The Future of Fuel Diversity
The fragmented electric industry structure poses an obstacle to a more stable, diverse, and secure power supply.
Daily news headlines have drawn attention to concerns about fuels, especially the rising prices of oil and natural gas. Fears of interruptions of oil exports from Iraq, Iran, Russia, and Venezuela (take your pick) roil the energy market. But coal is not exempt from bad news, as production declines reduce output from Eastern U.S. mines while rail transport bottlenecks limit deliveries of Western and Eastern coals. Meanwhile, state attorneys general seeking stiffer enforcement of environmental rules have brought lawsuits against owners of coal-fired power plants.
Amid all of these signs, the benefit of fuel diversity is clear. But the United States is not on course to maintain electric fuel diversity and avoid price shocks. The underlying public policy issue has been dormant since the oil shock of 1973-1974 and the subsequent oil and gas price deflation of 1982-1998. Structural changes in the power sector in the late 1990s have only added to the complexity of determining who, if anyone, is steering the ship.
The fragmented electric industry structure poses an obstacle to any focused public policy approach to promote a more stable and secure power supply. Some states have restructured investor-owned electric energy supply functions into a competitive market mode and other states have left power supply responsibility within an integrated investor-owned utility framework, while other consumers are served by an array of relatively small municipal utilities, public agencies, and cooperatives. Given this backdrop, it is not clear who will lead public policy: private enterprise, individual states, or the U.S. Congress or presidential administration, currently distracted in the run-up to a presidential election.
At issue is whether the public can rely on market forces to ensure adequate and stable fuels. The current industry structure, conflicting goals of different regulatory bodies with jurisdiction over the sector, and a history of inconsistent laws and regulations create a substantial bias against major capital investments in electricity power supply. Focused actions of individual states, the U.S. Congress, and federal agencies could mitigate that burden by reducing uncertainty and narrowing the risks facing investors. The U.S. public policy drift relating to power supply and diverse fuel sources, should it continue, does not bode well for consumers, the economy as a whole, or the credit prospects of the power sector.
Benefits of Diversity
Electricity consumers and the public in general benefit when electric power supply is secure and stable. Diverse fuel resources for power generation reduce the chance that embargoes, strikes, transportation constraints, or acts of war or unrest will disrupt power production. Fuel diversity and long-term supply contracts also reduce exposure to soaring costs of any single fuel.
Like buying insurance protection or hedging, fuel diversification entails an ongoing cost. In the short run, it will cost more to own and operate a portfolio of power resources that incorporates several fuels and technologies, including some that are not at the lowest short-run cost. But over the longer run, the added portfolio cost is an insurance premium that can reduce catastrophic risks of supply disruption or price spikes.
Currently, U.S. electricity production enjoys a reasonably diverse fuel base. In 2004, domestic coal supplies will produce approximately half of power output, and uranium and natural gas around 20 and 25 percent, respectively. Oil accounts for only about 3 percent of U.S. power production. But reliance on natural gas for power production is destined to grow over the next several years based on the existing hardware in the U.S. generation portfolio.
Fuels Outlook: Rising Dependence on Gas
The big three fuel sources for the immediate future remain coal, natural gas, and uranium (). While coal is the largest single-fuel source for power generation in the United States, natural gas is the fuel that is taking share, for the reasons explained below.
Roughly 200,000 MW of new power plant capacity was added in the United States between 2000 and 2004 to the 1999 capacity base of 903,000 MW. More than 94 percent of the incremental capacity built was natural-gas fueled ().
Today, natural-gas-fueled generation constitutes 39 percent of generating capacity, up from 10 percent in 1999. But in many regional markets, the new natural gas plants are idle for 75 to 80 percent of the hours of the year.
The projected 2 percent per annum growth in power consumption in the coming six years will occasion greater usage of natural gas fuel, since gas-fired power plants make up the bulk of the unused capacity in most U.S. regions. For example, in parts of the Southeast and Midwest, new combined-cycle gas turbines (CCGTs) are expected to operate fewer than 20 percent of the annual hours in 2004, rising to an estimated 40 to 45 percent by 2010. Thus there will be a disproportionate increase in gas generation relative to the overall growth in power consumption.
The projected rise in natural gas consumption comes at an unfortunate time for natural gas supply. North American gas production is simultaneously facing a decline. Exploration and development activity cannot replace reserves with the same ease as in the past. New gas supplies may be developed at higher costs through increased drilling, possibly in the deepwater Gulf of Mexico or Alaskan frontier and wilderness areas, or as a result of increased imports of liquefied natural gas, but none of these sources is a certainty and neither will be available in time to address near-term needs.
