Despite significant differences in how electricity is procured across the country, the objective often is the same. Regardless of whether the region has implemented retail competition or is subject to traditional regulation, the intention of the regulatory framework is to minimize the amount consumers spend on electricity. Industry observers, however, have begun to ask whether states that have introduced retail competition face demonstrably lower or higher electricity prices than those states that rely on a more classical, vertically integrated regulatory framework.
The answer largely is a function of the competitiveness of the wholesale electricity markets, as opposed to the specifics of how different states regulate their natural monopoly transmission and distribution companies. If the underlying wholesale electricity markets from which supplies are procured are competitive, then the remaining concerns regarding price levels and volatility can be addressed through regulatory policies.
In regions that have introduced retail competition, legislation has authorized public utility regulators to design and implement power-procurement processes to replace the previous obligation of utilities to plan supplies for all customers. As is well known, retail competition has been ineffective at producing competitive supplies for residential customers, and has had mixed results for other customer classes.1 As a result, regulators have found it necessary to create clear procurement policies for utility transmission and distribution companies. The procurement policies generally force utilities to competitively purchase generation supplies from the wholesale market to meet the expected demands of customers that do not obtain service from a competitive supplier. These electricity commodity procurement obligations are referred to under many names: provider of last of resort (POLR), supplier of last resort (SOLR), standard offer service (SOS), basic generation service (BGS), and default service.2
Far from being universal, the competitive solicitation processes and the product structure for these POLR services varies greatly. Thus, considerable effort is required to understand in detail how the POLR service is specified in each state. Even a simple classification of these services is complex because of the various factors affecting the pricing and volume definitions of these services, and ultimately the power products themselves. Laws promulgated by state legislatures and the regulatory policies developed to implement these laws form the basis for defining important pricing and volume attributes of the POLR products.
When determining the POLR services’ pricing and volume definitions, regulators and utility companies need to consider a variety of factors that cannot be examined in isolation. At a minimum, these factors include:
1) The existing utility customer classes;
2) The existing utility rate schedules;
3) The perceived levels of risk each customer class is willing to manage; and
4) The policy objectives of the state’s regulators.
For example, existing utility customer classes often are the starting point for breaking up volume obligations with typical classifications being residential, small commercial and industrial, and large commercial and industrial. Within each of these classifications there may be numerous different rate schedules. Each rate schedule historically may have built-in subsidizations creating the need for careful consideration of how to translate competitive supply prices into rates. The perceived risks customers are willing to bear will have a significant impact on pricing terms. Regulators must decide whether utilities are to obtain the entire supply in a single solicitation or to obtain portions of the supply at various intervals over a longer time horizon. A closely related decision is to determine the term of the supply contract. Regulators also must decide whether utilities are to obtain wholesale supply at fixed annual prices, fixed seasonal prices, or fixed monthly prices, or simply obtain wholesale supply at varying hourly prices. These numerous decisions result in markedly different state-procurement frameworks.
Table 1 surveys the structure of POLR services and associated procurement policies across the Northeast and Mid-Atlantic where retail competition has been introduced. Generally speaking, requests for proposals (RFPs) are the most common electricity procurement approach utilized in the United States. As Table 1 shows, POLR service definitions vary among states in a number of ways:
1) The groupings of retail customers for the purposes of POLR supply solicitations;
2) The contract term of POLR supply;
3) The pricing format of the wholesale POLR supply; and
4) The pricing format of the retail POLR service.
State regulators’ complex decisions in implementing POLR procurement processes have led to some notable changes in customer rates and rate structures. An objective often associated with introducing retail competition is to align customer class electricity pricing with the actual costs incurred to meet that particular customer-class demand. In many regions, all that is needed to achieve this alignment is for regulators to implement policies that specify the type of product and pricing a particular group of customers should face. To accommodate pricing that varies seasonally as well as diurnally no longer requires utilities to develop complex wholesale price-to-rate structure translations. This type of pricing can be obtained simply by requesting it from wholesale suppliers.
However, there can be obstacles to taking full advantage of the ability to specify pricing in a POLR supply solicitation. Indeed, it can sometimes be difficult to incorporate competitive market prices into existing rate structures due to the historic cross-subsidization among certain customer classes. In these circumstances, despite the reliance on wholesale suppliers for generation commodity pricing, the competitive price must be translated into retail rates that may not reflect the actual costs incurred to serve a particular customer or rate schedule.3 Table 2 provides examples of how some utilities obtain retail rates from wholesale prices and shows that these “translation processes” can be simple or very complicated.
