This article was originally presented at the March, 2003 International Association of Assessing Officers (IAAO) Public Utility seminar. The article was authored by Judith Ross, Senior Manager, Ryan & Company, Atlanta office. Ms. Ross is a member of the International Association of Assessing Officers (IAAO).
Introduction
Restructuring or deregulation of the electric industry began in earnest during the 1990's. The stated objective of opening energy markets to competition through deregulation was the expected benefit that consumers would realize by having a choice among energy suppliers. Since restructuring initiatives began, deregulation has progressed in varying degrees throughout the United States. In some states such as Texas, Michigan and Pennsylvania, there have been significant regulatory changes, including the separation of the ownership of generating, transmission and distribution assets. In other states, such as Kansas, Alabama and Georgia, there has been virtually no restructuring action. A number of states are taking a cautious approach and are continuing to monitor and evaluate this issue. Although California was one of the first states to enact legislation to deregulate the retail sale of electricity, restructuring activity has been suspended as the result of numerous problems encountered due to factors such as higher than anticipated demand, extreme weather patterns, constrained supplies, rising fuel prices, and regulatory policies.
The purpose of this paper is to summarize how regulation of the electric industry has evolved and to discuss the valuation issues that have arisen as a result of these changes. Since restructuring activity began, there have been many papers presented at this forum, as well as at the Wichita Workshop, about electric industry deregulation. My objective is to provide a high level overview of key developments and to address the impact that this new environment may have on property and business value.
The most significant regulatory changes have affected generating assets. There appears to be widespread agreement that transmission and distribution facilities will remain strictly regulated for years to come. Accordingly, this paper will focus on issues relating to generating assets.
The History of Regulation
The following is a brief synopsis of the major acts that have established regulatory policy for the electric industry. The electric industry is regulated on the federal level by the Federal Energy Regulatory Commission (FERC) and on the state level by the various state Public Service Commissions. Federal law and policy changes have been the driving force behind changes impacting this industry.
Federal Power Act of 1935 (FPA) and Public Utility Holding Company Act of 1935 (PUHCA)- The Federal Power Act gave the Federal Power Commission (predecessor to the FERC) ratemaking authority over interstate transmission services and wholesale sales of electricity. Pursuant to this act, state regulatory agencies maintained jurisdiction over intrastate transmission and retail sales of electricity. PUHCA limited a holding company to owning only one integrated public utility system and related businesses necessary to support this system. This act also required that equity must comprise at least 30% of a holding company's total capitalization.
Public Utility Regulatory Policies Act of 1978 (PURPA)- This act made it possible for non-utility generators to enter the wholesale power market. The primary goal of PURPA was to stimulate production of natural gas and other forms of energy and to conserve energy by encouraging increased efficiency. PURPA created two new types of non-utility electricity generators that were termed "qualifying facilities"- small power producers and co-generating facilities meeting certain efficiency standards. Small power producers have generating facilities of 80 MW or less and use renewable fuel sources such as solar, wind, or hydro. Co-generating facilities produce both electric and steam energy. When PURPA was first passed, co-generation facilities had to be owned by non-utilities and could not sell electric power at retail. PURPA also required that electric utilities must interconnect with and purchase power from the qualifying facilities when the price did not exceed the incremental cost of alternative electric energy to the utility.
Power Plant & Industrial Fuel Use Act of 1978 (amended in 1990)- Because it was feared that the U.S. was running out of gas and oil, this act was passed to prohibit utilities and industrial manufacturers from building natural gas-fired plants. This act resulted in electric utilities building nuclear and coal-fired plants. This act was amended in 1990, removing barriers to the construction of gas-fired plants.
In 1978, Congress also passed the Natural Gas Policy Act of 1978 (NGPA)- This legislation deregulated natural gas prices. The deregulation of natural gas prices, combined with the fact that natural gas plants could be built faster and at less cost than coal or nuclear plants, led to gas becoming the preferred fuel source for new generating facilities.
