The utility sector still has excellent access to the capital and credit markets. Yet, it is never safe to assume utilities will continue to enjoy the same low costs of capital. This is particularly true for companies facing compressed margins, regulatory deferrals or disallowances, and rising debt leverage.
Unit costs of electricity and gas service are rising faster than the underlying inflation rate, and that trend will intensify with the higher market prices of natural gas and other energy commodities.
Commodity prices are not the sole factor raising the longer-term costs of electric and gas service. Capital expenditures are on the rise for network reliability, mandated environmental compliance, and resource adequacy. Utilities face rising non-fuel operating and maintenance expenses, particularly for pensions, employee medical expenses, and post-retirement benefits. A trend of declining interest expense that benefited the sector over the past four years is likely to reverse in the next several years. These factors all contribute to an outlook for rising unit costs of electric and gas service. In an environment of increasing unit costs, the financial prospects and credit outlook for many utilities will depend on whether they pass along such costs to consumers in the form of higher tariffs.
Fitch views higher costs per unit of sales as a negative development for many utilities. Consider the alternatives. On the one hand, utilities in more punitive regulatory jurisdictions that do not allow recovery of the full costs will experience lower profit margins, increased debt leverage, and weaker credit measures. On the other hand, even in a regulatory jurisdiction that permits full fuel adjustments and base- rate increases to recover higher costs, a possible adverse consequence could be declining sales growth or even demand destruction that requires the utility to raise unit prices even more to recover fixed costs.
In the immediate aftermath of 2005 hurricanes Katrina and Rita, the sector’s risks are elevated. The ramifications of higher gas-commodity prices and the related effects on the prices of coal, emission credits, and wholesale electric power are tipping the balance toward greater risk for regulated gas and electric utilities and for those generators most dependent on natural gas. The extreme-ly rapid rise in natural-gas prices creates concern about rate shock to residential and commercial customers of those utilities most sensitive to natural gas and commodity price volatility. While public service commissions generally recognize that escalating fuel and purchased-power costs are beyond the control of gas distribution and electric utilities, undoubtedly there will be public pressure to moderate tariff increases. As a result, investors in utility securities face greater risk of adverse regulatory, political, or legislative decisions.
The consequences of these developments will differ among individual companies. The most immediate effect of rising costs will be felt by those local gas distribution companies (LDCs) that did not hedge the vast majority of their customers’ winter gas consumption. Conversely, non-utility power generators with predominantly coal and nuclear resources typically benefit from the effect of higher gas prices to raise wholesale electricity prices, and if their sales previously were not contracted at lower fixed prices, they stand to reap windfall cash flows.
In the case of integrated electric utilities with predominantly coal and nuclear resources, the primary beneficiaries of their favorable resource mix are consumers (ratepayers), but the utilities themselves benefit by maintaining more stable profitability and credit ratings. While costs of power produced from coal have risen more gradually than gas-fueled power generation, future environmental compliance and potential new investments in base-load capacity additions will drive cost increases for coal-based power generators during the next five years.
The electric utility sector previously experienced several sustained periods of rising or falling unit costs. A significant and prolonged increase in real unit production costs from 1974 through 1982 was associated with reduced growth (or even declines) in utilities’ sales volumes, contraction of profit margins, adverse regulatory decisions, and declining credit measures. On the other hand, prolonged declines in real unit costs (such as 1950-1970 or 1983-1999) are associated with growing demand and improving profitability. All other things being equal, the latter environment is more conducive to stable or improving profitability and financial conditions.
Figure 1 illustrates the long-term trend in electric power prices over the past 40 years, both in nominal dollars and in constant 2004 dollars. Fitch views utilities’ prices as a reasonable proxy for their costs over the long term, although tariff regulation normally creates a lag in the linkage between costs and prices both on the upside and downside.
In a period of sustained rising prices per unit of sales in the decade following the 1974 oil shock, electric utilities experienced difficulty in passing through all expense increases to consumers, resulting in shrinking cash flow from operations and increased dependence on external financing. The era from 1983 through 2001 was a period of relatively flat prices in nominal terms and declining real prices.
Today’s circumstances are not a perfect analogue to the 1974-1985 era, and at present, Fitch has no reason to expect that the coming five years will replicate the financial distress utilities experienced in that period. A number of factors in the current environment may mitigate the negative effects of rising unit costs over the next five years. These include:
Higher commodity costs broadly affect gas LDCs and electric utilities, with positive or neutral implications for a few companies with favorable energy positions, but unfavorable implications for many others. During 2005, U.S. natural-gas prices were elevated due to declining gas deliverability relative to demand, as well as the market correlation of gas prices to the price of oil and the geopolitical risk premium affecting the worldwide oil markets.