By deciding how to group customer classes (and whether to maintain certain rate structures) and the term periods for supply, regulators have the ability to create a menu of supply options they see as appropriate. Through these options, regulators can achieve policy goals, such as signaling when electricity is most costly, encouraging associated demand responses, and minimizing price volatility. The ability regulators have to determine this menu is a significant benefit of retail competition.
In regions that have not introduced retail competition, procurement policies continue to be tightly aligned with the development of integrated resource plans (IRP).4 In recent years, several utilities in the Western and Southern regions of the United States have submitted updated IRPs5 which, in most instances, have identified the need for additional generating capacity. However, the approaches by which utilities have obtained the needed capacity have varied considerably. While there are some instances where utilities are self-building generation capacity, this typically has not been the case. Instead, utilities are buying unregulated generation capacity and contracting for generation supply. In some instances, when utilities seek additional generation supplies, they issue requests for proposals from competitive developers of generation resources.6 In other instances, utilities may compete (or negotiate bilaterally) to purchase the assets of firms that are exiting the generation business or restructuring. In many regions, this particular strategy has been facilitated by a generation supply surplus. As supplies tighten, there may be more self-build programs.
To the extent that a utility is short or long on generation over seasons, or that a utility needs to balance shorter-term supply and demand, there is a reliance on wholesale electricity markets. In this manner, these utilities often rely on competitive suppliers for portions of the generation capacity even though they are engaged in regulatory planning processes. Thus, competitive wholesale markets continue to be the source of power supplies on the margin throughout the United States.
In general, utilities in these regions no longer can conduct planning in isolation from commercial markets. The outcome of the planning process has been affected as open access to the transmission system has resulted in the construction of unregulated generation facilities. With these new generation facilities integrated into the transmission system, opportunities emerge to rely on these facilities for needed generation supplies. The primary difference between procurement from the unregulated plants in these regions and procurement from unregulated plants in regions that have introduced retail competition is that IRPs often identify longer-term supply commitments. This difference is due to the latitude utilities have to make longer-term purchases in regions without retail competition. Indeed, one of the key distinctions appears to be the greater propensity to make longer-term commitments in regions without retail competition.
The procurement approach in states that have not implemented retail competition is to minimize energy expenditures through a combination of using the least-cost mix of underlying generation supply identified by the IRP and ongoing wholesale transactions. This procurement method can be loosely described as a portfolio-resource-mix approach where the utility’s portfolio, or resource mix, dictates its average total costs at any point in time.7 To ensure timely payment of all supplies, utilities usually are allowed to pass through variations in fuel costs using fuel-adjustment clauses.8
Most utilities ultimately price supplies on an average total-cost basis. The implication is that it is more difficult to expose customers to prices that are reflective of supply and demand at the time of their electricity needs. That is, there are components of the price that are passed through to customers ex post, such as fuel and purchased-power costs incurred in short-term market transactions, which create an average cost that includes important purchases necessary to balance supply and demand.
One of the key differences between the portfolio-resource-mix approach and the competitive-solicitation approach is the greater propensity to obtain longer-term commitments under the portfolio-resource-mix approach. The practical implication of this difference is the registration of demand in the longer-term wholesale market. Although these portfolio resource-mix procurements have been observed over recent years to produce more longer-term supply commitments,9 the approach itself is a closely regulated risk-management strategy.
Once longer-term commitments are made, utilities still must buy and sell electricity to balance their systems, and these transactions require explicit risk-management procedures to be in place so that regulators can be assured that utilities’ power purchases are not exposing customers to unnecessary risks. In essence, the portfolio-resource-mix approach does not provide price certainty to the buyer; instead, the utility is in the position of constantly buying and selling in daily, weekly, monthly, and even yearly wholesale markets to balance the underlying resource mix. The regulator must then rely on detailed procurement policies (including reliance on complex modeling tools and financial risk assessments), and must conduct periodic prudence reviews to ensure that the utility has acted consistent with state regulations. The important observation is that the procurement approach in states without retail competition requires the regulator to explicitly oversee this risk-management policy.
