As the credit problems spread from sub-prime mortgage failures, financial investors have become more risk averse. This has caused a broader concern about credit quality and fears of loss of credit liquidity, hurting project financing which buyout firms rely on to fund their transactions. Banks are said to have a $300 billion backlog of deals. The list of hedge-fund casualties is growing. Highly leveraged funds also got into trouble as risk-averse investors sell off their investment positions indiscriminately.
Lenders know there are billions of dollars of weak financial assets in the market, such as securities backed by bad mortgages. The problem is no one knows who is exposed at what level to those weak financial assets. This causes a lack of confidence in the lending industry, and a credit crunch that — if unabated — could cause a recession.
As several recent plant auctions have been postponed or cancelled, investment banks have pulled back their stapled-financing packages, or “staples,” used by sellers’ banks to attract private-equity bidders. This seller-financing is called “stapled” because it is often physically stapled to offering documents. Staples have long been touted as a way to provide a floor price for potential buyers, in the absence of other financing sources.
The backlog of pending private-equity financings is growing, and in a volatile credit market, investment banks have retreated from offers to finance other deals in process because of larger problems in the market. Wall Street has committed to funding some $225 billion or more of pending leveraged buyouts (LBO), which means the banks will need to provide the debt if other debt investors are too concerned to share the financing for these deals. Faced with the possibility of having to use their own money to finance a big portion of those deals, the banks are turning down any new commitments.
During the energy markets’ recovery in recent years, private equity and hedge funds have supplied desperately needed liquidity for the industry. A significant amount of generating capacity has been bought by financial investors and private equity funds during the 2003-2005 time frame (see Figure 1, “Changing Buyer and Seller Profiles”). But now, the tide has turned back, and these players began selling out in 2006 to lock in high returns.
Is the party over? Financial alchemy has allowed private-equity firms to attract a whole new base of investors including pension funds and insurance companies that never would have bought risky loans before. As private equity firms bid up the prices for ever larger LBOs, the transactions began getting riskier. The KKR and Texas Pacific Group’s $32 billion acquisition of TXU so far has been the peak for the energy industry. The underlying opportunity for investors resulting from strong fundamentals eventually will calm the markets and propel investors forward in search of profits, value creation, and competitive advantage.
The United States is a good place to invest in an uncertain world. It’s the largest economy in the world, and still growing at a respectable pace. Despite relatively steady load growth, fuel demand for power generation largely is consuming the reduction in industrial load as energy-intensive industries move offshore looking for lower costs — not just for energy, but also for labor and materials. As a result, the average energy intensity of U.S. households has been increasing, although it’s already one of the highest among developed countries. Since the 1970s, the average home in the United States has doubled in size. As old inefficient appliances vanished, energy usage did not decrease but increased with the new electronic gadgets, such as plasma TVs and other electrical devices. The United States needs vast amounts of infrastructure investment, particularly in transmission and generation businesses.
The key problem for the U.S. energy market is uncertainty about how to meet its growing energy needs. The last merchant-boom market was dominated by gas-fired, combined-cycle power generation assets. Now there are concerns about fuel diversity as well as reductions in greenhouse gas (GHG) emissions. The long lead times, added technology and regulatory risk and the expected cost of new climate-friendly power plants — most notably nuclear and coal-gasification facilities with carbon sequestering — make it extremely critical for the energy industry and investors to understand how deep and how long any credit crisis is going to last.
As we enter the next build cycle, debt markets will play a crucial role in facilitating the new energy projects. Stricter financing terms, lower leverage and higher debt rates are all possible outcomes of the crisis. These factors very likely will delay financing of several new projects, as well as merger and acquisition deals, while others will proceed with higher debt costs. Senior executives likely will put deals on hold for a few months to see if the markets stabilize and show signs of recovery. If the problem persists longer, this could substantially alter the financial structure and timing of many deals in the pipeline today. Significant delays in particularly resource tight regions would lay the groundwork for the next boom cycle.
Global Energy’s Power Generation BlueBook asset advisor analysis found the average North America asset value has increased by 6 percent to $773/kW.1 Value has moved significantly in some regions, and for some fuel and asset types.
• ERCOT stands out from the rest with low reserve margins. Several mothballings and retirements, along with higher than expected demand growth over the last few years, have caused reserve margins to drop to critical levels. Despite the lack of any support from a structured capacity market, projections show robust cash flows for coming years in this market. In addition to projects now under construction and some restarting mothballed stations, this market needs new capacity as early as 2008.