Energy Policy Act of 1992 (EPAct)- The objective was to promote greater competition in the wholesale or bulk power market. Congress created another class of generator called exempt wholesale generator (EWG). This act exempted non-utility generators from the regulatory constraints of the Public Utility Holding Company Act of 1935, allowing holding companies to own EWG's. PURPA was also amended to allow PURPA qualifying facilities to be owned by holding companies and by electric utilities in any geographic territory. In implementing this act, the FERC issued Orders 888 and 889 with the stated objective to "remove impediments to competition in wholesale trade and to bring more efficient, lower cost power to the Nations' electricity customers". Order 888 required utilities to unbundle their services and to provide open and equal access to jurisdictional utility transmission lines for all electricity providers. Order 889 required utilities to participate in an electronic open access same time information system (OASIS) that provides information to the public on the cost and availability of transmission services. Although there have been areas of disagreement with respect to the implementation of open access, nevertheless the legal and regulatory framework facilitates evolution to a fully competitive market place.
Overview of the Physical Infrastructure and Regulatory Framework
The Electricity Grid
There are three main power grids in the United States
- Eastern Interconnected System
- Western Interconnected System
- Texas Interconnected System
The Eastern and Western Interconnects have limited interconnections to each other. The Texas Interconnect is only linked to the other grids via direct current lines. All electric utilities in the U.S. are connected to at least one other utility through these power grids.
The purpose of the electricity grid is to bring power from electric plants to users. The grid consists of high voltage transmission systems and lower voltage distribution systems, which draw electricity from transmission lines and distribute it to individual customers. Electrical substations have transformers that step down the voltage from the transmission systems to the distribution lines.
The U.S. power grids provide the technology to transport or "wheel" electricity generated in one part of the country to customers in another part of the country. Although utilities buy and sell electricity to one another, there have been regulatory barriers restricting the supplier from whom retail customers could purchase their electricity. Accordingly, the most significant barrier in the deregulation of retail power is regulatory in nature rather than technological constraints.
Regulatory Framework
As previously stated, the operation of electric generating facilities is impacted by both federal and state regulation.
The FERC approves rates for wholesale sales of electricity and transmission in interstate commerce for private utilities, power marketers, power pools, power exchanges and independent system operators. FERC also confers exempt wholesale generator status under the EPAct and certifies qualifying small power production and co-generation facilities. While FERC has expressed a commitment to the concept of market-based rates, it has the power to impose price caps as deemed necessary, as it did in California during 2001.
State Public Service Commissions continue to oversee retail rates and distribution. Public Service Commissions have been addressing the issue of electric industry restructuring in a different manner and to varying degrees in the states throughout the country. However, in implementing deregulation, state PSC's have generally tended to phase in retail competition, thereby providing a certain level of rate stability for a specified period.
For example, the State of Michigan has been in the forefront of deregulation. Michigan passed comprehensive restructuring legislation that provided retail consumers a choice in selecting electric providers effective January 2002. Under a phased-in plan, customers can elect to bypass their local utility to purchase electricity from the supplier of their choice, much like consumers can choose their long distance telephone carrier. In order to implement this plan, Detroit Edison was required to convey electricity generated by another supplier through Detroit Edison's lines. This movement of electricity is known as "wheeling".
In facing the prospect of retail wheeling, electric utilities have expressed numerous concerns. The primary criticism has been that consumers will suffer because only large industrial users will have the market power to strike favorable deals. It has been suggested that if large users buy up the cheaper electricity, retail customers will be forced to purchase from higher priced systems. Indeed in Montana, where restructuring legislation has been enacted, consumers have experienced increases in the prices of electricity. Concern has also been raised that retail customers will bear the brunt of paying for stranded costs. The issue of stranded costs will be addressed in the section on valuation issues.
A Review of the Past
Until relatively recently, the electric industry had been a classic monopoly. The majority of electricity was provided by investor-owned public utilities subject to state and federal regulation. These companies owned integrated assets that generated electricity and then transmitted and distributed the electric power to customers within a designated service territory. The customers had no choice as to who their electric provider would be. In exchange for this exclusive right to serve all customers in their service area, the utilities were subject to classic rate base regulation, where rates were set to allow the utility to recover its cost of capital and to provide the opportunity to earn a fair rate of return.
While the passage of PURPA in 1978 introduced competition in wholesale markets through the proliferation of co-generating facilities, this regulatory change had relatively little impact on the property tax treatment of utility companies, which still held the vast majority of the electric generating capacity in the U.S.
