What's That Power Plant Really Worth?


An analysis of current valuation trends explains why some assets command better values than most.

Fortnightly Magazine - January 2007

Average North America power-plant asset value is at $725/kW.1 Compared with our winter 2005-2006 analysis, this figure has barely changed; however, we have seen significant value movements based on region, fuel, and asset types. Important findings include:

Nuclear plant values have increased by almost 25 percent. Average nuclear value is now around $1,730/kW. This increase is primarily driven by higher energy costs across all fossil fuels.

Average coal-fired generation values have dropped more than 10 percent. Coal plants continue to enjoy healthy spark spreads because of higher gas prices in the short term; however, compared with our last valuation, average coal-fired generation values have dropped more than 10 percent. That is driven primarily by the significant amount of new coal generation activity, particularly in the Midwest and eastern WECC regions. Global Energy now expects more new coal-fired generation will be built in the long term. That suppresses the values of the existing coal plants in these regions.

Generators in load pockets such as New York and eastern PJM still are enjoying healthy cash flows. In New York City, a typical new gas-fired combined-cycle plant can be valued from $1,100/kW to $1,500/kW depending on the leverage of the investment.2

Capacity payments are a key component of recovering asset values in the Northeast and Mid-Atlantic regions. Projected revenues from capacity markets account for $188/kW in eastern PJM, over $450/kW in New York City, and around $216/kW for New England markets.

Despite all the confusion in the Western market about resource adequacy, we are projecting the WECC market getting into a larger overbuilt status. Particularly in California, without the support of a contract with a utility, the assets will have a hard time generating enough revenue from energy markets only. Obtaining a contract with a utility is a critical risk as there will be more resources competing for it.

The gas-fired generation values are slowly recovering in Southeast markets. Liquidity and transparency are still key issues in these markets and generally transmission access is the primary source of conflict between IPPs and utilities. Realizing the full option value of an asset in these markets is challenging.

Figure 1 summarizes the net present value (NPV) range of all the assets we have analyzed. Each bar represents the lowest and the highest NPVs we have calculated for a plant and fuel type.3 Some of the low or negative NPVs are driven by the must-run or cogeneration obligations of the plants. Because of these operational obligations, these units are not dispatched economically, but they are forced to stay on line at all times. In this analysis, we capture the operational characteristics, market revenues, and operating costs of these plants; however, the contract revenues are not included here.

Figure 2 illustrates the value of a 7,100 Btu/kWh heat rate combined-cycle plant across North America. As noted earlier, this valuation is made using a 15-percent real discount rate on expected merchant cash flows for a 20-year period. In general, the net values have recovered; however, they are still below the new build level in most areas.

Although Figure 2 summarizes the overall values, it does not necessarily give the whole picture in terms of where the value lies, or how much of it is driven by the extrinsic value and future recovery of the market. Figure 3 shows a generic combined-cycle plant’s net revenue projections in the Entergy market. As illustrated, a significant portion of the value lies in the future years. Early year cash flows are driven by the extrinsic value of the plant, which may be hard to realize in these less transparent markets.

The discount rate used in the valuations is a critical factor. Figure 4 illustrates how average asset NPVs vary between the 10 percent and 15 percent real discount rates. Using the appropriate discount rate is particularly important in evaluating mergers and acquisitions, because any management bias on risk perception can affect the transaction and the overall company risk profile. The bottom line: The discount rate captures the risk perception in cash flows. Throughout this article, we generally use a 15 percent real discount rate to present our results.

Industry Players Have Been Evolving

During the down cycle, the industry’s liquidity gap was filled by financial players such as hedge funds, private-equity investors, and other key Wall Street investment banks. These entities traded distressed project debt, founded energy infrastructure investment companies or funds to acquire distressed portfolios, and looked for other various opportunities. Some of these early entrants capitalized on the low market sentiment in the middle of the bust cycle and captured the low-hanging fruit. During the fire-sale period, companies such as KKR-led consortium-acquired Texas Genco assets, Goldman Sachs acquired several NEGT assets through Cogentrix, and Mattlin Paterson’s KGen Partners acquired Duke’s Southeast assets.