But although combined-cycle plants might expect significant energy revenues, they are still not high enough to support a full recovery until the 2011-12 time frame. Therefore near-term capacity needs of the market likely will be met by projects with some contracted revenue support. Not every location in ERCOT, however, shows the same revenue potential. Local differences will be more prominent as this market moves to locational-marginal pricing (LMP). ERCOT will be the test ground to see if the industry learned the lessons of the last overbuild cycle.
• New York also needs new generation. However, most of the need is in the Eastern region, particularly in New York City and Long Island. New transmission projects into Long Island and New York City will alleviate some of the near-term resource needs, but the problem is not completely solved. Additional resources or more transmission projects will be needed in the near term.
• In New England, transition-period capacity payments have boosted cash flows for generating assets and brought market stability. This is another market where reserve margins are decreasing fast with high load growth and aging fleet retirements. Location is key in New England as some areas such as Southwest Connecticut and Boston are relying heavily on imported energy from other areas. Major transmission investments now underway are targeting these locations, however. This creates an economic uncertainty for new generation projects, because the economic impacts of these projects are not clear yet. Finally, the Regional Greenhouse Gas Initiative (RGGI) has been creating another complexity threatening the economic viability of some of the old coal units.
• PJM reserve margins are eroding fast. Although there are excess reserves in the West PJM (ComEd, AEP, APS), Virginia Power and East PJM reserves are critically low. The coal-powered generation in the region is enjoying a healthy spark spread with the support of high natural-gas prices. On the other hand, energy revenues for gas-fired generation have been mediocre at best. Despite tightening reserve margins, this trend likely will hold for at least a few more years.
The key to value is an asset’s location in PJM. Auctions held recently in the forward capacity market returned higher-than-expected capacity clearing prices for Eastern PJM. This is a significant boost for assets located in this area. The result of these auctions is another indication of tightening reserve margins in some PJM sub regions.
• Western power markets as a whole are projected to be overbuilt for several years. Compared to our summer 2006 projections, the average asset value in the WECC region has decreased by 10 percent to $548 /kW.2 The merchant cash flows for gas-fired generation in WECC likely will be problematic for several years. More efficient units are benefiting from the better spark spreads associated with higher gas prices. However, lower expected gas prices in the years ahead pose a major risk for these generators. WECC markets have not hit the bottom yet. Despite all the confusion in the Western market about resource adequacy, the WECC market will become more overbuilt than before. 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 to justify MW construction costs. We project a California combined-cycle unit’s expected net-merchant revenues will stay below $40/kW each year for the next five years. Obtaining a contract with a utility is a critical risk as there will be more resources competing for such contracts.
• Southeast markets are recovering with strong load growth but full recovery is still years away. There are some tight markets such as Florida, Virginia-Carolinas, and Oklahoma-Kansas, where new resources will be needed in the near future. Nearby, the Entergy, Southern and TVA markets are still in a slow, painful recovery phase. These overbuilt markets partially suppress energy prices in the adjacent tighter markets, making investment there in new merchant facilities uneconomic.
Compared to last year’s analysis, the average U.S. generating-asset value has changed by only 6 percent in nominal terms. However there are stark changes in valuations for different plant categories based on fuel or technology.
Coal-fired generation values have increased by as much as 30 percent. This is primarily driven by higher fuel prices. In particular, long-term natural-gas price projections are much higher due to international competition. On the other hand, expected future CO2 regulation suppresses this increase moderately. The base CO2 price projection starts with $2/metric ton for CO2 in 2012 and escalates by $1/mton per year, and is capped at $15/mton. However there are several different proposals for GHG-emission regulation and the final market design and pricing is unclear. Despite the fact coal plants have been enjoying healthy spark spreads due to higher gas prices, uncertainty around GHG regulation poses a major risk factor for future cash flows.
This uncertainty, coupled with increased construction costs for coal plants, has driven several project delays and cancellations. As developers and state commissions have had second thoughts about new coal projects, almost 40,000 MW have been either put on hold or cancelled within the last two years. But the installed coal-fired base largely will remain.
Amid these market trends, nuclear plant values on average have decreased by almost 20 percent. The average value for an existing nuclear plant now is around $1,400/kW. Higher energy costs across all fossil fuels and future CO2 regulation are improving the outlook for nuclear generation, but the increasing cost of uranium more than cancels these gains, decreasing overall plant values.