In the past, the issues surrounding the valuation of the electric industry were for the most part the same as those impacting other public service industries. Investor owned utilities were generally centrally assessed using unit valuation techniques. Valuation controversies tended to focus on traditional unit value issues such as the appropriate cap rate and income stream, the measurement of obsolescence, the applicability of the Stock & Debt approach and the weights that the three approaches to value should receive in the correlation process.
Because of the vertical integration of electric assets and the operation of these assets in a strictly regulated business environment, this industry was historically perceived as very stable. For most investor owned electric utilities, both assets and net operating income grew slowly but steadily over time. While earnings were sometimes adversely impacted by regulatory lag, this industry experienced relatively little volatility.
The Present Status of the Electric Industry
The electric industry is currently facing many uncertainties. In considering the issues impacting this industry, one must keep in mind that the electric industry segment is comprised both of electric utility companies and of independent power producers operating unregulated plants, known as merchant plants. As the result of regulatory changes, the industry is transitioning toward a structure where competitive companies will generate electricity while utilities will continue to provide transmission and distribution services.
As previously stated, the status of restructuring varies significantly by state. Almost half of the states have passed major legislation and/or regulations to restructure their electric power industry. According to the Department of Energy (DOE), states that historically had higher than average electricity prices, such as Pennsylvania, New York and most of New England, have opened their retail electricity markets to competition, thus allowing customers to choose their electricity supplier. Recent problems with supplies and prices of electricity in California appears to have caused states that have not yet enacted restructuring legislation to become more cautious in pursuing deregulation.
State restructuring legislation has either required or encouraged the divesture of generation assets. The DOE's statistics show that at the end of 2000, approximately 16% of all electric utility generating capacity had been sold to unregulated companies or transferred to unregulated subsidiaries, which sell their power in competitive markets, rather than under cost-of-service regulation. In some portions of the country, such as New England, almost all generating plants have been sold from electric utilities to independent power producers. As of 2000, independent generators produced 28% of all wholesale power.
When generating plants were integrated with transmission and distribution facilities, there appeared to be little disagreement that unit valuation was the most appropriate valuation model to use. However, now that generating assets have, in many states, been divested from regulated utilities, industry observers have begun to question the applicability of unit valuation.
Outlook for the Future
More than half the states have not yet addressed restructuring of the electric industry. Five states that previously passed restructuring legislation have delayed further implementation. California has suspended its restructuring activity. Some states, such as Pennsylvania, view deregulation as a success. In Pennsylvania, retail electric rates are reported to have gone from being 15% higher than the national average to being 4.4% lower. Although deregulation is in its early stages, Michigan and Texas are also viewing their retail deregulation efforts as being successful.
There are many factors that contribute to the success or failure of electric deregulation. Variables such as the stability of gas prices, generating plant capacity, demand growth and the effectiveness of regulatory policies all play a role in whether deregulation efforts are perceived positively or negatively in a given state. Additionally, developments such as the collapse of Enron have adversely impacted the interest in deregulation, at least in the short run. Difficulties encountered in the retail deregulation of natural gas have also contributed to a more cautious approach toward electric industry deregulation. Moreover, it is unclear at this time what role the economic distress of the merchant companies will play in further deregulation of the market place.
Present and Future Key Valuation issues
Now that we have reviewed the history of the electric industry, we can consider the issue most relevant to this audience- that is, does regulation affect value and if so, how? There appears to be consensus that regulation does impact value. If this premise is accepted, should the differing regulatory structures in place across the county have a bearing on the valuation method selected? The issue of how to reflect the changing regulatory climate in the valuation process, particularly when there are such disparate regulatory policies in effect across the country, is still the subject of debate.
Assessments must be established for companies operating in several different economic and regulatory environments. There are regulated utilities operating in states where restructuring has not occurred and where competition from unregulated plants has not become significant. Presumably there are utilities operating in states where restructuring of retail sales has not occurred but where there is strong competition for wholesale sales either in the form of unregulated plants or large industrial customers providing their own generation. There are utilities operating in states where significant restructuring has occurred and in which the utilities have divested some or all of their generating assets, thereby facing strong direct competition from independent power producers.
