Asset values, and the value of their associated debt instruments, are being driven in the short term by an extreme fuel market and in the long term by a back-to-basics mindset among electric utilities. Still, asset valuations in most markets are not yet at replacement costs, leaving current investors with a residual level of risk. A perception that power markets are recovering more quickly than expected may be fueling high expectations, but volatile gas and oil prices are creating excitement and anxiety throughout the industry. For some time to come, the only certainty in this market will be change.
The past year has allowed the North American power sector to continue its recovery, but it has been a treacherous time for investing. After sifting through all the recent market developments, the following issues stand out:
For the past three years, Global Energy has produced the Power Generation BlueBook to track changes in power plant asset valuation across the markets. We update this analysis every six months following the release of our Power Market Advisory Service regional forecast. In our recent analysis, we found that over the last six months, natural gas-fired combined-cycle (CC) asset values are up 10 percent from our last forecast, deriving their value increase from forecasted higher gas prices.
Figure 1 indicates the range of values for a standardized combined-cycle asset across the North American markets.
While limited in number, actual sales of merchant assets continue to validate the Power Generation BlueBook analysis, with discount rates using our cash flow estimates and actual sale prices falling in the wide range of 9 to 20 percent. Based on a real 15 percent discount rate, Global Energy is of the opinion that the average value of a “generic” CC plant in North America is $405/kW, with a range of $325/kW to $714/kW.1
However, the overall asset value for the total power generation fleet across North America is down 5 percent from 6 months ago in Global Energy's forecast, driven primarily by the long-term market view that more new coal-fired generation will enter the market in response to sustained higher gas prices. We forecast that once power prices revert to an equilibrium level, there will be a slightly lower valuation level than previously forecasted. However, the value change varies by region, plant technology, and fuel type.
For existing CC plants in North America, the average is $379/kW2—approximately 60 percent of a new build cost (based on an average new build cost of $629/kW). The low initial-year values and differing rates of recovery result in significant variation in CC plants across the regions, ranging from $85/kW to $760/kW.3
Figure 1 also shows that Entergy and the Southeast no longer remain the most depressed regions. The significant number of new merchant combined-cycle plants being completed in the WECC brought many Western markets into a value position similar to Entergy.4
New York City, Florida, portions of New England, Colorado, and ERCOT are relatively stronger merchant energy markets. Depending on the market, this may be driven by some combination of these markets having predominantly gas plants on the margin, thus setting market prices, or near-term supply being more in balance with near-term demand. Besides this, in the Northeast markets, capacity revenues, which are not included here due to their speculative nature, can also be a major source of revenue for the distressed assets.
The overall average value of coal assets across North America is $804/kW compared to a potential new build cost of approximately $1,200/kW for a pulverized coal plant. However, given that the majority of existing coal plants are between 20 and 50 years old, this may well be higher than existing book values in many cases. While coal assets have not been immune from the overbuild situation, over the past several years they have seen an increase in value from the run-up in gas prices relative to delivered coal prices.
The simple two-part answer is: resource planning and timing. As part of their resource planning process, a number of utilities (investor-owned and public power) see additional resource requirements in the medium term. Coal looks like a more cost-effective solution than gas in many areas. And even though some coal prices have experienced volatility in the past two years, coal prices overall are viewed as being less volatile than gas prices. The timing issue is a simple artifact of calculating net present values; the coal plants often are scheduled to begin operation five or more years in the future, and their merchant value is appropriately looked at as an NPV in the on-line year, removing the under-performing early merchant years and using a lower discounting factor for the balance of the investment period.
As long as current gas prices remain well above the $4/MMBtu level, there will be continued interest in using coal assets rather than gas assets to meet new base-load demand. For many, this will simply be seen as the return to normality. However, there is a downside risk for a coal investment; if the gas prices drop unexpectedly, the value of coal assets can go down significantly. Figure 2 shows how the NPV of a coal unit changes with gas price change at the Henry Hub. While the base case merchant value of coal is in a $750/kW (deterministic) to $820/kW (stochastic) range, the value can drop to a $610/kW to $630/kW range if the gas prices decrease by $1.50. Although a coal investment can be a good hedge against gas price increases it also brings a downside risk (see Figure 2).
