Behind-the-meter energy threatens the utility business model. Does history offer a lesson for crafting a response?
Banking on the Big Build
The need for many hundreds of billions of dollars in capital expenditures creates huge opportunities and challenges, especially in a more challenging credit environment.
TXU’s experience trying to build a fleet of pulverized coal plants suggests that, as a practical matter, it will be difficult for other developers of conventional coal-fired plants to follow. And there was in any event widespread skepticism regarding TXU’s cost estimates of $1,100/kW. By comparison, Duke’s projected costs for its Cliffside coal-fired project in North Carolina increased from $1,250/kW in May 2005 (based on a 2-unit plant) to $2,288/kW in March 2007 (based on a 1-unit plant, including interest).
This leaves combined-cycle gas turbines, with capital costs of around $800/kW to $900/kW, looking increasingly attractive from a capital cost standpoint, though total generating costs will be highly dependent on volatile natural-gas prices. And in common with other technologies, construction costs for combined-cycle gas turbines (CCGTs) may come under further pressure from increased steel, cement copper, and other commodity prices, a weak dollar, and a shortage of skilled labor.
The story is similar with transmission and distribution, although the numbers are even larger. Southern California Edison has estimated that its rate base will almost double in 5 years, increasing from $10.9 billion in 2006 to $20.4 billion in 2011, with over 75 percent of total projected spending on T&D. The industry as a whole has been through an extended period of underinvestment, influenced in part by rate freezes. In the May 2007 issue of Public Utilities Fortnightly (“ Spending Capital as if it Mattered ”), Tom Flaherty and Tim Gardner estimated that average annual T&D capital expenditure between 2005 and 2010 is expected to be more than 50 percent higher in real terms than in the 30 years previously.
The leading indicators already are evident in increasing construction budgets. The graph shows capital spending by investor-owned-electric utilities on a trailing 12-month basis. (see Figure 1, p. 50)
Fortunately, the starting point for utilities to finance their future capital programs has improved a little over the last few years. Average equity ratios for investor-owned electric utilities have increased from 38.2 percent at year-end 2003 to 46.2 percent in March 2007 (source: EEI). Also, even though they are off recent highs, utility P/E ratios remain relatively robust, indicating that the timing for equity issuances may be relatively good.
But credit ratings for the industry remain weaker than they were earlier in the decade. At year-end 2001, 42 percent of electric utilities were rated A- or higher, and 68 percent were rated “BBB+” or higher, compared with 19 percent and 42 percent respectively at present. By contrast, 29 percent of the industry is currently rated “BBB-” or lower, compared with only 18 percent in 2001.
Also, free cash flows for electric utilities remain barely sufficient to cover current levels of capital expenditures, even before payment of dividends. And free cash flow after payment of dividends is expected to decline further in coming years (see Figure 3).
The scale of the projected investments is especially daunting relative to the size of the companies in the sector. A new coal or nuclear plant costing $3 billion to $4 billion or more represents a meaningful percentage