The tradeoff between the portfolio-resource-mix approach and the competitive-solicitation approach appears to be between maintaining system reliability and ensuring that costs associated with generation are minimized over the long-run. The portfolio-resource-mix approach may be viewed as more reliable because of the ability of the regulator to approve plans for new generation supplies, but may entail significantly higher electricity costs if utilities with regulatory oversight make poor planning decisions. The competitive-solicitation approach may be viewed as less reliable because of the reliance on the wholesale market to plan generation supplies, but should entail lower electricity costs since competition is the driving force. There is no evidence that reliability will be compromised under either approach. We believe the heart of the debate is over which approach will minimize consumer electricity expenditures over the long-run.
Both procurement approaches rely heavily on a competitive wholesale market for generation supplies. The key difference is how risk is managed. For example, under the competitive-solicitation approach, risk often is managed by soliciting ex ante fixed-price products, such that all costs to serve customers are known; under the portfolio-resource-mix approach, prices of some resources are not fixed and customer costs vary over time. Due to ongoing debates regarding the ability of organized wholesale markets to signal the need for new generation supplies, there is a tendency to overlook the actual happenings in the procurements themselves. Here we set aside the debate on wholesale market structure and focus on the risk-management issues that are being overlooked.10
The competitive-solicitation approach has resulted in a new group of wholesale electricity suppliers that have developed approaches for pricing electricity that manage price and volume risk in a competitive environment. These competitive suppliers make use of many of the same analytical tools as utilities using IRPs, but these competitive suppliers also have developed various internal proprietary systems to compete as risk managers. Unlike utilities with some degree of regulatory protection, these suppliers have strong incentives to get the analysis right because if they are wrong, competition will drive them out of business. Moreover, competitive wholesale suppliers continually will refine their analytical tools precisely because their livelihoods depend on it.11 Thus, the introduction of retail competition along with the introduction of transparent wholesale spot markets has created the means by which competitive suppliers can evaluate supply risks and provide numerous different products to utilities and individual customers on a competitive basis. We believe the underlying issue of this approach is assessing the risk-management costs of these shorter-term supply arrangements.12
The ability of the portfolio-resource-mix approach to manage risk more successfully over the long run, as compared with the risk management of competitive suppliers under the competitive-solicitation approach, is uncertain as well. One major concern flowing from the use of often very long-term supply commitments (e.g., 10 to 20 years) is that the price at which these supplies have been obtained may, over time, become significantly different from the realities of supply and demand.13 Indeed, this concern cannot be overstated. The portfolio-resource-mix approach, instead of taking advantage of market price signals that will change year-to-year, is precisely the kind of framework that can be far out of step with the economics of energy markets. Moreover, historically there has been a propensity to “overshoot” and end up with excess capacity that takes significant time to absorb. The costs associated with these excesses will be passed through as fixed-generation charges as opposed to proper electricity price reductions in times of excess supply. Meanwhile, the costs of balancing supply and demand and the benefits of responding to seasonal and daily changes must all be tracked and ultimately passed through to customers.
Thus, a major difference between these two procurement approaches is the cost of managing the risks of changes to supply-and-demand conditions and the associated change in prices. Procurement policies in states that have introduced retail competition often directly request pricing that incorporates the management of these risks. That is, prices are fixed over various terms depending on product. In states that have not introduced retail competition, utility customers are charged fixed rates, but are subject to true-up mechanisms that allow for recovery of fuel costs and purchased-power costs associated with the management of price and volume risk. The key question is, Which approach results in lower risk-management costs over time?
Unfortunately, there is no easy way to quantify the risks involved in electricity procurement. It often is argued that utilities using the regulated portfolio-resource-mix approach enjoy the benefit of lower costs of capital and subsequently have lower investment and working capital costs. This consideration, however, does not take into account long- and short-term decision making that may be inefficient, or that benefits can be realized by providing customers with more accurate price signals. At the same time, there are concerns that the shorter-term risk-management costs incurred to supply power in states that have introduced retail competition are consistently higher than those that would be incurred under a portfolio resource mix approach. No evidence suggests that this is true. Instead, there is simply a great deal of concern at the moment that the marginal cost of electricity is causing consumers to pay too much for electricity. Evaluating the true cost differences between these approaches may be impossible, but as time passes we will accumulate evidence on how well each approach performs overall.
