesale prices to the levels of the standard offer.
Two years after open access, only 0.2 percent of Massachusetts residential
customers are buying competitive supplies, and only 19 percent of industrial
customers have switched. By comparison, in Pennsylvania, almost 10 percent
of residential customers and 56 percent of the industrials are buying
competitive supplies. 1

New Hampshire

New Hampshire, which was paying the highest electric rates in the country
to one electric utility serving over two-thirds of the state, took a decidedly
different tack than the Massachusetts negotiation and settlement strategy.
After attracting significant market interests in 1996 with an electric
competition Pilot Program, the legislature provided the Public Utilities
Commission with a broad outline for electric industry restructuring and
directed them to implement that plan in short order. Encouraged by the
flood of marketers participating in the Pilot Program, the legislature
and Commission focused on creating a truly “competitive” market, and included
no hard and fast requirements for immediate rate reductions or discounted
standard offer service.

The Commission’s Final Plan sought to impose a new regulatory regime
by which any stranded costs recovery would be tied to a comparison of
a utility’s rates with a regional average. Utilities with rates at or
below the regional average would have an opportunity for 100 percent recovery
of their standard costs, while those above the regional average (i.e.,
Public Service Company of New Hampshire) would not be allowed to recover
that percentage of their stranded cost equal to the percentage by which
their rates exceeded the regional average. This recovery mechanism was
based, in part, upon the Commission’s determination that as a matter of
state and federal law, utilities had no legal right to stranded cost recovery,
even if they purchased the power under federally approved wholesale rates
that have traditionally been found to preempt any state attempts to disallow
those costs in retail rates.

The Commission’s Final Plan led to immediate litigation in the federal
courts and a stay of the state’s restructuring plan. While the MECo affiliate,
Granite State Electric, was able to develop a settlement along the same
lines as the Massachusetts plans, the other utilities in the state have
been involved in the federal lawsuit for over three years, including five
interlocutory reviews by the 1st Circuit Court of Appeals.

In August 1999, PSNH filed a comprehensive settlement that provided for
implementation of electric retail choice in 2000, an 18 percent electric
rate reduction for standard offer (transition) service customers, divestiture
of PSNH’s generating assets, a write-off by PSNH of $367 million in stranded
costs, and securitization of up to $725 million of PSNH’s stranded costs.
In conditionally approving the settlement, the Commission required PSNH
to absorb additional stranded costs and increase the transition service
rates in order to bring them closer to wholesale prices and avoid creating
large deferrals for later recovery.

In June 2000, the New Hampshire Legislature passed, and the governor
signed, new legislation authorizing securitization of PSNH’s stranded
costs, establishing transition service rates and requiring a system benefits
charge. The law required certain revisions to PSNH restructuring settlement,
which are currently under consideration by the Commission. Assuming those
modifications are approved, most of New Hampshire is now open to competition
– over three years after the originally mandated customer choice date.
It may be too early to predict whether marketers will return to New Hampshire,
but at this time there is only one registered competitive supplier in
the state.


The Maine legislature also passed electric restructuring legislation
in 1997, but provided for a three-year implementation period culminating
with retail choice in March, 2000. The extended period for accomplishing
restructuring provided the Commission with an opportunity to conduct numerous
rulemakings and consider stranded cost recovery and restructuring plans
for each of the electric utilities in the state. The Maine restructuring
statute includes a requirement for standard offer service through at least
2004, divestiture of generation assets by March 1, 2000, and stranded
cost recovery determined by the Commission, with true up at least every
three years.

During 1998 and 1999, prior to the start of retail access, all of the
Maine electric utilities sold their fossil fuel generation assets through
auctions, which proceeds allowed them to mitigate their stranded costs
and reduce rates or deferrals. The Commission also completed proceedings
on establishment of stranded cost recovery for each of the electric utilities.
These proceedings culminated in settlements or stipulations establishing
not only stranded cost recovery, but also the unbundled transmission and
distribution rates and new rate designs.

The one area in which Maine has encountered difficulties is in the solicitation
of Standard Offer suppliers. The Maine Commission, like several other
states, has conducted auctions for standard offer service from third-party
suppliers. The intent of bidding out the right to serve customers is to
counteract any advantage of the incumbent utility. Commission mandated
auctions in 1999 for standard offer supply yielded bids which the Commission
ultimately determined were too high for two of the three participating
utilities. The Commission has sought to balance the need to keep rates
down with desire to make the Standard Offer as close as possible to actual
market prices so as to encourage new market entrants.

The standard offer rates in Maine are move “competitive” than those adopted
in Massachusetts, and the impact of these prices can be seen in the greater
migration of customers to competitive electric providers. In the first
four months of open access in Maine, a large portion of industrial customers
have switched to competitive suppliers, though there has been little movement
of residential customers.

The Power Markets: Price Administration or Reregulation

In attempting to design a market structure for competitive retail markets,
all of the states recognized the importance of creating a workable wholesale
market as a key ingredient to restructuring the electric industry. The
New England wholesale market operates over a coordinated transmission
grid or power pool known as NEPOOL. In 1997, NEPOOL which was formerly
controlled by the integrated utilities which were the major transmission
owners, restructured to create an Independent System Operator (ISO-NE).
The ISO-NE is a not-for-profit, private corporation charged initially
with management of the regions electric bulk power generation and transmission
systems and ensuring open access. As of May 1999, the ISO-NE also administered
the restructured wholesale electricity marketplace for the region. Market
participants buy and sell seven electricity products through an Internet-based
market system.

In New England, and more recently in California, the price spikes in
the volatile new wholesale electric markets have collided head on with
the desires of end users, regulators, and legislators to shield consumers
from such risks. After all, the intent of restructuring the electric industry
is to harness the forces of competition to reduce overall prices to consumers,
not enrich marketers and generators. Electricity’s unique characteristics,
however, make price volatility inevitable in a free market.

Electricity can not be economically stored, creating a need to constantly
balance supply and demand.2 Moreover, demand for electricity is extremely
inelastic during the short run, and there is a constant need to ensure
reliability of the grid.3 Thus, when demand rises above production, the
inelastic demand results in higher prices, which prices do not necessarily
produce increased supply or decreased demand, but rather can result in
extreme price spikes.4

In May 2000, an unseasonably hot day in New England coincided with a
number of planned and unplanned outages of generating units. The resulting
demand and price escalation was from $10 per megawatt to $6,000 per megawatt.
The reaction of the ISO-NE to a comparable price spike in the previous
year was to seek a retroactive price cap. While the ISO-NE is now investigating
the cause of this year’s spike, many parties are seeking imposition of
price caps to protect against such price volatility.

The issue has not attracted the same attention as in California, however,
in part because consumers in states like Massachusetts are protected from
any short-term impacts. Under the retail regulatory regime, utilities’
standard offer and default service rates are capped to ensure the mandated
15 percent discount. To the extent the utility is purchasing supplies
that reflect the volatile market rates, any increases in the actual cost
of standard offer or default service above the overall rate ceiling are
deferred for future recovery. Thus, consumers are shielded from the actual
market prices today, but they face prospects of paying for those increases
somewhere down the road when the utilities’ combined rates fall beneath
the overall price cap. The danger is that these artificial upfront discounts
will create growing deferrals that will continue for years to prevent
imposition of accurate price signals.


