During the last few years, the generating asset-ownership structure in North America has gone through a major change. The recent boom-and-bust cycle has created a different generating plant asset-ownership landscape. During one of the most severe bust cycles of the industry, and the gradual recovery of the markets, significant amounts of assets have changed hands. Between 2002 and 2006, about 144 GW of generating assets have been sold. Average asset value for these transactions was at $441/kw.1
We saw significant activity in this area during the first quarter of 2007, and the general expectation in the industry is the remainder of 2007 will be busy, too. We expect more activity during the second half of the year.
Figure 1 shows the number of transaction deals we have seen between 2002 and 2006. The deal count peaked in 2004, with 60 counted deals based on the closing dates. This peak was driven mostly by the energy companies selling their assets as they struggled to improve their balance sheets.
During this period there were several project-financed assets that defaulted. Because the markets were not robust enough, most of the lenders have set up companies to operate the assets until the markets allow them to recover their debt. Although we do not count these cases as deals, this was a major development in terms of ownership structure.
Figs. 2 and 3 tell us the story about who is involved in these transactions. As we went through the bust cycle, the majority of the sellers were unregulated/diversified companies, developers, and independent power producers (IPPs). On the other side of the table were the private equity and financial investors grabbing a major chunk of distressed assets from 2003 through 2005 (see Figure 2). Some of these opportunistic buyers and banks have started offloading these assets in 2005 and 2006 (see Figure 3). Financial players have sold about 17 percent of the assets transacted between 2002 and 2006.
For diversified energy companies on the sell side, such as Aquila, El Paso, TECO Energy, Duke Energy, and Allegheny Energy, their transactions represent a strategic shift away from the unregulated power business. In many cases this was, by necessity, a “back-to-basics” tactical move. About 55 percent of the plants sold during the past five years came from the non-regulated merchant affiliates of investor-owned utilities (IOUs) whose assets lost significant value with the increasing uncertainty in the trading business. Next came the IPPs, which sold about 20 percent of the assets transacted between 2002 and 2006. Some IPPs like Calpine and Mirant experienced bankruptcy, while others, such as Dynegy and NRG, embraced leaner, more focused business models. New players also have entered the industry.
As the pioneer financial players see the return on their investment, we expect some of them to continue to cash out, in a fashion similar to the Texas Genco sale to NRG.
The asset-transaction fuel mix has been dominated by natural-gas and mixed portfolios, which are responsible for 48 percent and 36 percent, respectively, of the sold assets (see Figure 4). During the down cycle, gas-fired merchant assets particularly were troubled. In some overbuilt markets, peaking facilities had little value left. As the owners of these troubled assets have brought them to market they also have bundled them with more valuable base-load or contracted assets. Most of these mixed portfolios also have been diversified geographically to attract more buyers.
The annual average transaction values have varied significantly by portfolio type and year. In many regions the market recovery, driven by high natural gas prices and robust load growth, came faster than expected. Recent transactions have valued mixed portfolio and base load capacity more favorably as shown in Figure 5. The average prices for coal and mixed portfolio transactions have almost doubled since 2003. As we look at the figures closely, we see an emerging upward trend in the transaction values. Across all portfolio types, the average transaction value has increased from $340/kW in 2004 to $580/kW in 2006.
Last year was a major step toward a more stable long-term asset-ownership structure in the industry. We see several companies such as NRG, Dynegy/ LSPower, FPL Energy, and BG stepping in for a longer-term asset ownership. The newcomers to the asset owners are building their asset-trading operations and gearing toward a structure where they make money by not buying and selling, but effectively operating these assets and collecting the cash flows. However, the impact of financial players has not subsided yet. Energy Capital Partners, Carlyle/Riverstone, Wayzata Investment, GSO Capital, and Rockland Capital are a few of the players who were on the buyer side in 2006.
Traditional market participants, including utilities and IPPs, have become reluctant to own merchant facilities in deregulated markets where the overbuild of new entrants has weakened market prices. As a result, distressed assets continue to change hands while market prices strengthen and the next wave of new entrants is being developed.
As we update the valuation of generation units every six months, we look at emerging trends. Figure 6 shows the merchant valuation of generic combined-cycle plants across North America markets. The NPV calculations are based on 20-year merchant unleveraged cash flows.
With support of structured installed capacity (ICAP) markets, the Northeast plants show highest valuation. On the other hand, the Western Electricity Coordinating Council (WECC) merchant valuations have been depressed significantly. Despite some opposite views in the market, WECC has been significantly overbuilt and the merchant generators in these markets may observe depressed cash flows in coming years.
Northeast and ERCOT markets have seen signs of recovery with healthier spark spreads and new development activity. On the other hand, some overbuilt regions such as the Southeast is yet to recover fully from high reserve margins. As the markets recover we expect to see more activity in these regions.
In December 2005, FERC issued its final rule in compliance with the electric company merger and acquisition (M&A) stipulation of The Energy Policy Act of 2005, with the objective of protecting against generation market power while encouraging the required investment in transmission and generation.
The final rule relieves several restrictions on mergers and acquisitions, including the requirement for utilities to be physically interconnected, operate within a single region, or limit their activities to utility related businesses. The rule also grants blanket authorizations to some transaction categories, including holding-company acquisitions of foreign utilities, intra-holding-company system financing and cash arrangements, certain internal reorganizations, and certain holding company acquisitions. The new rule was expected to support and strengthen the already instigated industry consolidation.2 Table 1 lists the mergers and acquisitions announced since late 2004, and their status.
Some of these announced deals have been consummated successfully while others have been abandoned due to the lack of regulatory support. If completed, some of the proposed mergers would create mega utilities spanning wide geographic areas across divergent regulatory and competitive landscapes.
As in the case of single-asset or asset-portfolio acquisition, M&A activity in the United States is attracting foreign capital. Examples include Australia’s Babcock & Brown, which acquired South Dakota’s NorthWestern; the purchase of KeySpan by U.K.-based National Grid; and Canada’s Gaz Métro’s subsidiary purchase of Green Mountain Power.
Despite M&A activity, deal values in 2006 actually dropped by 64 percent from 2005 levels. This is in contrast to the 52 percent hike in M&A deal values in worldwide deals, according to Price Waterhouse Coopers.
The repeal of the Public Utility Holding Company Act under the M&A final rule may have motivated state regulators to impose even stricter requirements, but state opposition has demolished two mega-merger agreements during 2006—PSEG/Exelon and FPL/Constellation. Such regulatory uncertainty might be holding back future merger plans. At the same time, energy company earnings during 2006 were far beyond what would be expected from organic growth. As such, the North American electric-power sector remains highly fragmented, with much consolidation potential.
1. Sale price estimates are based on available data that covered only about 134 GW of the transacted capacity. Transaction data excludes electric utility mergers.
2. FERC made certain revisions in April 2006 and July 2006 to the final rule, updating merger review policies in response to comments made by interested parties and providing clarifications to specific issues.