APPENDICES – CASES FROM DIFFERENT PLAYERS IN THE ENERGY

SUPPLY CHAIN

In studying energy deregulation, the researchers adopted a case study approach. In order

to obtain an unbiased and broad perspective on all of the thorny issues surrounding deregulation,

we developed a research design that relied on case studies, interviews, and written transcripts

from many participants located in different sectors of the energy supply chain. All of these

parties have been or will be affected by deregulation in the years to come. Some have a direct

impact on its development (state governments), while others play a lobbying role (utilities, large

commercial agencies), while others play a relatively minor role but actively await the outcomes

(local aggregators). In addition to the cases described in the appendix, approximately five other

companies involved in purchasing electricity were interviewed, but the cases were not

documented in this report. In accumulating the various perspectives of these different players in

the supply chain, we were able to build a broad picture of the important trends, future strategies,

market climate and political issues surrounding this complex issue.

As shown in Figure 6.1, the following cases represent the views of different participants

in the energy supply chain:

Case A: Voltron* and Sun Energy1: Investor-Owned Utilities in regulated states Gear Up for

the Deregulated Era

CASE B – A Power Utility in Pennsylvania (A Deregulated State)

CASE C – Co-Generation: Cutting Energy Costs in the Steel Industry:

1 These names are fictional in order to hide the true identify of the companies studied.

CASE D: Purchasing Electricity in a Globally Transitioning Market: An Automobile

Manufacturer’s Perspective

CASE E - A Joint Venture Between a Manufacturer and Power Marketer to Drive Down Energy Costs

CASE F – Harnessing the Power of Aggregation: The Towns of Black Creek, Lucama, Stantonsburg, and Sharpsburg, North Carolina

CASE G – The State of Texas Bill on Deregulation: A Microcosm of National Deregulation

Although the cases represent a diversity of perspectives, one common theme emerges from the

cases: electrical deregulation is imminent, prices will decrease, utilities will face extreme

competition unlike any experienced in the past, and industrial and residential consumers will

have increased choice. As deregulation becomes a reality across the nation, purchasers are

advised to begin preparing for change today. Hopefully, the information contained in this report

will provide useful guidelines to enable this preparation to take place.

Figure 6.1 – Case Studies

CASE A - VOLTRON* AND SUN ENERGY2: INVESTOR-OWNED

UTILITIES IN REGULATED STATES GEAR UP FOR THE

DEREGULATED ERA

As restructuring and deregulation of electricity markets becomes inevitable, investor-

owned utilities (IOU) are being forced to reinvent at least their business plans, if not their

corporate identities. Two such companies, Sun Energy and Voltron, generate and distribute

electricity in a populous industrial state that is enjoying low unemployment and prosperous

economic growth. Though Sun and Voltron have serviced adjacent areas for most of the century,

the unique systems governing IOUs have insured they have never had to compete for customers

in an open-access market. Tables 1 and 2 show recent income statements of the two firms.

When the state where Voltron and Sun Energy operate restructures its electricity market,

peaceful co-existence between them will cease. Competition - between Voltron and Sun, as well

as with other sellers of electricity - will become the new reality. Restructuring will occur in their

state within five years. How they prepare themselves between now and then will determine their

survival.

Background

IOUs such as Voltron and Sun Energy are defined and governed by regulatory

commissions at the state level and by the 1935 Public Utility Holding Company Act (PUHCA) at

2 These names are fictional in order to hide the true identify of the companies studied.

the federal level. These regulatory constructs have traditionally treated electric companies as

natural monopolies. This is due to the fact that utilities' costs of doing business are "sub-

additive". This concept means simply that it is cheaper for electrical utilities to service all

customers within their transmission and distribution networks than it is to serve just some of

these customers. Thus, it was thought to be more efficient and desirable if just one utility

serviced a given area. PUHCA established the traditional IOU as a vertically integrated unit

charged with generation, transmission and distribution of electricity within a set service area or

territory. Competition from outside providers was effectively precluded. When they lacked

sufficient generation capacity within their own systems to service customers during peak periods,

IOUs in adjacent service areas often traded power at "courtesy" rates; there was no need to be

adversarial or competitive. For most of this century, the regulated electricity market (supported

by state utility regulatory commissions) has insured growth and profitability for IOUs, who until

recently enjoyed economies of scale.3

The regulatory status quo for IOUs changed with the passage of three

legislative/executive actions: First, the Public Utility Regulatory Policies Act of 1978 (PURPA)

forced IOUs to open their transmission systems to independent power producers (IPPs) and to

purchase power from them. Second, the Energy Policy Act of 1992 (EPACT) further eased

restrictions on independent electricity wholesalers and forced IOUs to transmit independent

wholesalers' electricity over their transmission lines, charging no more than a "just and

reasonable rate." The final blow to the traditional regulated structure came in 1994, when the

Federal Energy Regulatory Commission (FERC) issued Orders 888 and 889. These executive

3

? Peter Fox-Penner, Electric Utility Restructuring: A Guide to the Competitive Era, 1997, Lib. Of Congress catalog card # 97-066610

orders required IOUs to develop a transmission notification system that provided internal rate

and capacity information to all power producers, effectively eliminating much of the competitive

advantage that a transmission system-owning IOU held over a non-transmission-owning

electricity wholesaler. In a 16- year span, the wholesale generation market had been completely

deregulated.4

The inevitable next step is the deregulation of retail electricity generation. States such as

California and Pennsylvania have done this already. Assuming the federal government acts

sooner rather than later (activity in Congress is currently vigorous on this front),

deregulation/restructuring will be raised to the level of a national initiative as well.

Sun Energy Company

4 "Northeast Utilities - Between a Rock and a Hard Place", (1998 Case Study - author unknown)

Employees: 9,130

1998 Sales Vol.: $4.6 billion

Table 1: Sun Energy Co. Income Statements

(in millions)

Source: 1998 Annual Report

Category 1998 1997 1996

OPERATING REVENUES $4,643 $4,140 $4,010

OPERATING EXPENSES

Fuel & Purchased Power 1,169 921 931

Operation & Maintenance 1,417 1,101 1,027

Depr. & Amortization 727 726 688

Steam Heating Special Charge -- -- 164

Taxes Other Than Income 299 292 285

Total Operating Expenses 3,612 3,039 3,094

OPERATING INCOME 1,031 1,101 915

INTEREST EXPENSE & OTHER

Interest Expense 351 327 317

Pref. Stock Dividends of Subsidiary 7 13 18

Other - net 17 20 (2)

Total Interest Expense & Other 374 360 333

INCOME BEFORE INCOME

TAXES

657 741 583

INCOME TAXES 169 283 243

NET INCOME $487 $459 $340

AVG COMMON SHARES

OUTSTANDING

160 160 160

EPS - BASIC & DILUTED $3.06 $2.88 $2.13

(in millions)

Source: 1998 Annual Report

Table 3: Percentage Breakdown by Cost of Goods Sold - Sun and Voltron

Line Item Sun Energy Voltron

Fuel-related inputs 33% 50%

Maintenance, repair &

operating costs (MRO)

39% 10%

Capital & equipment 20% 10%

Direct labor (less

than 8%)

25%

Indirect costs 5%

Costs

Table 3 provides some relevant comparative information regarding Voltron and Sun's

costs of doing business. In the regulated environment, IOUs in most states are guaranteed a

"reasonable rate of return" based upon prospective costs and investments. This rate is embodied

in the per-kilowatt price that utilities are authorized to charge customers in their service areas.

Since by definition the "reasonable rate of return" increases as their costs increase, there

is little incentive for regulated utilities to hold the line on costs. Procurement practices designed

to slash input costs and directly improve profit margins are therefore less relevant in the

regulated utility environment than in competitive markets such as the automotive industry.

Requirements that IOUs maintain sufficient capacity and system reliability to control for

anomalies, such as cold snaps and heat waves that cause "spikes" and peak load periods, as well

as potential outages, have also driven up costs. To boost capacity, many IOUs have invested in

what have become costly and problematic generation assets, such as nuclear plants. Also, most

have entered into prohibitively expensive long-term contracts to purchase supplemental

electricity from independent wholesalers. These costs represent stranded costs to utilities facing

restructuring/deregulation of their businesses. Not surprisingly, these utilities are lobbying

furiously for states to require ratepayers to cover these costs.

Both Voltron and Sun, for example, have nuclear generation plants that are soon being

decommissioned. Decommissioning of a nuclear plant is a long, costly and unpredictable

process: Voltron holds among its long-term assets $613 million of trust funds set aside for

nuclear decommissioning. Sun has $340 million of such assets. Time will tell whether these

precautions are sufficient.

Other significant and potentially unpredictable costs are embodied in programs

undertaken to address Year 2000 issues involving plant information systems. Both Sun and

Voltron claim they have a fully deployed strategy for this. Sun will have spent at least $80

million implementing system modifications and contingencies by the time its Y2K-readiness

initiative ends this year. Voltron estimates its total cost will be around $30 million, including

25% of its 1999 Information Technology budget.

Threats and Opportunities

Supply chain and materials managers from both Sun Energy and Voltron were asked to

assess their firms' threats and opportunities by responding to a survey. Table 4 lists several

likely changes resulting from electricity market restructuring and whether each company regards

the change as a threat, an opportunity or neither (neutral).

Table 4: Perceived Threats/Opportunities by Sun and Voltron

Category Sun Energy Voltron

Federal energy deregulation

policy

Opportunity Opportunity

State deregulation policy Major Opportunity Opportunity

Local deregulation policy Major Opportunity (No Response Indicated)

Emergence of major utility

buying consortiums

Neutral Neutral

Competition from electricity

companies in other states

Major Threat Opportunity

Competition from electricity

companies in other countries

Major Threat Neutral

Competition from natural gas

utilities

Neutral Major Opportunity

Existing power brokers in the

market

Major Threat Neutral

New power brokers entering

the market

Major Threat Neutral

Potential of industrial

consumers to install

interruptibility capability

Neutral Neutral

Deregulation. As mentioned, the major effect of deregulation or "restructuring" of the

electricity business is the opening of electricity generation to retail competition. This concept,

often described as direct access, represents further evolution of the energy policy initiatives

forged over the last 16 years by open-access laws. Both Sun and Voltron regard deregulation as

an opportunity rather than a threat, which is fortuitous since the state in which they operate will

unquestionably restructure its electricity market.

Results of restructuring initiatives implemented in California and Pennsylvania have

shown that two major aspects of deregulation laws have the greatest impact upon competition

among electricity generators in the restructured market. First and foremost is the default rate.

This is effectively the rate that customers will continue to pay their formerly regulated IOU once

deregulation is implemented. Simply, it is the price one pays for not switching electricity

suppliers. Electricity is a commodity, and price pretty much determines the market; if the default

rate is low, customers will have little incentive to switch. This has been the scenario in

California, where the default rate was set close to the wholesale price of electricity, and large

IOUs such as Pacific Gas & Electric have not had to endure much new competition.5

Conversely, if the default rate is set high, as it is in Pennsylvania, competition is healthier and

upstart electricity sellers like Green Mountain Energy Resources are on a more equal footing

with established IOUs such as Pennsylvania Power & Light.6

5 Enron Corporation, frustrated about California legislative action regarding the default rate, bailed out of the California residential market after spending around $7.5 million recruiting 30,000 customers.6 Bart Moore, "An Assessment of the Value Proposition of Green Electricity in Restructured Markets", 1999 graduate study

As indicated earlier, the second major aspect affecting competition in restructured

markets is the mechanism allowing IOUs to recover stranded costs. Both Voltron and Sun have

lobbied vigorously regarding stranded cost recovery; the tentative plan in their state allows them

to recover these costs through five years after restructuring is implemented. In California,

ratepayers cover these costs via payment of rather high competitive transfer charges (CTCs)

which appear as a line item on all monthly electric bills. This effectively makes the line item for

energy generation - the only competitive portion of the electric bill - proportionately smaller, and

competition suffers. Thus, generous and long-term stranded cost recovery mechanisms tend to

choke the market.