In late 2005, one-half of U.S. offshore continental shelf natural gas production remained out of production and shut-in, as a result of damage from hurricanes Katrina and Rita. Spot and forward prices for natural gas consequently surged. Producers are in the process of quantifying the extent of damage to U.S. gas reservoirs and infrastructure, and the potential for restoring the prior level of deliveries.
Forward- and spot-market prices for natural gas are expected to decline from the post-hurricane level if a substantial amount of production comes back on line, the current winter is mild to normal, and demand for gas declines materially in response to price increases. However, natural-gas prices could remain at an elevated level, at or above $7 to $8 per thousand cubic feet for some time because of declining production curves in the existing production areas and the rising consumption of natural gas for power generation in many parts of the United States. High natural-gas prices (relative to those prevailing between 1995 and 2002) will tend to influence higher market prices for related fuels, such as coal, uranium, and emission credits.
Meanwhile, individual utilities vary in their ability to pass on costs of purchased gas, fuel, and purchased power to consumers. In general, utilities with effective and frequent commodity price-adjustment mechanisms have greater protection in a rising fuel-price environment. However, during a profound increase in energy commodity prices, even utilities with the most protective commodity price adjustors are vulnerable to a sudden change in the rules and procedures governing tariffs. In rare cases, regulators have placed a moratorium on adjustments, deferred recovery for longer periods, or investigated prior utility management decisions, disallowing full recovery.
Capital spending is another source of rising unit costs—one that will persist over the intermediate and longer term, particularly for electricity distributors or integrated electric utilities.
In 2005, many investor-owned electric utilities began to boost their five-year forecasts for capital investment. Capital expenditures are targeted for reliability-driven distribution and transmission system upgrades and environmental compliance at generation plants in the 2006-2010 time frame.
These investments are not driven by increased units of demand but are largely undertaken to enhance service quality or meet environmental mandates. While a few utilities experience faster unit sales growth of 2.5 to 3 percent or higher, growth in electricity consumption for most companies recently has been in the range of 1.1 to 1.6 percent per annum. Capital spending of approximately $40 billion in each of 2003 and 2004 averaged roughly 7.5 percent of net book investment in PP&E.
Fitch projects that utility capital investment will exceed 8 percent of electric utilities’ net book value of PP&E for the next 4 to 5 years on average. Companies making major environmental upgrades to coal plants and those building new baseload generation will have higher investment rates. Unless the new investments result in major reductions in other operating costs, the effect of rolling in the capital recovery for new rate-base assets will be to add 3 to 5 percent per annum to electric utilities’ revenue requirements, assuming no further decline in the rate of demand growth. This trend will spur the need for continuing base-rate increases over the next 4 to 5 years.
The cost of marginal investments in capital equipment has exceeded the embedded cost of existing PP&E for some years, and ongoing capital spending by utilities in recent years has consistently exceeded the rate of growth of sales demand. However, this cost trend was offset by declines in other expense categories, notably by refinancing debt at lower interest rates as well as by a long trend of generally declining costs from their peak in 1981-1984 until 2000. Looking forward, neither interest expenses nor fuel costs are expected to moderate the effect of rising capital investment or pension and employee benefit costs, so base-rate increases will be required.
Utilities typically fund a portion of their capital expenditures with short-term debt prior to permanent funding with a mixture of debt and equity. A rise in the prices of fuels or purchased power typically results in increased working capital needs. Furthermore, regulatory/political resistance to rate hikes may result in deferred recovery of commodity costs and thus, more borrowing needs. Worse still is the possibility of regulatory disallowance of deferred costs, which would result in lower cash flow and more debt. In addition, utility cash flows could be adversely affected by slower customer payments and reduced demand, as residential, industrial, and commercial consumers experience difficulty in coping with higher energy bills.
Moreover, access to capital also will be a major issue in the future in respect to rising unit costs. In 2003-2004, many utility holding companies were overleveraged and suffered significant reverses in their non-utility and competitive businesses.
A major benefit for the sector in recovering its credit profile was ample access to capital markets and the bank market at low interest rates, both in the investment-grade and speculative-grade categories. Utilities took advantage of favorable capital market conditions to term out their short-term debt balances and pare back scheduled maturities to manageable levels, thereby improving liquidity and lessening refinancing risk and exposure in the event of a rise in interest rates. In 2004-2005, utilities and utility holding groups were favored by easy conditions in the debt and bank market, high equity valuations, and lower cost of capital.
In Fitch’s view, the sector’s credit recovery is now fading, and investors should exercise greater caution regarding the power and gas sector.