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CHAPTER 24

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING

GEORGE R. OWENS, P.E. C.E.M.

Energy and Engineering Solutions, Inc.

24.0 INTRODUCTION

“ Utility Deregulation,” “Customer Choice,” “ Un￾bundled Rates,” “Re-regulation,” “Universal Service

Charge,” “Off Tariff Gas,” “ Stranded Costs,” “Competi￾tive Transition Charge (CTC),” “Caps and Floors,” “ Load

Profi les” and on and on are the new energy buzzwords.

They are all the jargon are being used as customers,

utilities and the new energy service suppliers become

profi cient in doing the business of utility deregulation.

Add to that the California energy shortages and

rolling blackouts, the Northeast and Midwest outages of

2003, scandal, rising energy prices, loss of price protec￾tion in deregulated states and you can see why utility

deregulation is increasingly on the mind of utility cus￾tomers throughout the United States and abroad.

With individual state actions on deregulating

natural gas in the late 80’s and then the passage of the

Energy Policy Act (EPACT) of 1992, the process of de￾regulating the gas and electric industry was begun. Be￾cause of this historic change toward a competitive arena,

the utilities, their customers, and the new energy service

providers have begun to reexamine their relationships.

How will utility customers, each with varying

degrees of sophistication, choose their suppliers of

these services? Who will supply them? What will it

cost? How will it impact comfort, production, tenants

and occupants? How will the successful new players

bring forward the right product to the marketplace to

stay profi table? And how will more and better energy

purchases improve the bottom line?

This chapter reviews the historic relationships

between utilities, their customers, and the new energy

service providers, and the tremendous possibilities for

doing business in new and different ways.

The following fi gure portrays how power is gen￾erated and how it is ultimately delivered to the end

customer.

1. Generator – Undergoing deregulation

2. Generator Substation – See 1

3. Transmission System – Continues to be regulated

by the Federal Energy Regulatory Commission

(FERC) for interstate and by the individual states

for in-state systems

4. Distribution Substation – Continues to be regu￾lated by individual states

5. Distribution Lines – See 4

6. End Use Customer – As a result of deregulation,

will be able to purchase power from a number

of generators. Will still be served by the local

“wires” distribution utility which is regulated by

the state.

24.1 AN HISTORICAL PERSPECTIVE OF

THE ELECTRIC POWER INDUSTRY

At the turn of the century, vertically integrated

electric utilities produced approximately two-fi fths of

the nation’s electricity. At the time, many businesses

(nonutilities) generated their own electricity. When utili￾ties began to install larger and more effi cient generators

and more transmission lines, the associated increase in

convenience and economical service prompted many

industrial consumers to shift to the utilities for their

electricity needs. With the invention of the electric motor

came the inevitable use of more and more home ap￾pliances. Consumption of electricity skyrocketed along

with the utility share of the nation’s generation.

The Power Flow Diagram

638 ENERGY MANAGEMENT HANDBOOK

The early structure of the electric utility industry

was predicated on the concept that a central source of

power supplied by effi cient, low-cost utility generation,

transmission, and distribution was a natural monopoly.

In addition to its intrinsic design to protect consumers,

regulation generally provided reliability and a fair rate

of return to the utility. The result was traditional rate

base regulation.

For decades, utilities were able to meet increasing

demand at decreasing prices. Economies of scale were

achieved through capacity additions, technological ad￾vances, and declining costs, even during periods when

the economy was suffering. Of course, the monopolistic

environment in which they operated left them virtually

unhindered by the worries that would have been created

by competitors. This overall trend continued until the

late 1960s, when the electric utility industry saw decreas￾ing unit costs and rapid growth give way to increasing

unit costs and slower growth.

The passage of EPACT-1992 began the process of

drastically changing the way that utilities, their custom￾ers, and the energy services sector deal (or do not deal)

with each other. Regulated monopolies are out and cus￾tomer choice is in. The future will require knowledge,

fl exibility, and maybe even size to parlay this changing

environment into profi t and cost saving opportunities.

One of the provisions of EPACT-1992 mandates

open access on the transmission system to “wholesale”

customers. It also provides for open access to “exempt

wholesale generators” to provide power in direct compe￾tition with the regulated utilities. This provision fostered

bilateral contracts (those directly between a generator

and a customer) in the wholesale power market. The

regulated utilities then continue to transport the power

over the transmission grid and ultimately, through the

distribution grid, directly to the customer.