Another aspect of electricity restructuring with huge implications for IOUs involves the

portions of the electricity business that will remain regulated: Transmission and distribution of

electricity. In order to assure fair competition and open access to power lines, IOUs are being

made to abdicate day-to-day operation of their lines to regional transmission organizations

(RTOs) and/or independent systems operators (ISOs). ISOs operate the transmission and

distribution system and coordinate transactions, while IOUs owning the network hardware

charge a user fee to electricity generators and marketers. Strict legislative guidelines ideally

prevent generation companies affiliated with transmission and distribution companies from

gaining price and rate advantages. While ISOs such as the California ISO represent a complex

and problematic solution to these "fair market" problems, they have many obvious advantages as

well. RTOs and ISOs are the mechanism favored by FERC for insuring fair competition in a

deregulated electricity environment, and federal law may force ISO systems onto the states.

Whether RTOs and ISOs should be public or private is subject to robust debate.7

7 Fox-Penner

Sun and Voltron have differing views on this; currently, the two firms have a power

pooling agreement that establishes a common tariff for their adjacent transmission systems. Sun

favors terminating this agreement in the wake of restructuring and replacing it with a more

comprehensive RTO that encompasses several IOUs; Voltron favors maintaining the power pool

agreement.

Competition from natural gas utilities. Sun Energy has no gas utility holdings and is

neutral on this issue. Voltron's gas utility generates about 40% as much revenue as its electric

company. Natural gas is doubly valuable, as an end product as well as a fuel input for electricity

generation. Gas is already deregulated in Voltron's state, and Voltron views gas deregulation as

a major opportunity.

Competition from other electricity sellers. Voltron and Sun managers clearly have

different views regarding competition and direct access. Voltron is generally sanguine about

open markets, and sees prospective competition as an opportunity. Sun views competition as a

major threat. This difference may be attributable to the fact that unlike Sun, Voltron has a gas

utility and a gas transmission operation. Such diversity arguably provides Voltron with a

valuable hedge against the uncertainties wrought by electricity deregulation, hence a more

optimistic internal prognosis.

The arena of energy services - metering, integrated billing, energy management,

electricity brokering, and many other "outgrowths" of the newly-deregulated market - is being

prospected aggressively by many energy companies, Sun and Voltron among them.

Best Procurement Practices

For much of the 90s, utility experts and watchdog groups have warned of the pending

upheavals of restructuring and the need for IOUs to get into cost-slashing, competitive modes.8

Electrical World estimated in 1994 that 44% of the utility sector was undergoing

"reengineering." Utilities such as Arizona Power & Light, Illinois Power Co. and Carolina

Power & Light have rebuilt their operations, enjoying mixed results.9

Success stories such as that of Florida Power & Light, which was able to drop rates 11%

over 12 years, are extraordinarily rare. Procurement initiatives like supply base rationalization,

establishment of commodity teams, and bar coding and electronic data interchange (EDI)

implementation enabled FP&L to reduce O&M costs 30% over seven years, insuring the rate

reduction.10

However, FP&L is exceptional, and the fact that IOU reengineering successes are so few

and (generally) unspectacular is good news for prospective competitors in the new retail markets:

Energy service companies such as Conectiv, and the monolithic Enron Corporation, who are

competition-tested, international in scope and vision, and unburdened by such albatrosses as

"stranded assets". It is potentially good news for companies such as Sun and Voltron, who can

distance themselves greatly from each other, and most other IOUs, by adopting purchasing

initiatives that will engender strategic cost-cutting, leaner supply chains and higher profits.

Managers from the two utilities were surveyed regarding their willingness to embrace best

purchasing practices. Table 5 shows the comparative results of the survey.

Table 5: Procurement Practices of Sun Energy and Voltron

8 Judith B. Sack, "Competitive Strategies for the '90's and Beyond", Presented at The Edison Electric Institute Spring Financial Forum9 H.A. Cavanaugh, "Re-engineering: Buzz Word, or Powerful New Business Tool?", Electrical World, Apr. 199410 Timothy M. Laseter, Balanced Sourcing, Cooperation and Competition in Supplier Relationships, c1998, Jossey-Bass Publishers

Practice Sun Energy Voltron Ideal

Highest level of procurement

activity

Combined central/local Combined central/local Global

Supplier selection process

implemented by:

Cross-functional teams

representing two depts.

Cross-functional teams

representing two depts.

Cross-functional teams

representing 3+ depts.

Supplier development programs Yes No Yes

Frequency of supplier performance

evaluations

Less than once a year Less than once a year 4+ times a year

Co-location of personnel with

supplier

No No Yes(for strategic supplies)

Areas of supplier evaluation Quality, delvry time

reliability, price,

technological capability

Quality, delvry time

reliability, price,

technological capability

Quality, delvry time

reliability, price,

technological capability

Required supplier quality initiatives None EDI (e.g.)EDI, Total Quality

Management, Statistical

Process Control

General purchasing strategy Price, technological

capability, augmented

service

Price, technological

capability, augmented

service

Total cost of ownership

Strategic alliances Being considered Being considered Fully deployed

Commodity teams Being considered Being considered Fully deployed

Supplier integration into new

process/product/service development

Fully deployed Being considered Fully deployed

Cross-organizational info sharing

systems

Being considered Fully deployed Fully deployed

MRO/Indirect purchase strategy

development

Being considered Fully deployed Fully deployed

Insourcing/outsourcing strategy

development

Being considered Partially deployed Fully deployed

Strategic cost management strategy

development

Being considered Being considered Fully deployed

Supply base development Being considered Being considered Fully deployed

Globalization None Fully deployed Fully deployed

Projections

Long term projections by the Energy Information Administration (EIA), an arm of

the Department of Energy that forecasts trends in energy usage, are that U.S. electricity demand

will continue to grow. However, energy demand through 2020 will slow continually, following

a trend prevelant since the 1960's. Increased demand management by utilities, sure to be driven

further by retail competition, will exacerbate this slowdown. The result is the average price of

electricity in 1997 dollars is predicted to decline 0.9 percent per year through 2020. (See Figure

1).

Volatile competition among the fuels of electrical generation will continue.

According to the EIA, coal will continue to dominate as coal prices continue to decrease, though

coal-fired plants' share of total generation will decrease from 53% to 49% by 2020. Nuclear

capacity will be cut in half, assuming that 27 plants are retired by 2020 and no new ones come on

line. The remainder will generate just 7 percent of U.S. electricity, and barring major

technological leaps in nuclear technology and/or waste storage capability, the industry looks all

but dead. Petroleum remains a tiny fraction of total generation. Figures 1 and 2 show the big

winner over the next 20 years is natural gas, the only fuel that will enjoy price increases (0.8%

per year) and will take substantial share (33% of total generation in 2020, up from 14%

currently).

Figure 1: Fuel Prices to Electricity Suppliers and Electricity Prices 1990-2020

(index: 1990=1)

1.2

1.0

0.8

0.6

0.4

0.2 history projections

0

1990 '95 2000 '05 '10 '15 '20

Source: Energy Information Administration "Annual Energy Outlook" (1998)

Figure 2: Electricity Generation by Fuel, 1997 and 2020 (billion kilowatt hours)

Source: Energy Information Administration "Annual Energy Outlook" (1998)

Natrl Gas

Coal

Electricity

Renewables - defined as hydroelectric, wind, solar thermal, photovoltaic, geothermal and

biomass generation - will continue to grow in usage. Projected scenarios for the share of

electricity generation accruing to renewables range from 3% to 6.5% by 2020. Renewables have

tremendous advantage over fossil fuels in terms of fuel input costs ($0 in the case of sun and

wind) and carbon emissions (zero). They represent a potential clean and sustainable energy

source, and their fate will depend greatly upon the degree to which the federal and state

governments subsidize renewable technology research and encourage expansion of renewable

capacity, thereby reducing the relatively high costs (up to 50% more per kilowatt hour than

conventional generation) associated with renewables.11

Table 6 indicates the electricity fuel mix within Sun Energy and Voltron's generation

portfolios. Given the volatile price landscape indicated earlier, part of Sun Energy and Voltron's

challenge over the next 20 years (and beyond) certainly will entail building diversified fuel

portfolios that are flexible enough to withstand price fluctuations, yet also have sufficient

duration to insure stable pricing and enable long-term planning. Even then, fuel costs represent

only half of Voltron's procurement spend and just one-third of Sun Energy's. The costs of labor,

wire systems construction and maintenance, and information system improvements represent

perhaps the lion's share of both companies' costs. New costs resulting from the competitive

environment, such as marketing and advertising initiatives, ramped-up customer service call

centers and energy management units are a certainty.

How Sun and Voltron procure these direct and indirect inputs - whether they insource or

outsource them, how they rank-order components in terms of strategic importance, what

companies (and how many companies) they buy from, how they pick suppliers and who within

11 Moore

the firm picks them - will directly determine cost structures. Thus, procurement strategy may

replace guaranteed "reasonable rates of return" as the prime determiner of Sun and Voltron's

bottom lines in the restructured world.

Table 6: Percentage Breakdown by Electricity Generation Fuel Type in Energy Portfolios

of Sun and Voltron

Type Sun Energy Voltron

Natural Gas 2.8% 12%

Coal 72% 45%

Uranium 12.3%% 12%

Renewables** 0.4% 1%

Oil 0.4% --

Whlsle Purch. of Electricity 12% 30%

Ave. length of fuel contracts 1-3 yrs 1+ yrs

** Hydroelectric, wind, solar thermal, photovoltaic, geothermal and biomass

CASE B – A POWER UTILITY IN PENNSYLVANIA (A DEREGULATED

STATE)

This manager interviewed for this case study has 25 years of experience in the energy

industry. He spent his first 15 years with the company working in generation engineering,

procurement, and working on the completion and modification of the company’s last two units of

nuclear generation. Later a management shakeup occurred, and new managers came in and

revamped the organization in order to be better prepared for the upcoming revolution in power

deregulation within the US and worldwide. The company was reorganized into six strategic

business units:

1) Nuclear generation

2) Fossil generation

3) Distribution

4) Transmission entity

5) Power team (Brokers)

6) New Ventures Group

The Power team was actually situated in a different location, and was given a mandate to buy

and sell electricity to customers at wholesale prices. For instance, the group worked closely with

a grocery chain; in exchange for fixed percentage of the savings achieved, the group would go

into the power market and buy power at the lowest market price for the entire chain of stores. In

other cases, the group was contracted to purchase electricity for certain blocks of time of the day

for industrial customers, acting as a type of “stockbroker” amassing a “portfolio of power” at

spot market as well as long-term prices (in order to hedge risk). The New Ventures Group was

tasked primarily with global acquisitions of promising utility companies worldwide. Since 1990,

this company has grown at an intense rate, and has acquired several large utilities in different

regions of the world.

During this period, the manager spent four years with the nuclear fuel division for four years;

two years at the one facility, and two years at a second newer facility. The latter facility was

shut down by the Nuclear Regulatory Commission when a core accident occurred. This resulted

in a major financial loss for the company, which was forced to shut down a nuclear plant at a

time when the regulatory climate in Pennsylvania was easing substantially. Without the “safety

net” of being able to cover this expense into their stranded costs as in the past, the company went

through a major reorganization and began an aggressive campaign to expand its operations

globally to diversify its risk.

