William W. Hogan

Chandley, John, and William W. Hogan. “A Path To Preventing Undue Discrimination and Preference In Transmission Services.” In, 2006.Abstract

Excerpt from the Introduction:

 

The Federal Energy Regulatory Commission proposals for Order 888 Open Access Transmission Tariff (OATT) reform arise from a continuing frustration with the Commission’s efforts to provide open access to transmission both for its own sake and to support competitive markets. The Commission has found it difficult to meet the basic requirement to avoid undue discrimination and preference in transmission services. This difficulty follows in part from the nature of the electricity grid. But more important, the transmission access procedures promulgated in Order 888 are not consistent with the requirements of reliable and efficient operation of the grid, nor do they support workable competitive markets. A better approach, more closely aligned with actual grid operations and compatible with competitive principles, is obviously needed. Unfortunately, the narrow focus in the Commission’s Notice of Proposed Rulemaking (NOPR) does not allow it to see the problems inherent in the current Order 888 framework that must be addressed to achieve the Commission’s goals.

After many prior attempts at broader reforms to meet its expansive goals for industry reforms, the Commission seeks now to narrow its scope to advancing limited changes to the OATT. The focus is on improving the consistency and transparency of the determination of available transfer capability (ATC) as the primary means to address undue discrimination. But if inconsistent ATC calculations and methods are not the underlying problem, then the proposed “solutions” will fail.

The emphasis of the past analyses has been on the defects of the OATT contract path and ATC framework. Although the Commission’s own analyses have recognized these defects, the Commission has not been able to address these matters without entangling itself in a larger debate about electricity market design and electricity restructuring. Given the impasse, it may be that the emphasis on ATC imposes too much on the Commission if it is to find a path to preventing undue discrimination and preference in transmission services. A different approach is needed.

Gribik, Paul, William W. Hogan, and Susan Pope. “Market-Clearing Electricity Prices and Energy Uplift.” In, 2007.Abstract
Electricity market models require energy prices for balancing, spot and short-term forward transactions. For the simplest version of the core economic dispatch problem, the formulation produces a well-defined solution to the energy pricing problem in the usual form of the intersection of the supply marginal cost curve and the demand bids. In the more general economic unit commitment and dispatch models, there may be no analogous energy price vector that is consistent with and supports the quantities in the economic dispatch solution. Uplift or make-whole payments arise in this condition. Comparison of three alternative pricing models illustrates different ways to define and calculate uniform energy prices and the associated impacts on the energy uplift required to support the least cost unit commitment and dispatch.
Hogan, William W.Virtual Bidding and Electricity Market Design.” In, 2016. Publisher's VersionAbstract

Summary:

Summary Efficient electricity day-ahead market designs include virtual transactions. These are financial contracts awarded at day-ahead prices and settled at real-time prices. In PJM these virtual transactions include incremental offers (INCs) that are like generation offers, decremental bids (DECs) that are like demand bids, and up-to-congestion bids (UTCs) that are like transmission price spread bids. Virtual transactions offer potential benefits to improve the efficiency of electricity markets, mitigate market power, enhance price formation, hedge real-time market risks, and price those risk hedging benefits.

The role and performance of virtual transactions has been a subject of controversy. A report by PJM addresses some of these controversies, identifies possible problems in the present implementation of virtual transactions with the associated settlement rules, and makes recommendations for changes in the treatment of virtual transactions. The PJM report is generally supportive of the contribution of virtual transactions as improving overall market performance. Illustrative examples in the report highlight these contributions and add to the general understanding of the benefits and some of the problems with its current rules for treating virtual transaction.

Although these examples help in explaining the mechanics of virtual transactions, and the interactions with the underlying physical market, the examples do not provide a framework for evaluating the overall cost and benefits of virtual transactions. The PJM analysis is not alone in this regard, because the evaluation task is not easy. There is no readily available template waiting to be applied to the PJM case. The limited available analyses from other regions indicate that the benefits are material and outweigh the costs, but no available studies cover all the relevant issues. However, going beyond examples of particular outcomes to consider, the broader context is important. Looking to the broader framework can change both the diagnosis of the symptoms and the prescriptions for the cures.

Under the current PJM market rules, there is an asymmetry in the settlement treatment of different types of virtual transactions, applying residual uplift charges to INCs and DECs but not to UTCs. One of the PJM recommendations is to eliminate this asymmetry by extending the same uplift treatment to UTCs. The argument is based on allocation of uplift costs according to the deviations between real-time quantity and day-ahead schedules. This approach is particularly problematic for virtual transactions, which by design involve a 100% deviation.

There is no simple connection between deviations, uplift costs and market efficiency. Under a broader equilibrium analysis there can be conditions where there is no relationship between any of these components. Furthermore, the allocation of properly defined residual costs according to a cost causation argument can in itself be a contradiction. More importantly, the focus on uplift cost causation is misplaced. The important question is the aggregate net benefit of virtual transactions, not the residual cost. If virtual transactions increase the net benefits in the market, then there is no incentive-based reason to assign additional costs to virtual transactions. The iii criterion for assigning residual costs would then turn to doing the least damage to the performance of the market.

A better symmetric solution is to avoid any uplift allocation to virtual transactions. The residual cost allocation would then apply to real load; liquidity and entry in financial day-ahead virtual transactions would be enhanced; market power would be reduced; accurate price formation would be supported; and the efficiency of the overall PJM electricity market system should be improved. This reversal of the conventional wisdom follows from a broader framework than that applied by PJM for consideration of the costs and benefits of virtual transactions.