A national debate surrounds the regulatory process behind procurement of electricity supplies. There are broadly two approaches: the competitive-solicitation approach in regions that have introduced retail competition and the portfolio-resource-mix approach in regions that have not introduced retail competition. The two approaches provide different means for managing the risk inherent in a world of growing energy needs and changing fuel prices. In the portfolio-resource-mix approach, the utility that faces no competition directly oversees risk management under the regulator’s scrutiny. In the competitive-solicitation approach, market forces manage risk through competition to supply utilities, and regulators assess the outcome. To date, no evidence exists to suggest that market forces cannot manage risk effectively. If anything, regions that have introduced retail competition are beginning to see the start of a healthy wholesale market, with the help of innovative and previously impossible regulatory decisions regarding supply choices. At the same time, regions that have not introduced retail competition are seeing IRP usage with ongoing prudence reviews of utility resource-mix-procurement decisions. These regions have experienced increases in procurement costs from fuels in the current portfolio resource mix; in some cases, these procurement costs have led to increases in retail rates, while in other cases there have been disallowances. No current studies suggest any one approach is preferable.
During periods of escalating prices, shorter-term procurement approaches inevitably will come under criticism when compared with the longer-term fixed-supply options that had been in place prior to the price increases. During periods of declining prices or technological innovation, we would expect the opposite. Regulators can narrow the gap between these approaches, however, by promoting longer-term supply commitments in restructured markets and more flexible market-based pricing approaches in non-restructured markets. However, the most important action regulators can take to minimize consumer electricity costs is, and will continue to be, ensuring competitive wholesale markets while demanding a rich mixture of products from the suppliers in these markets. The less often utilities find themselves “competing” with wholesale market suppliers, the easier the process will be for regulators to oversee, and the better the outcome for retail consumers.
1. See, for example, United States of America Electric Energy Market Competition Task Force and the Federal Energy Regulatory Commission (June 5, 2006), Docket No. AD05-17-000, Report to Congress on Competition in the Wholesale and Retail Markets for Electric Energy (FERC Competition Report), Chapter. 4, and, Joskow, P.L. (2006), “Markets for Power in the United States: An Interim Assessment,” The Energy Journal, Vol 27, Number 1, International Association for Energy Economics.
2. We use the term “POLR” throughout to describe these services.
3. See, for example, FERC Competition Report at p. 21, and references cited therein.
4. Integrated resource plans examine company-specific supply/demand balances from time-to-time and establish going-forward strategies based on economic forecasts for meeting projected growth in demand.
5. For example, Avista, PacifiCorp, and Nevada Power recently have undergone an IRP review process.
6. Numerous utilities rely on RFP processes for selection of new generation. For example, Pacific Gas and Electric recently announced that it had selected several newly proposed generation projects resulting from an RFP process. Other states where utilities recently have used RFP processes to evaluate new capacity additions are Utah, Idaho, Florida, Nevada, Arizona, Minnesota, Kentucky, Washington, North Carolina, Louisiana, and Georgia.
7. We use the term “portfolio resource mix” to represent the mixture of resources a utility has available at any point in time to meet customer demands.
8. For a listing of various states’ fuel and wholesale power cost-recovery mechanisms, see Regulatory Focus, Fuel and Wholesale Power Cost Recovery, A State-by State Review, Regulatory Research Associates, An SNL Energy Company, Oct. 3, 2005.
9. We note that utilities making these commitments typically are forecasting reduced reserve margins indicating the need for new capacity additions.
10. We do not mean to under-emphasize the importance of ensuring transparent wholesale market structure, but instead observe that centralized wholesale markets’ structures are evolving to ensure that these broader, regional systems produce accurate locational price signals. We believe that these price signals from the wholesale electricity markets and fuel markets will result in competitive suppliers building efficient generation.
11. In fact, we are aware of many competitive wholesale suppliers that closely guard their methods for analyzing the energy markets and treat these tools as company secrets.
12. We note that there is some concern that these shorter-term supply arrangements are unable to provide sufficient incentives to build additional generation to meet growing electricity demands, but these concerns are thus far unproven.
13. These kinds of pricing experiences have been a major factor in restructuring the electricity industry.