A line-by-line case study of two high-priced portfolios, comparing fixed, variable and capital costs against forecasts of regional market prices.
A multi-billion-dollar wave of utility divestiture and power plant auctions has taken place during the last 18 months. Table 1 details some of these transactions, including the purchase price on a dollar-per-kilowatt basis and as a multiple of net book value. These measures frequently are cited as indications that buyers paid too much. Here we refute the use of these measures for the valuation of competitive power plants, and offer step-by-step analytical approaches that are better suited to the task.
Pace Global Energy Services has provided valuation services to bidders for much of the divested utility capacity. Our analysis, supported by in-house financial and fuels services as well as our proprietary market price analysis system, indicates that some of the winning bidders of plants really are winners, some are maybe winners and some should prepare for a fire sale. But in no case was the book value a significant indicator of the market value of the plant. In all fairness, there may be a valid reason for the confusion surrounding the meaning of the multiple of net book value purchase price.
Our simplified analysis includes the following steps to assess each case:
1. Determine likely capacity factors;
2. Determine plant's output in megawatt-hours given its capacity factor and its demonstrated capacity in megawatts;
3. Establish variable costs of production based on historical data from the U.S. Energy Information Administration (EIA) in dollars per megawatt-hour;
4. Establish fixed operating costs based on historical EIA data in dollars per kilowatt translated into dollars per megawatt-hour on the basis of its estimated capacity factor determined in step 1;
5. Determine capital recovery costs assuming financing and tax-related costs that are typical for domestic power markets translated into dollars per megawatt-hour on the basis of its estimated capacity factor; and
6. Determine unit revenues necessary to provide cost recovery for fuel, non-fuel O&M, fixed O&M and capital costs on a dollar-per-megawatt-hour basis. If the required revenues appear to be achievable under reasonable market conditions, we declare the acquisition a winner.
In this article we analyze and compare two cases of utility plant divestitures. The two transactions are (1) Mission Edison's purchase of the Homer City plant in Pennsylvania, and (2) the purchase by FPL Energy of the Central Maine Power (CMP) portfolio of assets. We selected these projects because they are the most expensive acquisitions on a dollar-per-kilowatt basis of the projects shown in table 1.
Our analysis demonstrates that a power plant purchase price in excess of net book value cannot be interpreted automatically as an overpayment. Even with a purchase price of more than three times the net book value, Homer City appears to be a sound investment. Likewise, a price per kilowatt in excess of the price of a new combined-cycle station is not necessarily an indication that the buyer overpaid. Homer City's unit cost was $955 per kilowatt, while a new combined-cycle plant can be purchased for about $500 per kilowatt. Yet Homer City's all-in cost on a reasonable capacity factor assumption is comparable to that of a new combined cycle.
Power plant valuation requires a detailed look at several potential revenue sources. Our simplified CMP portfolio analysis - examining only potential energy market values - indicates the need for a more sophisticated asset-specific type of approach. In addition to energy market value, a complete valuation would include an estimate of value flowing from the ancillary services market, trading and retail value, and plant site value.
Finally, the transaction may need to be analyzed to see if the deal itself adds value to the asset. For example, frequently there are transition contracts offered by the seller that provide additional value. Tax value issues and IRS rulemaking also may impact asset value, particularly if contract restructuring is involved. Niagara Mohawk's independent power producer restructuring is a case in point.
Book Value Multiples:
How They Foster Confusion
Confusion about the relationship between net book value and power plant market value may result from the tradition of price regulation in the utility business. The net book value is similar to what regulators call the "rate base." Both are measured as original cost minus accumulated depreciation. The reason some people may attach undue importance to net book value as an indicator of power plant value may be that utility revenues are tied systematically to the similar measure, rate base, under cost-of-service regulation.