Following this, the manager spent the last three years were spent in the utility’s supply chain

management organization. The manager was responsible for drafting technology policies,

leading training efforts, and leading the transition of the purchasing organization from a

traditional “buyer” mentality into a greater focus on supply chain integration. This proved to be

a highly challenging objective. Initially, his objectives were to improve the structure of the

utility’s purchasing organization. This was done by bringing together purchasing executives

from the different strategic business units of the company into a common group. The group met

on a weekly basis for a period of time, with the initial focus on training and sharing of best

practices within the different divisions. This was followed by a kickoff of several major

initiatives in the different business units, including supply base reduction and leveraging of

shared services across the company. The manager emphasized that there was initially a great

deal of skepticism on the part of these executives, particularly those who had been in purchasing

for a number of years. Despite the difficulty of introducing change, the results were largely

successful in terms of meeting cost reduction objectives.

The Pennsylvania-Jersey-Maryland Interconnection (PJMI)

The utility was connected to the PJMI, consisting of utilities from Pennsylvania, New Jersey,

Maryland, Delaware, and District of Columbia. The heart of this interconnected power grid was

the central station, which had a large board showing the different loads occurring at different

locations in the grid. The arrangement was essentially a type of alliance among the participating

utilities to use the next best (efficient) power generation to serve customers in cases when the

load was exceedingly high. Flows through the grid were managed using an economic impact

model – as loads increased, the next most efficient generator was brought on-line with savings

shared between the parties. This allowed all the parties to leave their turbine generators on and

maximize efficiency. An economic formula was used to share the costs among the parties - one

utility would not waste capacity resulting from idle generators, while the others would benefit

from cheaper more efficient energy from other members in the power exchange.

Today, the power exchange operates differently. . In the past, prices were fixed, and an

agreed price per kWh was paid to each utility in the exchange. Buyers could also purchase

longterm contracts from a generator at a fixed cost. Today, prices are much more volatile, and

the exchange is operated more like a stock exchange. Spot prices appear across the board, with

different bidders and sellers determining the price. Futures contracts are available to buyers,

who purchase electricity in blocks of time. Generation and transmission technology has evolved

to the point where a utility can direct electricity to certain lines, a capability which was not

possible a few years ago. By managing the different interconnections in the grid, buyers can buy

“blocks” of power which are subsequently “dumped” into the grid by the generator. A buyer can

also buy a portion of a generating facility’s capacity, which includes the purchase price plus the

“wheeling costs” (costs associated with the use of the transmission facilities of one system to

transmit power for another service).

The Distribution Arm

When the utility was split up into the different SBU’s, the idea was for each division to

develop and focus its unique competitive strategy (cost, availability, etc.). The distribution arm

of the company at one time had exclusive rights in certain areas of Pennsylvania, and was very

heavily regulated. A distribution company refers to the system of lines, transformers and

switches that connect between the transmission network and customer load at homes and

businesses. This is the portion of an electric system that is dedicated to delivering electric

energy to an end user at relatively low voltages. A distribution company is also responsible for

metering, billing and repairs. When the state of Pennsylvania introduced deregulation, it did so

on a progressive basis. The first year, 5% of the load was deregulated, followed by 30% the

second year, and so on until 2001 when all distribution would be deregulated. The distribution

arm was tasked with focusing on improving customer satisfaction to defend its market from

competition.

However, a number of “difficult” issues arose during the process of deregulation that remain

unresolved. For instance, it is not clear who is financially responsible in the event that a power

customer is delinquent in paying their bill. In the state of Pennsylvania it is illegal to cut off

someone’s power during certain times of the year (winter) for humanitarian reasons. As a result,

the company in the past has incurred some significant losses (approximately $80 million / year).

Previously, such losses were absorbed into the new rates for other customers the following year.

The company was also able to introduce a set of special low rate structures for low income

customers. However, this type of “electricity social program” is unlikely to occur – competitive

markets may well be defined by the state government, and its willingness to address this issue.

However, if rates decrease enough through competition, this may well become a non-issue.

Another sticky issue brought about by deregulation involves building capacity in rural areas.

If a company decides to build a manufacturing plant in a rural location which does not have

enough capacity in the existing grid, who is responsible for providing power to that region? In

most cases, the company building the plant would have to pay for upgrading capacity. In the

past, local customers would have seen their rates go up. In the future, the outcome will depend

on the regulations within the state. Consumers throughout the state may be charged if the

manufacturing plant is helping to reduce unemployment in the area, for instance. Other states

may choose to establish a cap on power costs charged to rural areas of the state. This example

illustrates how state regulators will have a major effect on power distribution regulations,

including cutoff conditions, distribution facilities, and charges. To some extent, distribution will

always be regulated, with the primary requirement being to serve and provide customers with an

uninterruptible source of power.

The distribution arm of this organization was almost always responsible for any type of

power outage that occurred. This was most likely due to a tree falling on a line, a vehicle

running into a post, etc. On rare occasions a transmission line went down. On average, the

company had approximately 5000 customers a day that experienced an outage. This number

went up to as high as 100,000 per day when a major storm took down major lines. The company

went so far as to hand out dry ice to customers who had no power for a greater length of time, in

order to help them preserve the supplies in their freezers!

Future Vision – Automated Metering and Billing

Currently, metering and distribution is still largely a government-regulated function.. This is a

highly regulated process because any errors in the customer’s favor are acceptable, but errors

favoring the utility require a rebate and penalties in some cases. Meters are a very sound

technology – they remain accurate for a very long time. Although the electric dials measuring

the energy use are very cheap, automated metering is still not an economically viable

proposition. When working with the utility, this manager was involved three years ago in a

major project investigating the possibility of automated metering. Manual electric metering

costs between $5 and $14 per meter per year, and costs approximately $25 to install. Automated

metering costs at least $100 per meter, and have a 12 year payback period. The extra cost of

between $60 and $90 over a 12 year payback simply did not make this option commercially

viable.

However, we may witness different types of metering technologies evolving in the future.

Potential technologies include meters with relays that send out signals to a centralized home

office, or trucks that drive by and pick up the signals from meters on the buildings. Technologies

are also being developed by companies such as Cell Net, Ericsson, and ABB, that may provide

“intelligent meters” that facilitate two way communication between the meter and the home

office. However, it is unlikely that technologies such as metering via EDI will become viable in

the near term. Similarly, “time-of-day pricing” was not believed to be able to generate any

substantial net savings for residential markets. In most cases, loads for residences can be

predicted fairly regularly, and is generally tied to “degree days” (on both the high and low end of

the spectrum). Of course, heat waves occurring for multiple days at high humidity levels (such

as in the summer of 1999) do not fall into this pattern , and often put a strain on existing systems.

Advice to Purchasers

The most important action that purchasers can take is to understand their own usage

patterns. Many industries that use a large amount of power have developed cost curves for

different days of the month, and are able to select what times to run their plant to optimize power

costs. For instance, some plants run a light day shift and a heavy night shift, since kWh costs are

generally lower at night. High use companies also negotiate very detailed contracts that are

highly customized to the plants specific power requirements. Generally speaking, commercial

customers should try to smooth their demand and reduce peak loads. For instance, an ingot

manufacturer in Redding worked very closely with the utility by sharing their specialized

requirements for power. The utility was able to work with this customer in “load shaping” to

reduce peaks, in order to derive the lowest energy costs. This is done a lot by other industries

with mechanical equipment that can operate in a “lights out” environment at night (pumps,

furnaces, etc.)

CASE C - CO-GENERATION: CUTTING ENERGY COSTS IN THE

STEEL INDUSTRY

On February 1, 1999, disaster struck on the site of Blue Steel Company12. An explosion

rocked the ancient Blue Complex Powerhouse, which had provided on-site electrical generation

for both the steel company and its neighbor and customer, a large auto assembly plant. . Six

automotiveemployees were killed and many more injured in the blast, the cause of which is

undetermined at this writing.

12 Fictitious company name.

Blue shared ownership of the Powerhouse with the auto maker, which had built it in the

1920s and continued to manage and maintain it. Though the Powerhouse was not cost effective,

it was the primary source of power for Blue and it provided a profitable use for the blast furnace

gas by-product from Blue's steel melting process. Blue was able to provide blast furnace gas to

the Powerhouse as an input for electricity generation and charge the auto maker for a portion of

the gas. With their power source suddenly depleted, Blue and the auto maker had to quickly

arrange a hook-up to the transmission grid of the area regulated utilityin order to resume

operations.

The Powerplant disaster, and the string of lawsuits and bad press that resulted from it,

culminated a tough 1998 for Blue, a period that featured: 1) a 54-day General Motors strike that

greatly affected orders, 2) increased steel production and competition from "mini-mills" and 3) a

disastrous Asian economy that caused foreign steel to be dumped on the US market at prices

lower than cost. These factors coalesced to cause spot market steel prices to plummet. "In all

my years in the steel business," said Blue's Chairman and CEO, "I've never seen a strong market

go soft so fast".

Fortuitously, Blue Steel executives had been developing an alternative plan for

generating electricity on site prior to the Powerhouse blast. The new plan, involving a joint

venture with a large investor-owned utility (IOU) and Blue's powerful automotive company

neighbor and customer, is designed to save Blue substantial energy costs over the next 15 years.

Blue Steel, which has not recovered after seeing its 1996 net income fall by 75% from the

previous year, covets those savings

Background

Blue Steel began as part of a vertically integrated automotive empire in 1919, with a

battery of Coke ovens and two blast furnaces. Through the 1930s, Blue added rolling and

finishing mills to upgrade its steel products. An oxygen furnace was added in the 60s, and in

1974 Blue added a hot strip mill, the last full size mill of its kind to be built in the US. Through

the 80s, Blue invested $760 million in capital improvements. In 1986, it formed a joint venture

that ranks as the world's largest electrogalvanizing facility and makes products such as outer

body parts for automobiles.

Blue was purchased in 1989 by a consortium led by the current CEO. The company went

public in 1994 and trades on the New York Stock Exchange. Currently, Blue Steel ranks as the

eighth largest steel manufacturer in the US.

Products and Processes

Blue Steel products include flat-rolled carbon steel products, including hot rolled, cold

rolled and coated steels. Company literature touts technological advances in lightweight and

dent-resistant steel, and corrosion-resistant steel that prolongs the life of exposed auto parts.

Blue has also diversified by forming joint ventures with several companies.

Blue uses two blast furnaces for melting steel, and has invested about $100 million since

1994 to maintain these and to increase production capacity. In addition to electricity

requirements amounting to roughly 20% of Blue's total procurement costs, steam requirements

for driving these blast furnaces are one million pounds per hour, which the Blue Complex

Powerhouse provided prior to the February 1999 explosion.

Though steel industry trends favor more efficient electric arc furnaces over steam-driven

blast furnaces, Blue has decided that replacing their blast furnaces would not be cost effective for

two reasons: First, Blue's site would not easily accommodate the much larger electric arc

furnaces; second, the blast furnace gas that is created as a by-product of the blast furnace process

is valuable as a fuel for electricity generation. Thus, Blue had been recycling its blast furnace

by-product and supplying it to the now-defunct Blue Complex Powerhouse.

The new co-generation facility also will convert blast furnace gas to electricity, and the

automaker will continue to procure a portion of the gas from Blue.

Customers

Blue serves primarily the Big Three automakers, which account for about 85% of sales.

Other customers include tier-one auto suppliers, service centers and nonautomotive end users.