After the failure of merchant generation, and several bankruptcies, energy markets finally are regaining the confidence of investors. In the last two years, merchant generators have made considerable progress by paying off debt, refinancing, addressing legacy issues, and divesting non-core or non-performing assets. Other energy companies are rethinking their overall strategy and divesting some non-core businesses they acquired in the 1990s. As independent power producers demonstrate the ability to improve performance in the face of the currently depressed markets, investors are warming up to the U.S. energy market again.
Several energy companies have refinanced their debt with more attractive rates compared with a year ago. KGen Partners recently refinanced its acquisition of Duke Southeast assets at much lower rates, even though it had been only seven months since the first financing. Calpine, NRG, and Astoria Energy LLC are some of the others who took advantage of refinancing opportunities.
However, uncertainty remains in the industry. Many believe the worst is over, and view lower interest rates as another sign of this belief. Others view the lower interest-rate environment as a sign of increased demand for the limited amount of power-sector debt available, and are concerned that the market has become overly optimistic.
In the past two years, generation power-plant sales have picked up and continue at a healthy pace, with almost 70 announced transactions of more than 50 GW of capacity. This represents just under $16 billion in total value (cash and debt assumed). However, the buyers and sellers are changing.
Financial players, including private equity groups and investment banks, dominate the buy side, purchasing more than 60 percent of the total capacity sold and representing more than 50 percent of the total value of the capacity purchased. Figure 3 shows that while unregulated energy companies have been trying to clean their portfolios of non-performing assets, private equity companies and other financial players—such as hedge funds—are opportunistically grabbing the undervalued assets and portfolios.
For a number of diversified energy companies on the sell side, such as Aquila, El Paso, TECO Energy, and Allegheny Energy, their assets represent a strategic shift away from the unregulated power business. In many cases this was a "back-to-basics" tactical move.
The other trend in the recent asset transactions is that most asset transactions were in the form of larger portfolios instead of single assets. Figure 4 shows that 56 percent of the total capacity transacted was in larger portfolios. In some cases sellers found it more efficient to bundle the assets because some of the assets have very low values, and it is difficult to find buyers for them.
On the buyer side, bundled portfolios have better values because one can get some discounting due to bundling. In the KGen acquisition of Duke Southeast assets, the peakers in the portfolio were credited practically no value. KGen has considered dismantling and selling the peaking equipment to Middle Eastern and Korean markets.
The vast majority of the financial players are private equity groups including ArcLight Capital Partners, Kohlberg Kravis Roberts, MatlinPatterson, AIG, and Complete Energy. In the largest transaction, four private-equity firms—KKR, Texas Pacific Group, Blackstone, and Hellman & Friedman—joined to purchase Texas Genco's 16,400 MW of assets. In another deal, the private equity firm, Carlyle/Riverstone, teamed with Sempra Energy to buy a collection of AEP's plants in Texas.
Diversified energy companies—those entities with both regulated and unregulated subsidiaries—and regulated utilities (including munis and co-ops) were distant second and third buyers by megawatt capacity and total dollar value.
Another fundamental change in the industry is the entry of hedge funds particularly on the secondary debt market. Although not shown in the asset buyer's column yet, hedge funds likely will make an appearance soon. Seventy-five to 330 hedge funds are estimated to be active in the energy commodities market, and that number is expected to rise. Hedge funds in general are said to have under-performed last year, with average returns of 8 percent; on the other hand, the funds focusing on energy investments have been enjoying returns of 40 to 60 percent. Even if the returns drop to more modest levels (e.g., 15 percent), the energy market will still be more attractive than other areas.