What EPACT-1992 did not do was to allow for “re￾tail” open access. Unless you are a wholesale customer,

power can only be purchased from the regulated utility.

However, EPACT-1992 made provisions for the states

to investigate retail wheeling (“wheeling” and “open

access” are other terms used to describe deregulation).

Many states have held or are currently holding hear￾ings. Several states either have or will soon have pilot

programs for retail wheeling. The model being used is

that the electric generation component (typically 60-70%

of the total bill), will be deregulated and subject to full

competition. The transmission and distribution systems

will remain regulated and subject to FERC and state

Public Service Commission (PSC) control.

A new comprehensive energy bill, EPACT-2005, was

signed into law in 2005, just as this edition was being

fi nalized. Look for expanded discussion of EPACT-2005

in future editions of this chapter. This bill affects energy

production, including renewables, energy conservation,

regulations on the country’s transmission grids, utility

deregulation as well as other energy sectors. Tax incen￾tives to spur change are key facets of EPACT-2005.

ELECTRIC INDUSTRY DEREGULATION TIME LINE

1992 - Passage of EPACT and the start of the debate.

1995 & 1996 - The fi rst pilot projects and the start of

special deals. Examples are: The automakers in

Detroit, New Hampshire programs for direct

purchase including industrial, commercial and

residential, and large user pilots in Illinois and

Massachusetts.

1997 - Continuation of more pilots in many states and

almost every state has deregulation on the leg￾islative and regulatory commission agenda.

1998 - Full deregulation in a few states for large users

(i.e., California and Massachusetts). Many states

have converged upon 1/1/98 as the start of

their deregulation efforts with more pilots and

the fi rst 5% roll-in of users, such as Pennsylva￾nia and New York.

2000 - Deregulation of electricity became common for

most industrial and commercial users and began

to penetrate the residential market in several

states. These included Maryland, New Jersey,

New York, and Pennsylvania among others. See

fi gure 24.1.

2002/3- Customers have always had a “backstop” of

regulated pricing. Now that the transition peri￾ods are nearing their end, customers are faced

with the option of buying electricity on the open

market without a regulated default price.

2003 - During the summer, parts of the northeast and

upper Midwest experience a massive blackout

that shuts down businesses and residential

customers. The adequacy of the transmission

system is blamed.

2005 - EPACT-2005 becomes law

24.2 THE TRANSMISSION SYSTEM AND THE

FEDERAL ENERGY REGULATORY COMMISSION’S

(FERC) ROLE IN PROMOTING COMPETITION IN

WHOLESALE POWER

Even before the passage of EPACT in 1992, FERC

played a critical role in the competitive transformation

of wholesale power generation in the electric power

industry. Specifi c initiatives include notices of proposed

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING 639

rulemaking that proposed steps toward the expansion

of competitive wholesale electricity markets. FERC’s

Order 888, which was issued in 1996, required public

utilities that own, operate, or control transmission lines

to fi le tariffs that were non-discriminatory at rates that

are no higher than what the utility charges itself. These

actions essentially opened up the national transmission

grid to non-discretionary access on the wholesale level

(public utilities, municipalities and rural cooperatives).

This order did not give access to the transmission grid

to retail customers.

In an effort to ensure that the transmission grid

is opened to competition on a non-discriminatory ba￾sis, Independent System Operators (ISO’s) are being

formed in many regions of the country. An ISO is an

independent operator of the transmission grid and is

primarily responsible for reliability, maintenance (even if

the day-to-day maintenance is performed by others) and

security. In addition, ISO’s generally provide the follow￾ing functions: congestion management, administering

transmission and ancillary pricing, making transmission

information publicly available, etc.

24.3 STRANDED COSTS

Stranded costs are generally described as legitimate,

prudent and verifi able costs incurred by a public utility or

a transmitting utility to provide a service to a customer

that subsequently are no longer used. Since the asset or

capacity is generally paid for through rates, ceasing to use

the service leaves the asset, and its cost, stranded. In the

case of de-regulation, stranded costs are created when the

utility service or asset is provided, in whole or in part,

to a deregulated customer of another public utility or

transmitting utility. Stranded costs emerge because new

generating capacity can currently be built and operated

at costs that are lower than many utilities’ embedded

costs. Wholesale and retail customers have, therefore, an

incentive to turn to lower cost producers. Such actions

make it diffi cult for utilities to recover all their prudently

incurred costs in generating facilities.