Regulators determine utility-allowed revenues using the actual expenses that utilities incur, plus a return on rate base, plus an annual depreciation expense. Utility revenues based on expenses simply "pass through" the utility to entities such as fuel suppliers, workers and taxing authorities. On the other hand, the return on rate base and depreciation expense provide utility investors with their return on investment and a return of investment. Hence, plant revenues and rate base are linked strongly under cost-of-service regulation. Net revenues are the basis of plant value under both cost-of-service regulation and competition.
Competitive market revenues are not tied to rate base. Rather, competitive market prices are determined by the relationship between supply and demand, and power sales result from a plant's competitiveness relative to other suppliers. Low-cost power plants will sell more power than will higher-cost rivals, and prices will reflect the supply/demand balance and the value consumers place on reliability.
There is no systematic relationship between net book value and market value because net book value affects neither the market price for power nor the operating costs of a power plant. Consequently, would-be buyers of generating assets should base their bids not on the asset's net book value, but on estimates of market revenues, net of power production costs. An accurate projection of net revenues provides a solid foundation for power plant valuation in the emerging competitive U.S. power market.
Competitive Value:
Tied Closer to Demand, Capacity
The process of determining a power plant's market value requires a team of analysts, each contributing specialized skills across diverse fields such as finance, fuels, engineering and computer science. Steps include:
* Forecasting hourly power demand over a 20-plus-year period.
* Forecasting changes in the amount and character of generating capacity.
* Forecasting the costs of inputs such as fuels and capital.
* Assessing the likelihood and timing of technological innovation.
* Including these parameters in a simulation of the operations of the market with an overlay of theories on bidding behavior and market equilibrium conditions.
* Analyzing and projecting revenues from ancillary services, plant optionality value and trading value.
* Analyzing the plant's site value, including transmission access, environmental status, expansion potential, etc.
The primary sources of power plant value are illustrated in figure 1. Of course, long-term market price forecasting is more an art than a science, but understanding and quantifying a few fundamentals and their impacts on power prices can facilitate a solid revenue forecast. These fundamentals include:
* Replacement costs and the impact of incremental capacity that places a long-term "cap" on prices in the energy market.
* The inelasticity of power demand, the absence of short-term substitutes, and the attribute of electricity as an essential commodity with high outage costs mean that reliability commands a premium in both the energy and ancillary services markets.
* Price volatility results from power's inelasticity and the absence of large-scale storage technologies, and enhances a power plant's trading value, retail value and "option" or "reserve" value.
Clearly, there are many pieces to the power plant value puzzle. The following describes the key aspects of a projection of energy market revenues (figure 1).
Price Expectations. A competitive power price forecast depends first and foremost on an assessment of the supply/demand balance in a given market. Power prices and power price volatility are influenced more heavily by the supply/demand balance than are the prices of other commodities. What makes electricity unique, of course, is that it cannot be stored, and the price of power will spike when unexpected plant outages and transmission congestion accompany high demand caused by extreme temperatures. Suppliers not only benefit from these short-term price spikes, it is likely that many suppliers will depend on high-price periods to recover fixed costs. However, if an abundance of capacity is available in the market during peak demand periods due to overly exuberant development or lackluster demand, prices will not rise dramatically and many suppliers will have difficulty achieving fixed-cost recovery. Therefore, the price of power and the profitability of power plants both are highly dependent on the supply/demand balance.
An efficient power market will trend toward an equilibrium supply/demand balance, and prices will approach the cost of replacement or incremental capacity. In other words, consumers will be willing to pay just enough for electricity to provide for a reliable power market. The resulting prices will provide incentives for developers to construct only as much capacity as the market needs. If prices are higher than the cost of new capacity, then developers will achieve a return on their investment higher than their cost of capital. They will continue to build until the amount of new capacity is sufficient to drive prices down to equilibrium levels. If prices are lower than the cost of new capacity, developers will wait until increases in demand or reductions in existing generating capacity drive prices higher. Therefore, power prices will trend toward the all-in cost of new generating capacity. Today, that is either the all-in cost of new natural gas-fired combustion turbines or combined-cycle generators.