Price Volatility

Steel prices have traditionally been volatile. To protect itself from volatility, Blue sells

two-thirds of its steel products via fixed-priced contracts, negotiated annually. In 1991, prices

reached a nine-year low in response to low production and shipments industry-wide. Prices rose

steadily through mid-1995. After that time, prices trended down and Blue lost one-half of the

pricing gains it had realized since 1993. The company has not turned this situation around. In

spite of robust demand, Blue's total net income over the last three years has not equaled its 1995

figure of $94.7 million.

The Interim Energy Solution

In the wake of the Powerplant disaster, Blue and the automaker have implemented an

interim solution to provide power till the new co-gen facility fires up in June of 2000: They have

contracted with the local wire company (wireco) to supply 125 megawatts (mW) of firm

(guaranteed) power to run the plants. An additional 55 mW of interruptible power - 35 mW for

Blue, 20 mW for the automaker, by internal agreement - is available from the wireco.The per

kilowatt-hour (kWh) aggregate price for electricity in this interim arrangement is actually

cheaper than the price from the defunct Powerhouse, which was 6-7 cents per kWh. However,

the constraints of the interim arrangement have hampered Blue's energy-intensive milling and

metallurgical operations. When Blue's electrical load exceeds the 125 mW of firm power - not

an infrequent occurrence - The wireco has the option of cutting Blue's supply down to the 125

mW firm limit.

Because Blue's steelmaking processes are highly variable in their load requirements, it is

difficult to gauge when they will exceed the 125 mW limit. One manager says "(The wireco's)

people in their downtown offices can tell when a steel bar hits a certain point in the mill, just by

watching the meters jump."

As a result of the 125 mW constraint, Blue has contingency plans in place to prioritize

operations and shut down certain mills during power interruptions. These cutbacks have

amounted to $10 million in production losses since February 1999. Additionally, lacking an on-

site generating facility, Blue has had to invest in temporary 'package boilers' - mobile-home

sized, natural gas-driven systems - to produce the one million lbs. per hour of steam required to

drive the blast furnaces. Lastly, without a means to utilize its blast furnace gas, Blue has had to

dispose of its valuable by-product by burning (flaring) it, a process that results in $15-$18

million per month of disposal and opportunity costs.

The Co-Generation Facility

"There is no single project that is more important to the future viability of Blue Industries

than the development and implementation of this new co-generation facility."

___Blue Steel CEO

In June 2000, Blue and the neighboring automaker will begin receiving 400mW of

dedicated electricity froma generating facility being built across the street from the Blue

complex. 310 additional mW will be made available some time after June 2000. The

plant will be cleaner and more efficient than the old Complex Powerhouse since it will

use natural gas to generate electricity instead of coal, a high-pollution fuel. Like the

Powerhouse, the new facility will also run on blast furnace gas and will generate the vast

amounts of steam needed to drive Blue's processes.

The facility represents a joint venture between an outside investor-owned utility

(different from Blue's current wireco); the automaker; and Blue. The utility will build the

facility for $240 million and staff it with 30 operators. The utility is charged with managing the

generation process in the most cost -effective way to insure price targets are met.

The automaker will continue to procure blast furnace gas power from Blue.

The venture has a term of 15 years, with electricity prices set in advance. In the first

year, Blue will pay 4 cents per kWh. This will decrease to 2.9 cents per kWh the next year, and

fluctuating thereafter based on certain agreed-upon contingencies through 2015. Blue officials

expect this arrangement will reduce company operating costs by $30 million per year

Procurement "Best Practice" Issues

Blue does not have a commodity purchasing group dedicated to energy procurement.

The co-gen joint venture was implemented at the executive level. The 15-year term of the

agreement precludes many 'short-term' strategies that Blue may have used for energy purchases,

especially in the soon to be restructured environment of Blue's home state. Many companies in

currently restructured environments waited for state restructuring initiatives to be implemented,

observed the short-term price trends, accepted Requests For Quotes from dozens of new energy

providers and marketers, and cut short-term deals with providers that included an array of

associated value adding services.

Conversely, Blue opted for a purchase agreement that was quick, long-term, and

primarily price-based. It is arguably fortuitous that it did; had Blue (and the automaker) delayed

in finalizing this venture until after the powerhouse explosion, the utility that constructed the co-

gen facility would have been in a far stronger negotiating positionThough Blue management

feels the agreement took restructuring out of the equation, it is evident that restructuring played a

role. Currently, ratepayers are captives of the regulated utilities that transmit and distribute

electricity within the designated service area. However, Blue's home state's utility regulating

agency is moving forward on an initiative that would see state ratepayers eligible to freely

choose their energy service provider within 2-3 years. Action at the federal level may accelerate

that process. It is doubtful that the utility, anticipating deregulated electricity price reductions of

perhaps .09% per year through 2020,13 would have locked in a 15-year deal absent pending

deregulation.

Other deregulation/restructuring issues impacting the co-gen venture are:

Competition. One manager remarked that one of the hallmarks of the deal was the

amount of competition between two utilities to build the facility and provide the power. (Blue's

13 Annual Energy Outlook 1998, Energy Information Administration

current wireco was originally in for a 30% equity stake but ultimately opted out.) A Blue official

said "We would not have done so well on this deal had there not been a great deal of competing

between (the utilities)."

Wheeling. Electricity restructuring and deregulation laws permitting, many of those 400

mW of firm power owed by the utility to Rouge under the co-gen agreement may be available

for resale by Blue to its equity-based joint venture partners. In order for this to occur, the

restructuring initiative would have to force Blue's current wireco, which owns the area

distribution system, to allow Blue to act as a retailer and "wheel" electricity to its partners over

the wire company's system.

Tax exemptions. As generation units of utilities become deregulated entities, they lose

many tax exemptions for capital investments and improvements. Thus, the utility building the

co-gen unit will not likely qualify for tax abatements on the facility itself.. Blue is lobbying in

the State Legislature for tax abatements on the utility's behalf. The tax abatement issue is galling

to Blue management because the co-gen plant represents an investment in a dedicated, highly

efficient and clean (relative to coal and nuclear facilities) gas-fired generation plant. Blue argues

that the government should not be discouraging such ventures by disallowing tax abatements.

Opportunities

World-class procurement practices generally include development of strategic buyer-

supplier relationships that feature inter-organizational information exchange, goal congruence,

supplier evaluations and mutual cost-reduction efforts. Though the Blue - auto maker - electrical

utility joint venture is well beyond the adversarial, purely transactional relationship that

undoubtedly characterizes Blue's interim arrangement with its current wireco, it is still primarily

price-based. Issues of demand management, energy efficiency, net metering and load shifting

that will affect many energy deals in the restructured environment are nullified somewhat in this

deal due to prices being locked in for such a long period. Initially, issues of cost-cutting and load

management are incumbent only upon the utility, which has promised set prices for at least the

first two years. The auto maker and Blue are not required to help the utility, nor to periodically

evaluate the utility based on anything but their monthly bill.

Yet, the co-gen plant is a de facto example of supplier co-location, a strategic

arrangement in which a supplier stations live personnel at its customer's plant. There is

tremendous opportunity for the utility to learn about the unique requirements of its joint venture

partners, who also happen to be greatly significant, strategic customers, via the 30 operators it

will station at the co-gen facility. It may well be to the utility's advantage to work closely with

both Blue and the auto maker to make their customers' facilities more energy efficient. This

would be true primarily if wholesale electricity prices eventually trend above the utility's pre-

arranged prices under the co-gen agreement and the utlility decides that they want to free up

some of the excess load to sell in the deregulated market.

CASE D: PURCHASING ELECTRICITY IN A GLOBALLY TRANSITIONING MARKET: AN AUTOMOBILE MANUFACTURER’S

PERSPECTIVE

The deregulation of electrical utilities is rapidly becoming a reality in the United States.

This transition has already taken place in other countries as well, including the UK (1982), and

Argentina. Legislation is also being considered for the European Economic Community at large,

as well as Canada, Mexico, and other large trading partners. Organizations that purchase

significant amounts of electricity as part of their operating expenses can benefit from adopting a

global energy procurement strategy, as the organization described in this case study has done.

This is a large global automotive company with 1998 sales of $145 billion with plants in

the United States, Canada, Mexico, the UK, Germany, South America, and China. Coordination

of all energy procurement for plants located around the world is centralized at the company’s

corporate headquarters in Michigan. The Energy Efficiency and Supply group is led by the Vice

President, who has North American, European, Argentinean and Brazilian managers reporting to

him in the areas of Natural Gas, Electricity and Water, and Energy Efficiency programs (see

Figure 1). The managers of natural gas and electricity are primarily responsible for tracking and

negotiating with suppliers of these commodities, while the energy efficiency managers work

with plant managers to improve the efficient use of electrical power in their core processes. The

VP of Energy Efficiency and Supply in turn reports to the Executive VP of Sourcing, who sets

all goals and objectives regarding annual targets, etc. This is an important linkage, as to achieve

these goals, the VP of EE&S must often obtain the cooperation of other functional Executive

VP’s, especially in Manufacturing and Engineering. Having access to a corporate champion at

the executive level is a core requirement for implementing a global energy procurement strategy.

The VP of Energy Efficiency and Supply is tasked with a huge responsibility: managing

and controlling energy costs for all of the company’s plants worldwide. Electrical power is a

significant portion of the total cost of producing an automobile; in 1998, the company spent $750

M on energy worldwide. The stretch goals for the VP were to reduce costs by $50M (a net

reduction of 6.7%). This objective is the primary criteria upon which this individual’s

performance evaluation is based.

Energy Strategy Objectives and MeasuresThe strategy of this company for achieving these goals is fairly straightforward, as

discussed by the VP: “To succeed, we need to know more about the business of electrical

generation and distribution than the suppliers of power themselves! To accomplish this, we

spend a lot of time training people to learn about the business. We are also not afraid to hire

engineers right out of the utilities and put them to work for us, since they are the experts! More

than anything, we need to be able to understand our power needs and negotiate better with

suppliers to achieve economies.”

This strategy begins by closely tracking demand for power in all of the company’s global

vehicle operations. For every plant, the group collects information on total usage by kilowatts,

kilowatt-hours, BTU’s, total dollars spent, and prices paid (cents per kilowatt-hour). This

information is also broken down by type of energy usage (natural gas, electricity, oil, and

purchased air and steam). Finally, the information is tracked by BTU’s (millions) per vehicle

produced. The shape of the latter graph over the last several years is shown in Figure 2.

This analysis is further broken down to adjust for production volume increases. In all of

the plants, approximately 60% of the energy costs are fixed, not variable. Examples of fixed

energy costs are the paint shops and heating, both of which are run 24 hours a day and do not

vary with the number of vehicles produced. As shown in Figure 2, when paint shop capacity was

doubled, energy requirements naturally increased as well. For the remaining 40% of the costs

that are variable, however, the volume-adjusted cost reductions achieved have been on the order

of 5% per year (adjusted by volume).

Strategy DeploymentThe strategy for achieving energy cost reductions across multiple plants in multiple

countries is not an easy one. It begins by establishing objectives for each division in terms of

energy cost reductions. To help in deploying these objectives, the VP of Energy and Supply

enlists the help of the Executive VP of Manufacturing in getting “buy-in” to these objectives in

evaluating each plant’s performance. The common cost driver for each plant is BTU’s per

vehicle produced. While this is sometimes a contentious issue in terms of measurement, it is a

common metric that can be easily calculated and employed across all divisions. Differences in

economics, etc., are resolved by setting different levels of goals and objectives for each division

and each plant. To aid in developing these objectives, the VP of Energy works closely with the

Executive Vice President of Manufacturing, with the common cost driver being the number of

vehicles produced by plant. Each year, the divisions report on their performance, and the

numbers are rolled up and presented to the VP of Sourcing. The major objectives are focused on

North American energy spend, which represents forty-nine of the company’s one hundred and

three plants worldwide. The objective was to reduce North American energy spend by 20% in

two years – the actual savings were on the order of 18%.

