by Jamie Read, Rich Goldberg and Peter Fox-Penner, The Brattle Group
As the U.S. electricity utility industry prepares itself for a new era characterized by rapid innovation, new regulatory and technological developments present great opportunity and equally great risk. Peter Fox-Penner’s recent book “Smart Power: Climate Change, the Smart Grid, and the Future of Electric Utilities” chronicles the challenges facing utility CEOs and many business risks related to decarbonizing the utility industry.
In an environment of rapid changes in fuel prices, technologies and regulatory policies, risk management for utilities is more important and complex than ever.
Risk management can mean different things to different people. When the term is used in the electric power industry, it most often refers to market risk (in particular, the risk associated with market prices of electricity, natural gas and other commodities used to generate electric power) or credit risk (risk associated with the possibility that counterparties to power purchase agreements, fuel supply contracts and energy derivatives will be unable to pay or deliver as promised). This was not always the case, however.
Prior to restructuring, risk management in the electric utility industry focused primarily on operational and sometimes state regulatory risk. In this period the typical risk management issues were managing fuel inventory and setting capacity planning targets, the principal objectives of which were to maintain system reliability. What accounts for the shift in emphasis from physical to financial risk? Did industry restructuring create financial risk? And can we anticipate another shift in risk management as we look to the future?
Price Volatility, Risk
The ascendance of financial risk management coincided with the restructuring of the electric utility industry. This was a period during which the mantra of open markets leading to reduced costs was on the rise, and a finance-centered world view began to dominate all others. Although cost-based bulk power trading had been used among utilities for many years, restructuring stimulated wholesale and retail market growth. Electricity trading revealed the market value of electric energy and the volatility of market prices.
Volatility is the term of art in financial and commodity markets for describing the rate of change in market prices, not the direction of prices but the degree of uncertainty. For example, over any fixed time horizon, the greater the volatility, the greater the uncertainty about what the price will be at the end of that horizon. Thus, exposure to volatile electricity prices means exposure to price uncertainty.
Electric industry restructuring followed the phaseout of price caps on natural gas and the unbundling of interstate natural gas pipeline services. The resulting demand for risk management services in the natural gas industry gave rise to, among other things, the introduction of natural gas futures contracts on the New York Mercantile Exchange (NYMEX) in 1990.
Natural gas restructuring followed the commoditization of oil. NYMEX introduced heating oil futures in 1978 and crude oil futures in 1983. With all the major energy commodities actively traded in spot and forward markets, the volatility of energy prices was evident for all to see. Energy prices are volatile—more volatile than most financial assets—and electricity is widely viewed as the most volatile energy commodity.
In centralized electricity spot markets, market energy prices constantly are changing to keep supply and demand balanced. The demand for electricity, which exhibits predictable daily and seasonal patterns, also varies randomly in response to unexpected weather conditions and other events. Supply costs increase as load moves up the generation stack, but they also vary with fuel prices, generation availability and hydro flows. Local supply and demand variances can be mitigated to some degree by power imports and exports, but transmission constraints can result in substantial variation in price over relatively short distances.
The supply-demand balance in electricity is particularly sensitive because, unlike most commodities, electricity cannot be stored economically. As a consequence, supply must match demand in real time. These characteristics of generation, transmission and absence of storage make for very volatile electricity prices, particularly in the short run. That very little of the demand for electricity is responsive to short-term price changes only aggravates volatility.
Households and businesses all along the electricity supply chain are exposed to market price risks. Those exposures might be results of energy consumption, (e.g., for lighting homes or commercial office buildings); ownership of or rights to energy resources, such as power plants, transmission lines and natural gas storage; or commitments to buy or sell electricity, fuel and related commodities (e.g., SOX and NO2 permits). When market price exposures represent a substantial portion of household or business earnings, managing those exposures can be essential to financial viability.
While exchange-traded futures and options are important tools for managing price risk, they are not the only instruments available. Forward and option contracts traded in over-the-counter markets have played an even larger role in the energy industry than exchange-traded contracts. Risk also can be managed through the design of power purchase agreements, fuel supply contracts and retail service agreements. In addition, price risk can be managed to some degree through the management of physical resources—i.e., via operational risk management.
Risk Before vs. After Restructuring
Prior to restructuring, the investor-owned portion of the U.S. industry was dominated by vertically integrated electric utilities performing the generation, transmission and distribution functions.