What is important for purchasers of power plants is how long the transition to equilibrium prices will take and the nature of emergent competitive power market business cycles (boom-bust market price fluctuations). That transition will vary from market to market depending on the existing technological mix of generators, the rate of growth in demand and how much new capacity is added to the market by new market entrants. In the New England market, for example, developers plan a tremendous amount of new generating capacity relative to what the market will support. Our studies indicate that if even a fraction of this capacity actually enters service, New England power prices could be depressed for five years or more (bust). On the other hand, in the Midwest, a shortage of generating capacity has resulted in very high prices for the last two summers (boom).
Dispatch Projections. The amount of power that a given plant produces relative to its maximum potential output is its "capacity factor." As with market prices, a plant's capacity factor and the timing of its sales are determined by supply and demand. Likewise, the competitiveness of a plant relative to other suppliers in its market is an important consideration in the timing and amount of its sales.
Stack analysis often is used to determine a power plant's position in the dispatch queue relative to all other resources in the market area. By overlaying a load duration curve on the graphical representation of the supply resources, it is possible to gauge the approximate capacity factor of any given resource. Figure 2 illustrates a stack analysis for the PJM Interconnection in 2003. The amount of capacity by technology is stacked in blocks from the cheapest hydropower resources ("hydro") to the most expensive combustion turbines ("CT-old"). Also shown is a representation of hourly demands, or loads, sorted from highest to lowest ("Load Duration Curve"). By comparing the dispatch queue to the load duration curve, an approximate load factor for each technology can be determined. For example, a low-cost coal plant in PJM will operate at between 70 percent and 100 percent of its maximum output, depending on where it falls relative to other coal plants.
Stack analysis, while a simple analytical technique, cannot consider operational constraints such as start times and ramping capabilities. Nor can it accurately project the timing of plant operations. Our firm and others use computer models to match a plant's dispatch to system prices, enabling a forecast of market revenues for a specific plant. Such models allow the specification of plant start costs, ramping capabilities and other detailed operational parameters including bidding behavior, in order to gain a realistic representation of the operations of a power system and each generating station. These detailed simulations allow for more accurate projections of plant dispatch and market prices.
In addition to simulations of expected market conditions, our market assessment team develops high- and low-valuation cases using variations in input parameters. Typically, sensitivities are constructed using variations in future fuel prices, the rate of generating capacity additions, the rate and impact of technological innovation (improved heat rates), and demand growth rates. In this way, a conceptual confidence band can be placed around the power plant valuation.
The Case Studies:
Homer City and the Central Maine Portfolio
Without using the additional values attributable to ancillary services and trading or retail sales, our firm evaluated two acquisitions and determined if a fair price was paid. The purpose is not to provide a detailed valuation, but to answer the simpler question, "Did the buyer pay too much?"
Homer City. Homer City is a coal-fired power generating plant located in central Pennsylvania. Units 1 and 2 were constructed in 1969; a third unit was completed in 1977. Because Homer City is a low-cost producer and is in the unique position of having access to two markets - PJM and the New York Power Pool - it appears to be a highly competitive plant.
According to data from the U.S. EIA, Homer City's demonstrated heat rate consistently has been at or below 10,000 British thermal units per kilowatt-hour for almost a decade. Combined with a non-fuel, variable O&M cost of less than $1 per megawatt-hour, Homer City's total variable costs averaged just over $17 per megawatt-hour from 1993 to 1997. Further, our analysis of fuel costs, as reported by EIA Forms 759 and 423, differs from the FERC Form 1 data used for the $17 per megawatt-hour reported figure. The Form 1 data includes fuel handling, storage and other costs in addition to the delivered fuel costs reported in EIA Forms 759 and 423. These additional costs may not persist under the pressures of competition. Further, our in-house fuels experts project a long-term decline in delivered coal prices. For these reasons, and to provide a conservative estimate of Homer City's costs, our analysis uses a delivered cost of fuel of $11.20 per megawatt-hour based on a 10,000 Btu per kilowatt-hour heat rate. This price is more consistent with our projection of delivered fuel costs to Homer City.[Fn.1]
With its low variable cost of operations, Homer City has enjoyed a capacity factor of more than 70 percent during the same five-year period (1993 to 1997). Under competitive conditions, it is likely that this capacity factor will increase substantially, and our computer models indicate that Homer City could dispatch at an 84 percent capacity factor for the next 20 years. Therefore, this analysis assumes that Homer City runs at 84 percent capacity. A sensitivity test is provided, testing the impact of a 90 percent capacity factor.
