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637 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 protection in deregulated states and you can see why utility deregulation is increasingly on the mind of utility customers 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 deregulating 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 generated 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 regulated 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 utilities 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 decreasing 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 customers, and the energy services sector deal (or do not deal) with each other. Regulated monopolies are out and customer 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 competition 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 “retail” 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 periods 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 basis, 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 following 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 previously 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 recovering 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 restructuring 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 access. 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 recovering their stranded costs. Customer advocacy groups, on the other hand, have argued that the stranded costs proposed 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 proceedings. 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 developed beyond the traditional vertically integrated electric utility. Energy marketers and brokers are the new companies 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 suppliers 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 recognized 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 taking 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 customers 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, commissioning, 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 relationships 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 deregulation 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 owners 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 energy 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 responsibility 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 aggregation even if they have the same load profi les • Pricing and risk can be tailored to similar customers 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 aggregation • 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 aggregation 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 already 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 provide 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, commissioning 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 maintenance 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 determine if they would be better served by outsourcing these functions. Performance contracting or outsourcing 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 contract 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 issues. 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 purchase 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 business, 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 additional 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 reliability 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 supplying 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 economics 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 outsourcing project. It shows the capital and operating impact 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 considered. 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 646 ENERGY MANAGEMENT HANDBOOK new supplier. Another personnel concern is the effect on the moral of the employees due to their fear of losing their jobs. 2. Which services to outsource? Where there are other services located in the central plant that are not outsourced, these need to be identifi ed in the documents. These could include compressed air for controls, domestic water, hot water, etc. A method of allocating costs for shared services will need to be established and managed through the duration of the contract. 3. Product specifi cations The properties of the supplied service need to be adequately described to judge if the supplier is meeting the terms of the contract. Quantities like temperature, water treatment values, pressure, etc. needs to be well defi ned. 4. Early Termination There should be several options in the contract for early termination. The most obvious is for lack of performance. In this case, lack of performance can range from total disruption of service to not meeting the defi ned values of the commodity to letting the equipment deteriorate. There should also be the ability to have the building owner terminate the contract if the building owner decides that they want to take the central plant in-house or fi nd another contractor. If the supplier is in default, then a “make whole” payment would be required of the building to terminate the contract in this case. Risk Management As with any long-term commitment, the most important task is to identify all of the potential risks, evaluate their consequences and probability and then to formulate strategies that will mitigate the risks. This could be in the form of the contract document language or other fi nancial instruments for protection. One of the most important areas of risk management mitigation is to choose a supplier that will deliver what is promised over the entire contract period. 