In addition to struggling with the issue of whether these varying economic and regulatory climates require changes in assessment methodologies, one must keep in mind that in many states, regulated utilities continue to be centrally assessed while the property of independent power producers is locally assessed. Inasmuch as a significant amount of the generating capacity owned by independent power producers was formerly owned by regulated utilities, it is possible that plants of similar type and age will have very different assessments depending on whether they are centrally assessed or locally assessed. For regulated utilities where generating assets are still vertically integrated with transmission and distribution property, there may not be a compelling reason to depart from unit valuation at this time. However, while knowledgeable observers understand that the assessed value for a generating plant owned by a regulated utility and valued on a unit value basis is simply the allocated portion of a business enterprise value and therefore does not represent an asset value, the question remains as to whether this potential value disparity can be justified, particularly when the regulated and unregulated plants compete for the same customers.
Irrespective of what valuation methodology is used, the objective is to arrive at fair market value. Accordingly, issues such as technological change, competition, obsolescence and the inclusion or exclusion of intangible property must be addressed no matter what valuation technique is used.
If deregulation continues to progress, the questions regarding how to assess generating assets will become increasingly important. If utilization of unit valuation is no longer relevant in valuing generation assets, particularly when ownership of generating assets is separated from ownership of transmission and distribution assets, the question arises as to what alternative valuation methodologies should be used. Unfortunately, there appears to be little agreement. The primary alternatives that have been proposed are the use of Replacement Cost New Less Depreciation (RCNLD), application of a Discounted Cash Flow (DCF) methodology and the use of market transactions in the context of a comparable sales approach.
In discussing value, consideration must also be given to the economic outlook for electric utilities and unregulated independent power producers. 2002 was not a good year for the power industry and prospects for 2003 are not bright. The December 2002 Value Line Investment Survey points out that the weak economy, soft demand and increased capacity have pushed down electricity prices and hurt margins at the competitive operations of utilities. Purchases by electric utilities of overseas operations have not had the positive economic benefits that were anticipated.
The Value Line Investment Survey for Electric Utilities notes that:
The industry has been in a state of flux since deregulation took effect in California in 1996 and then spread to 24 states. Utility managements, fearful of lower earnings in the new environment, have turned to sources other than basic electricity operations to lift profits, with varying degrees of success.
The outlook for independent power producers is even more grim. Value Line gives this industry the lowest rating in the Investment Survey (98 of 98). Developments that contributed to this industry's problems include an over-supply of generating capacity, reduced access to capital markets and the imposition of price caps in California. Additionally, Value Line points out that trading activity was not nearly as profitable as it claimed to be due to illegal market manipulation causing a spike in spark spreads (electricity revenues minus fuel costs). Accordingly, Value Line's Power Industry Report states that earnings growth among generators and energy traders will likely be minimal to non existent in the year ahead, as companies focus on asset sales to ward off creditors and strengthen their balance sheets.
Those of us interested in property valuation must sort out what this news means for the assessment of electric generating assets. Valuation models must also deal with the issue of stranded costs. Stranded costs are those costs incurred but which cannot be recovered in a competitive environment. As previously mentioned, states have been phasing in the implementation of retail deregulation. One of the purposes of the phase-in is to provide an opportunity for utilities to recover stranded costs. With the decisions as to whether to allow the recovery of stranded costs and the mechanism for doing so being made on a state-by-state basis, there is question as to whether full recovery can be achieved. Stranded costs can have a significant impact on property assessments. For example, for the 2002 tax year in Texas, stranded costs were estimated to have decreased the property tax base by some $6 billion. To the extent that an electric utility has un-recovered stranded costs, this fact must be considered in the assessment process.
In concluding the discussion of valuation issues, the following are some thoughts on how these various valuation issues come into play in the three approaches to value.
The Cost Approach
In a unit valuation model, the cost approach is based on Historical Cost Less Depreciation (HCLD). The HCLD methodology can also be used in local assessment process by applying a designated depreciation schedule. However, given the decline in the cost of building a new state-of-the-art power plant, HCLD will over-state value. Certainly at least for merchant plants that are unregulated and locally assessed by the jurisdictions in which they are located, there is no supportable reason to use any cost approach methodology other than RCNLD.
