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Veterans’ Affairs (VA) healthcare providers perceive that Veterans expect and base visit satisfaction on receiving antibiotics for upper respiratory tract infections (URIs). No studies have tested this hypothesis. We sought to determine whether receiving and/or expecting antibiotics were associated with Veteran satisfaction with URI visits.
This cross-sectional study included Veterans evaluated for URI January 2018–December 2019 in an 18-clinic ambulatory VA primary-care system. We evaluated Veteran satisfaction via the Patient Satisfaction Questionnaire Short Form (RAND Corporation), an 18-item 5-point Likert scale survey. Additional items assessed Veteran antibiotic expectations. Antibiotic receipt was determined via medical record review. We used multivariable regression to evaluate whether antibiotic receipt and/or Veteran antibiotic expectations were associated with satisfaction. Subgroup analyses focused on Veterans who accurately remembered antibiotic prescribing during their URI visit.
Of 1,329 eligible Veterans, 432 (33%) participated. Antibiotic receipt was not associated with differences in mean total satisfaction (adjusted score difference, 0.6 points; 95% confidence interval [CI], −2.1 to 3.3). However, mean total satisfaction was lower for Veterans expecting an antibiotic (adjusted score difference −4.4 points; 95% CI −7.2 to −1.6). Among Veterans who accurately remembered the visit and did not receive an antibiotic, those who expected an antibiotic had lower mean satisfaction scores than those who did not (unadjusted score difference, −16.6 points; 95% CI, −24.6 to −8.6).
Veteran expectations for antibiotics, not antibiotic receipt, are associated with changes in satisfaction with outpatient URI visits. Future research should further explore patient expectations and development of patient-centered and provider-focused interventions to change patient antibiotic expectations.
The Spanish constitutional and legal system grants the right to free legal assistance for Spanish citizens as well as foreign nationals in Spain who lack the financial means to litigate or are part of certain vulnerable groups. However, many poor individuals do not meet the means test to qualify for free legal aid, as the economic threshold is very low and many nonprofit organizations are also not eligible. The decade-long economic downturn, from which Spain only recently emerged, led to drastic funding cutbacks in government support, which have not been fully restored. In addition, other administrative obstacles may effectively prevent access to legal aid. For example, even those who qualify for free legal aid may not be able to effectively access the help of a legal aid lawyer in practice, as is typically the case for asylum seekers in Spain.
Traditionally state utility regulators ensured adequate capacity to meet peak demand by imposing regulatory capacity requirements on vertically integrated electric utilities. With electricity restructuring in many regions of the country in the 1990s, newly created regional transmission organizations operating under FERC’s purview began to introduce wholesale markets for capacity. This first generation of capacity markets in the Northeast U.S. were viewed as a more flexible means of complying with capacity requirements, rather than as an altogether new capacity policy. Accordingly, the early markets were adopted without considering the underlying question of how best to attain reliability in the new era of competitive electricity markets.
In the 1990s, many electricity markets in the United States moved away from traditional public utility regulation and toward competitive markets. Regional transmission organizations (RTOs), under the oversight of the Federal Energy Regulatory Commission (FERC), operate the electricity grid in areas with competitive markets. These markets include energy markets that sell power, ancillary services markets that sell services necessary to maintain the stability and security of the grid, and capacity markets.
After two decades in which they have grown tremendously in size, importance, and complexity, capacity markets are due for a comprehensive reassessment. The analysis in this book challenges several of the core assumptions on which capacity markets rest:
1. There is no consensus regarding the missing money theory used to justify capacity markets.
2. The use of forward capacity markets appears to lead to systematic errors in forecasting electricity demand, inducing capacity markets to procure excess capacity and impose excess costs on consumers.
3. Both regional transmission organizations (RTOs) and FERC seem fixated on concerns that capacity prices are too low, despite strong evidence that prices are higher than necessary.
4. Capacity markets have become increasingly and inexorably complex, due in significant part to regulatory accretion that undermines the role of market forces.
5. The widespread use of an engineering-based reliability standard based on a fixed risk-of-outage metric is ill-suited to the goal of reliability.
By the mid-2000s, the shortcomings of the first-generation capacity markets had become clear. Each of the three Northeast regional transmission organizations accordingly replaced its first-generation capacity market with a significantly more robust second-generation capacity market. Whereas first-generation capacity auctions merely supplemented the traditional capacity procurement mechanisms of self-supply and bilateral purchases, second-generation capacity auctions reflected a vision of capacity markets as a distinctive policy for sending corrective price signals to incentivize investment in generation. Unfortunately, FERC did not take advantage of this opportunity to consider deeper questions about capacity markets, such as in what circumstances capacity markets are appropriate and how they compare to other available policy options for achieving reliability.
Capacity markets are created to ensure that restructured electricity markets provide reliable service. Reliability requires that generation capacity in electricity markets is adequate to meet demand at all times, including during periods of peak usage. In a typical market, the reliability of supply is left to buyers and sellers to resolve through their transactions. Electricity markets, however, have their peculiarities. In particular, the missing money problem is a theory contending that features specific to electricity markets distort incentives for investment in generation capacity, impairing reliability. Potential sources of these distorted incentives include inelastic demand and supply, price caps, system reliability as a public good, the use of engineering-based reliability standards, and system operations. Missing money theories provide the general rationale for policies seeking to enhance the supply of capacity in electricity markets. Each of the potential causes of missing money has generated both support and critique and may have different implications for policy.