The reasons for the sell off are many. Some of these assets are not expected to generate significant cash flow for some time to come. And, in many cases, the original owners did not have the time to await market recovery. At the time, the best option appeared to be a write-off of these investments and the pursuit of a back-to-basics strategy. These entities divested some, or all, of their merchant assets at discounted prices, which probably was fair value at the time.

In some regions the market recovery, driven by high natural-gas prices, came faster than expected. As some of these pioneer financial players see the return on their investment, we expect them gradually to cash out, as recently happened when Texas Genco was sold to NRG. However, other new players just now are coming into the acquisition and development market with serious capital. Some of these companies, such as U.S. Power Gen, Waypoint, and Complete Energy, are comparably new and are backed by private-equity investors. Others, such as LS Power4 and CPV, are not new, but are in a new growth pattern of actively pursuing acquisition targets and new development projects.

Additionally, there is a growing interest in U.S. energy assets from foreign investors in Japan, the UK, Australia, and other countries. Despite all the turmoil and uncertainty in our energy industry, the United States is still a stable, transparent, and business-friendly environment for foreign capital. These investors, such as JPower5 and Diamond Generating, are looking for investment opportunities in the United States. Others, such as Macquarie, have a more diversified investment strategy and a broader objective—U.S. infrastructure investment.

M&A Activity

As the industry recovers from the bust cycle, we are seeing a significant number of asset sales, new generation proposals, and merger and acquisitions (M&A). Despite the failed Exelon-PSEG and FPL-Constellation mergers, we expect the level of M&A activity to stay high, with more assets changing hands as the markets recover. Figure 5 summarizes the asset transaction amounts since 2004. The “Unregulated/Diversified” category consists of unregulated generation assets of major utilities and independent power producers.

Asset sales by financial and private-equity groups have been rising. Clearly, some of these players are cashing in on the investments they made during the buyers-market bust cycle. In the future, we expect to see more of this group’s assets coming to market. In fact, we expect that many of these assets will be flipped several times as different potential owners pursue various portfolios with different perceived value streams.

Assets also are changing hands as some newly formed investment companies develop their asset portfolios, while other players divest non-core assets and reshape their holdings. Two players in particular, Mirant and Calpine, are working hard to emerge from bankruptcy with “the right stuff.”

The story in the Southeast region is a bit different. The liquidity in this market is still low, and there are several assets still owned by banks or other debt holders. Several banks and debt holders have set up operating companies to manage their assets until the market is more liquid or until they can adequately recover some or all of their debt. However, a significant amount of debt has been traded since the bottom of the bust cycle, and several banks have cleaned up their portfolios or limited their exposure. Because there still are significant risks in this region, potential buyers are emerging just now.

The other major problem with Southeastern transactions is the issue of market power. For example, when Entergy tried to acquire the Perryville plant, located within its territory, the deal generated controversy over Entergy’s perceived market power.

Today’s energy investors clearly understand the need for economies of scale and adequate diversification of their portfolios. Good examples of this are the recently announced LS Power/Dynegy merchant generation joint venture and NRG’s acquisition of Texas Genco. Today, with the uncertainty of fuel prices and regulatory pronouncements, a larger portfolio with both fuel and geographical diversification may be the best way to obtain more extrinsic value from generation assets.

The Same Mistakes?

The next-generation build cycle, which we are now entering, includes significant liquidity flowing into energy infrastructure. Before we jump in with both feet, however, it may be instructive to look back so as not to repeat the mistakes of the past.

One of the key problems of the last boom-and-bust cycle was the way merchant developers and their bankers were incented financially to make the deal, close it, and then get the merchant plant operational on time and within budget. This was true for both greenfield development and acquisitions. Additional pressure was created as both U.S. and international banks competed to finance merchant projects. Neither the developers nor the bankers adequately assessed the bigger, regional perspectives or the overall risk.

As overbuilding became obvious in some regions, many developers did not want to discard their projects. The general feeling was that as competition spread, older, less efficient units would be retired and the newer, more efficient units would take their place.