For plants that are owned by regulated utilities, there appears to be less consensus as to whether these plants should continue to be assessed using a unit value approach or whether they should be separately assessed using either HCLD or RCNLD. Advocates of RCNLD maintain that in a competitive environment where electricity prices are becoming market driven, an existing plant must be valued based upon what a modern replacement facility would cost. According to an article on electric industry deregulation written in January 2002 by Ms. Suedeen Kelly, an attorney involved in electric industry issues, as long as the competitive market in electricity continues or expands, a primary goal of electric generators will be producing electricity at the lowest possible cost.
Combined cycle gas turbine generators are currently considered to be the state-of-the-art technology for generating plants. However, about 50% of the generating capacity in the U.S. is coal-fired. In the aforementioned paper, Ms. Kelly points out that in recent years natural gas has been the preferred fuel for new generation and that it is therefore unclear what place coal technology will have in future electric generation. The price of fuel is a significant factor in the choice between operating gas-fired and coal-fired generators. When the cost of purchasing natural gas reaches the $5-6 per million BTU level, coal-fired plants become less expensive to operate than gas-fired plants. However, other factors such as environmental concerns and the difficulty in obtaining permission to site coal-fired plants impact the current preference for constructing gas-fired versus coal-fired power plants. Accordingly, if the appraisal assignment is to value a 1980's vintage coal-fired plant, the appraiser should consider that a modern replacement facility would likely be gas-fired and thus would have a lower construction cost, require less capacity and be more efficient to operate than the existing coal-fired plant. As a result of these differences, a RCNLD model for a coal-fired plant would reflect a considerable amount of obsolescence.
Even relatively new gas-fired plants may suffer from obsolescence. Improved technology has resulted in a significant decline in the cost to build gas-fired combined cycle plants. According to a 1996 McGraw Hill report, the construction cost per KW for new gas-fired combined cycle plants declined about 40% from the cost several years earlier.
The Income Approach
If a traditional unit valuation model is not used, the question arises as to whether the income approach is applicable. It has been suggested that a DCF model may be an appropriate valuation technique for assessing generating assets. However, concern has been raised as to whether in this uncertain environment, where revenues and fuel costs can be volatile, an income approach is feasible. An additional challenge in utilizing an income approach to assess generating assets is whether it is possible to determine the income stream for just the tangible property.
In applying an income approach, whether in the context of unit valuation or in an asset valuation model, the appraiser must recognize the appropriate level of risk. The level of volatility in an increasingly competitive environment would suggest that equity rates should be higher than in the economic environment prior to deregulation.
Comparable Sales Approach
When transactions of electric generating plants began to occur, some observers suggested that these transactions provided the data for a comparable sales approach. When regulated utilities first began divesting their generating assets, sales occurred at a premium over net book value. However, there was question as to what these sales included. For example, if long-term power purchase contracts were involved at prices above current market spot prices, did these contracts constitute intangible property? Other types of intangible property such as emissions allowances and fuel supply contracts may also impact transaction prices.
Another issue with regard to using market transactions is the fact that the terms of the transactions are typically proprietary. Because critical factors affecting sales price can't be determined, critics of using a comparable sales approach maintain that there is not sufficient information to adjust comparables as required.
More recently, independent power producers have been divesting their generating assets at prices below what they paid. As the result of a lack in demand, there are numerous plants that have been offered for sale that have not sold. Because of the distressed conditions in the market, perhaps these current prices are not any more reflective of the asset's values than were the prices that anticipated synergies and operating benefits that never materialized.
Conclusion
As is the case with most of the issues we face, there are no easy answers. Whether a state's legal framework requires the valuation of the business or the assets, the objective should be to arrive at the fair market value of the property subject to tax in that state. Irrespective of the valuation technique used, the value of property is impacted by issues such as competition and technological change. Accordingly, the valuation methodologies selected must recognize the variables that affect value and properly measure the impact of those variables.
If you have any questions regarding the above information, please call Judith Ross at 404.365.9101 x142631. You can also reach Ms. Ross by e-mail.