A more sophisticated analysis also would include consideration of emissions rights and valuation. In particular, a projection of allowance demands and prices could have an impact on the valuation of coal-fired power plants. However, for brevity and simplification, we omitted that step.
To determine the price and run time at which Edison Mission may expect to achieve a reasonable return on its purchase, Homer City's per megawatt-hour costs were determined assuming 84 percent capacity utilization. We calculated fixed-cost recovery on a megawatt-hour basis using the cost assumptions shown in table 2.
Financial assumptions, shown in table 2, were developed from our experience in project development and acquisitions, and are consistent with a conservative valuation approach. For example, the assumption of a 70/30 debt-to-equity ratio is viable given the capital structure of many recent divestiture and greenfield merchant projects observed during the past six to eight months.[Fn.2] Also, the after-tax ROE (ROE) of 12 percent is a bit lower than the typical developer hurdle rate of about 14 percent. Here, the ROE is used only to determine acquisition revenue requirements on a unit basis (dollar per megawatt-hour) for comparison to market price projections. In reality, a lower ROE could infer a lower discount rate for use in this value calculation, increasing estimates of plant value. Finally, income and property tax assumptions are representative of U.S. and state tax rates.
The initial book value is assumed to be the $1.8 billion purchase price. Annual Debt Service ($133,145,428 per year) is the fixed payment whose present value is equal to the debt portion of the purchase price (70 percent times $1.8 billion = $1.26 billion). Taxes are adjusted each year by the interest portion of the debt service. The annual depreciation expense is assumed to be straight-line with the first and last years at half the usual annual rate of 5 percent. These assumptions are consistent with common accounting conventions.
The $218 million per year in capital-related costs has been levelized. Fixed costs decline over time as debt principal is paid off and interest expenses fall. In reality, these front-end-loaded capital expenditures can be levelized through a sales-leaseback deal or other arrangement. The fixed annual capital cost shown here results in the same present value as the declining costs, assuming a discount rate equal to the after-tax weighted average cost of capital. At an 84 percent capacity factor, Homer City generates 13,863 gigawatt-hours, resulting in a capital recovery cost (including taxes) of $15.73 per megawatt-hour. (See table 2.)
To determine the price at which Edison Mission will receive a conservative 12 percent ROE, the $15.73 per megawatt-hour annual capital cost must be added to Homer City's operating costs. EIA data indicates that Homer City's fixed O&M costs averaged just over $40 million, or $21.25 per kilowatt-year, from 1993 to 1997. Assuming an 84 percent capacity factor, this translates to approximately $2.89 per megawatt-hour.
By adding its variable operating costs to the revenues required for fixed-cost recovery, Homer City will achieve a modest 12 percent after-tax ROE if it receives an average revenue of $30.65 per megawatt-hour and operates at 84 percent capacity. As mentioned, we believe Homer City may achieve a higher capacity factor in a competitive environment. If it achieves a 90 percent capacity factor, Homer City will realize a 12 percent after tax equity return with average revenues of $29.41 per megawatt-hour. The unit cost components included in this analysis are presented in table 3.
As discussed, these results are dependent on Edison Mission's ability to levelize the debt service and other capital-related costs for its acquisition of Homer City. Not levelized, Homer City's average capital-related costs for the first two years are more than $225 million as compared to the 20-year levelized $218 million. Achieving this level of revenue requires that Homer City sell power at an average price of $31.18 per megawatt-hour.