Even after system operators have defined supply and demand for their capacity markets, important questions of market design remain. Most centralized capacity markets such as those of the three Northeast regional transmission organizations (RTOs) operate their markets primarily through auctions. RTOs must choose an auction format and a method for determining the market-clearing price and quantity in the auction. In addition to operating a base auction, RTOs also have created smaller incremental auctions to allow sellers and buyers of capacity to adjust their capacity holdings at other times. For those load-serving entities that own or procure their own capacity outside of the auctions, the RTOs offer opportunities for opting out of capacity auctions and supplying their own capacity needs directly. Finally, RTOs have created incentive structures to encourage capacity owners to fulfill their capacity obligations and to penalize those who do not.
Many market design choices involve details and nuanced differences. These details matter. The decisions underlying market design features carry important consequences for the outcomes and performance of capacity markets.
Regional transmission organizations (RTOs) administratively create capacity market demand curves derived from three components: the capacity requirement based on forecasted peak demand plus an additional margin, the Net Cost of New Entry based on the cost of new facilities entering the market, and the shape of the demand curve. The processes that RTOs use to generate these components depend on stakeholder negotiations, lack theoretical or analytical justification, and tend to produce biased results. There is thus little reason to believe that capacity market demand reflects the actual value of capacity.
Imagine a scenario in which there is great concern for maintaining an adequate number of grocery stores to serve the food-purchasing public around the clock, so that consumers always have access to open grocery stores to buy food. In response to this concern, a new revenue stream is created for grocery stores. Previously grocery stores earned their revenues entirely from consumer purchases of food. Now consumers will also be required to pay in advance to ensure that grocery stores will be open for business twenty-four hours per day. Grocery stores will receive these payments from consumers merely for being open, even if no consumers buy any food. These new payments to grocery stores do not entitle consumers to purchase food at any particular price from the stores. The grocery stores’ only obligation is to be open for business, ready to sell food.
The Electric Reliability Council of Texas (ERCOT) is responsible for system operation in most of Texas. Instead of establishing a capacity market, ERCOT has chosen to address resource adequacy through its energy market. In the energy market, ERCOT sets the maximum price of power equal to an estimate of the value of lost load. This attempts to alleviate the missing money problem underlying the rationale for capacity markets. ERCOT also has adopted an Operating Reserve Demand Curve, a price adder that is based directly on economic principles. Since restructuring, ERCOT has experienced three significant electricity shortage incidents. The most recent incident, in 2021, was a major event, creating outages for up to seventy hours. It was caused in large part by fuel supply issues due to the lack of weatherization of the natural gas industry and was not primarily the result of capacity shortages. Accordingly, it does not appear that any intervention in electricity markets alone would have solved this problem.
Capacity policies are designed to enhance grid reliability by increasing investment in electricity generation capacity. Because capacity is perceived to be undervalued in the market, capacity policies attempt to induce demand for capacity through regulatory mandates. These mandates take several forms. Some capacity policies create new policy markets for capacity, while others attempt to create value for capacity within existing electricity markets. Capacity policies can be evaluated based on how well they ensure adequate capacity, their costs, their effects on the energy market, their practical feasibility, and their vulnerability to the exercise of market power.
The supply curve of a capacity market represents the aggregated bids of the suppliers of capacity. Different suppliers’ bids indicate their differing opportunity costs of incurring capacity obligations. Existing suppliers with firm plans to continue operating often bid at a price of zero, indicating that they are price-takers willing to accept a capacity obligation for any positive price. New suppliers and existing suppliers that are considering exiting the market, however, tend to bid at a non-zero price representing the additional revenue – that is, beyond the revenue they expect to earn from the energy and ancillary services markets – they need to receive to be able to operate without losing money.
For bidding to be possible, however, the object of the bidding – the capacity product – must first be defined. Defining the capacity product includes specifying how capacity is to be counted. This has turned out to be quite complicated. Centralized capacity markets are based on the premise that capacity is fungible, which allows a uniform capacity product to be traded in the market. In reality, however, different capacity resources make different contributions to overall system capacity. Factors such as the timing of generation and location of capacity are important. Regional transmission organizations (RTOs) operating capacity markets therefore must constantly balance two competing considerations that together constitute a complexity dilemma – creating a unified market that maximizes competition and minimizes transaction costs, versus creating a market that recognizes the different attributes of capacity resources.
When regional transmission organizations (RTOs) in the northeastern United States created their second-generation capacity markets in the mid-2000s, they included – at least partially at FERC’s urging – regulatory programs aimed at preventing some vertically integrated firms – “net buyers” – from intentionally suppressing market prices for financial gain. In adopting these programs, the RTOs took the unusual step of acting against not only prices that were too high due to monopoly, but also prices that were perceived to be too low. These regulatory moves were highly unusual in practice and lacked foundation in economic theory. In combination with other institutional features of capacity markets discussed in previous chapters, they exerted upward pressure on capacity prices. Over time, these Minimum Offer Price Rules (MOPRs) have proliferated, broadening their targets to price suppression more generally and expanding their scope to include most new capacity resources, as well as some existing resources. In the process, the regulation of capacity markets has strayed from the purpose of capacity markets, which was to provide adequate capacity at the lowest possible cost. MOPR expansion has justifiably triggered harsh criticism of FERC’s regulatory overreach.
This chapter introduces the essential elements of capacity markets. This creates a foundation for the subsequent chapters, which investigate more specific issues. The broad overview that this nutshell introduction provides is both necessary but also wholly insufficient to truly understanding electricity capacity markets. As the saying goes, “the devil is in the details.” This is especially true for capacity markets.
The exercise of market power is a continuing problem in electricity markets. This is especially true for capacity markets. To deal with this challenge, each of the Northeast regional transmission organizations (RTOs) uses a variant of the pivotal supplier test to determine if market power exists. Which variant is used has important implications for the risks of error in the analysis of market power. Where market power is found, it needs to be mitigated. How such mitigation takes place in capacity markets has posed difficulties for the RTOs.