One of the key differences in today’s market is that many new investors are, or are backed by, sophisticated risk experts from the financial industry. Instead of being incented just to get the deal done, these players must get the deal done and ensure that the deal has real future value. These investors aim to capture good opportunities, rather than build long-term infrastructure portfolios. They want to buy low and sell high and then move on to the next opportunity. These investors always consider risk, resale value, and the likely number of buyers that will bid for their assets in the future.

Another key trend is that more robust hedging mechanisms are being implemented in the acquisition financings. Financial players such as Goldman Sachs, Merrill Lynch, and JP Morgan are setting up complex derivative structures to hedge future cash-flow risk. Hedges reduce the risk involved in these deals and improve the liquidity by attracting more lenders and lowering debt rates.

As the number of buyers in the market is increasing, the race to get the best deals is heating up. Good opportunities are becoming increasingly difficult to find. Neophyte players may be too eager to invest quickly, rather than waiting for their very best option. If underlying risks and cash flow are not properly assessed, these buyers could get stuck with overpriced, non-performing assets.

Why Is Asset Market Activity Increasing?

Lately, we have seen significant market activity, particularly in the Northeast and Midwest regions. While some risk still is present, market conditions in these regions are improving.

In New England, the forward capacity market settlement, which was just approved by FERC, sets the capacity price at $3.05/kW-month to $4.10/kw-month range from years 2007 through 2010 for all of New England. After year 2010 there are floor and cap mechanisms for the first three successful forward capacity auctions to keep the prices in $4.10/kW-mn-$10.50/kW-mn range. Figure 6 illustrates the historical and forecast New England capacity prices. Compared with the past, the new rules give a significant boost to distressed assets by giving cash-flow certainty for several years.

Similarly, PJM is seeking approval for a forward-based locational capacity market called the Reliability Pricing Model. One key difference from the New England model is that PJM wants to use a downward sloping demand curve similar to the New York capacity market, where excess capacity has value. Figure 7 shows a generic gas turbine (GT) net revenue projection in eastern PJM including capacity revenue based on the Reliability Pricing Model. The intrinsic value of a GT is fairly low, and the major value lies in the extrinsic value and capacity payments. Considering that PJM’s control area level reserve margin is about 25 percent for 2006, this new model should supply some cash flow support for critical markets, such as eastern PJM and ComEd, when it is implemented in 2008.

Current market activity has been stimulated by decreasing reserve margins, some retirement and mothballing decisions, and the perception that future plant cash flows will increase. Sellers are trying to capture the market’s perception that extrinsic plant values are increasing. Buyers are trying to get into the market before all players embrace these trends.

Recently, we have seen single assets and several small and mid-sized portfolios on the auction block. Northeast Utilities’ Select Energy finalized the sale of its New England portfolio just after FERC approved the forward capacity market settlement. The sales process for Lake Road, a natural-gas-fired combined-cycle (CC) plant in New England, and Liberty, a natural-gas-fired CC plant in eastern PJM, has just begun. Calpine has indicated it is considering selling all of its assets outside of its core market, and New England is one such area.

The acquisition of Calpine’s Dighton asset by BG is, at press time, going through the bankruptcy court approval process. And, the sale of Calpine’s Westbrook asset, a natural gas-fired CC plant in New England, has been considered. Lowell Power (owned by Delta Power), B.L. England (owned by Atlantic City Electric Co.), and Benton Falls (owned by BayCorp Holdings) are a few other assets which appear to be on the auction block.



1. Unless otherwise noted, Power Generation BlueBook asset values have been calculated as the NPV of the unleveraged EBITDA-level expected stochastic merchant cash flows for 20 years, using a 15 percent real discount rate. This applies to all assets, even those insulated from merchant risk due to ownership by vertically integrated electric utilities.

2. NPV range is calculated with 10 percent and 15 percent real discount rates.

3. We have pointed out the median value, instead of the mean in the graph, because the mean value of NPVs can be calculated in two different ways: 1) the simple average; 2) the capacity (MW) weighted average. The first method biases the mean toward the smaller sized units’ NPVs, while the second biases it toward the large units’ NPVs.

4. As we compiled this article, LS Power and Dynegy announced their agreement on combining their portfolios.

5. Source: JPower April 6, 2006, news release on Tenaska plant acquisition.