International Energy SpendingOne of the important tasks in being able to negotiate lower energy rates is simply keeping

track of energy usage. For instance, the company tracks total usage of electricity, gas, and coal

by country, and within plants by country. Total usage is shown in Table 1. Price trends are

tracked, and used to further justify lobbying efforts focused on deregulation. A sample of the

average price paid by the company per kilowatt-hour in the different countries is shown in Table

2.

Achieving Savings ObjectivesThe $55 million in energy savings in the plants has been achieved in several ways. The

primary focus is on 1) Exchanging power modes ($16M), 2) Volume and performance

contracting ($7M), 3) working with plant personnel on energy efficiency through training,

process analysis, and policy deployment ($32M). In addition, the company works extensively

with federal and state lobbying groups to put pressure on deregulation of energy in the different

states the company operates in. Each of these strategies will next be described.

Exchanging Power Modes

The company has enjoyed a $16M savings by conversion of natural gas to electricity power

modes. Increasingly, automation is driving the use of greater electrical use, and is thereby

improving efficiencies. Deregulation of natural gas and lower cost alternatives has helped in

fueling this conversion. Although some capital outlays were required, the forecasted savings

will be substantial.

Volume Leveraging

Another $7M in savings is achieved every year through volume leveraging and entering

into longer-term fixed price contracts with utility providers. This is obviously more easily

achieved in states that deregulated their markets. Prices paid per kilowatt-hour will also vary by

state, according to whether it is a “low-cost” or “high-cost” state. An example of the price

differential found by state and by different utilities is shown in Table 3.

In each case, this process is initiated by collecting plant-level data on energy usage. This

is a tedious process, and it takes six weeks every year to collect the data. Although the company

is beginning to install metered systems that are capable of reading loads by plant in real-time,

this technology is not yet fully deployed throughout its global plant network. Once the relative

loads and prices paid are well-understood, efforts are made to negotiate lower rates with the

utility in that area. This is largely ineffective in states that are still regulated, and obviously

easier in states introducing deregulation. . In all of the company’s major markets, electricity was

still regulated at the time of the interview (with the exception of Pennsylvania and New York). It

is notable that of the prices shown in Table 3, some of the lowest rates are found in

Pennsylvania. It is also interesting to note that one of the largest energy price reductions was in

New York (see Plant #18 in Table 3). In this case, the company opened up its energy contract

for bid once deregulation went into effect. Not surprisingly, the local utility won the bid, but

lowered its rates from 7.5 to 5.5 cents per kwh.

The highest price paid in the country is to an energy company that is straddled with a

nuclear energy facility that was shut down due to safety issues in the 1970s. This debt burden is

continuing to be passed on to customers in the form of “stranded costs”. The lowest rate in the

country is paid in Pennsylvania. This was an interesting story in itself. In negotiations, the

utility was asked why it could not provide a lower rate currently provided for a local university.

The reason cited was that the university rate was based on a 10MW load that “is not applicable to

you, since your load is 9.6MW”. Subsequently, the CEO of the utility was invited to the plant,

and a number of quality problems related to numerous momentary disruptions in power over the

last six months were presented. Next, the CEO walked into the plant, where he was greeted by

plant workers who had brought in electrical appliances (hair dryers, fans, etc.) all turned on, in an

effort to bring the load over 10MW! The CEO quickly got the point, and agreed to provide

power at the lower rate!

3. Energy Efficiency

A significant chunk of a plant’s energy bill occurs because of inefficiencies in plant

operations. Energy Efficiency (EE) Managers therefore spend a lot of time with plant operations

personnel to educate them on techniques to reduce power usage. This can be done by

rescheduling of jobs on machines, turning lights out on Sundays when the plant is not operating,

turning off compressors when not in use, finding and eliminating air leaks in compressors, and a

variety of other techniques. When all of these little changes are combined, they add up to

significant savings! In most automotive assembly plants, the paint shop is responsible for over

one-third of the energy bill. The painting process requires that air be heated, re-humidified to the

proper level, solvents added, and any waste incinerated (as dictated by EPA regulations). Many

shop managers believe that getting the paint shops to the right equilibrium is an "art, not a

science.” Thus, when the painting process reaches a proper equilibrium, the plant may choose to

leave it on all weekend rather than turn it off, and disrupt shop operations. A major training

effort by the EE group convinced these paint shop managers that they could turn off the

equipment on Friday without disturbing the equilibrium, and start it back up on Monday. This

involved understanding the process, demonstrating the case, and getting buy-in from the

individuals.

In addition to internal efforts to generate efficiencies, significant savings are generated by

converting investments in power generation to energy contracts with suppliers (essentially

outsourcing). Many older substations are no longer efficient, and are being mothballed and

replaced by long-term energy contracts with cost-competitive suppliers. As part of these

contracts, suppliers are also responsible for managing energy requirements, peak loads, and

improving efficiencies. For instance, some suppliers are now replacing fixtures in equipment in

the facility and obtaining savings of up to 20 % on individual processes within the plant. They

will pass on 75% of these savings to the company. For the remaining 25%, the BTU’s saved are

adjusted by the hours worked on the project, and they are paid for the energy saved. This has

been done in the area of lighting, heating and ventilation, air leaks, and compressors.

Evaluating Energy Suppliers and Managing Energy Contracts

The Vice President points out that although price is important, a purchaser should also

evaluate a utility providers’ quality record, since power outages can be very costly in terms of

lost time and plant operations. Thus, Quality is a primary criteria for evaluating the utility,

which in turn is determined by the distribution company. In one case, the VP met with a

Canadian utility company to discuss quality issues. When the CEO of the company was

confronted with the issue, he insisted that there was no problem at all with power interruptions.

However, records were then brought out to demonstrate that there were over a dozen momentary

power outages in the last six months. The CEO was astounded, as he had no idea this was the

case. Subsequent to this effort, the number of power outages was cut in half over the next six

months.

Price is the next most important criteria in choosing a utility, in order to achieve cheap

and certain delivery of power. In negotiating price, a first step is to understand the utility’s tariff

structure, the local energy commission’s approved rates, and all “unadvertised programs” that the

utility may be offering to other entities in the area. Once these rates are understood, the

company works with the utility to understand what different options are available to work jointly

in lowering energy costs. The output of this stage of negotiation is a contract. In one case that

occurred five years ago, the energy group was unable to negotiate any price reductions with a

local utility in Arizona that provided power to its test track in the desert. In this case, the

solution was to cut the existing power lines into the facility, and install diesel generators to

provide power at a much lower cost! This arrangement is still in place today.

The company employs a variety of different energy contracts with different providers,

depending on the situation. Generally, a mix of long-term fixed contracts and spot market price

floats are used to manage price risk. This is done largely “on good judgement, based on

regulatory patterns, natural gas prices, and other events that may occur.” Market hedging is not

employed, largely because the cost of a hedge is so high that the savings do not materialize.

In other cases, the company negotiates longer term pricing. One contract with a

Michigan-based utility extends ten years into the future, but is 25% below current tariff rates.

Another contract with an Ohio utility in 1995 is also 10 years in duration, but requires a gradual

reduction in energy purchased over time. For the first five years of the contract, 100% of

requirements are purchased from the utility, with reductions in 20 percent over each of the five

ensuing years.

The company has also worked with local municipalities to aggregate purchasing power.

In one case, it worked with a group of a small township in Michigan to create a municipal utility.

Faced with the alternative of having to create a new power plant, the VP approached he mayor of

the township. He promised a savings of at least $150 per homeowner over five years, by

combining domestic residential energy requirements with their plant requirements. To help

instill good faith and gain credibility in the community, the VP delivered these savings up front,

and presented the mayor with a check of $1 million (discounted at 6%) at a public ceremony.

This option was both good for the community and good for the business. We will undoubtedly

see more townships becoming aggregators and municipal electrical systems in the future, and

partnering with business can provide significant savings to both parties.

Finally, the importance of managing long-term relationships with energy providers

cannot be discounted. In one case, the company has worked in a cooperative manner with a

nearby steel manufacturer and local energy utility to build a new 700 mW co-generation facility

that will supply energy directly to both the steel and automotive manufacturing facilities. The

contract stipulates that if the utility fails to build the facility on schedule, they must cover the

cost difference in their generated pricing. The contracted rate of the co-generation facility is

fixed for a 15 year period.

When a major explosion destroyed the steel company’s existing substation in 1999, the

co-gen facitlity was only in the planning stage. Thus, an interim energy solution had to be

implemented to allow the plant to run in the meantime. Due to the nature of the long-term

relationship between the company and the local utility, the plant was up and running again in 18

hours using diesel generators. The utility took immediate action to resolve the crisis. The

importance of developing supplier relationships, even in a monopoly market, was an important

lesson learned from this occurrence. Integration of energy providers into plant operations will

become even more important in the future.

Lobbying Efforts in State, Federal, and International Arenas

An important component of this company’s long-term energy strategy is its efforts to

introduce competition into the state of Michigan, and promote efforts to introduce competition

on a nationwide basis. The VP insists that “utility monopolies breed inflexible utility executives

who have no motivation to reduce costs”. In order to promote deregulation, the VP works

closely with a number of industrial intervention groups, including ABATE in Michigan,

Industrial Electricity Users in Ohio, and Elcon in Washington D.C. He has testified at both the

state and national levels, and in each state, belongs to an organization composed of the top 25

users of electricity. The state groups all employ law firms to represent them at hearings at the

state commission, with Elcon helping to coordinate these groups from the federal level.

In Michigan, deregulation has been a particularly perplexing problem, since the Governor

does not want to see local utilities purchased by outside utilities in a deregulated market. This is

an aspect that the utility companies have played up to a great extent. Thus, laws have been

established for a stranded costs commission. If utilities are purchased, the purchasing company

must hand over all stranded costs collected back to the state. An issuance by the Commission on

March 8 1999 sought to phase-in customer choice. In a more recent ruling (June, 1999),

legislation seeking to increase deregulation has not passed at the state level, despite an active

Public Service Energy Commissioner who actively promotes deregulation. In a public statement,

the Commissioner noted that “. . we have recognized that government regulation, as well-

intended as it has been, cannot bring about the same degree of economic efficiency and

innovation which is spurred by the competitive market. I believe that unrestrained competition

can produce the best results. I also believe that, to create an environment in which competition

can flourish, we must have a national vision unconstrained by artificial state boundary market

barriers. 14

Lobbying efforts are also promoted on an international basis. The VP claims that “one-third

of our international results are due to effective lobbying.” Although European Economic Union-

mandated energy deregulation was supposed to be in place by February 1, 1999, there are no

such laws in France and Germany. Meanwhile, although deregulation was initiated in the UK in

1992, prices have actually risen by 33% because of flaws in the bidding process! In the opinion

of the VP, collusion within the industry is occurring as a result of the deregulation structure.

14 Statement by The Honorable David Svanda, Commissioner, Michigan Public Service Commission, House of Representatives SubCommittee on Energy and Power Hearing, Thursday July 1, 1999, Washington DC.

When Margaret Thatcher deregulated the UK system, the structure included 40% power

generators, 40% national power companies, and 20% nuclear power generation. The electrical

pool was structured in such a way that companies bid in their highest price for electricity that is

determined by their highest capacity run. However, all parties involved are bidding high prices,

with no bidding at the lowest levels. This in turn raises the total cost of electricity.