Table 4 illustrates the cost components of replacement capacity in PJM, assuming the same financing costs and an 84 percent capacity factor. Delivered natural gas prices in the Homer City location in Western PJM are assumed to be the strip price of $2.57 per million British thermal units reported as of this writing in Natural Gas Week, plus our PJM basis differential off of Henry Hub of $0.25 per million British thermal units. The installed cost of a new combined-cycle station is assumed to be $525 per kilowatt in PJM. Assumed new combined-cycle heat rate is 6,900 Btu per kilowatt-hour, resulting in a fuel cost of $19.46 per megawatt-hour. That indicates that prices in PJM will trend toward the all-in price for a combined-cycle generating station, estimated to be $31.43 per megawatt-hour. That amount is close to the required revenues for Homer City to recover its assumed ROE.
Homer City's unit cost range of roughly $29 to $31 per megawatt-hour may be fully recoverable in the two energy markets to which it has full access. With any additional value by virtue of ancillary services, trading, retail revenues or site considerations, Homer City appears likely to recover its acquisition costs and likely will be a winner for Edison Mission.
Central Maine Portfolio. FPL's purchase is a little more complicated to analyze because the CMP assets make up a diverse portfolio of five distinct pieces: hydroelectric assets, the Cape Gas Turbine, the Mason Steam plant, the W.F. Wyman steam plant and the Aroostook Valley biomass generating plant. The hydropower portion of the portfolio consists of several small plants on the Kennebec, Androscoggin and Saco rivers. EIA data indicates a total capacity of 368 MW.
The average capacity factor during the last several years is approximately 50 percent for the hydropower portion of the CMP portfolio. Average non-fuel variable O&M was $0.75 per megawatt-hour from 1988 to 1997. Fixed O&M averaged $12.65 per kilowatt. The contribution of these plants, because they are energy-limited hydroelectric assets, will be limited by the flows of their respective rivers. They will be limited to a 50 percent capacity factor in this analysis, in spite of their low operating costs.
The Cape Gas Turbine facility, on the other hand, will not contribute to the fixed costs of FPL's portfolio unless trading and ancillary services values are applied. The heat rate on this plant is well in excess of 15,000 Btu per kilowatt-hour. Its highest capacity factor was 1.9 percent in 1988, and has not surpassed 0.1 percent since 1989. EIA's "Inventory of Power Plants" indicates that this 42-MW plant was operational as of the beginning of last year. However, it is unlikely that Cape can cover its own fixed O&M costs, let alone contribute to FPL's capital recovery, unless there are significant high-demand periods accompanied by capacity shortages resulting in high price spikes. That is unlikely in New England Power Pool (NEPOOL) given the great amount of capacity additions planned there. For this reason, a conservative approach indicates that, for the purposes of this analysis, the Cape Gas Turbine will have no base value.
The same assumption will be made with regard to the Mason Steam facility. Mason is a 145-MW oil-fired steam generator of 1952 and 1955 vintage. Its heat rate exceeds 15,000 Btu per kilowatt-hour, its fixed O&M expense ranges between $3 and $6 per kilowatt, and it is unlikely to contribute to FPL's portfolio cost recovery without additional investments, more sophisticated valuation methods or higher than expected NEPOOL energy market prices.
The William F. Wyman station is a heavy oil-fired steam generator consisting of four units built in 1957, 1958, 1965 and 1978. The first two units output 54 MW each with a heat rate of approximately 12,300 Btu per kilowatt-hour. Unit 3 is 119 MW with a heat rate of 10,100 Btu per kilowatt-hour and unit 4 is a 620-MW unit, of which FPL purchased CMP's share of 367 MW. Unit 4 has a reported heat rate of between 10,400 and 10,613 Btu per kilowatt-hour.