Stranded costs can occur during the transition to

a fully competitive wholesale power market as some

wholesale customers leave a utility’s system to buy

power from other sources. This may idle the utility’s

existing generating plants, imperil its fuel contracts,

and inhibit its capability to undertake planned system

expansion leading to the creation of “stranded costs.”

During the transition to a fully competitive wholesale

power market, some utilities may incur stranded costs

as customers switch to other suppliers. If power previ￾ously sold to a departing customer cannot be sold to

an alternative buyer, or if other means of mitigating the

stranded costs cannot be found, the options for recover￾ing stranded costs are limited.

The issue of stranded costs has become contentious

in the state proceedings on electric deregulation. Utilities

Retail access is either currently available to all or some customers or will soon be

available. Those states are Arizona, Connecticut, Delaware, District of Columbia, Illinois,

Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio,

Oregon, Pennsylvania, Rhode Island, Texas, and Virginia.

In Oregon, no customers are currently participating in

the State’s retail access program, but the law allows

nonresidential customers access. Yellow colored states are

not actively pursuing restructuring. Those states are Ala￾bama, Alaska, Colorado, Florida, Georgia, Hawaii, Idaho,

Indiana, Iowa, Kansas, Kentucky, Louisiana, Minnesota,

Mississippi, Missouri, Nebraska, North Carolina, North

Dakota, South Carolina, South Dakota, Tennessee, Utah,

Vermont, Washington, West Virginia, Wisconsin, and

Wyoming. In West Virginia, the Legislature and Governor

have not approved the Public Service Commission’s re￾structuring plan, authorized by HB 4277. The Legislature

has not passed a resolution resolving the tax issues of

the PSC’s plan, and no activity has occurred since early

in 2001. A green colored state signifi es a delay in the

restructuring process or the implementation of retail ac￾cess. Those states are Arkansas, Montana, Nevada, New

Mexico, and Oklahoma. California is the only blue colored

state because direct retail access has been suspended.

*As of January 30, 2003, Department of Energy, Energy

Information Administration

Figure 24.1 Status of State Electric Industry Restructuring Activity*

640 ENERGY MANAGEMENT HANDBOOK

have argued vehemently that they are justifi ed in recover￾ing their stranded costs. Customer advocacy groups, on

the other hand, have argued that the stranded costs pro￾posed by the utilities are excessive. This is being worked

out in the state utility commissions. Often, in exchange

for recovering stranded costs, utilities are joining in settle￾ment agreements that offer guaranteed rate reductions

and opening up their territories to deregulation.

24.4 STATUS OF STATE ELECTRIC

INDUSTRY RESTRUCTURING ACTIVITY

Electric deregulation on the retail level is deter￾mined by state activity. Many states have or are in the

process of enacting legislation and/or conducting pro￾ceedings. See Figure 24.1.

24.5 TRADING ENERGY -

MARKETERS AND BROKERS

With the opening of retail electricity markets in

several states, new suppliers of electricity have devel￾oped beyond the traditional vertically integrated electric

utility. Energy marketers and brokers are the new com￾panies that are being formed to fi ll this need. An energy

marketer is one that buys electricity or gas commodity

and transmission services from traditional utilities or

other suppliers, then resells these products. An energy

broker, like a real estate broker, arranges for sales but

does not take title to the product. There are independent

energy marketers and brokers as well as unregulated

subsidiaries of the regulated utility.

According to The Edison Electric Institute, the

energy and energy services market was $360 billion in

1996 and was expected to grow to $425 billion in 2000.

To help put these numbers in perspective, this market is

over six times the telecommunications marketplace. As

more states open for competition, the energy marketers

and brokers are anticipating strong growth. Energy sup￾pliers have been in a merger and consolidation mode for

the past few years. This will probably continue at the

same pace as the energy industry redefi nes itself even

further. Guidance on how to choose the right supplier

for your business or clients will be offered later on in

this chapter

The trading of electricity on the commodities

market is a rather new phenomenon. It has been rec￾ognized that the marketers, brokers, utilities and end

users need to have vehicles that are available for the

managing of risk in the sometimes-volatile electricity

market. The New York Mercantile Exchange (NYMEX)

has instituted the trading of electricity along with its

more traditional commodities. A standard model for an

electricity futures contract has been established and is

traded for delivery at several points around the country.