The Future of the Power Market

In looking to the future, the VP believes that the cost of electricity will inevitably go down to

at least the 3.5-4 cents/kwh range for industrial users of 10 MW and up.15 He also believes that

in the future, the company will not necessarily eliminate the practice of single sourcing, even

though more alternatives will exist. In an open market, however, the potential of new entrants

will make utility providers more competitive. The future market will consist of power marketers

capable of bundling and unbundling power in order to match the loads of specific customers.

Customers will also band to form power cooperatives, capable of wielding greater market power.

Following previous trends in the telecommunications and natural gas industries, the number of

such power marketers will inevitably explode initially, followed by a consolidation within the

industry.

This is a major change from the current state of affairs, wherein companies must buy from

local utilities. Even in deregulated states, the VP emphasized that they must nevertheless pay for

marginal rates, plus transmission costs plus recovery of stranded costs.

15 Based on an assumed powerload factor of 70%.

Figure 1

Reporting Structure: Global Energy Procurement

VP – Energy Efficiency and Supply

Executive VP of Sourcing

Supply Manager -

Natural GasN. America

Supply Manager – Electricity & Water

N. America

Supply Manager –

Energy EfficiencyN. America

Supply Manager -

Natural Gas Europe

Supply Manager – Electricity & WaterEurope

Supply Manager –

Energy Efficiency

Europe

Supply Manager -

Natural Gas Brazil & Argentina

Supply Manager – Electricity & WaterBrazil &

Argentina

Supply Manager –

Energy EfficiencyBrazil &

Argentina

Figure 2 – BTU’s (millions) consumed per vehicle produced

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

ADDED PAINT SHOPS TO DOUBLE CAPACITY

REDUCED TOTAL COSTS BY 5% IN

LAST TWO YEARS

16M BTU’s / vehicle

Table 1 – Total Energy Usage (Millions of BTU’s)

Electricity Gas Coal TotalNorth America 372 124 35 541Europe 138 46 13 198Other Countries 22 7 2 29Total 532 177 50 760

Table 2 – Average Price Paid by Country (cents per kilowatt-hour).

Canada 3.96United States 4.48Mexico 4.49Europe (Average) 5.6 France 4.38 Belgium 5.33 United Kingdom 5.91 Germany 6.09 Spain 7.33

Table 3 – Contracted Electricity Prices Paid by Manufacturing Facilities in North America (average cents per kilowatt-hour)

Location 1998 1997 97 vs. 98

Comments

1. Pennsylvania 3.19 3.01 -5% Off peak charge increase2. Tennessee 3.30 3.07 -7% Contract through 9/993. Oklahoma 3.31 3.48 5%4. Pennsylvania 3.47 3.43 -1%5. Ohio 2 3.52 3.48 -1%6. Indiana 3.56 3.52 -1%7. Kentucky 3.60 3.54 -2% Contract through 9/998. Pennsylvania 3.87 3.75 -3% Fuel Price Increase9. Ontario, Canada 3.94 3.96 1%10. Georgia 4.06 3.78 -7% Contract through 9/9911. Virginia 4.08 4.21 3% Contract through 9/9912. Pennsylvania 4.10 4.16 1%13. Kansas 4.20 4.10 -2%14. Michigan 4.46 4.46 0%15. Mexico 4.59 4.85 6% Peso deflation16. New York 4.61 4.43 -4%17. Ohio 5.00 5.05 1%18. New York 5.20 6.06 17% Bidding / Negotiation19. New York 5.68 5.77 1%20. New Jersey 6.33 6.35 0%AVERAGE 4.22 4.22 0%AVERAGE of “Best 10”

3.72 3.50 -6%

Note: The names of utilities in these locales are withheld.

CASE E - A JOINT VENTURE BETWEEN A MANUFACTURER

AND POWER MARKETER TO DRIVE DOWN ENERGY COSTS

Zschau-Bork16 is weathering perhaps the roughest period of its 60-plus year history. The

$705 million net income loss ($13.16 loss per share) the company posted on its 1998 income

statement was largely attributable to a $1.4 billion provision for litigation claims pertaining to

manufacture and sale of asbestos, the cancer-causing, fire-resistant material which the company

stopped making in 1972. (See Appendices A and B for recent Zschau-Bork financial data). The

1998 loss came on the heels of a $284 million loss registered in 1996, also a result of asbestos

litigation payouts. Though Zschau-Borkclaims to have the asbestos matter under control via a

comprehensive initiative designed to resolve claims over the next decade, massive payouts will

continue for a while.

In response to the uncertainties facing Zschau-Bork over the next ten years, its CEO is

driving a vigorous restructuring and refocusing effort. Among other goals, the CEO wants

operating costs eventually reduced by $175 million per year.

Given that Zschau-Bork'sglass making and composites operations are extremely energy

intensive, their global buyers of electricity and natural gas will be under pressure to control costs.

As the CEO put it: “As an energy-intensive industry, composites is…targeting a substantial

improvement in energy productivity”. Given that Zschau-Bork's operating processes do not

result in a by-product that can recycle as an energy input for on-site generation energy cost

reductions at Zschau-Borkmust come via price and cost reductions related to energy purchases.

16 Fictious company name.

Electricity restructuring, especially in the U.S., provides opportunities for Zschau-

Borkprocurement managers to negotiate favorable pricing structures and slash electricity costs.

Background

.

Zschau-Borkbegan as a joint venture in 1936. It became a publicly traded company on

the New York Stock Exchange in 1952.

Global expansion began as ventures were established in Japan and Australia. In 1960,

Zschau-Bork expanded existing operations in Canada and began operations in New Zealand and

South Africa. The 1980s were abundant with new plant openings all around the world.

In 1986, in the wake of the unfolding asbestos disaster, a firm presented an unsolicited

offer to purchase Zschau-Borkat $74 per share. Zschau-Bork's Board of Directors rejected the

offer. Zschau-Borkstockholders formally approved a restructuring plan, still ongoing, which

focused on its core businesses. The plan was designed to give shareholders more value than the

outside offer. Eventual approval by the shareholders preserved Zschau-Bork's independence, but

entailed a total charge of $243 million against earnings for the restructuring. Still, as the 80s

came to a close, Zschau-Bork reported sales of $3 billion, and employed 18,300 people. The

company is currently a global leader in building materials and composites systems, with 135

manufacturing facilities and more than 180 distribution centers in over 30 countries.

Energy and Electricity

One of the CEO's primary initiatives since taking over in 1992 has been implementing

the operations restructuring measures that grew out of efforts to stave off the 1986 takeover

attempt and to address uncertainties in the face of the asbestos disaster. These efforts have

resulted in $185 million in direct restructuring costs (primarily the elimination of 1,900 positions

worldwide) and approximately $200 million in associated costs (primarily asset impairments)

since the last quarter of 1997 alone, with more to come. Subtracting the $1.4 billion cost for

asbestos litigation claims, the $385 million restructuring cost to date represents one-fourth of

1998 total operating expenses.

Charged with capitalizing on this huge restructuring investment are senior managers such

as Jim Lewen, who is charged with global procurement of gas and electricity. Zschau-Bork's

manufacturing and composites operations are very energy intensive; expenditures entail $100

million per year for electricity and $40 million per year for gas, a total representing nearly 20 %

of operating costs for 1997.

U.S. electricity restructuring initiatives have provided energy buyers like Lewen with

new opportunities to drive down energy costs. Zschau-Borkhas U.S. operations in some 20

states, most of which are restructuring, or have restructured, their gas and electricity markets.

Energy cost management at Zschau-Borkis a two-pronged effort: Global buyers such as

Lewen are responsible for getting energy to plant meters as efficiently as possible and at the

lowest total cost. Floor-level plant level managers are then responsible for monitoring energy

expenditures, explaining variances and managing individual loads efficiently and well.

Zschau-Bork'soverall energy purchasing strategy involves participating in “intervention

groups” that work at a legal and policy level to influence electricity restructuring policies

currently being formulated in most states. These groups work with state utility regulators and try

to insure that rates are reduced and that true retail competition is realized in the deregulated

environment.

In states where deregulation is in place or soon to be in place, Zschau-Borkleverages its

large total spend with its existing electricity suppliers, using the specter of open competition as

additional leverage. For Zschau-Bork, price is the primary metric used to evaluate potential

electricity suppliers. “We spend close to $1 million a month on electricity at some facilities”,

says Lewen. “If existing utilities want to preserve or increase their portion of our spend, then

prices better come down now, in anticipation of a deregulated market.”

A second key supplier metric is reliability. Zschau-Bork'sglass melting plants run around

the clock; outages and blips can be extremely costly. However, since reliability is more a

function of non-deregulated transmission systems than energy generation, the company has less

leverage in this arena for forcing compliance and performance.

Zschau-Bork's strategy for driving energy costs down remains uniform across the globe.

“Regulators may vary from country to country,” says Lewen, “but our strategy does not.” One

area where Zschau-Bork is able to ramp up its leverage, however, is the area of new

(“greenfield”) facilities. One criterion Zschau-Bork uses to decide where to locate new facilities

is the energy rates they will be charged by the resident wire company or utility. In short, Zschau-

Bork can insure an acceptable rate from a utility by simply threatening to build or buy its factory

elsewhere, a situation Lewen likens to playing off one car dealer against another.

Zschau-Borktends to enter into long-term electricity contracts, given that 1) long-term

agreements are often dictated by the current regulatory market and 2) electricity prices are

perceived as relatively volatile – certainly compared to natural gas prices – in the short term.

Thus, locking in long term electricity rates is a hedge against uncertainty.

Zschau-Bork - ToyonJoint Venture

No initiative underscores Zschau-Bork's commitment to driving down energy costs than

its joint venture with Toyon Corporation.

In September 1999, Toyon Energy Services, a subsidiary of Toyon Corporation, and

Zschau-Bork announced a $1 billion, ten-year outsource agreement for total energy management

services at 20 of Zschau-Bork'smajor manufacturing facilities located throughout the United

States. The two corporations will jointly implement an energy savings program designed to

decrease energy consumption and lower costs for Zschau-Bork. They will "share costs after

equipment costs are amortized", Lewen says, but the share percentages are not disclosed.

Through the agreement, Toyon will:

* supply or manage energy commodity requirements including

electricity and natural gas. The total spend on commodity over the life of the deal will be

$100 million annually. Lewen says Zschau-Borkretains the ability to get bids and buy directly

and independently if Toyon is unable to meet certain cost and other parameters. The challenge

for Zschau-Bork's energy buyers will be to keep this "optional" spend, plus the spend at plants

not covered by the Toyon deal, below $40 million in order to drive total costs below the

current $140 million level and meet restructuring targets.

* mitigate risks of price volatility using Toyon's expertise in managing

large commodity portfolios; and

* design, build and finance certain energy infrastructure projects. Lewen says infrastructure is

"anything inside the plant…chillers, lighting etc…which the parties agree can save money."

Cogeneration, a cornerstone of new millennium energy strategy for some firms, is not part of the

Zschau-Bork- - Toyon venture because of its scope and cost. However, Lewen acknowledges

the potential savings that could be realized via a cogeneration facility. It may emerge as a

separate category for future negotiations between Toyon and Zschau-Bork.

It is a recurring mantra voiced by supply chain managers that their firms must "do more

with less." One important value proposition companies like Toyon have for firms like Zschau-

Bork is a form of risk assumption: For a sizable fee, Toyon will own and manage a large share

of Zschau-Bork's asset base, which has ballooned more than 50% over the last three years.