In the short run, investors can expect heightened risk associated with extremely volatile fuel prices and constrained fuel supplies. In the current environment, Fitch factors risks driven by commodity price volatility into the credit ratings of companies in the industry (). Credit ratings incorporate a composite of potential risks, some but usually not all of which pertain at a given point in time.
Will Market Forces Save the Day?
One policy alternative is to rely on market forces, such as the signals provided by substantially higher natural gas spot prices, the natural gas forward price curve, or rising coal prices, to spur new investments to foster diverse fuel supply.
Given the long lead times for investments in electricity infrastructure and large amounts of capital required, market forces in this sector tend to operate by a long deterioration in supply leading to supply disruptions and extreme price spikes, followed by a decline in economic activity, with a subsequent loss of jobs, personal income, and pubic tax revenues. This may lead to reductions in consumption and ultimately a lower price level. While this scenario appeals to some economics professors, few voters or elected officials would consider this a desirable course of action.
Free-market solutions depend on investors' willingness to supply capital. Uncertainty about future market outcomes creates a powerful disincentive for private investors to invest capital in future power supply initiatives for the public good, which may produce disastrous investment results. The record of the U.S. power and gas sector over the past 25 years has been punctuated by insolvency, credit distress, and bankruptcy brought upon individual companies due to their investments in fixed production assets or long-term supply contracts. Examples of costly power plant investments bringing about a financial crisis or bankruptcy include regulated utilities such as Public Service Company of New Hampshire, El Paso Electric, Long Island Lighting Co., and Gulf States Utilities, as well as competitive suppliers such as Mirant Corp. Cases of financial distress brought on by costly long-term supply contracts include Columbia Gas Transmission and Niagara Mohawk Power Co., among many others. The hazards of large investments in power supply affect monopoly utilities with conventional cost-based tariff regulation as well as companies that operate in a competitive market with market-based pricing, as illustrated in the accompanying simplistic example of the island continent of Euphoria ().
Public Policy Can Lower Investment Risk
Fortunately, there are ways that regulators and policy-makers can mitigate the investment disincentives illustrated in the foregoing example. A host of mechanisms is available to spread the payment for those investments that benefit all consumers across a broad consumer base ("socialize" the costs) and thereby reduce investment risks and the cost of capital for these activities. For example:
State legislatures and/or utility regulatory bodies can direct the regulated distribution utilities or integrated electric utilities to enter into contracts to purchase power or fuel from a particular type of source (e.g., new technology coal plants, LNG terminals, wind farms) under long-term contracts, by lease, or by direct investment, perhaps in proportion to customer load. It is critical that the law or regulation grant the utility a binding approval of its planned contract or investment plan at the time of initial commitment, not subject to subsequent disallowance based on later changes in market conditions. State legislatures and/or utility regulatory bodies can direct the regulated distribution utilities or integrated electric utilities to enter into contracts to purchase power or fuel from a particular type of source (, new technology coal plants, LNG terminals, wind farms) under long-term contracts, by lease, or by direct investment, perhaps in proportion to customer load. It is critical that the law or regulation grant the utility a binding approval of its planned contract or investment plan at the time of initial commitment, not subject to subsequent disallowance based on later changes in market conditions. State regulators generally can allow immediate or accelerated expense recovery of spending for approved R&D projects, as well as the costs to obtain site licenses, environmental approvals, and other development costs. State regulators can avoid multi-year rate freezes and rate caps that do not permit periodic adjustment for costs associated with commission-approved capital investments and required costs for environmental compliance. Such rate freezes provide an incentive for utility owners and managers to make do with the and eke out efficiencies in the short run, and to employ lobbying and legal defenses to fend off environmental mandates, while failing to address the public's longer term energy needs. A state may form a power agency or mandate an existing agency to procure specific types of resources and require the customers of load-serving entities or utilities to buy power from the agency. Or the state agency can offer the power to the competitive market or to the regional transmission organization (RTO or ISO), perhaps under a "must-run" contract. California government used a similar means to deal with a power crisis in 2001-2002, enlisting the California Department of Water Resources to purchase power for delivery to utilities' retail customers on an emergency basis. The New York Power Authority also constructed turbines in New York City in 2002 to provide power to the New York ISO. In a region with a multi-state RTO and a program for coordinated state and regional planning, the RTO could theoretically be the entity that enters into a contract for energy from a new source, or that directs all load-serving entities to enter into contracts for energy of a certain type to achieve the desired resource portfolio. However, this is a long shot. To date, no RTO has entered into long-term power contracts on behalf of consumers, and RTO decision-making on transmission matters is already a contentious balance of conflicting interests. The U.S. Congress can enact laws requiring utilities to purchase power from certain sources, as in the Public Utility Regulatory Policies Act of 1978 (PURPA). Congress has in the past directly funded or provided loan guarantees for certain projects, and this approach could be applied to hasten the construction of demonstration plants for new coal gasification and generation technologies, or to increase R&D. Aside from providing direct funding, lawmakers can provide incentives for private investment via investment tax credits, accelerated tax depreciation lives, or production tax credits for specific types of energy investments. Congress can reduce investment risk and lower the cost of capital for new private investments that promote fuel diversity and stable energy supplies by providing a safe-harbor against applying future changes in environmental regulations to these facilities. This would benefit new investments in energy production equipment that meet and exceed current environmental and fuel diversification objectives by removing the necessity to comply with future best available control technologies as those evolve.