Replacing regulated electric prices, subject to command and control regulation
for over 100 years, with competitive retail and wholesale markets can
not be achieved overnight. Decision-makers may have to choose between
guaranteed price reductions, which will inhibit market entrants and postpone
the development of a viable market, and exposing consumers to the risk
that the market may not produce savings in the short run and will inevitably
be volatile. A structured timetable, rather than a rush to the finish
line, allows opportunities for consensus-building, negotiation, and settlement.
Postponing the scheduling of retail choice may provide sufficient time
for divestiture of utility assets and market development, so that customers
actually have competitive options on the date retail access occurs.

Imposition of artificial rate reductions through retail price caps may
be the price to be paid for gaining a political consensus to accomplish
restructuring. While such compromises may be preferable to attempting
to achieve immediate rate reductions through litigation, they create a
potential for ever-increasing deferrals of costs that will eventually
be passed onto consumers. These artificial discounts also prevent accurate
price signals that are essential to a fully operational market.

The issue of price volatility in wholesale electric markets will likely
be addressed in multiple forums in the coming months and years. Shielding
customers from these impacts and deferring the recovery of market increases
for years will not allow for an informed debate. A viable and competitive
market is one in which customers are to be provided an opportunity to
choose, even if they do not exercise that option.


1 Admittedly, Pennsylvania has taken the opposite approach and instituted
“shopping credits” at prices above the utilities’ cost of supplying power,
thus providing an incentive for migration.

2 Severin Borenstein and James Bushnell, Electricity Restructuring: Deregulation
or Reregulation, Regulation, Vol. 23, No. 2, 2000, pp. 48-49.

3 Ibid

4 Ibid

How Did We Get Here?

For eight decades, the electricity supply industry and its customers
enjoyed the benefits of increasing economies of scale. Electric utilities,
people reasoned, were natural monopolies because they enjoyed economies
of scale. In other words, the larger the generating station, the lower
the cost per unit of output. In order to assure that the utility could
install the largest possible unit and operate it at maximum output, the
state would prevent others from selling in that market. (Many small generators
would produce electricity at a higher cost than one large generator.)
Then, in order to assure that consumers would capture the benefits of
the lower costs, rather than the monopolist, the state regulated the price
charged by the monopolist, limiting the price to costs incurred, plus
a fair profit for the capital employed.

As the industry installed larger generating stations, the cost per unit
of output declined. Thanks to the regulatory system in place, the utility
had to pass on to customers those cost reductions in the form of lower
prices. Customers took more electricity because of lower prices and a
plethora of new uses. Higher sales volume enabled the utilities to install
even larger generators. That reduced costs and prices even more, and the
cycle continued, until the 1960s, when conventional steam generating stations
ran up against the efficiency limits inherent in the Rankine Cycle. From
that point forward, electricity suppliers could eke only minimal additional
efficiencies from the system, not enough to overcome the inflation in
other costs.

Solving the Problem

Electric utility executives did not rest on their laurels. They embraced
a technology that they knew would bring about an unprecedented new age
of abundant and cheap electricity – nuclear power. Unfortunately, nuclear
power raised rather than lowered costs, and the financial stress of financing
the long-drawn-out construction processes pushed many utilities to the
brink of, or into, bankruptcy.

Ironically, during the 1960s, equipment manufacturers introduced the
stationary gas turbine, a derivative of the aircraft jet engine, as a
power generator. Utilities must have viewed these little devices with
as much disdain as did the American automobile manufacturers when they
saw those first, tinny, little Japanese imports. “Gas turbines? They’re
okay for peaking,” they said. Over the coming decades, though, manufacturers
perfected the gas turbine, raising it to unprecedented levels of efficiency
and reliability, while the conventional, huge power station favored by
the utilities showed minimal improvement. The electric utility industry
had bet on the wrong horse. Or better still, at a key point in the industry’s
evolution, the industry bet on the dinosaur instead of the rat.

Figure 1
The evolution of electricity pricing and the power plant (Source: Leonard
S. Hyman, Andrew S. Hyman, and Robert C. Hyman, “America’s Electric Utilities:
Past, Present and Future” (7th Edition) Vienna, VA: Public Utilities Reports,
scheduled for 2000 publication).

Figure 1


Technological change will not take hold if the only possible users of
it resolutely decide to ignore it. The utilities, after all, did have
a monopoly on electric generation, unless you planned to do it yourself
off the grid. Congress changed that stranglehold on generation when, in
1978, it passed the Public Utility Regulatory Policies Act (PURPA), whose
Title II established a special type of generator that could sell its output
to utilities. Those qualifying facilities (QFs), in the main, employed
gas turbines to produce electricity. The independent power producers,
over the next decade, demonstrated that they could efficiently and reliably
build and operate the new power stations.

The electric industry pushed up prices to reflect higher costs due to
nuclear cost overruns, environmental controls, and higher fuel costs.
Industrial customers began to notice that the independent power producers,
without the baggage that the utilities carried, could produce electricity
for less. Some industrial customers realized that they could put in their
own generation and produce power for less than the local utility charged.
Small, modern gas turbines produced electricity at costs competitive with
those of large electric utility generators. Electric utility generators
no longer had a natural monopoly. Regulation now protected the utility
against competition rather than the consumer against exploitation by the
monopolistic utility.

Industrial customers first noticed the increasing gap between price and
marginal cost. They began to demand lower prices, threatening to move,
close up, divert production to other places, or self generate unless the
electric utility reduced prices to them. The utilities or the state regulators
usually caved in to the pressure. Industrial customers gained the benefits
of competitive pricing despite the lack of competitors.

In 1992, Congress passed the Energy Policy Act, which removed restrictions
on independent power producers and enjoined the transmission-owning utilities
to open their lines to all comers, including competitors that needed the
utilities’ lines to transport power to the utilities’ own customers. The
industry paid little attention to the change. The Federal government moved
slowly and had jurisdiction over only a small part of the industry’s sales.
Then regulators in California decided to ask why Californians paid such
high prices for electricity, and other high-cost states quickly began
their own inquiries. By the end of 1996, 14 states had either enacted
new regulations or had investigations underway with action likely to open
up the electricity market to competition at the retail level. The old
state-protected monopoly seemed on the way out.

The Reaction

Utilities reacted to the changes in law and the threat of competition.
They decided to invest in utility properties abroad, because of greater
opportunities for growth. They put money into unregulated generation in
the United States, figuring that they understood that business. Many utilities
decided to get out of the regulated generating business, and some decided
to get out of the generating business altogether. Success in the commodity
generating market required expertise and scale that the exiting utilities
believed they did not possess.

For that matter, the utilities believed that they had to achieve greater
scale in their overall operations in order to efficiently serve consumers.
They had to offer consumers a greater choice of energy services in order
to remain competitive. They required a wider range of skills, too, in
order to succeed in rapidly changing businesses. Rather than attempt to
develop scale, scope, and expertise internally, the utilities launched
into a wave of mergers probably unprecedented since the 1920s. They bought
or merged with neighboring electric and gas utilities, natural gas pipelines,
energy traders, telecommunications firms, and even water utilities. Meanwhile,
foreign utilities eyed the U.S. market, plunged into generation and power
trading here, and then purchased two large utilities.

Utility managements know best how to manage regulation. They proved that
during the restructuring process. In almost every jurisdiction, they convinced
regulators of the need to allow the utilities to recover the costs that
were supposedly “stranded” by the introduction of competition – that is,
the costs above the competitive level that they could not charge customers
in a competitive environment.