As these contracts become more actively traded, their

usefulness will increase as a means to mitigate risk. An

example of a risk management play would be when a

power supplier locks in a future price via a futures or

options contract to protect its position at that point in

time. Then if the prices rise dramatically, the supplier’s

price will be protected.

24.6 THE IMPACT OF DEREGULATION

Historically, electricity prices have varied by a

factor of two to one or greater, depending upon where

in the county the power is purchased. See Figure 24.2.

These major differences even occur in utility jurisdic￾tions that are joined. The cost of power has varied

because of several factors, some of which are under the

utilities control and some that are not, such as:

• Decisions on projected load growth

• The type of generation

• Fuel selections

• Cost of labor and taxes

• The regulatory climate

All of these factors contribute to the range of pricing.

Customers have been clamoring for the right to choose

the supplier and gain access to cheaper power for quite

some time. This has driven regulators to impose utility

deregulation, often with opposition from the incumbent

utilities.

Many believe that electric deregulation will even

out this difference and bring down the total average

price through competition. There are others that do

not share that opinion. Most utilities are already tak￾ing actions to reduce costs. Consolidations, layoffs, and

mergers are occurring with increased frequency. As

part of the transition to deregulation, many utilities are

requesting and receiving rate freezes and reductions in

exchange for stranded costs.

One factor has remained a constant until the early

2000’s. Customers have always had a “backstop” of

regulated pricing until recently. Now that the transition

periods are nearing their end, customers are faced with

the option of buying electricity on the open market

without a regulated default price. The risks to custom￾ers have increased dramatically. And, energy consultants

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING 641

and ESCOs are having a diffi cult time predicting the

direction of electricity costs.

All of this provides for interesting background and

statistics, but what does it mean to energy managers

interested in providing and procuring utilities, com￾missioning, O&M (operations and maintenance), and

the other energy services required to build and operate

buildings effectively? Just as almost every business en￾terprise has experienced changes in the way that they

operate in the 90’s and 2000 and beyond, the electric

utilities, their customers and the energy service sector

must also transform. Only well-prepared companies will

be in a position to take advantage of the opportunities

that will present themselves after deregulation. Building

owners and managers need to be in a position to actively

participate in the early opening states. The following

questions will have to be answered by each and every

company if they are to be prepared:

• Will they participate in the deregulated electric

market?

• Is it better to do a national account style supply

arrangement or divide the properties by region

and/or by building type?

• How will electric deregulation affect their relation￾ships with tenants in commercial, governmental

and institutional properties?

• Would there be a benefi t for multi-site facilities to

partake in purchasing power on their own?

• Should the analysis and operation of electric de￾regulation efforts be performed in-house or by

consultants or a combination?

• What criteria should be used to select the energy

suppliers when the future is uncertain?

24.7 THE TEN-STEP PROGRAM TO

SUCCESSFUL UTILITY DEREGULATION

In order for the building sector to get ready for

the new order and answer the questions raised above,

this ten-step program has been developed to ease the

transition and take advantage of the new opportunities.

This Ten Step program is ideally suited to building own￾ers and managers as well as energy engineers that are

in the process of developing their utility deregulation

program.

Step #1 - Know Thyself

• When do you use the power

• Distinguish between summer vs. winter, night vs.

day

Figure 24.2 Electricity Cost by State

Average Revenue from Electric Sales to Industrial Consumers by State, 1995 (Cents per Kilowatt-hour)

642 ENERGY MANAGEMENT HANDBOOK

• What load can you control/change

• What $$$ goal does your business have

• What is your 24 hr. load profi le

• What are your in-house engineering, monitoring

and fi nancial strengths

Step #2 - Keep Informed

• Read, read, read—network, network, network

• Interact with your professional organizations

• Talk to vendors, consultants, and contractors

• Subscribe to trade publications

• Attend seminars and conferences

• Utilize internet resources—news groups, WWW,

E-mail

• Investigate buyer’s groups

Step #3 - Talk to Your Utilities (all energy types)

• Recognize customer relations are improving

• Discuss alternate contract terms or other energy

services

• Find out if they are “for” or “agin” deregulation

• Obtain improved service items (i.e., reliability)

• Tell them your position and what you want. Now

is not the time to be bashful

• Renegotiate existing contracts

Step #4 - Talk to Your Future Utility(ies)

• See Step #3

• Find out who is actively pursuing your market

• Check the neighborhood, check the region, look

nationally

• Develop your future relationships

• Partner with Energy Service Companies (ESCOs),

power marketing, fi nancial, vendor and other part￾ners for your energy services needs

Step #5 - Explore Energy Services Now

(Why wait for deregulation?)

