The current recovery in global power-sector investment is being driven not only by rising demand for power, but also by the huge levels of liquidity in global financial markets. How long will the...
A Capital Problem: Financing the Next Big Build
As rate disallowances become more commonplace and capital requirements expand, infrastructure development will come with a higher price tag.
rates during the transition to a fully competitive power-supply market.
Since those agreements were struck, however, many changes have occurred in the industry. The wheels came off the retail-competition bandwagon when California’s power industry collapsed in 2000 and 2001. The merchant-power business soon followed. Enron imploded, the economy deflated and the natural-gas bubble burst. FERC scrapped its standard-market design, and while independent transmission operators (RTOs and ISOs) have emerged in some regions, credit constraints effectively have limited competition to only the largest players. In short, the transition to a “fully competitive” power market never really happened.
Even if it had, however—or if deregulation had not occurred in the first place—rising fuel prices still would be squeezing utility rates because environmental factors drove power generators to build clean-burning gas-fired plants. “The economics of coal or nuclear plants weren’t as attractive as gas-fired plants,” Petrosino says. “But being wedded to one fuel source is a risky proposition.”
As a result, a trend toward regulatory disallowances and subsequent impairment of utility credits would have serious consequences—for unbundled and integrated utilities, and ultimately the country as a whole. Not only have fuel prices increased the cost of electricity in the United States, economic growth has squeezed capacity margins in terms of power supply, transmission, and distribution. Investment requirements over the next decade, for new capacity and upgrades, total in the hundreds of billions of dollars.
“Clearly there is a lot of capital spending going on, and [a lot] on the drawing board,” says Edward Sondey, director of Merrill Lynch’s global energy and power group, and formerly vice president of finance at PSEG. “We are seeing it in the areas of traditional coal construction and electric transmission. The key to getting it financed is laying the groundwork with regulators to allow rate recovery.”
In general, utilities have anticipated—and in many cases received—favorable treatment from regulators as the companies move forward with critical investment plans. In Wisconsin, for example, WPS Resources is building a 500-MW coal-fired power plant near Wausau with more than $700 million in up-front rate recovery approved by the Wisconsin Public Service Commission.
In an environment where commissions are holding utilities’ feet to the fire—even for reliability-oriented distribution expenses—such rate-recovery commitments are a basic requirement for infrastructure investments. “Utilities get into trouble when they spend billions of dollars prior to having regulatory approvals,” Sondey says. “But based on the pre-approval concept, utilities will have a high degree of confidence they will maintain a healthy balance sheet and raise capital in a thoughtful way.”
Financing the Buildout
As a general principle, the prospect of building new infrastructure represents a growth opportunity for electric power companies. Realizing that opportunity, however, will depend on how utilities manage their investment and operational strategies.
Ratepayers understandably are reluctant to pay higher utility bills, and regulatory commissions likely will treat budget excursions and operating inefficiencies with extreme prejudice. Case in point: In addition to slashing APS’s rate increase, the Arizona Corporation Commission disallowed more than $17 million in cost recovery for several in a series of 2005 outages at the Palo