The states, however, wanted something in return. They introduced competitive
choice for retail customers, demanded immediate price reductions from
the utilities, and in order to create competitive markets, many states
insisted that the local utilities sell off their generating plants, so
they could no longer exercise local monopoly power over both generation
and distribution of electricity. Meanwhile, Federal regulators worried
that the utilities, as owners of generation and transmission assets, would
operate their transmission lines in a manner that would disadvantage competitive
generators seeking to reach the market. Therefore, late in 1999, the Federal
Energy Regulatory Commission told the utilities to put their transmission
lines under the supervision of independent regional transmission organizations.
That order could encourage some utilities to get out of the transmission
business altogether.

Neither the shareholders nor the managers of the investor-owned utilities
seemed to know how to react. Despite regulatory settlements, sale of power
plants at high prices, and the recovery of stranded costs through securitization,
utility stocks performed poorly. Perhaps the old utility investor, who
sought high dividends and steady income, no longer approved the new mix
of foreign investments, domestic competition, and uncertain dividends.
The utility companies, despite the dramatic changes in the business, not
only maintained the old financial policies, appropriate for the regulated
monopoly, but they actually put on more debt than before, acting as if
the business had gotten safer than when they had the monopoly. No wonder
investors were confused.

As illustrated in Figure 2, the business turned upside down within a
few years, but some folks did not seem to notice.

Figure 2
Trends in the utilities industry (Source: See Figure 1.)

Figure 2

What Next?

The electricity supply sector barely has moved into the competitive era.
The same managements run the same corporations with the same financial
structure and shareholder base as before. Consumers have limited choices
determined by regulators, who (in conjunction with state legislatures)
continue to set prices for much of the business. Transition periods stretch
on for years, with different terms for each state, thereby balkanizing
the market in a way that discourages the formation of nationwide competitors.

But, if a revolution in generating technology, aided by a worldwide retreat
from government regulation of the economy, could upset a well entrenched
industry over a 30-year period, how long will it take for the next technological
revolutions – encompassing distributed generation, time-of-day metering,
a more efficient transmission network, and the Internet – to shake up
a market that has not even completed the restructuring prompted by the
last revolution?

Major industrial corporations have launched programs to develop and market
small generators. Both microturbines and fuel cells could go on sale in
volume within two or three years. Those small generators could enable
consumers to either bypass the electric grid altogether or to limit their
use of grid electricity when price rises too much. Obviously, that distributed
technology could threaten the monopolistic position of the distribution
network and the profitability of power stations that make their profits
during peak periods.

Customers, of course, need real-time metering that allows them to make
decisions. Right now, the market does not take into account consumer reaction
to price, because most consumers do not see price until months later,
when the electric bill arrives, or maybe not at all. Competition will
not work until customers see prices. When they do, their reactions could
upset many a plan devised by aggressive electricity suppliers whose profitability
depends on shortages that might melt away when price rises in a visible,
real-time manner. Thus, real-time metering could have a profound influence
on the industry.

Generators today seem to assume that the transmission network remains
in its strangled state, with no improvements possible due to lack of financial
incentives. Even regulators will wake up to the possibilities, after a
few scary summers of shortages. Yet means do exist to improve the operation
of the network, without stringing new lines, and the introduction of more
economical DC technology and, later, superconducting cable, could transform
the network over the coming decade. Imagine the possibility of a deadly
price war that pits local central station generators against distributed
generation on one side and distant central stations that can now reach
the market, thanks to improved transmission, on the other. Then, consider
that Internet suppliers can cut out middlemen and achieve direct access
to the utility’s customers. They can run virtual utilities, relegating
the old utility to the position of supplier to the virtual utility, which
has the all-important contact with the consumer. Internet markets can
replace vast trading floors and reduce the value of expensively acquired
trading operations.

Is that all? The next revolutions, the third wave, could encompass decarbonization,
the hydrogen economy, and interactive markets between consumers and producers
that do away with the intermediary organizations that the regulators,
utilities, and marketers have worked so hard to erect. This will no longer
be the “old utility business.”

Global Trends in — and the Practical Effects of — Liberalization and Other Regulatory Approaches

It is important to start by clarifying what is meant by my use of the
term “liberalization.” To “liberalize” has a number of shades of meaning,
two of which are of particular relevance to the electricity reform that
is currently sweeping the world’s power industries:

  • To effect progress and reform

  • To promote individual freedom

Liberalization carries with it, therefore, both reference to a process
of the removal or reduction of barriers, regulation, and control, and
the implication that this process is a beneficial one. In the energy sector
context, liberalization is concerned with developing the freedom of suppliers
to take an active role in the extraction, refining, generation, distribution,
or supply of energy products and the freedom of customers to choose, on
price and quality, between different energy products and suppliers. It
is not a single process affecting only limited elements of a whole; it
is a process with many facets, affecting a wide-ranging number of elements
of the sector.

The motivations for liberalization to be entered into can be summarized
into three main categories :

  • The need to address energy sector inefficiencies and deficiencies
    such as the supply/demand gap; the lack of the necessary power asset
    infrastructure; and wider economic inefficiencies such as the inefficient
    use of fuel and heat brought about by uneconomic tariff arrangements

  • International pressures including momentum for reform brought about
    by international accords such as the Kyoto agreement; the need in
    some territories for a coordinated approach across various countries
    or states in order to develop an interconnected infrastructure; and
    finally, the process of globalization (creation of large global companies)
    causing international companies to seek parity of fuel pricing for
    all their operations

  • Various other practical reasons such as the lessening of reliance
    on imported fuel sources; the raising of capital – the inclusion of
    the energy sector on capital markets, through its sheer size, can
    bring much needed critical mass to fledgling capital markets; and
    also the removal of energy-related liabilities from the public sector.

Trends In Regulation

There are four distinct stages to liberalization: commercialization,
privatization, unbundling, and competition (both wholesale and retail),
although in practice, two or more of these stages may be combined in one
piece of legislation and one need not necessarily follow the other. In
Norway, for example, the electricity industry remains largely state-owned
but competition has been introduced.

Commercialization involves the initial application of commercial
practices to government-owned bodies such that there is more of an emphasis
on efficiency and cost-cutting. A commercialized body that is focused
on costs will need to find the least expensive route to supply rural areas,
since generally they are the areas least well supplied at present and
are thus in need of investment.

Privatization is the sale of public bodies into the private sector,
leading to an emphasis on both cost reduction and on revenue maximization
as profitability becomes the key performance measure. As the industry
moves towards a privatized state, its cost of capital generally increases.
Emphasis on costs is strengthened but a further emphasis on revenues,
profitability, and returns on investment has mixed effects on renewable
strategy. In addition, responsibility for social objectives is usually
passed to regulators who seek to balance these objectives with the utility’s
economic well-being.

Unbundling then brings about the separation of the industry into
transmission, generation, distribution, and supply, and with it, the requirement
to introduce a system for the allocation of costs and the introduction
of structural and tariff regulations to protect the consumer. Once unbundling
has taken place, competition can be introduced into the supply and generation
sectors, although within the natural monopoly areas of transmission and
distribution, it is not possible to introduce competition directly, so
regulation must act as a surrogate for competition.

Only a handful of countries have achieved, or come close to achieving,
truly competitive retail and wholesale electricity markets (Argentina,
Chile, Sweden, the U.K., and some U.S. states have achieved the former
while Victoria state, several Latin American countries, and U.S. states
have achieved the latter). This scarcity of examples indicates the challenge
of making the transition to competition, however large the potential benefits.
The vast majority of global electricity markets still have at least one
or two of the stages of liberalization to undertake.