• Implement “standard” energy projects such as

lighting, HVAC, etc.

• Investigate district cooling/heating

• Explore selling your central plant

• Calculate square foot pricing

• Buy comfort, Btus or GPMs; not kWhs

• Outsource your Operations and Maintenance

• Consider other work on the customer side of the

meter

Step #6 - Understand the Risks

• Realize that times will be more complicated in the

future

• Consider the length of a contract term in uncertain

times

• Identify whether you want immediate reductions

now, larger reductions later or prices tied to some

other index

• Determine the value of a fl at price for utilities

• Be wary of losing control of your destiny-turning

over some of the operational controls of your en￾ergy systems

• Realize the possibility some companies will not be

around in a few years

• Determine how much risk you are willing to take

in order to achieve higher rewards

Step #7 - Solicit Proposals

• Meet with the bidders prior to issuing the Request

For Proposal (RFP)

• Prepare the RFP for the services you need

• Identify qualifi ed players

• Make commissioning a requirement to achieve the

results

Step #8 - Evaluate Options

• Enlist the aid of internal resources and outside

consultants

• Narrow the playing fi eld and interview the fi nal￾ists prior to awarding

• Prepare a fi nancial analysis of the results over the

life of the project—Return on Investment (ROI) and

Net Present Value (NPV)

• Remember that the least fi rst cost may or may not

be the best value

• Pick someone that has the fi nancial and technical

strengths for the long term

• Evaluate financial options such as leasing or

shared

Step #9 - Negotiate Contracts

Remember the following guidelines when negotiat￾ing a contract:

• The longer the contract, the more important the

escalation clauses due to compounding

• Since you may be losing some control, the contract

document is your only protection

• The supplying of energy is not regulated like the

supplying of kWhs are now

• The clauses that identify the party taking responsi￾bility for an action, or “Who Struck John” clauses,

are often the most diffi cult to negotiate

• Include monitoring and evaluation of results

• Understand how the contract can be terminated

and what the penalties for early termination are

Step #10 - Sit Back and Reap the Rewards

• Monitor, measure, and compare

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING 643

• Don’t forget Operations & Maintenance for the

long term

• Keep looking, there are more opportunities out

there

• Get off your duff and go to Step #1 for the next

round of reductions

24.8 AGGREGATION

Aggregation is the grouping of utility customers

to jointly purchase commodities and/or other energy

services. There are many aggregators already formed or

being formed in the states where utility deregulation is

occurring. There are two basic forms of aggregation:

1. Similar Customers with Similar Needs

Similar customers may be better served via aggre￾gation even if they have the same load profi les

• Pricing and risk can be tailored to similar cus￾tomers needs

• Similar billing needs can be met

• Cross subsidization would be eliminated

• Trust in the aggregator; i.e. BOMA for offi ce

building managers membership

2. Complementary Customers that May Enhance the

Total

Different load profi les can benefi t the aggregated

group by combining different load profi les.

• Match a manufacturing facility with a fl at or

inverted load profi le to an offi ce building that

has a peaky load profi le, etc.

• Combining of load profi les is more attractive to

a supplier than either would be individually

Why Aggregate?

Some potential advantages to aggregating are:

• Reduction of internal administration expense

• Shared consulting expenses

• More supplier attention resulting from a larger

bid

• Lower rates may be the result of a larger bid

• Lower average rates resulting from combining dis￾similar user profi les

Why Not Aggregate?

Some potential disadvantages from aggregating

are:

• If you are big enough, you are your own aggrega￾tion

• Good load factor customers may subsidize poor

load factor customers

• The average price of an aggregation may be lower

than your unique price

• An aggregation cannot meet “unique” customer

requirements

Factors that affect the decision on joining an aggrega￾tion

Determine if an aggregation is right for your

situation by considering the following factors. An

understanding of how these factors apply to your

operation will result in an informed decision.