Secondly, synergies created by Zschau-Bork's expertise in insulation and energy conservation,

and Toyon's knowledge of energy management, will almost certainly drive Zschau-Bork's energy

costs down dramatically. And as the second millennium brings more fallout from asbestos

litigation, certainty is a precious commodity for Zschau-Bork.

TABLE E-1Recent Zschau-Bork Consolidated Income Statements

(in millions)

1998 1997 1996Net Sales $ 5,009 $ 4,373 $ 3,832Cost of Sales 3,944 3,482 2,840 Gross Margin 1,065 891 992 Percent of Net Sales 21% 20% 26%Operating Expenses Marketing and Administrative Expenses 587 544 500 Science and Technology Expenses 57 69 84 Provision for Asbestos Litigation Claims 1,415 0 875 Restructure Costs 117 68 38 Other 72 28 23 Total Operating Expenses 2,248 709 1,520

Gain on Sale of Assets 359 0 37Income (Loss) from Operations (824) 182 (491) Cost of Borrowed Funds (140) (111) (77) (Provision) Credit for Income Taxes 306 (9) 283 Equity in Net Income of Affiliates 8 11 9 Minority Interest (16) (11) (8)Income (Loss) before Extraordinary Items and Cumulative Effect of Accounting Changes (666) 62 (284) Extraordinary Items (39) 0 0 Cumulative Effect of Accounting Changes 0 (15) 0Net Income (Loss) $ (705) $ 47 $ (284)

Basic Net Income (Loss) per Share: Income (Loss) before Extraordinary Items and Cumulative Effect of Accounting Changes $ (12.44) $ 1.18 $ (5.54)Basic Net Income (Loss) per Share $ (13.16) $ 0.89 $ (5.54)Diluted Net Income (Loss) per Share $ (13.16) $ 0.88 $ (5.54)

TABLE E-2Zschau-Bork Consolidated Balance Sheets 1996-1998

(in millions)

Assets 1998 1997 1996

CurrentCash and Cash Equivalents $ 54 $ 58 $ 45Receivables 451 432 314Inventories 437 503 340Deferred Income Taxes 293 160 106Insurance for Asbestos Litigation Claims 150 100 100Assets Held for Sale 0 41 0Other Current Assets 144 134 53 Total Current 1,529 1,428 958OtherGoodwill 762 778 286Investments in Affiliates 45 52 64Deferred Income Taxes 608 328 474Insurance for Asbestos Litigation Claims 260 357 454Asbestos Costs to be Reimbursed - Fibreboard 74 116 0Other Noncurrent Assets 205 184 155 Total Other 1,954 1,815 1,433Plant and Equipment, at Cost 3,498 3,585 3,341Less: Accumulated Depreciation (1,880) (1,832) (1,819) Net Plant and Equipment 1,618 1,753 1,522Total Assets $ 5,101 $ 4,996 $ 3,913

CASE F – HARNESSING THE POWER OF AGGREGATION – THE TOWNS OF BLACK CREEK, LUCAMA, STANTONSBURG, AND

SHARPSBURG, NORTH CAROLINA17

An “aggregator” is essentially a consolidated group of individuals who harness

their combined purchasing power to drive down costs. This case provides an interesting

example of how three small communities joined forces to work together and reduce their

electricity prices. This case is important, as it provides insights into how this type of

aggregation activity can occur in the future. Also, it provides an excellent

counterexample to many of the claims made by opponents to deregulation who claim that

small consumers’ will be adversely affected due to low reliability in rural areas, and the

lack of purchasing power of small residential consumers. This case illustrates how a

small, rural community has banded together and has improved service, cut costs, and

provided reliable power for everyone in their towns without adverse effects. The towns

also anticipate further cuts in rates with the advent of deregulation. The following

testimony is provided by a representative from the towns, and was provided to the House

SubCommittee on Energy Deregulation.

Three years ago, the Towns of Black Creek, Lucama, and Stantonsburg appeared

before the Subcommittee on Energy and Power to discuss their ongoing wholesale power

project. Since that time, the towns have completed their project and realized large

wholesale power cost savings. Each town has now cut its retail rates at least 25%. In

Stantonsburg, for example, the typical residential customer will save $499 per year as the

result of the town’s effort to cut electricity costs to its citizens. Sharpsburg also

completed its power supply project this year and realized similar large savings in 17 Presented by the Honorable Virginia Johnson, Mayor, Town of Lucama, Testimony to the U.S. House of Representatives, Committee on Commerce, Subcommittee on Energy and Power, Thursday July 1, 1999.

wholesale power costs. Examples of economic growth and improvement in the quality of

life for citizens of these towns abound. Black Creek has attracted an electrical contractor

that will bring approximately 35 new jobs to the town. Residential building permit

requests are way up in Stantonsburg.

Contrary to what the subcommittee may have heard from other sources, rates in

North Carolina are high. North Carolina’s average industrial cost for electricity is above

the national average and its average residential cost is the second highest in the

Southeast.

The Towns of Black Creek Lucama, Stantonsburg, and Sharpsburg (referred to as

the “Towns” for the remainder of the case) are prepared for when retail customer choice

in electricity is allowed in North Carolina. The Towns have relatively short-term

wholesale power supply contracts that will give them the flexibility of offering customer

choice when it is finally allowed in here. Furthermore, each town is making substantial

improvements to its electricity distribution system in order to maintain reliable electric

service. The Towns were able to cut their power costs due to the Energy Policy Act of

1992 (EPACT). This federal law allowed wholesale customers, such as these towns, to

shop the open power markets and obtain lower cost power supplies. We are thankful to

the actions of current and former Congressmen and women that voted to enact this bill.

Due to their strong actions, we were able to drastically cut the rates that our citizens pay

for electricity.

Three years ago, the Towns had some of the highest electric rates in the country.

Typical residential electric rates were in the range of 11 to 12 cents per kWh. Now, each

town has cut its electric rates at least 25% and growth is returning to the Towns. In

Sharpsburg, where the lower cost wholesale power has been flowing for only six months,

the town has already cut rates 12% and is currently examining further rate cuts. Each

town is also upgrading their distribution systems and making payments on the new

substations and distribution lines needed to complete the projects.

Power Project Results

Examples of economic growth and improvements in citizens’ quality of life due to

lower electric rates abound in each town. In Black Creek, an electrical contractor that

employs approximately 35 people recently relocated to the town due, in part, to lower

electric rates. A developer, attracted by the lower electric rates, is also now constructing

a large new subdivision in the town. In Lucama, many residents are senior citizens that

live on social security checks alone. The 25% cut in the town’s electric rates means that

these senior citizens and other town residents will save over $300,000 per year. All four

towns have about 1,000 customers each. Savings of this magnitude are huge for the

typical consumer. Furthermore, the Lucama Town Board may not yet be done cutting

retail rates. Later this summer, the Town Board will examine the possibility of cutting

rates even further.

In Stantonsburg, new home applications are on the rise as the result of the

completion of the towns’ wholesale power project in February of 1998. Stantonsburg

received no more than 6 residential applications in the two years before completion of the

project. Now, less than 18 months after completion of the project, the town has 25 new

home applications. Since the completion of this wholesale power project, the town board

has cut residential rates approximately 33%, which translates into annual savings of $499

for the typical residential consumer using 1,000 kWh’s per month.

In Sharpsburg, the largest subdivision in the town’s history is now being

constructed. The subdivision is over 100 acres and will be home to approximately 200

families. The 12% rate cut that their town board approved in early 1999 lowered

residential rates to roughly 8 cents per kWh. The further rate cuts that are anticipated

will lower the town’s residential rates to some of the lowest in the southeast, and perhaps,

the country.

Rates in North Carolina

The Towns are fortunate that we were able to reduce energy costs to our citiens.

Changes in federal law allowed us to improve the lives of our citizens as well as our local

economies. Other towns in North Carolina are not as fortunate. Since the vast majority

of North Carolinians take retail electric service from investor-owned utilities regulated by

the state, these citizens must wait for passage of retail customer choice legislation before

they realize any meaningful cuts in electric rates.

Contrary to other sources, North Carolina is NOT a low cost state. Our state’s

average industrial cost is higher than the national average and our average residential cost

is the second highest in the southeast. Jobs are currently being lost in our state

specifically due to high electric rates. Recently, for example, a textile plant in Goldsboro,

NC moved its operations to South Carolina, citing high electric costs as the reason for

leaving our state.

Preparing for Retail Electric Competition

The Towns will be ready for retail electric competition when it finally arrives in

our state. Given the high rates that exist in our state, coupled with the fact that over 21

states have now passed customer choice legislation, we know that the state’s electric

industry must be changed.

We began our preparation for retail customer choice in electricity by entering into

relatively short-term wholesale power supply contracts. All four towns have contracts

that end no later that Dec. 31, 2002. This will then free us to offer customer choice in

electricity to our citizens at about the same time as it may become available to others

within our state.

If legislation is passed that will give municipalities the choice of opting out of

customer choice in electricity, we will examine the following two alternatives: for

providing lower electric rates:

1. The Towns continue to act as load aggregators and purchase power supplies for our

consumers; or

2. Our individual consumers purchase their own power supplies and the towns will

deliver those power supplies to our citizens.

Since each town is currently acting as a distribution utility and does not own any

generation assets, we believe that the financial condition of the towns’ electric systems

will not be affected by retail electric competition. It does not matter to us whether we

buy the electricity for our citizens or they purchase it themselves. Our primary concern is

that our citizens obtain the lowest cost and most reliable electricity available.

Also in preparation for retail customer choice in electricity, all four towns are now

upgrading their individual electric systems to improve system reliability. Old copper

wire is being replaced, old poles are being replaced, and distribution lines in heavily

wooded areas are being moved. Service has been, and will continue to be, a top priority

for us regardless of who buys the electricity for our citizens.

Small consumers can and are benefiting from electric competition. The Towns of

Black Creek, Lucama, Stantonsburg, and Sharpsburg are living examples of such success.

CASE G – THE STATE OF TEXAS BILL ON DEREGULATION: A

MICROCOSM OF NATIONAL DEREGULATION 18

In this case, a State Senator from Texas, David Sibley, discusses the process that

the state legislation used in arriving at the decision to deregulate the energy industry in

Texas. The Texas bill, which was signed into law by Governor George W. Bush in June,

1999, was the result of years of comprehensive study by key Texas leaders. A delegation

comprised of Texas House and Senate members, representatives of the offices of

Governor, Lieutenant Governor and Speaker of the House, and members of the Texas

Public Utility Commission visited California, Pennsylvania and England to learn about

their restructuring efforts. This bill reflects some of these groups’ good ideas, as well as

some bold new steps to create a long-lasting competitive market in Texas. The case is

also important in that Texas represents a “microcosm experiment” of the proposition to

create a stateless grid in the East and the West. Texas is the only state that has a self-

contained interconnected grid that remains independent of the Western and Eastern grid.

Thus, the events that took place, as well as the ensuing success of this strategy, represent

an important experiment that legislators will watch closely as they consider the

possibility of a stateless grid governed by separate Regional Transmission Organizations

(see Chapter 5 on Future Trends). What is remarkable about this case is that the

legislators attempted to reconcile a number of competing political elements, including the

interests of small customers, larger customers, publicly-owned utilities, and

environmentalists The outcome largely satisfies many of the concerns of each of these

groups. The bill was subsequently supported by the utilities, electric cooperatives, public

18 Textimony, State Senator David Sibley, District 22, Texas Senate, Hearing vefore the Energy and Power Subcommittee of the U.S. House of Representatives Commerce Committee, July 1, 1999.

power agencies, power marketers, environmental groups, and industrial and commercial

customers. While most consumer groups would not endorse the bill, they readily admit it

is the best restructuring bill in the country for residential customers.