A 1998 WEC study classified 71 percent of Asia-Pacific countries, 80
percent of Eastern European countries and 97 percent of African and Middle
Eastern countries as having governmental or regional government control
of the electricity industry. 36 percent of Asia-Pacific countries, 40
percent of Eastern European countries, and 14 percent of African and Middle
Eastern countries had either commenced or were planning for privatization
to take place at that time. Since then, even more countries have moved
into the liberalization process. A recent survey of the European Power
Markets by PricewaterhouseCoopers entitled “Electricité sans Frontieres
2000” showed that approximately 60 percent of the European Union (EU)
electricity markets were open to competition during 1999, compared to
the 25 percent required by current EU legislation.

While the process of liberalization may differ in detail from country
to country, there are certain common features that are demonstrated to
some degree across most liberalized power industries:

The commercialization of state-owned entities and their eventual privatization

In many countries, the boundary between these two stages may be unclear
or even nonexistent, as full or partial privatization may take place without
previous structural or operating changes to the entities. In other countries,
such as in many of the Nordic states, privatization may not take place
at all, though competition is introduced and the market can be classified
as “fully liberalized.”

The removal of entry barriers to an industry or country; monopoly status
for existing entities; unusually high tax burdens; and price-setting,
wherever this is possible

The removal, or at least the dilution, of entry barriers and monopoly
status of existing players is a key feature of liberalization programs.
One key way in which this is achieved is for regulation to contain restrictions
on the size of players in a newly-liberalized market, and there are a
variety of approaches to be seen. For example, in the U.K. the generating
capacity of National Power, PowerGen, and British Energy was, and still
is, closely monitored and restricted by the regulator and the government.
In Argentina, no one generating company is permitted to operate more than
10 percent of the country’s total generating plant. In Chile, there are
no such restrictions.

The removal of fixed price-setting arrangements and their replacement
with an alternative market structure provides further opportunity for
comparison. Some regimes have introduced a centralized System Operator
that has responsibility for setting the price based on bids made by generators,
like in the U.K., and New South Wales and Victoria states in Australia.
Others operate a single-buyer system although often these markets have
not yet entered into significant market liberalization (e.g., France and
Australian states other than New South Wales and Victoria).

As established liberalized markets continue to evolve, there is often
a move toward the introduction of bilateral contracts between interested
parties, as well as the shorter-term pooling arrangements supervised by
the Independent System Operator. This is already the case in the Nordic
countries and forms the basis of the proposed restructuring of the trading
arrangements in the U.K. At present in California, there is only an Independent
System Operator, but bilateral trading will be allowed from 2002 when
the five-year transition period ends.

The establishment of open access regimes for transportation infrastructure;
separate markets for different products; an independent regulatory function;
and tax incentives to promote investment

One of the main differences across liberalized markets is the approach
taken on the level of independence assigned to the regulatory function.
In some markets such as New South Wales, the proposed regulator will be
independent from government while in others the regulator forms a part
of government, such as in Denmark and Finland.

There is a range of regulatory bodies that incorporates an independent
council or consumer committee (or both), but the government still retains
the right to guide or issue advice to the regulator. In the U.K., for
example, the government has recently published proposed reforms that would
enable it to pass “guidance” on certain issues to the regulator, though
it is not clear how the final legislation will look.

The focus of the regulator is another area where different approaches
can be seen. The job of a regulator is to balance the interests of various
stakeholders, and therefore necessarily has to ensure that the producers
of power obtain an adequate return while ensuring certain standards of
supply to consumers.

The unbundling of vertically integrated operations

In most liberalization programs, there is provision for unbundling of
the industry, even if the regulation is restricted to separate accounting
functions and regulatory reporting within the same vertically integrated

There is a variety of regulatory approaches to the amount of vertical
integration that may remain or be developed. In the U.K., while vertical
integration has been allowed, with National Power, PowerGen, and British
Energy (the U.K.’s privatized nuclear generator) acquiring parts of regional
electricity companies, disposals of generating plant were required by
the government before the English generators could complete their acquisitions.
Also, Eastern Electricity (originally a Regional Electricity Company,
now renamed TXU Europe) has acquired significant generating capacity.

In Argentina and Mexico, regulation does not allow generation or distribution
companies to have an interest in the transmission monopoly and vice versa.
In addition in Mexico, distribution and generating companies are allowed
to hold no more than a minority stake in each other.

An interesting contrast can be seen in Chile, where no restrictions were
placed on vertical integration and two separate scenarios developed in
the North and South of the country. In Northern Chile, a number of large
companies were formed and intense competition developed in the market
while in Southern Chile, although subject to the same regulation, the
market is dominated by one investment company holding both the main generating
company and the largest distribution company, as well as owning the transmission

Practical Effects

Industry Realignment

The Future of Vertical Integration

During the initial stages of the liberalization process, there is a tendency
for power companies to vertically integrate, if they are permitted to
do so, in an attempt to hedge against price volatility risk. In the short
and medium-term, while wholesale and retail markets are only partially
competitive, incumbent generators will seek to remain or become vertically
integrated because of the secure market and margin shifting opportunities
it offers. These advantages, however, will diminish in the long-term.

European companies, in particular, have adopted vertical integration
strategies and these will require continual review as the new markets
develop. The need for multi-product retailing as a minimum entry ticket
to the mass market will constrain the scope for vertical integration of
generators and retailers, as retailers will need to source aggressively
the lowest cost supply of a portfolio of products. Retailers will not
be able to compete effectively if they are integrated with the supplier
of one element of a multi-product offer.

International Expansion

Ownership patterns are fast becoming international. There is heavy participation
in European markets from U.S. companies, and there is an equally high
level of transatlantic and wider international activity and ambition among
the big European companies. The leading players from the U.S. and Europe
now have truly international portfolios spanning several continents. National
Power, for example, one of the four non-nuclear British generators created
in the U.K. privatization process, currently has investments in 22,500
MW of generating capacity outside the United Kingdom in Australia, China,
Czech Republic, India, Ireland, Kazakhstan, Malaysia, Pakistan, Portugal,
Spain, Thailand, Turkey, and the United States.

Global merger and acquisition activity in electricity continues to intensify
as liberalization spreads across the world. PricewaterhouseCoopers global
mergers and acquisitions survey “Electric Deals” reveals that in 1999,
for the second year running, the number of announced cross-border electricity
deals rose by more than 35 percent on the previous year, to a record 124
cross-border deals. While the number of cross-border deals increased in
1999, the total value of deals decreased by 24 percent from $49.7 billion
in 1998 to $37.9 billion in 1999, and the average size of disclosed deals
fell from $740 million in 1998 to $440 million in 1999. This confirms
that the pace of change in the electricity industry is accelerating, although
a more cautious approach is being adopted when it comes to large deals.

Europe was the leading target continent, with 64 percent of total investment
and $19.7 billion worth of deals focused mainly on generation assets.
The emerging markets of Latin America and Asia that suffered an economic
decline in 1998 have now partially recovered, although the level of cross-border
activity has not returned to the records set in 1997. Chile was the main
target in this region, taking 50 percent of inward investment, followed
by Brazil.

After a large fall in 1998, the Asia Pacific region saw an increase in
cross-border activity in 1999 with 26 disclosed deals worth $5.4 billion.
New Zealand, India, and the Philippines were the target countries for
the majority of these deals, although the largest deals in value terms
took place in Australia ($2.3 billion).