• Size of load

• Load profi le

• Risk tolerance

• Internal abilities (or via consulting)

• Contract length fl exibility

• Contract terms and conditions fl exibility

• Regulatory restrictions

24.9 IN-HOUSE VS. OUTSOURCING

ENERGY SERVICES

The end user sector has always used a combination

of in-house and outsourced energy services. Many large

managers and owners have a talented and capable staff

to analyze energy costs, develop capital programs, and

operate and maintain the in-place energy systems. Oth￾ers (particularly the smaller players who cannot justify

an in-house staff) have outsourced these functions to

a team of consultants, contractors, and utilities. These

relationships have evolved recently due to downsizing

and returning to the core businesses. In the new era of

deregulation, the complexion of how energy services are

delivered will evolve further.

Customers and energy services companies are al￾ready getting into the utility business of generating and

delivering power. Utilities are also getting into the act

by going beyond the meter and supplying chilled/hot

water, conditioned air, and comfort. In doing so, many

utilities are setting up unregulated subsidiaries to pro￾vide commissioning, O&M, and many other energy

services to customers located within their territory, and

nationwide as well.

A variety of terms are often used: Performance

Contracting, Energy System Outsourcing, Utility Plant

Outsourcing, Guaranteed Savings, Shared Savings,

Sell/Leaseback of the central plant, Chauffage (used in

Europe), Energy Services Performance Contract (ESPC),

etc. Defi nitions are as follows:

• Performance Contracting

Is the process of providing a specifi c improvement

644 ENERGY MANAGEMENT HANDBOOK

such as a lighting retrofi t or a chiller change-out,

usually using the contractor’s capital and then pay￾ing for the project via the savings over a specifi c

period of time. Often the contractor guarantees a

level of savings. The contractor supplies capital,

engineering, equipment, installation, commission￾ing and often the maintenance and repair.

• Energy System Outsourcing

Is the process of divesting of the responsibilities

and often the assets of the energy systems to a

third party. The third party then supplies the

commodity, whether it be chilled water, steam,

hot water, electricity, etc., at a per unit cost. The

third party supplier then is responsible for the

improvement capital and operations and mainte￾nance of the energy system for the duration of the

contract.

Advantages

The advantages of a performance contract or an

energy system outsourcing project revolves around four

major areas:

1. Core Business Issues

Many industries and corporations have been re￾examining all of their non-core functions to deter￾mine if they would be better served by outsourcing

these functions. Performance contracting or out￾sourcing can make sense if someone can be found

that can do it better and cheaper than what can be

managed by an in-house staff. Then the building

managers can oversee the contractor and not the

complete operation. This may allow the building

to devote additional time and resources to other

core business issues such as increasing revenues

and reducing health care costs.

2. Monetization

One of the unique features of a performance con￾tract or an energy system outsourcing project is

the opportunity to obtain an up front payment.

There is an extreme amount of fl exibility available

depending upon the needs. The amount available

can range from zero dollars to the approximate

current value of the installation. The more value

placed on the up front payment will necessarily

cause the monthly payments to increase as well as

the total amount of interest paid.

3. Deferred Capital Costs

Many electrical and HVAC energy systems are at

an age or state of repair that would necessitate

the infusion of a major capital investment in the

near future. These investments are often required

to address end-of-life, regulatory and effi ciency is￾sues. Either the building owner or manager could

provide the capital or a third party could supply

it and then include the repayment in a commodity

charge plus interest; (“there are no free lunches”).

4. Operating Costs

The biggest incentive to a performance contract

or an energy system outsourcing project is that if

the right supplier is chosen with the right incen￾tives, then the total cost to own and operate the

central plant can be less. The supplier, having

expertise and volume in their core area of energy

services, brings this to reality. With this expertise

and volume, the supplier should be able to pur￾chase supplies at less cost, provide better-trained

personnel and implement energy and maintenance

saving programs. These programs can range from

capital investment of energy saving equipment to

optimizing operations, maintenance and control

programs.

Disadvantages

Potentially, there are several disadvantages to

undertaking a performance contract or an outsourcing

project. The items identifi ed in this section need to be

recognized and mitigated as indicated here and in the

Risk Management section.