EIA data indicates that the entire station's generation-weighted heat rate was approximately 11,585 Btu per kilowatt-hour from 1993 to 1997. Wyman's capacity factor has fallen steadily since 1988, when it was at 41 percent. EIA's generation-weighted fuel cost is $28.82 per megawatt-hour from 1993 to 1997. Given the heat rate described above, this would infer a heavy (#6) fuel oil cost of $2.49 per million British thermal units - low by most standards. However, since the plant likely will generate from the newer, lower heat rate units, in the spirit of conservatism it is reasonable to assume the average $28.82 per megawatt-hour fuel cost reported by EIA. Wyman's fixed O&M costs are $16.40 per kilowatt and variable O&M was $4.42 per megawatt-hour from 1993 to 1997.
Finally, the Aroostook Valley station is a wood-fired generating plant of 1994 vintage. It consistently has operated at a high capacity factor, but is capable only of 32 MW of output. Aroostook's fixed O&M costs average $6 per kilowatt, non-fuel variable O&M averages $1.49 per megawatt-hour and fuel costs average $21.30 per megawatt-hour. Aroostook should produce a positive contribution to FPL's capital costs in spite of its small size.
The portfolio described above is shown in table 5, assuming 20 percent and 40 percent capacity factors for the Wyman station. Input parameters for the portfolio are based on the weighted costs of the component plants. Portfolio fixed O&M in the table is weighted by capacity. To determine the fixed O&M on a megawatt-hour basis, fixed O&M is weighted by the assumed output of each plant. Variable costs are weighted by generation so the portfolio costs reflect the underlying assets. Table 6 shows the portfolio capital cost assumptions. Except for the capacity factors, these assumptions are identical to those for Homer City to facilitate comparison of results.
Table 7 shows the results of the analysis for the CMP portfolio. Revenue requirements of $54.85 per megawatt-hour for the 20 percent Wyman case and over $49 per megawatt-hour for the 40 percent Wyman case are the result of high capital costs associated with the acquisition. The variable operating costs of the 20 percent Wyman case - $14.24 per megawatt-hour ($12.11 + $2.13) - are quite low, reflective of the low operating costs of the hydropower assets and the Aroostook plant. However, the low capacity factor of 33 percent for the entire portfolio does not provide enough hours of operation over which to spread the acquisition costs, resulting in a unit cost of $35.53 per megawatt-hour for capital recovery and taxes. The energy-limited nature of hydroelectric assets is one of the causes of this apparent inconsistency between low operating costs and low capacity factor. Even assuming the higher 40 percent capacity factor for the Wyman station, its high variable operating costs partially offset the additional megawatt-hours over which FPL may recover the capacity costs.
At this basic level of analysis, the CMP portfolio revenue requirements do not bode well for FPL's ability to recover its acquisition costs. Even in the absence of a likely supply glut in the NEPOOL market, baseload market prices should be capped by the all-in costs of incremental combined-cycle capacity.
Table 8 shows the unit cost components for replacement capacity - both baseload combined-cycle and peaking combustion turbine technologies. Incremental capacity unit costs are calculated for both assumed CMP portfolio capacity factors, 33 percent and 45 percent, and the 84 percent capacity factor used in the Homer City analysis. That is done to determine the least-cost alternative between new combined cycle and new combustion turbine capacity for incremental capacity additions. With these input assumptions, the combined-cycle stations have the lowest all-in costs, and therefore are assumed to provide a price cap on NEPOOL market prices across all three capacity factors.
Natural gas price assumptions in northern NEPOOL are taken from the Natural Gas Week 12-month strip for Henry Hub of $2.57 per million British thermal units plus our firm's northern NEPOOL basis differential of $0.38 per million British thermal units. The same combined-cycle heat rate as was used in the Homer City analysis, 6,900 Btu per kilowatt-hour, is used here. The combustion turbine peaker heat rate is assumed to be 9,700 Btu per kilowatt-hour. The resulting fuel costs are $20.36 and $28.62 per megawatt-hour for combined cycles and combustion turbines respectively.