This broader framework builds directly on the basic principles of efficient electricity market design. Stepping back to consider first principles makes it easier to see the connections among the components of market design, in order to consider the function and benefits of virtual transactions from the perspective of aggregate market performance. PJM’s own analysis provides many examples of the contributions and effects of virtual bidding, but does not connect the examples to the broader framework of electricity market design principles. Furthermore, going beyond the uplift allocations, the PJM recommendations restricting the use of virtual transactions do not follow necessarily even from a narrower evaluation perspective. The principal problem PJM identifies with virtual transactions is a computational burden that would be only indirectly affected by uplift allocations, and could be addressed through other means with fewer negative consequences for the broader market design, such as by continuation of bidding budgets that allowed flexibility in the choice of virtual transactions.

Restricting explicit virtual bidding, as PJM proposes, creates market power for those who can make implicit virtual bids. Explicit virtual bidding mitigates or eliminates this market power, provides liquidity, improves price formation, allows hedging, connects naturally with longer term financial transmission rights, helps reveal defects in market design, and on average should improve system operations.

The PJM report appears in a context where virtual bidding is under attack. While a complete cost benefit analysis is not available, the PJM analysis can be expanded to enhance both the understanding of the role of virtual bidding and the policies that support overall electricity market efficiency.

Hogan, William W., Brendan Ring, and Grant Read. “Using Mathematical Programming for Electricity Spot Pricing.” In, 1996.Abstract
Recent moves around the world to introduce competition into electricity markets have created a need for mechanisms to determine electricity spot prices which provide good incentives for market coordination. Duality theory suggests that such prices can be found by solving a mathematical program. We derive implicit prices corresponding to an actual half.hourly dispatch of a full a.c. power system, and discuss the application of spot pricing in New Zealand and the United States.
Hogan, William W.A Wholesale Pool Spot Market Must Be Administered by the Independent System Operator: Avoiding the Separation Fallacy.” In, 1995.Abstract

Excerpt from the Introduction:

The notion of an Independent System Operator (ISO) has gained some currency in discussions of electricity market restructuring. There are significant advantages in this approach, but the key to success will be in a careful specification of the functions and responsibilities of the ISO. Simple independence of the individual participants is not enough; the ISO should support an efficient, competitive market. There is wide recognition that there must be a system operator coordinating use of the transmission system. This control of the use of the transmission grid means control of the dispatch, at least at the margin, because adjusting the dispatch is the principal (or, in some cases, only) means of affecting the flow of power on the grid. That this system operator should also be independent of the existing utilities is attractive in the greater simplicity of achieving equal treatment of all market participants. The ISO would be providing a service, but would not be competing in the energy market. Hence, the easy-to-state but hard-to-enforce principle of comparability would be transformed into an easier to enforce principle of non-discrimination.

Hogan, William W., and Susan Pope. “United States of America Before the Federal Regulatory Commission: Comments on Wholesale Competition in Regions with Organized Electric Markets.” In, 2007.Abstract

Excerpt from the Introduction: 

The Federal Energy Regulatory Commission is considering potential reforms to improve the operation of organized wholesale electric markets. The purpose of this paper is to discuss a larger framework for evaluating issues of regulation and market design in electricity markets. Regulation and competition are essential elements of electricity policy. The special requirements of electricity systems create a dual challenge: First, regulation must address issues of market design; markets cannot solve the problem of market design. Second, regulation must complement competition; inconsistent choices in either can undermine the foundations of reliable electricity supply at market prices and subvert the goals of organized electricity markets.

Organized electricity markets are developing with many advanced features that address the technical requirements of electricity systems. Initial defects in market design are being addressed in a continuous process of learning and improvement. As experience accumulates, inevitably problems arise that present challenges for regulators. In some cases, the problems can be addressed through the use of markets and incentives. In other cases, the problems require regulation and mandates. A critical task for the regulator is to provide a proper balance of regulation and markets. This challenge is complicated through the unintended consequences of decisions in each realm. Market design can have significant effects on the outcome of regulation. In turn, regulation can have significant effects on the operation of markets. Whenever regulators must act, there is a choice in the type of action. Big “R” regulatory solutions often call for mandates and subsidies for favored programs. Little “r” regulatory solution would emphasize reforms of market design to improve incentives or limits on regulatory mandates to support rather than replace market choices. Regulation may be unavoidable, but there is flexibility in the type of regulation.

A framework for evaluating issues of regulation and market design in electricity markets helps regulators identify regulatory choices that minimize the unintended consequences in markets, and identify market design features that can support the goals of regulation. A concern is that major regulatory decisions are being made without consideration of the interaction with markets and market design. The result is both a failure to resolve the immediate problems and collateral damage to operation of the market. The cycle precipitates more problems and more need for regulatory mandates to counter the effects of poor incentives in market design.

This is an avoidable problem. The discussion here illustrates the type of problems that arise in organized markets and provides examples of innovative approaches addressing the problems that balance regulation and market design.

Hogan, William W.Electricity Markets and the Clean Power Plan.” In, 2015. Publisher's VersionAbstract
The Environmental Protection Agency issued a final rule that defines a broad and complicated set of standards for controlling carbon dioxide (CO2) emissions from affected electricity generating units. (Environmental Protection Agency, 2015b) The proposed national average reduction by 2030 is 32% from the 2005 level of emissions, about half of which has already occurred. (Environmental Protection Agency, 2015j) The rules for new power plants are relatively straightforward and imply little more than reinforcing the current economic choice of natural gas over coal fired generation, given current projections for the price of natural gas. The Clean Power Plan rules for existing power plants arise under a different section of the Clean Air Act and present a more complicated picture. The result has implications for the nature and degree of future limitations on carbon dioxide emissions from the electricity sector. In addition, some versions of the possible implementation plans could have material implications for the operations of Regional Transmission Organizations under the regulations of the Federal Energy Regulatory Commission. The purpose here is to highlight some of the possible directions for relevant policies of electricity system operators.

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