Before hastening to draft legislation, we should keep in mind that prior national energy mandates and investment incentives to favor specific forms of energy development have sometimes been distorted when government regulations operate in the real world. PURPA, for example, resulted in unforeseen consequences, resulting in the development of questionable "PURPA machines" and burdensome power contracts, and synthetic fuel tax credits led to the rampant development of questionable "synfuel" machines. Fuel efficiency standards (CAFE) imposed on auto producers were undermined by the production of car-like vehicles on truck chassis and by the lack of consumer interest in buying fuel-efficient vehicles. On the other hand, introducing appliance efficiency standards accompanied by improved labeling of household appliances' energy consumption was a notable success at modest cost.
A common element in all the suggestions above is that they reduce some of the unnecessary risks affecting debt and equity investment in energy equipment and fuel development. For example, when a regulatory body gives up the opportunity to reconsider a project at a later date, the regulator has an incentive to study the plan carefully at the outset and to make a more informed decision the first time. The cost of this accommodation is small relative to the total capital investment, while the reduction in risk is material.
Even in Euphoria (), it is unlikely that all of the policies and mechanisms suggested above would be implemented. The adoption of one or more of the suggested approaches does not eliminate all business risks. To earn a moderate return, investors still must face normal ongoing uncertainties of operating and maintaining their facilities, variable weather, and changing consumer demands. Debt and equity investors are willing to accept risks and uncertainties, provided that there is a reasonable chance to earn a fair return. But it is foolish to load unnecessary and unproductive uncertainties onto the back of challenging infrastructure spending projects. Taking extra risks off the table expands the pool of capital that is available to fund vital projects.
Once Upon a Time in Euphoria
The hypothetical continent of Euphoria has four power providers, A, B, C, and D, all dependent on gas for power production. Gas supply is dwindling and the price is rising. Companies A and B foresee a severe future shortage, so one invests in facilities capable of generating power from local turnips while the other invests in drilling a deep gas well offshore. A and B incur debt and issue equity securities to finance their investments. Prior to completion, the debt service expenses of A and B begin to mount without any increment in available cash flow to pay the financing costs. Meanwhile, companies C and D do nothing. When the new production comes into operation, the expected shortage is averted, and the price of gas in Euphoria drops.
Case 1: Suppose that all four companies are in a competitive market and compete at freely determined market prices. Companies C and D, which made no investment, benefit from the ability to continue to buy gas at a low market price. They are "free riders." A and B will lose sales to C and D; their new assets will drop to below the cost of acquisition, perhaps to less than the amount of debt incurred. Insolvency for A and B is a real possibility. Perhaps C and D will buy out A and B at a bargain price.
Case 2: On the other hand, suppose that the four companies are regulated utilities, each with an individual tariff based on its own cost of production, and that rate-setting in Euphoria is similar to that of most U.S. states or Federal Energy Regulatory Commission tariff regulation. Customers of C and D will continue to enjoy low energy prices (they are "free riders"). Customers of A and B will protest against tariff increases to recover the high costs of A's and B's new investments. Perhaps Euphoria's regulatory commission will open an investigation, finding A's and B's capital investments imprudent and disallowing full cost recovery. With the benefit of hindsight, market prices of gas have not justified such a high investment in fixed assets or fuel development. In this case, A and B would be forced to write down the value of their investments. Operating cash flow from the allowed tariff would not cover A's and B's debt service, and A and B may become financially distressed and perhaps insolvent (though with a lower probability of insolvency and default than in Case 1). Perhaps C and D will buy out A and B at a bargain price.
In Cases 1 and 2, lenders and shareholders of A and B would suffer while investors in C and D would earn good investment returns. It wouldn't take long for investors in Euphoria to decide to shun investments relating to major capital expenditures for new fuel supply and power assets.
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