In recent months, uranium spot prices have been significantly higher than historical levels. In Global Energy’s projections, the average spot price of uranium will increase from $1.21/MMBtu in 2008 to $2.25/MMBtu in 2011. Then it will gradually decrease to the $1.30/MMBtu range by 2017 and continue decreasing by 1.5 percent per year after that.3
Because all nuclear plants have long-term fuel-supply contracts, recent uranium price spikes have not been reflected in actual cash flows. As these contracts are extended or renegotiated, long-term financial impacts of higher fuel costs will become clearer.
For combined-cycle plants, based solely on the intrinsic revenue projections, most of the Western markets do not show any return on equity at all (see Figure 2, “Generic Combined-Cycle Plant NPV Analysis”). Furthermore such markets as Entergy, TVA, MRO, and SPP provide lackluster returns and the initial years’ debt-coverage ratios for these markets are below 1-times earnings. Comparing these returns to a standard 16 percent ROE threshold, very few markets can fully support new combined-cycle entry. This indicates new gas-fired combined-cycle generation projects either must be supported with some long-term capacity payments or a different capital structure to justify the investment.
Generic combined-cycle net-present value (NPV) results don’t necessarily give the whole picture for some regions such as SPP, Entergy and TVA. While a generic combined-cycle plant shows a reasonable NPV for these regions (ranging from about $500/kW intrinsic and extrinsic value), most of the cash flows occur in future years, assuming a healthy recovery in these markets. A generic combined-cycle plant in the Entergy market, for example, likely produces investment-level merchant revenues for at least 10 years (see Figure 3, “Generic Combined-Cycle Annual Projection”).
In regions with structured capacity markets, generating assets’ values are strongly supported by installed-capacity (ICAP) payments (see Figure 4, “Generic Combined-Cycle Net Present Value”). Particularly in markets such as New England and East PJM, energy revenues are expected to comprise only half a plant’s total value. Comparing these to the likes of ERCOT, these markets seem to be evolving toward a two-part market with lower energy revenues and strong capacity revenues. On the other hand, a merchant generator in ERCOT can receive compensatory value from the energy market alone.
Finally, the intrinsic value of western markets is extremely low compared to other regions. This indicates that under normal hydro and weather conditions, merchant cash flows in these markets will be quite suppressed due to high reserve margins. However, high volatility driven by hydro conditions, weather patterns and transmission issues create some revenue potential presented as extrinsic value.
The next build cycle is already underway in several markets. However location and timing are critical. Asset investors should pay attention to the fundamentals and focus on location factors that can have major impacts on unit profitability.
The markets clearly anticipate new GHG-emission regulations, but there is major uncertainty about impacts and both significant risk and potential for newer power-generation technologies. Future GHG regulation is a key risk factor for the next decade. Such strategies as hedging positions and diversifying portfolios, both technologically and geographically, are more critical than ever. Building the optimal portfolio in line with corporate risk tolerance is a key challenge.
As clean-coal technologies compete with new nuclear technologies for the base-load future of power generation, higher construction costs and regulatory risks will continue to cause project cancellations. New base-load generation resources are needed to replace aging generation fleets, but there are significant uncertainties for different technologies and generation fuels. Natural gas-fired combined-cycle generation, often underutilized, is waiting to pick up the pieces and could end up being either a spoiler or surprise winner in the race for market share.
Investors shouldn’t forget: The boom-bust cycle is alive and well in the power-generation sector. Signposts will provide clues to trends beyond the forecast. Some of these trends are driven by changing key fundamentals, such as tightening reserves, while others are driven by volatile fuel prices. Analysis of historical asset transactions shows a significant correlation between asset-sales prices and natural-gas prices. Considering that gas prices have been highly volatile, it is crucial to hedge one’s position during these transactions.
The impact of the near-term credit crisis likely will be limited to a slightly higher cost of debt and reduced leverage. Globally, there is an amazing amount of capital looking to be invested, and North American power generation is regarded as a relatively safe investment for most portfolios.
1. Unless otherwise noted, asset values have been calculated as the net present value of the un-leveraged EBITDA-level expected stochastic merchant cash flows for 20 years, using a 12.5% percent real discount rate. This applies to all assets, even those insulated from merchant risk due to PPS’s or ownership by vertically integrated electric utilities.
2. Comparison is performed using Summer 2006 and Summer 2007 Power Generation Bluebook analyses with the same methodology. These are in nominal dollars; the change also includes 2006 to 2007 inflation.
3. In 2007 real dollars and at real escalation rate. These projections are much higher than previous projections which were around $1/MMBtu for the forecast period.