U.S. electricity companies remained the leading bidders globally in number
terms in 1999, although the value of U.S. cross-border acquisitions fell
by over 20 percent to $13.9 billion. The most active U.S. bidder was AES
with nine cross-border deals in Australia, Brazil, the Dominican Republic,
Georgia, India, and the U.K. totalling $4 billion. European bidders made
fewer transactions but at a higher value, accounting for 41 percent of
deals by number but 52 percent by value.

Another trend arising as a result of international expansion is the change
in the competitor profile highlighted in the “Electricité sans Frontieres”
2000 survey. In the survey, respondents were asked whether they expected
their major competitors for large customers to be either other domestic
utilities, foreign utilities, on-site generation, or other suppliers.
Over the past year, companies have become much more concerned with competition
from within their home markets and from neighboring countries than from
across the Atlantic.

Key Players

The trend toward global power companies is accelerating. Many European
and American power companies can already claim to be global players and,
as highlighted above, cross-border international deals are increasing
at a consistently high rate. Successful players in their chosen sector
will draw on global economies of scale and expertise to compete effectively.

Over 90 percent of electricity companies (and all the major players)
in Europe expect to form part of a larger combined entity. Utility leaders
are fairly unanimous on those companies that they expect to be the main
players in the future European electricity generation and supply markets.
The three dominating companies are EdF of France, RWE/VEW and Veba/Viag
of Germany, with Enel of Italy and Endesa of Spain showing slightly better
positions than the rest. The dynamics of the industry, however, suggest
that there will be room to accommodate a handful of other major players
– possibly companies choosing to seek success from focusing on new business
models rather than sheer size.

As power markets across other continents start to liberalize, the structure
of the regulation across those regions will determine the extent to which
players in those countries are able to compete with these existing global

Business Diversification

The face of the electricity industry has changed beyond recognition in
those countries that have fully-liberalized power markets. Liberalization
has allowed companies to become increasingly active and innovative in
seeking to create additional value through new sources of efficiency,
synergies, and customer services across the utility sectors and beyond.
Divisions between electricity, gas, and oil sectors are disappearing and
companies operating in these sectors are fast evolving into energy companies.

In the U.K., faced with increasingly stringent price controls and modest
growth in electricity demand, the regional electricity companies began
to diversify to secure income from new business activities. Electricity
generators and suppliers in the U.K. now compete in gas supply, while
Centrica is competing in electricity generation and supply.

TXU Europe Group PLC is one of the examples of a complex business structure,
which evolved in response to new business opportunities resulting from
liberalization of the energy markets. The Group comprises approximately
80 companies encompassing a wide range of businesses from electricity
generation, distribution and supply, to gas wholesaling and supply, insurance,
and project financing. Owned by TXU Inc. in the U.S., it has extensive
interests in the U.S.A., Australia, and elsewhere.

Regulatory Tensions

There is a host of contributory factors to the sorts of internal regulatory
tensions that can arise as a result of liberalization within a region
or country:

The Right to Electricity: Shareholders and Customers

First, there are tensions associated with electricity being a basic living
requirement and regarded by most citizens as something that they are entitled
to by right. Taking ownership of and responsibility for the supply of
power out of the hands of a directly electable and thus accountable government
and placing them under the control of a private (possibly even foreign)
company, which is often not directly accountable to government ministers,
causes understandable tensions. The political realities of life, however,
are that any organization that consistently ignores the political environment
in which it operates will reap only a short-term benefit at best.

Customers worry that organizations, which previously existed to serve
consumers and had as their main objective the reliable supply of electricity,
will suddenly change their focus to their shareholders who expect a return
on investment. Governments seek to overcome this problem by establishing
some sort of regulatory body over which they retain some influence or
power. The structure of this regulatory body and the level of governmental
influence over it is key to the success of the liberalization process.
It is also worth noting that a business that does not focus on its customers
is unlikely to succeed in providing acceptable returns to shareholders.

Customers’ Champion or Market Referee

A related problem is that by introducing competition, not only do consumers
have a choice in their provider of electricity, but companies theoretically
have a choice in the types of customers that they want. This could give
rise to unattractive customers (e.g., low-income families unable to enter
into direct payment arrangements) being unable to buy any electricity
at all. Any government with the ambition of continuing in power would
need to introduce or maintain measures designed to protect such customers.
However, any legislation designed to limit the freedom of electricity
providers runs contrary to the theme of liberalization and thus further
tensions arise. This issue of “Customer’s Champion and Market Referee”
is a difficult balance to make.

There is a clear theme of customer focus throughout the regulatory structures
that exist. In Mexico, the principal function of the Comision Reguladora
de Energia is the protection of short and long-term consumer interests,
and the regulatory reforms included a transparent and effective policy
of subsidies with explicit social welfare objectives.

In the United States, the Public Utility Commissions are mandated to
frame rules for consumer protection against fraud and other unfair trade
practices. In the state of Orissa in India, the electricity regulator
has to consider the interests of consumers during its price-setting process
and is also required to advise the government on a tariff policy which
is fair to customers.

Domestic or International Focus

A further practical effect of liberalization is the possible international
competitive disadvantage that can be caused by a regulatory structure
designed solely to focus on creating a fully competitive national market
without considering the impact of globalization. This has been a particular
complaint of many of the U.K. power companies as the U.K. government has
forced them to divest of generating plant, or blocked their plans completely
when they have sought to expand within the U.K. to develop their asset

While this has prevented the domination of the U.K. market by any one
U.K. player, it has not prevented external investment on a large scale
by European and U.S. players, and it has not allowed U.K. companies to
expand to the same international competitive scale as, say, Electricité
de France.

Cross-Border Issues

There is considerable disquiet within the utilities industry about the
progress made toward dismantling the hurdles that lie in the way of a
fully open and competitive European market. One of the biggest issues
impeding full competition is unequal access to networks and markets, or
a lack of reciprocity. As discussed briefly above, one of the main practical
effects of the varying pace of liberalization across different countries
has often meant that companies in those countries further down the liberalization
road are disadvantaged when it comes to reciprocal investment and expansion
into non-liberalized countries.

The different regulatory regimes in different countries across Europe
have meant that some companies are able to expand across borders while
retaining a virtual monopoly position at home.

Stranded Assets

This constitutes one of the leading barriers to market liberalization,
and two-thirds of Electricité sans Frontieres 1999 respondents cited it
as the leading barrier to liberalization in their home country. The problem
arises when expensive and uneconomical assets have been built and run
under a pre-liberalization regime whereby the costs of the assets can
be recovered through the tariff structure. This arrangement has been built
up in order to encourage the production of sufficient electricity to meet
a country’s energy requirements. As such regimes are liberalized, the
tariff structure is changed or abolished, leaving these assets unable
to compete against newer, more efficient assets built more recently.

A range of responses to this issue can be seen across liberalized states
or countries. In California, the regulatory recovery of $6 billion of
stranded costs has been allowed each year to 2002, and in Spain, $135
billion of stranded costs has been identified and will be recoverable
to 2007. However, in the Nordic electricity and the U.K. gas markets,
no stranded costs have been earmarked for recovery in the adopted regulatory

The knock-on effect of stranded assets can reach entirely separate industries
such as the coal industry. In the U.K., one unforeseen impact of liberalization
combined with falling gas prices was the move away from coal-fired toward
gas-fired power stations. Prior to privatization, coal accounted for 67
percent of the U.K.’s energy source, compared to 33 percent in 1998. A
gas-fired power station moratorium was introduced for a period as an attempt
to overcome this effect, and recently the government has announced a new
subsidy to the coal industry that may reach £100 million.