Due to higher observed installed costs for new capacity in NEPOOL, combined-cycle installation is assumed to be 10 percent higher in the CMP analysis than in PJM for the Homer City analysis. Thus, combined-cycle stations are installed at $578 per kilowatt instead of the $525 per kilowatt cost assumed for PJM. Combustion turbine peakers cost $325 per kilowatt. All financing cost assumptions are identical to the Homer City analysis.
At a 33 percent capacity factor for the CMP portfolio, it might be expected that generating stations would at least capture the higher peak period prices. However, hydropower, a significant portion of this CMP portfolio, frequently is limited in its ability to "load follow" and may not be able to concentrate its generation time during the higher-demand, higher-price periods. This aspect is an important consideration because the all-in unit cost of incremental capacity, which establishes theoretical price caps, is $33.18 per megawatt-hour for baseload capacity factors (84 percent) and $48.12 per megawatt-hour for the CMP portfolio capacity factor (33 percent). However, even the $48.12 per megawatt-hour potential from the energy market is quite short of the $54.85 per megawatt-hour that would provide a modest 12 percent ROE for the CMP portfolio.
Clearly, a more in-depth analysis is needed to assess all of the market revenues available to the CMP portfolio. Additionally, a hydrological analysis to determine the ability of the hydro portion of the CMP portfolio to concentrate its output on peak demand periods where it could capture the higher market prices is necessary. In the absence of a more complete analysis of all of the factors that contribute to power plant value, it is not possible to conclude that the CMP portfolio will support FPL's acquisition cost.
Art Holland is project manager at Pace Global Energy Services. He can be reached at hollanda@paceglobal.com. Paul Meyers, Bo Poats and Xiang Kong contributed to this article.
Asset Divestiture: Bargain or Bust?
Some thoughts on the Fortnightly's recent feature.
The Sept. 1 feature article, "Generation Asset Divestiture: Steal of the Century?" by Richard Stavros (Public Utilities Fortnightly, p. 42) discusses some of the most important considerations regarding the prices paid to acquire generating assets. It examines regional vs. national portfolio strategies, unit operating costs, fuel mix and the market supply/demand balance. The article also touches on price volatility, but describes it as a risk variable that generators must "accept."
It is our view at Pace Global Energy Services that power plant owners should embrace price volatility, and endeavor to extract the full value that a power plant offers in a price-volatile environment. The potential for power price "spikes" enhances revenue and upside profit potential, key determinants of plant value.
Plan Strategically. The mistake many people make when assessing a power plant's value is not recognizing that effective operational and growth strategies increase market value. Power plant value is not static. Rather, plant value is tied to the owner's ability to use the asset in a way that maximizes and supports a 20-year-plus investment. To maximize value, generating companies will employ strategies that result in "best in class" status for a portfolio. These strategies include:
* Fuel management and procurement optimization,
* Operating excellence resulting in operations and maintenance synergies,
* Wholesale trading, and
* A regional presence that facilitates a market-maker rather than price-taker status. Don't Bank on Diversity. Several people quoted in the article by Stavros expressed the view that regional diversity is important because markets do not move in tandem. At Pace Global Energy Services, we hold the view that a dominant presence in one regional market is preferable to owning one small plant in several regional markets, as economies of scale may be achieved. Of course, a dominant presence in several markets is better still. Think Long and Short. Above all, valuation is a multi-tiered exercise. It must integrate supply and demand, encompassing the value that a plant has as both a power-producing machine and a hedging instrument. Our firm has developed such a multi-tiered approach. While a full presentation of the entire process is well beyond the scope of this publication, a simplified application of a single aspect of the approach can address the question, "Were the prices paid for recent power plant acquisitions too high?" - A.H.
1 This fuel cost assumption is also more consistent with the assumptions used in the confidential Offering Circular for the 144A Bond offering that financed Edison Mission's Homer City deal. 2 While this capital structure is consistent with recently financed transactions, the actual debt-equity ratio for the Homer City deal had a much higher proportion of equity capital.
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