As public utilities, they held exclusive service franchises, so they did not face direct competition for retail electricity sales. The quid pro quo for monopoly protection was that rates and services were subject to approval by a state public utility commission. Rates were set according to the principles of rate of return regulation, and investments in power plants and other assets were put into rate base at embedded costs (assets valued in rate base at the original cost net of depreciation), absent a finding of imprudence.
When the utilities bought or sold power through a power pool, they often did so under split-savings rules. In many jurisdictions, electric utilities operated with fuel and purchased power-adjustment clauses, under which variation in those costs were flowed through to ratepayers. Other than these adjustment clauses, rates were fixed over the period of regulatory lag and adjusted only through a rate case.
Financial risk management was built into this traditional rate of return regulation. With embedded cost, some of the risks of asset construction and ownership are born by ratepayers rather than shareholders. Thus, the returns to investors in an electric utility that owns regulated generations assets are likely to be less risky than the returns to investors in a merchant generation company, but more modest as well.
Restructuring did not so much create financial risks, but rather revealed the underlying financial risks. It could be said to have facilitated risk discovery. And because risks are allocated differently in the restructured power industry, resources are likely to be allocated differently, as well. Where there is retail electricity competition, consumers can make their own choices about risk bearing rather than accepting the risk bearing that has been determined by utilities and their regulators. (Operational risks still exist and must be managed. Now, however, the cost of failure in many cases is more likely to be felt in financial terms, e.g., liquidated damages under a contract to deliver power, rather than as physical ones, e.g., power outages.)
As we look to the electric power industry’s distant future, we anticipate mostly favorable changes from the standpoint of market price volatility and risk management.
Volatility is in part a manifestation of the dearth of large-scale electricity storage. Storage permits arbitrage of intertemporal price spreads for other commodities, and the absence of storage makes large electricity price variations over short time intervals possible. Therefore, a breakthrough in storage technology could lead to markedly lower price volatility. Similarly, transmission lines enable arbitrage of geographical price spreads, so the existence of transmission constraints allow electricity prices to vary over relatively short distances. Therefore, advances in transmission technology and expansion of the transmission grid (if not offset by power consumption increases) imply reduced resistance to electricity flow across geographical boundaries.
The implications of increasing renewable energy amounts in the electricity supply mix on market price volatility are less clear. To the extent that renewable energy displaces what otherwise would be additions of fossil-fired generation, it might tend to reduce volatility. Wind turbines, the main source of renewable energy, are variable power supplies. As such, their variability of output might contribute to an increase in market volatility as they become deployed on increasingly larger scales.
The anticipated change with the most favorable implications for price risk management is the expansion of smart meters, or meters that record customers’ power usage hour by hour, and the dynamic pricing approaches that accompany them.
Although many electric utilities for years have offered interruptible services, which allow utilities to shed load in the event of a supply shortfall, these rates have not had a major impact on price volatility.
In contrast, a world with widely deployed smart meters (and ancillary technology to help consumers make usage decisions based on market conditions) potentially could result in a great reduction in the short-term volatility of electricity prices. After all, shifting electricity demand from high-price periods to lower-price periods is just the flip side from storing supply at low-price periods for use during high-price ones; either method eases the disparity in prices between the periods. Smart meters are also an important early step to technological breakthroughs in negawatt storage technology.
Smart meters and time-based pricing open a panorama of new possibilities, and the nonprice risks related to smart meter deployment will be harder to predict. Utilities will have more pricing options at their disposal, and customers will adopt a new generation of smart appliances to complement their meters. These developments will alter how customers interact with utilities, driving profound changes to utility business models. The new technologies also will increase the amount of customer data collected and transmitted on the grid, introducing privacy and security concerns.
These technological and institutional developments—greater renewables, more storage, smart meters and dynamic prices—all point toward a future of reduced energy price risk. The road to this future, however, involves enormous risks of other types less easily characterized and managed, namely policy and transition risks. During this transition, risk management policies of all types will be more important than ever.
“Smart Power: Climate Change, the Smart Grid, and the Future of Electric Utilities” site: http://smartpowerbook.com
The views expressed in this article are strictly those of the authors and do not necessarily state or reflect the views of The Brattle Group Inc. or its clients.
James A. “Jamie” Read Jr. is a principal at The Brattle Group. Reach him at firstname.lastname@example.org.
Richard E. Goldberg, Ph.D., is a principal at The Brattle Group. Reach him at email@example.com.
Peter S. Fox-Penner, Ph.D., is a principal and chairman emeritus at The Brattle Group. Reach him at firstname.lastname@example.org.
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