In conclusion, it is clear that liberalization yields many benefits for
companies, governments, and consumers. There are, however, clear lessons
to be learned from observation of those countries and continents where
it is far advanced. With planning and awareness, many of the practical
difficulties encountered in Europe can be overcome. In Autumn 1999, a
wide-ranging study into best practices for encouraging private sector
investment and competition in the power industry was carried out by specialists
at PricewaterhouseCoopers Securities. Eighty-nine separate best practices
were identified that included guiding principles and specific actions.
The top six of these were as follows:

  • The need to achieve lasting benefits for customers in the shortest
    possible time should drive the restructuring process

  • The power sector should be unbundled into separate generation, transmission,
    distribution, and possibly retailing sectors to achieve the maximum
    benefits for customers

  • Privatization should include the sale of power distribution as well
    as generation utilities and should include existing assets as well
    as new generation projects

  • Open access to transmission and distribution wires, and the ability
    to trade power between buyers and sellers in an open market, are critical
    to achieving a competitive framework

  • In a competitive market, it is critical to define a new role for
    the regulator, separate and apart from the role played in the past
    by the ministry overseeing the industry

  • Multilateral institutions should be partners with developing countries
    to help them achieve maximum benefits for customers, though their
    role may shift toward becoming facilitators of competition rather
    than just direct lenders in the power sector.

As increasing numbers of countries enter into the liberalization process,
those which follow these best practices will succeed in the vibrant and
active global power market.

A New Paradigm for Customer Care and Service in a Deregulated Energy Market

Utilities have no experience with competition or strategies for winning
customers when primarily dealing with a product like electricity or natural
gas. Competing utilities must be customer-oriented, study consumer behavior
and purchasing habits of customers, and operate creatively regarding their
product offerings. Consequently, they must overcome their traditionally
civil service mentality.

Significant price differences no longer exist between regulated and deregulated
energy. Free commerce in energy is valuable to customers with considerable
energy needs. However, with the inclusion of the small, private consumer,
low profits oppose the high investments required to organize and optimize
complex business processes in a deregulated energy market.

Deregulation significantly impacts the customer service departments of
utility companies. On the one hand, these departments are able to offer
consumers an easily understood and attractive energy product with a punchy
name, such as EnergyPLUS, YELLO, or GreenPower. On the other hand, deregulation
complicates the sale of energy, making it a complex transaction for both
administration and accounting.

The revolutionary changes brought about by deregulation become most evident
in an examination of customer information systems (CIS). A utility can
hardly survive if it continues to use a standard CIS. To develop a CIS
that complies with the new requirements, complex projects are necessary,
which often operate against the background of provisional deregulation
policies that IT departments can only convert into systems with great

By collaborating with many utility companies throughout the world, SAP
has developed a CIS that responds to the new paradigm of such systems
in a competitively-oriented, open energy market. In the first 20 months
since its release, more than 170 companies in more than 30 countries,
typically with advanced deregulation policies, have adopted the industry
solution, mySAP Utilities Customer Care & Service (IS-U/CCS). The experience
gained during development of the system and its implementation at customer
sites forms the basis of this article.

The following sections discuss the changed frameworks of the deregulated
utility market and resultant CIS requirements. The last section sketches
the architecture of the optimum CIS for the deregulated energy market,
using the example of mySAP Utilities IS-U/CCS.

The Effects of Unbundling

The unbundling of utility companies means that there is a bilateral relationship
between customers and their local suppliers. What once existed in a regulated
market has become a multilateral relationship. At minimum, customers have
a contractual relationship with the energy supplier (RetailCo) and a service
relationship (in many cases also a contractual relationship) with the
distribution company (DisCo). Since customers can change their supplier
dependant upon market offerings, further contractual relationships develop.
Commercial and industrial customers can purchase energy from multiple
vendors. Many deregulation models also predict assignment of metering
and reading services, historically a DisCo function, to an additional
type of energy services company, a meter management operator. Here, the
customer enters yet another service relationship.

The coordination of services provided by a RetailCo, DisCo and, in some
cases, a MeterOp to the same customer, and the coordination of the administration
and accounting of these services, demand intensive data exchange. Bilateral
communication or an exchange marketplace occurs between the various customer
information systems of participating energy companies. These types of
collaborative business-process scenarios can include informing a DisCo
about a customer’s transfer of service from one energy supplier to another.
They might also include a meter-reading service sending the results of
a reading to the appropriate DisCo and RetailCo, or transmitting accounting
information from one service provider to another so that they can issue
a single common invoice.

Obviously, the receiving CIS must process this huge amount of incoming
data as quickly as possible without manual intervention. Neither legacy
CIS products, nor the many standard CIS products offered today, meet these

Forms of Deregulation

There is no clear definition of deregulation in the utility industry.
Each country, and every state in the U.S., understands and governs deregulation
a bit differently. The reasons for such diversion lie in the infrastructure
of the supply grid, ownership behavior in the energy industry, treaties
between states or countries, currently applicable law and the structure
of the population served. Above all else, however, the regulatory agencies
and the industry associations emphasize their own solutions to deregulation,
rather than a standard solution. The following examples highlight the
diverse forms of deregulation and the consequences of each for a typical

The Distribution of Roles Between DisCo and RetailCo

The various deregulation models agree on only one point: the DisCo operates
the grid and distributes energy to household connections, while only the
RetailCo can close competitive energy-supply contracts. In practice, every
possible hybrid exists between these two poles. A DisCo, an independent
MeterOp, or a RetailCo can claim responsibility for operating and reading
meters. According to one variant, the RetailCo (or even the customer)
might own the meter, but only the DisCo or MeterOp can install, remove,
maintain, or read it. In another variant, the DisCo or MeterOp holds responsibility
for the meter and reading, but the consumer requests a meter or reading
service through the RetailCo, which then directs the service request to
the appropriate DisCo (MeterOp). This procedure can even include the reporting
of power outages.

Many deregulation models foresee that the DisCo will continue to supply
energy to customers who have not yet decided to change to a free (independent)
RetailCo. Other models plan a transfer of all energy contacts to a RetailCo
in the same corporate group on a cutoff date, so that as of that date,
the DisCo must operate with strict neutrality. It must handle communication
with the related RetailCo exactly as it does with any other RetailCo.

With this in mind, the CIS must support and maintain an open assignment
of company type (DisCo, MeterOp, and RetailCo) and process type (such
as meter management, meter reading, contract billing, and accounting or
work management). This assignment is determined when configuring the system.

Defining the Point of Consumption

The unbundling of utility companies and the distribution of customer
relationships between DisCos and RetailCos force a redefinition of the
point of consumption. The previously used meter number no longer suffices;
it does not remain unique with regard to service areas of several DisCos.
The utility industry has been unable to determine a standard, unique identifier
for a point of consumption. Additionally, almost every country understands
this term differently in regards to its technical aspects and data format.
Therefore, the CIS must maintain compatibility with every conceivable
identifier for a point of delivery.

Customer Enrollment

In principle, customers can choose when and how to accept an offering
on the free energy market. However, the procedure for making that choice
remains one of the most discussed topics of local deregulation agencies.

Some deregulation plans leave DisCo system customers as somewhat full-service
customers until they freely choose their first RetailCo. Other plans require
the forced assignment of customers to a RetailCo. The first plan offers
the advantage of an evolutionary – and more manageable – migration into
deregulation. The second plan brings a DisCo into the competitive neutrality
intended by the principles of deregulation.