1. How to Choose a Supplier In addition to price, the following factors are important to the success of a project and should be evaluated before selecting a supplier. • Track record • Knowledge of your business, priorities and risk tolerance • Size • Financial backing • Customer service and reporting • “Staying Power” 2. Long Term Contracts Because the potential supplier will be investing capital for increased life, reliability and effi ciency, the contract needs to be long enough to recover the costs and provide a positive cash fl ow. The length of the project can vary from three to fi ve years for a simple, small-scale project up to ten to twenty years for one of increased complexity. Cost impacts at the termination of the contract needs to be adequately addressed, such as: • Renewals • Buyouts • Equipment leases • Equipment condition at the end of the contract 3. Changing Assumptions • Interest rates • Utility rates • Maintenance and repair costs • Areas served (i.e., expansions/renovations/ contractions) • Regulations; building specifi c, environmental, OSHA, local codes, etc. • Utility deregulation 4. Other Risks • The impact of planned or unplanned outages of the central plant • The consequences of the supplier not being able to maintain chilled water temperature or steam pressure • “Take or Pay” This provision of a contract requires the customer to pay a certain amount even if they do not use the commodity • Defaults and Remedies 24.10 SUMMARY This chapter presented information on the changing world of the utility industry in the new millennium. Starting in the 80’s with gas deregulation and the passage of the Energy Policy Act of 1992 for electricity, the method of providing and purchasing energy was changed forever. Utilities began a slow change from vertically integrated monopolies to providers of regulated wires and transmission services. Some utilities [...]... 669,375 619,2 18 393,524 440,747 493,637 552 ,87 4 0 225,694 1 78, 471 125, 581 66,345 619,2 18 619,2 18 619,2 18 619,2 18 619,2 18 1 ,88 0, 782 1, 487 ,2 58 1,046,511 552 ,87 4 0 367,056 159,279 387 ,169 571,405 83 8,375 530,625 -619,2 18 124,799 54,155 131,637 194,2 78 285 ,0 48 180 ,413 205, 983 276,627 199,145 136,503 664,953 1,019, 588 —————————————————————————————————————————————— 2,500,000 Net Present Value at 18% : $ 681 ,953 ——————————————————————————————————————————————... 357,250 612,250 437,250 312,250 111,625 669,375 2,500,000 370, 789 426,407 490,3 68 563,924 6 48, 511 2,500,000 375,000 319, 382 255,421 181 ,86 5 97,277 745, 789 745, 789 745, 789 745, 789 745, 789 530,625 2,129,211 1,702 ,80 4 1,212,435 6 48, 511 0 180 ,413 217,750 18, 3 68 257,329 455 ,88 5 741,0 98 1,019, 588 74,035 6,245 187 ,492 55,001 251,973 Net Present Value at 18% : 130,176 197,966 116,719 49,210 -47,761 $757,121 ——————————————————————————————————————————————... 1,000,000 1,000,000 0 0 0 0 0 80 0,000 80 0,000 80 0,000 80 0,000 80 0,000 80 0,000 80 0,000 80 0,000 80 0,000 80 0,000 200,000 200,000 200,000 200,000 200,000 Net Present Value at 18% : 68, 000 68, 000 68, 000 68, 000 68, 000 132,000 132,000 132,000 132,000 132,000 $412, 787 —————————————————————————————————————————————— Notes: ESCO purchases/operates equipment Host pays ESCO 80 % of the savings = $80 0,000 The contract could... 393,216 4 48, 266 511,024 280 ,000 237,641 189 ,351 134,301 71,543 500,000 582 ,567 582 ,567 582 ,567 582 ,567 582 ,567 2,000,000 1,697,433 1,352,507 959,291 511,0241 0 312,750 100,109 323,399 503,449 766 ,83 2 530,625 106,335 34,037 109,956 171,173 260,723 180 ,413 –500,000 261,0 98 333,396 257,477 196,260 106,710 1,019, 588 —————————————————————————————————————————————— 2,500,000 Net Present Value at 18% : $710,962... 375,000 2 ,87 5,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 0 217,750 -37,250 137,750 262,750 463,375 530,625 Net Present Value at 18% : 74,035 -12,665 46 ,83 5 89 ,335 157,5 48 180 ,413 500,965 587 ,665 5 28, 165 485 ,665 -2, 082 ,5 48 1,019, 588 953,927 —————————————————————————————————————————————— Notes: Loan Amount: Loan Finance Rate: 2,500,000 (used to purchase equipment at year 0) 0% MARR 18% Tax Rate... 669,375 592,750 337,750 512,750 637,750 83 8,375 530,625 201,535 114 ,83 5 174,335 216 ,83 5 285 ,0 48 180 ,413 -2,500,000 7 48, 465 83 5,165 775,665 733,165 664,953 1,019, 588 —————————————————————————————————————————————— 2,500,000 Net Present Value at 18% : $320,675 —————————————————————————————————————————————— Notes: Loan Amount: Loan Finance Rate: 0 0% MARR Tax Rate 18% 34% MACRS Depreciation for 7-Year Property,... 612,250 400,000 337,750 437,250 400,000 512,750 312,250 400,000 637,750 111,625 2,500,000 400,000 83 8,375 669,375 530,625 2,500,000 ATCF = 0 201,535 114 ,83 5 174,335 216 ,83 5 285 ,0 48 180 ,413 3 48, 465 435,165 375,665 333,165 2,235,0 48 1,019, 588 —————————————————————————————————————————————— Net Present Value at 18% : 477,033 —————————————————————————————————————————————— Notes: Value of Stock Sold (which is... kd(1-T) FINANCING ENERGY MANAGEMENT PROJECTS Thus, WACC= (.3)(.1)(1-.34) +(.6)(.15) + (.1)(.12) WACC= 12. 18% References 1 Wingender, J and Woodroof, E., (1997) “When Firms Publicize Energy Management Projects Their Stock Prices Go Up: How High?—As Much as 21.33% within 150 days of an Announcement,” Strategic Planning for Energy and the Environment, Vol 17(1), pp 38- 51 2 U.S Department of Energy, (1996)... Environment, Vol 17(1), pp 38- 51 2 U.S Department of Energy, (1996) “Analysis of Energy- Efficiency Investment Decisions by Small and Medium-Sized Manufacturers,” U.S DOE, Office of Policy and Office of Energy Efficiency and Renewable Energy, pp 37- 38 3 Woodroof, E and Turner, W (19 98) , “Financial Arrangements for Energy Management Projects,” Energy Engineering 95(3) pp 23-71 4 Sullivan, A and Smith, K (1993) “Investment... Your Energy Management Projects,” Strategic Planning for Energy and the Environment, Summer 1999, Vol 19(1) pp 65-79 10 Cooke, G.W., and Bomeli, E.C., (1967), Business Financial Management, Houghton Mifflin Co., New York 11 Wingender, J and Woodroof, E., (1997) “When Firms Publicize Energy Management Projects: Their Stock Prices Go Up,” Strategic Planning for Energy and the Environment, 17 (1) pp 38- 51 . 312,250 563,924 181 ,86 5 745, 789 6 48, 511 455 ,88 5 55,001 49,210 5 950,000 111,625 6 48, 511 97,277 745, 789 0 741,0 98 251,973 -47,761 5* 1,200,000 669,375 530,625 180 ,413 1,019, 588 2,500,000 Net. 370, 789 375,000 745, 789 2,129,211 217,750 74,035 130,176 2 950,000 612,250 426,407 319, 382 745, 789 1,702 ,80 4 18, 3 68 6,245 197,966 3 950,000 437,250 490,3 68 255,421 745, 789 1,212,435 257,329 187 ,492. 592,750 201,535 7 48, 465 2 950,000 612,250 337,750 114 ,83 5 83 5,165 3 950,000 437,250 512,750 174,335 775,665 4 950,000 312,250 637,750 216 ,83 5 733,165 5 950,000 111,625 83 8,375 285 ,0 48 664,953 5*

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