1. Loss of Control

As with any service, if it is outsourced, the service

is more diffi cult to control. The building is left with

depending upon the skill, reliability and dedication

of the service supplier and the contract to obtain

satisfactory results. Even with a solid contract; if

the supplier does not perform or goes out of busi￾ness, the customer will suffer (see the Risk Man￾agement section). Close coordination between the

building and the supplier will be necessary over

the long term of the contract to adjust to changing

conditions.

2. Loss of Flexibility

Unless addressed adequately in the contract,

changes that the building wants or needs to make

can cause the economics of the project to be ad￾versely affected. Some examples are:

• Changes in hours of operation

• New systems that require additional cooling

or heating, such as an expansion or renova-

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING 645

tion, conversion of offi ce or storage space to

other uses, additional equipment requiring

additional cooling, etc.

• Scheduling outages for maintenance or re￾pairs

• Using in house technicians for other services

throughout the building. If this situation oc￾curs in current operation, provisions for ad￾ditional building staff or having the supplier

make the technician available needs to be ar￾ranged. If additional costs are indicated, they

should be included in the fi nancial analysis.

3. Cost Increases

This only becomes a disadvantage if the contract

does not adequately foresee and cover every con￾tingency and changing situation adequately. To

protect themselves, the suppliers will try to put

as much cost risk onto the customer as possible.

It is the customer and the customer’s consultants

and attorneys responsibility to defi ne the risks and

include provisions in the contract.

Financial Issues

The basis for success of a performance contract

or an energy system outsourcing project is divided

between the technical issues, contract terms, supplier’s

performance and how the project will be fi nanced. These

types of projects are as much (if not more) about the

fi nancial deal than the actual supplying of a commodity

or a service. (See Chapter 4 -Economic Analysis and Life

Cycle Costing) The answers to some basic questions will

help guide the decision making process.

• Is capital required during the term of the project?

The question of the need for capital is one of the

major driving factors of a performance contract

or an energy outsourcing project. Capital invested

into the HVAC and electrical systems for effi ciency

upgrades, end of life replacements, increased reli￾ability or capacity and environmental improve￾ments can be fi nanced through the program.

• Who will supply the capital and at what rate?

The answer to the question of who will be supply￾ing the capital should be made based upon your

ability to supply capital from internal operations,

capital improvement funds, borrowing ability and

any special financing options such as tax free

bonds or other low interest sources. If capital is

needed for other uses such as expansions and other

revenue generating or cost reduction measures,

then energy system outsourcing may be a good

choice.

• Is there a desire to obtain a payment up front?

As stated previously, a performance contract or

energy system outsourcing project presents the

opportunity to obtain a payment up front for the

assets of the HVAC and electrical systems. How￾ever, any up-front payment increases the monthly

payment over the term of the contract and should

be considered similar to a loan.

• Does the capital infusion and better operations generate

enough cash fl ow to pay the debt?

This is the sixty-four dollar question. Only by

performing a long-term evaluation of the eco￾nomics of the project with a comparison to the

in house plan can the fi nancial benefi ts be fairly

compared. A Net Present Value and Cash Flow

analysis should be used for the evaluation of a

performance contract or energy system outsourc￾ing project. It shows the capital and operating im￾pact of the owner continuing to own and operate

a HVAC and electrical systems. This is compared

to a third party outsourced option. The analysis

should be for a long enough period to incor￾porate the effect of a major capital investment.

This is often done for a 20-year period. This type

of analysis would allow the building owner or

manager to evaluate the fi nancial impact of the

project over the term of the contract. Included in

the analysis should be a risk sensitivity assess￾ment that would bracket and defi ne the range of

results based upon changing assumptions.

Other Issues

1. Management and Personnel Issues

• Management - Usually, an in-house manager will

need to be assigned to manage the supplier and the

contract and to verify the accuracy of the billing.

An in-house technical person or an outside consul￾tant should have the responsibility to periodically

review the condition of the equipment to protect

the long-term value of the central plant.

• Personnel - Existing employees need to be consid￾ered. This may or may not have a monetary conse￾quence due to severance or other policies. If there

is an impact, it needs to be refl ected in the analysis.

It would usually be to the building’s benefi t if the

years of knowledge and experience represented by

the current engineers could be transferred to the