The type of contractual relationship that a customer has with a utility
company depends upon the policies of deregulation in force. In the event
of multiple contracts, customers keep the contract covering their connection
to the supply grid with the DisCo; they execute a second contract for
energy delivery with the RetailCo. In the event of a single contract,
the contract between the customer and the DisCo becomes obsolete; only
the new contract with the RetailCo remains.

Country-specific deregulation policies differ in determining who informs
whom about customer enrollment and the preconditions that both customers
and the RetailCo must fulfill. Diverse approaches also apply to the enrollment
periods, procurement of meter reading services, the behavior of customers
in the event of outstanding payments, the response to slamming of customers,
and the transfer of customer data from the DisCo to the RetailCo.

Standardization of Data Exchange

As noted above, data exchange between the RetailCo and the DisCo calls
for standardization. Although European utilities can use the EDIFACT standard
of the United Nations, and North American utilities can use the EDI standard
X.12 of ANSI, a great deal of diversity still exists within the standard,
even though it has long been used in electronic commerce. Consideration
of the diversity of country-specific dialects demands a great deal of
investment and time for a RetailCo. The different approaches to deregulation
are the basis of the requirement for diverse dialects.

For the manufacturer of a CIS, the realization of a standard solution
is particularly difficult. As a generic tool the required Transaction
Exchange Engine must provide the following:

  • It must offer a compatible interface for all data-exchange formats.

  • It must interpret the received messages with a scenario-specific
    script and use its CIS open method-interfaces to process the messages
    automatically in the background.

  • It must have functions to generate outgoing messages over defined
    user-exits and assemble them in their final form according to scripts
    that follow the scenario in use.

  • It must develop the scripts in a meta-language so that users can
    develop scripts themselves and, if needed, change them on short notice,
    without having to wait for a new release from the manufacturer.

SAP has developed such a transaction exchange engine as a subcomponent
of IS-U/CCS. The engine has proven itself and has been operating successfully
for more than a year. A large utility company in Pennsylvania, a completely
deregulated state, serves as one example.

Figure 1

Figure 1


An invoice and the processing of its payment are usually the one regular
contact that utility companies have with their customers. They represent
a type of business card. Utilities should rightly have a concern about
issuing a clear and easily understood invoice. Deregulation makes this
goal more difficult because utilities must observe several new rules.
An invoice also serves as a marketing instrument – it should contain additional,
useful information for consumers and inform them of additional services.

According to the original idea of deregulation, an invoice from a utility
company should transparently show charges for the individual regulated
and deregulated links in the value-added chain (generation, transmission/distribution
services, sales, and administration), so that customers can actually compare
prices. The laws of each country follow this idea very differently. Some
countries require precise invoices; other countries leave this decision
to the utility. In Germany, for example, retail companies offer consumers
flat-rate prices that not only summarize individual items in the value-added
chain, but also are to some extent independent of the actual consumption.

In line with the original idea of deregulation, it would be very helpful
for a RetailCo, as a competitive and consumer-oriented business unit,
to issue customers a consolidated invoice for all services, regardless
of which firm provided them. That isn’t the case. Retail companies often
turn to the experience and infrastructure available at distribution companies
and let those companies handle settlement of their energy services. Recently
developed deregulation models, such as those used in Texas, require that
the RetailCo handle billing almost exclusively and that their invoices
include the charges of the DisCo. Other models, such as those in Pennsylvania,
let customers decide if they want a consolidated invoice or one from each
service provider.

Settlement for third parties makes sense and follows the basic principle
of offering one face to the customer. As a precondition, of course, the
settling company must have all the billing information for third parties,
from both related and external companies. Sometimes a message can contain
the settlement parameters (quantity, tariffs, prices, and so on), so that
the settling company can prepare an invoice just as it does for its own
services. More frequently, the settling company receives completed billing
line items electronically, over the Internet, which it then incorporates
into the invoice. The rate-ready and bill-ready procedure has several
implications for the following process steps in accounting and consolidation
in the general ledger that cannot be treated here.

Competition and customer orientation add another dimension of complexity
to invoicing. As noted, retailers want to offer attractive energy products,
not simply electricity or gas commodities. Several products or services
from various utility areas and service providers should be shown on one
invoice that also explains the price dependencies between the products.
Additional complications arise when the customer base of a RetailCo resides
in different deregulation areas. In the U.S., for example, customers might
reside in different states, each with its own deregulation laws. The RetailCo
must incorporate different regulations and laws into its invoices. Complexity
increases if a RetailCo offers the consumer-friendly service of Consolidated
Invoices for both electricity and gas with each commodity, which follow
different deregulation rules and time lines.

These scenarios indicate the level of flexibility that a CIS must have
for settlement, billing, printing invoices, contract accounting, as well
as Customer Relationship Management. In addition, mergers and acquisitions
lead to ever-larger energy companies with ever-larger customer bases,
and therefore ever-higher performance requirements. To enable execution
of several hundred thousand settlements in a period of a few hours, batch
processes must run in parallel at any level. The CIS must also be able
to automatically control and reprocess error logs as quickly as possible
with workflow control.

Settling and Cost Comparison

The settlement procedures performed for third parties, described in the
previous section, and those that arise from deregulation require an additional
process step. The revenues collected for third parties must be settled
quickly and accurately. Various procedures apply here. In the simplest
case, the settling company sends all the fees it has collected from customers
directly to the third party, without any consideration for payment settlement.
In the most difficult cases, the settling company performs exact accounting
at the settlement item level of all calculated revenue and received payments.
It considers various settlement priorities in the event of underpayment
by a customer. An accounts payable posting to the third party transfers
the aggregate revenue at a specific time.

Definition of an Energy Product

Americans call both electricity and gas a “commodity,” a basic service
in everyone’s life that contains nothing of competitive interest except
its price. It is left to the marketing creativity of the RetailCo to determine
how to develop an attractive product out of electricity and gas, a product
attractive enough for the consumer to buy, and to therefore change to
a different company.

Those who look for an attractive energy product or for criteria for an
attractive energy supplier have only to ask the consumer the questions
below. From SAP’s experiences with utility companies and customers worldwide,
we believe the customer would respond in the following manner:

  • When considering one-stop shopping, the consumer prefers to receive
    all of his utility needs from one company These should include not
    only electricity and gas, but also other services, such as heat, water,
    sewage, garbage collection, and so on.

  • For questions and preferences about meters and household connections,
    the consumer prefers to turn to his energy supplier instead of having
    several service partners including the DisCo and MeterOp.

  • Consumers demand quick, friendly and uncomplicated service from a
    call center. As an alternative they want Internet self-services (B2C)
    that allow them to handle typical customer processes from home or
    office. And when they use self-service, they expect a better price
    for this efficient form of processing.

  • Consumers want comprehensible price structures and, above all, the
    lowest possible prices.

  • Consumers with a record of on-time payment want a variable and comfortable
    payment system, such as monthly bank transfers of a fixed amount,
    annual accounting for down payments, or payment by credit card. They
    value fair treatment by a utility: payment of interest on overages
    in down payments or premiums for customer loyalty.

  • Consumers regard “KWh and more” services as attractive, combined
    services that include discounts for household appliances, energy consumption
    consultations, alarm and monitoring services, Internet services, and
    much more.

Commercial and industrial customers demand more from an energy product.
They require the following:

  • Point of delivery bundling – They want to combine the energy
    used at all subsidiary points of consumption (in an area or country)
    into one contract at a special, reduced price.