Introduction

My name is David Sibley, and as a Texas state senator, I authored the recently passed

electric structuring legislation in our state. I would like to start by giving a brief

overview of the Texas bill, and finish by discussing federal restructuring efforts.

The Texas bill, which was signed into law by Governor Bush just two weeks ago,

was the result of years of comprehensive study by key Texas leaders. When we started

this process, I was skeptical about the benefits of restructuring for residential customers.

My question to the advocates was: What’s broke? Texas has, by most measures, some of

the lowest rates in the country, and the competitive wholesale market we implemented in

1995 has been bringing them down even further. I knew that through regulation and the

status quo our residential customers would continue to be well served. What was broken

was the customer bearing the risk of loss, not the companies. Under rate of return

regulation, companies are guaranteed a ten percent return on investment no matter how

unwise. The costs are passed through to the ratepayers. A free market would reward

good investments and punish bad ones.

After intensive study I came to the conclusion that residential customers can get

lower rates and better service from a truly competitive electric market. The rub is: how

do you structure a market lucrative enough to attract new entrants for the long term,

while at the same time paying off stranded costs, letting existing utilities compete fairly

without being punitive to them, and all the while ensuring lower rates and continued

reliability for customers?

Texas Legislation

The Texas bill recognizes the unique circumstances of electric cooperatives and

municipal utilities by allowing them to opt into competition at their own pace. They are

not required to opt in by a date certain, but we believe that the new market structure will

encourage most public utilities to voluntarily open their markets. After we made the

decision to allow the coops and munis to compete at their own pace ,the most difficult

challenge we faced was designing a market structure that is conducive to competition

without being punitive to existing utilities. Our market structure carefully balanced the

unbundling of existing utilities, a rate design to foster competition while providing rate

cuts, payment of stranded costs, market power restrictions to protect new competitors and

customers, strenuous customer protections, environmental protections and the enhanced

reliability of our grid.

Unbundling The Texas bill requires separation of existing utilities into three companies:

a transmission/distribution company that will continue to be regulated (wires company or

Wireco), a power generation company that can only sell to the wholesale generation

market (Genco), and a retail electric company that markets to retail customers but cannot

own or operate generation facilities (retail electric provider or REP). These formerly

integrated companies will operate as affiliates under a strong code of conduct included in

the bill to ensure independence. Our legislation requires open access to the transmission

and distribution systems and nondiscriminatory rates for those services.

Rate Design Beginning on the market opening date, January 1, 2002, all existing

customers are automatically transferred to the existing utilities retail electric provider

affiliate. We did this because we found that a lottery system of assignment would be

perceived as state-mandated slamming. However, if we let existing companies keep their

customers we had to make sure they couldn’t force their prices down to keep competitors

out of the market. We also had to make sure they didn’t receive windfall profits from

keeping those customers. At the same time, we wanted to provide an immediate benefit

to customers through a rate reduction.

We came up with what we call the “Price To Beat”. On Day One, January 1,

2002, residential and small commercial customers will automatically receive a 6 percent

rate reduction from the new utility affiliate. This new rate is the “price to beat”, which

includes transmission/distribution service and energy charges (distribution/transmission

is billed through whichever REP is providing the energy service so that a customer

receives only one bill). A customer can shop around and get a lower price from a

competitor. The incumbent utility REP cannot charge a price lower or higher than the

“price to beat” within the residential and small commercial markets for a period of three

years or until it has lost 40 percent of its load within each respective market. And, once

the incumbent utility REP has met one of those thresholds, it cannot charge a price higher

than the “price to beat” through the fifth year after competition starts. While the

incumbent utility REP cannot lower prices in their former service area, they may compete

at any price outside of their former service area.

The purpose of the “price to beat” mechanism is to provide enough headroom for

profit so that new entrants will have an incentive to market to residential and small

commercial customers. The 40 percent threshold ensures that incumbent utility REP’s

are not subject to this price freeze once the market is competitive. And, the price cap for

years 3 through 5 ensures that customers will not see a price increase once the utilities

begin to compete on price.

A lot of thought went into the “Price To Beat” concept. We had to ensure that the

rate reduction was not so large that a competitor wouldn’t want to serve customers. In

fact, we sere under constant pressure throughout our legislative session to make much

deeper rate cuts, which we could have done since we were working off of 1999 rates in a

declining-cost business. However, doing so would have compromised our ability to

create a competitive market. We don’t want to deregulate monopolies. Also, the utilities

lobbied hard to allow their utility affiliates to compete on price. Our bill allows a utility

REP affiliate to freely compete outside of its affiliated distribution company’s service

territory, but places the “price to beat” restrictions on the affiliated REP within the

existing service area. We felt like it would be extremely difficult for new players to

compete without these restrictions, though, for example, we wanted the TXU Electric

REP competing in the Reliant Energy (formerly HL&P) service area without restrictions,

and vice versa.

Stranded Costs

The fight in Texas wasn’t about whether we should pay for stranded costs. There

was consensus early on that the utilities should receive some compensation for their

potential losses. I do believe there is a regulatory compact, i.e. utilities gave up their

right to charge whatever the market will bear and agreed to charge only what a state

agency said they could in exchange for the exclusive right to serve an area with

electricity. Government at all levels then dictated what energy sources would be

permitted for the generation of electricity and where the plants would be sited. For

example, in the ‘70s Washington decided that we were running out of natural gas and

pushed utilities into nuclear. In retrospect, this was not a good decision. I believe

utilities are entitled to some compensation as we transition into a competitive market.

The difficult issue is determining how much should be paid, how utilities would be paid

and who would pay them.

Our two biggest concerns were that customers would pay too much, and that real

competition would be delayed or stunted due to large non-bypassable charges (the

California problem). Beginning this September, we are freezing existing rates for the

transition period to competition so that any over earnings can go towards stranded cost

recovery. This will minimize the amount we have to pay under competition. To make

sure customers and utilities are treated fairly, our legislation requires market valuation

methods in all cases except for nuclear assets. It allows utilities to securitize stranded

costs early based on an administrative model established by our PUC. A final true-up in

2004, two years after competition, would consider how much, if any, utilities had over-

earned during the transition period and during the first two years of competition under the

“Price To Beat”.

Stranded costs are recovered through non-bypassable charges on distribution and

transmission services, which are included in the delivery portion of the REP bill. The

PUC has the authority to adjust these charges to ensure that they are not too high. Since

the “price to beat” is based on the full price of electricity, including delivery, production

and fuel, a large non-bypassable charge would have the effect of reducing the

“headroom” or profit margin in the generation-related part of the price. This would make

it more difficult for competitors to make a profit, and therefore discourage their entry into

the market. The consideration of stranded cost recovery and its effect on rate design is a

crucial component of restructuring that cannot be overlooked.

Market Power

Texas broke new ground in addressing market power. As you may know, the

Electric Reliability Council of Texas (ERCOT) is a wholly contained interconnection

grid within Texas. There are no interstate interconnections within this grid. This has its

advantages and disadvantages for us in considering legislation. A disadvantage is that the

existing market concentrations within our state are relatively high, without the option of

bringing in power from other grids. We addressed this issue head-on by prohibiting the

ownership of more than 20 percent of the installed generation capacity within a power

region. (Texas is also in the SPP, SERC, and WSCC). We do not require divestiture but

instead allow the auctioning of rights to capacity. The utilities were initially opposed to

the capacity limitations within the bill, but have come to embrace it as part of a larger

package that is fair to the industry.

Another market power provision we included is a requirement that utilities sell 15

percent of their Texas jurisdictional capacity through auctions to ensure there is enough

available capacity for competitors to resell. This is required for five years or until 40

percent of the residential and small commercial market is served by competitors. Other

market protections include a strong affiliate code of conduct to prevent cross-

subsidization and the preferential treatment of generation and retail affiliates by the

transmission/distribution company (Wireco).

Customer Provisions

Our customer protections are very strong due to our experiences in the

deregulated telecommunications market and England’s experiences in the restructuring of

their gas markets. A stand-alone customer protection bill was passed to address the

telecommunications and electric industries, especially since we believe these industries

will begin to merge and package services together. In addition to slamming and

cramming protections, our law prohibits disconnections for nonpayment during extreme

weather and gives the PUC the authority to promulgate marketing rules and guidelines.

A system benefit charge on wire charges funds a customer education program to facilitate

shopping, a low-income program for families at or below 125 percent of the poverty level

and a school-property tax replacement program to protect our school finance system.

Environmental Protections

Governor Bush provided strong leadership in the area of environmental reforms.

The legislation establishes an emissions cap for grand fathered units and requires

statewide 50 percent NOx emission reductions and 25 percent SO2 reductions by May 1,

2003. The costs of retrofitting certain older generation assets are allowed to be recouped

as stranded costs to incentivize companies to retrofit to the highest technology available,

and a renewable energy trading credit program was established to help the industry meet

renewable energy goals. The bill also includes some energy efficiency requirements.

Reliability

Finally, the anchor of our legislation lies in the improvement of our existing

independent system operator (ISO) and the implementation of strong reliability standards.

The ISO will be responsible for the physical and financial transactions within ERCOT.

In addition, our PUC has been given the authority to revoke the certification or

registration of any market participants that do not abide by the ISO rules. The ISO is

governed by an 18-member board comprised of representatives from all of the market

sectors, including residential, commercial and industrial customers.

State and Local Issues in Electricity Utility Restructuring

I believe the Texas legislation is a far-reaching comprehensive bill that will create

a robust competitive environment. However, what works in Texas may not work in

California or in Kentucky. And, retail competition may not benefit every state. I

encourage this subcommittee to defer to each state in their decision of whether to allow

retail competition. I believe most states will choose competition because it is more

efficient and beneficial for all consumers.

I do encourage you to pass a federal restructuring bill that recognizes the

differences among states and market sectors. The grandfathering of existing plans will

preserve the delicate compromises made by many parties, and will ensure a smoother

implementation of our restructuring plans. Preemption will only create a legal quagmire

that will slow down the establishment of competitive markets.

There is clearly room for federal intervention and assistance. Outdated federal

regulations, such as the mandated purchase requirements within PURPA, should be

abolished. FERC should be given the necessary tools to ensure that strict reliability

standards are implemented and to assist states and regional councils in assuring

nondiscriminatory access to transmission systems. FERC should play the role of referee

in the oversight and formation of regional transmission systems. Frankly, we can’t

implement our restructuring legislation in the non-ERCOT parts of Texas without

FERC’s help.

Another extremely important role for Congress is to ease private use restrictions

on outstanding tax-exempt bonds so that customers of public utilities are able to

participate in retail competition. Competition in the service areas of public utilities

cannot occur without open transmission access, which is discouraged by the possibility of

retroactively taxable bonds if the private use issue is not clarified. Texas has many great

municipal utilities that are eager to compete and will do well.

Another concern I have is the possibility of federal system benefit charges.

Deregulation of the telecommunications market at both the state and federal level has

brought with it a laundry list of new charges to implement government programs. While

these programs are often necessary, we should avoid duplicating programs at the state

and federal levels. I’m also concerned that because Texas is a high energy use state,

federal system benefit charges may tax Texans more heavily while the benefits may

accrue in other areas. I urge you to defer to the states for all of these programs.

Finally, I understand that Texas is different from other states because of its unique

grid. I urge you to recognize that our Legislature and PUC have done an excellent job in

regulating.