  • Time-of-use or real-time pricing contracts – Here, pricing
    conditions depend upon maintaining or exceeding previously agreed-to
    load profiles and set the expected consumption for each interval (15,
    30, or 60 minutes). This approach can also include an up-to-the-minute
    energy price from an electricity exchange. With these types of contracts,
    the energy supplier can offer consumers very attractive prices. Consumers
    share or take the risk of exceeding the amounts specified in the consumption

The definition of such flexible energy contracts or even the bundling
of energy contracts with sales, service, maintenance, and financial services
overwhelms traditional customer information systems. Such instruments
presuppose a flexible data model and software architecture that can define
and settle dependencies between different types of contracts: a model
and architecture found in mySAP Utilities IS-U/CCS.

Customer Relationship Management (CRM)

CRM encomasses all customer-related processes that deal with the marketing
and sales of products, along with the fulfillment of contracts in a competitive
and therefore customer-oriented industry. The significance of CRM has
grown with the change from a supply monopoly into a competitive market.
This observation applies much more to competitive retail companies than
it does to regulated distribution companies.

Here, the idea arises of applying the successful CRM systems of other
industries exclusively to settlement components of a utility-specific
CIS. Some sample projects of deregulated utility companies have shown
this approach to be incorrect – the functional scope of industry-neutral
CRM systems cannot handle the special contractual forms and services that
relate to energy products. A study has shown that the data model for a
CIS for the utility industry conflicts with the data model and functional
scope of a CRM system, particularly in the areas of sales and service.
Both systems claim ownership of certain central business objects such
as customer, contract account, contract, product catalog, prices, conditions,
and so on.

What’s the solution then? It makes the most sense to use the CRM system
to transfer all the transactions it cannot process to the industry-specific
business objects of the CIS. The CIS then executes the transactions and
returns confirmations of their execution to the CRM system. This integrated
use of a front-office CRM system with a back-office CIS presumes open
and flexible software architecture on both sides, as well as strenuous
development work in producing manageable, easily understood and easily
maintained connectors. SAP is currently developing this coupling for mySAP
Utilities CRM and IS-U/CCS components.

Note, however, that given the distributed responsibilities of the CRM
system and the CIS for handling customer processes, both systems must
now consider and process the data-exchange transactions noted above.

Figure 2
CRM independent component of mySAP
larger image

Figure 2

Deregulation has also increased the demands made upon the call center
of a utility company. The call center becomes the hinge of Customer Relationship
Management. Calls from customers flow in to a call center, which notifies
the system of grid failures, schedules service appointments, generates
complaints, notifies the system of a move-in/out, and above all, handles
marketing and sales activities. Typical demands made on call centers include
integration with telephone computer systems, interactive voice recognition
systems, and Internet transaction servers to support B2C processes over
the Web. The benefits of a call center system rise and fall with its integration
into the information and processing functions of the CIS. Only this kind
of integration enables rapid identification of the customer or point of
consumption, clear information functions tailored to customers’ questions,
and workflow and script-controlled processes that allow employees to handle
typical contacts quickly, with only a few transactions.

Energy Data Management

Energy data includes information on past and future consumption by customers,
measured in physical consumption units, such as KW or KVA, and influential
factors such as outdoor temperature or calorific value (gas). Utility
companies have always had such information, but a deregulated market makes
this data even more valuable, as illustrated in the following paragraphs.

The opening of electricity and gas grids as natural monopolies to carry
energy from suppliers to various addresses demands exact accounting of
the quantities transmitted, so that companies can balance accounts for
the quantities provided by each vendor and used by each consumer. Since
energy prices can reflect significant variations over time, the account
balancing must run as a function of time, normally in intervals between
15 and 60 minutes. Because energy in a deregulated market can come from
almost any source, a forecast account balance must also guarantee the
availability of more energy than will actually be consumed at any time
(or interval). These backward and forward energy balances, therefore,
depend on the actual or forecasted measurements of each point of delivery
or point of supply. Regardless of account balance responsibility or the
availability of up-to-date energy data, companies must first develop a
procedure to obtain the data. Doing so requires the use of meters that
measure energy correctly at each interval. It would hardly be profitable
to outfit all points of consumption, including those of private users,
with interval meters. To determine the load profile of private customers,
extrapolation and differential accounting procedures have been developed
based upon synthetic (means typical) load profiles.

Each utility company must contribute to account balancing by transmitting
its own meter readings and/or prognosis data. Precision is not only a
question of grid stability, but also a precondition for optimal commerce:
the better a RetailCo can forecast its consumption at each interval, the
better than it can control its energy purchases and generation.

In a deregulated energy market, every RetailCo has an interest in influencing
the consumption patterns of its customers so that it can match the quantities
it procures and generates to those patterns as exactly as possible. In
the ideal case, a RetailCo could influence customer consumption dynamically,
depending upon the current price situation in the energy market. The ideal
cannot be realized. However, a RetailCo can transfer the risk of unplanned
higher or lower consumption or the risk of unexpectedly higher prices
to customers within a defined framework.

These kinds of contracts make the most sense for large consumers. Combined
with the metering techniques previously noted, they assume that the RetailCo
maintains measured or forecasted load profiles that it can assign to energy
delivery contracts as conditions. Depending upon the size and energy consumption
of a customer, the RetailCo can develop more or less complicated rules
based upon various known data points such as load profiles, agreed-upon
price profiles, and prices on the energy spot market.

Utilities can also influence the consumption patterns of private or commercial
customers by installing meters that measure consumption according to zones
throughout the day. This approach requires investment in new meter technology,
but the time-of-use contracts that it offers enables customers to save
money by adjusting their energy consumption to periods of the day when
it costs less.

Marketing departments are also interested in energy data. Organizing
energy data by region, energy product (tariff), industry, customer characteristic,
etc., provides valuable information for tariff and price policies and
identifies new target groups for marketing campaigns. Permanent monitoring
of customer consumption patterns also helps recognize changed patterns
early and introduce the appropriate measures on the procurement and sales

Energy data management depends on each customer’s data and individual
energy contracts maintained in the CIS. Moreover, as a direct precondition
for that data, utilities must offer commercial and industrial customers
competitive energy contracts. It is conceivable that within a few years,
all large customers and a large portion of commercial customers will have
real-time-pricing or time-of-use contracts settled with energy data from
interval meters.

SAP has taken advantage of this development and enhanced mySAP Utilities’
CCS component with the Energy Data Management component. The integration
of both components enables utilities to settle both real-time-pricing
and time-of-use contracts and to link them to other forms of settlement.
It also supports and can settle the account balancing processes previously
noted, in the role of an independent system operator, for example.

CIS for the Deregulated Energy Market

The previous sections have attempted to explain the new paradigm of CIS
in a deregulated energy supply market, based upon a description of new
business processes in a deregulated energy market. The remaining task
involves presenting the results as the structure of a CIS for the liberalized
energy market. Figure 3 illustrates the essential components of such a

Figure 3
Structure of deregulation-enabled utility CIS system

Figure 3

Modularity is an important characteristic of the system. It allows a
utility company to implement the system in phases and avoids the creation
of overly large runtime systems and databases for large utility companies.
The system components of the first level can also be used as independent
subsystems in their own runtime environments. Doing so shouldn’t hinder
the integration of the components needed to handle cross-system business

Meeting this goal requires developing multiple method-interfaces for
the business objects within the components. Connector software can then
provide secure collaboration between the components, even for those of
other manufacturers.

The list in the right section of the illustration clarifies the flexibility
required of the CIS. A lack of flexibility means that the utility company
would have to implement different customer information and settlement
systems dependent upon company roles, types of supply, customer groups
and products.



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