Papers

Abstract — In this paper we apply the recently proposed Nodal Pricing and Amp-Mile tariffs for distribution networks to the case where a wind distributed generator is located in the network. The ability of this tariff structure to capture the real cost and benefits of DG is analyzed for this case of intermittent generation using real wind and network data from Uruguay and a standard wind turbine. A comparison is made in relation to the case with no DG placed in the network, to the case with controllable DG and to the case of intermittent DG of different capacity factors. We find that in expectation intermittent wind DG does little to reduce overall line losses or reduce peak line utilization. Consequently, under nodal pricing and amp-mile tariffs the intermittent wind resource collects very little additional revenue over the case where the intermittent wind DG source is simply paid the price of power exclusive of losses and is not compensated for freeing up network capacity

Excerpt from the Executive Summary:

A. Congressional Request The Energy Policy Act of 2005 (EPAct 2005)1 was designed to provide a comprehensive longrange energy plan for the United States. Section 1815 of the Act2 created an “Electric Energy Market Competition Task Force”3 (Task Force) to conduct a study of competition in wholesale and retail markets for electricity in the United States. Section 1815(b)(2)(B) required the Task Force to publish a draft final report for public comment at least 60 days prior to submitting the final report to Congress. The Task Force published the draft final report in June 2006 and sought comment on the preliminary observations contained in the draft. Based on those comments, and other input received earlier, the Task Force hereby submits this final report to Congress.

The development of adequate marketbased congestion management methods in continental Europe lags similar developments elsewhere, e.g. in the US. To achieve greater integration of the single European market, the EU countries were grouped into seven regions, one of which is Central East Europe (CEE). Based on publicly available data, a flow-based coordinated auction for this region is modeled and simulated to demonstrate different auction income distribution schemes. The model is a linear optimization problem which is solved in GAMS. It is based on a zonal model of CEE including 8 zones and 13 tie-lines. We show that the auction income distribution schemes as defined by the European Transmission System Operators (ETSO) in 2001 do not provide proper incentives. Additionally, the most efficient auction income distribution scheme differs with the chosen market structure. Therefore, an allocation procedure that is based upon the estimated flows according to the bids accepted appears to be an appropriate trade-off for all of the cases included in our analyses.

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.

By reducing system loads during critical‐peak times, demand response (DR) can help reduce the threat of brownouts and blackouts. DR is also widely regarded as having an important role in lowering power costs—and customer bills, by making organized wholesale power spot markets more competitive and efficient and less subject to the abuse of market power.  Consequently, there is common agreement among California’s energy policy makers, utilities, independent system operator and other interested parties that DR should be a key resource option.   The Brattle Group was engaged by the California Energy Commission—as part of the 2007 Integrated Energy Policy Report (IEPR) process—to gather inputs from a broad array of sources and to assess the accomplishments and shortcomings of DR activities in California. This assessment will explore the Energy Commission’s “load management” authority as a way to achieve higher levels of cost‐effective DR. The California Energy Action Plan II (EAP II) places DR at the top of the resource procurement loading order with energy efficiency (EE). It specifies that five percent of system peak demand be met by DR in 2007. However, despite significant past and continuing efforts by all of the parties, this goal is unlikely to be achieved.   How soon and whether the goal can be achieved are open questions. Despite California’s accomplishments in DR, the question remains: are new policy instruments necessary to expedite, extend and solidify the adoption of DR? This draft white paper is the first deliverable from this project. Its purpose is to define the current state of DR in California, laid out in this chapter, report key stakeholder observations and comments on DR policy, draw lessons learned from DR policy outside of California, both in the U.S. and internationally  and lay out ideas that could help move California forward.  

Harvard Kennedy School Insight, Interview with William Hogan on Electricity Policy. September 30, 2013.

PJM. Resource Investment in Competitive Markets: Technical Appendix." PJM Interconnection, May 5, 2016.

Prior to the 1990s, most electricity customers in the U.S. were served by regulated, vertically-integrated, monopoly utilities that handled electricity generation, transmission, local distribution and billing/collections. Regulators set retail electricity prices to allow the utility to recover its prudently incurred costs, a process known as cost-of-service regulation. During the 1990s, this model was dis- rupted in many states by “electricity restructuring,” a term used to describe legal changes that allowed both non-utility generators to sell electricity to utilities – displacing the utility generation func- tion – and/or “retail service providers” to buy electricity from gen- erators and sell to end-use customers – displacing the utility pro- curement and billing functions. We review the original economic arguments for electricity restructuring, the potential winners and losers from these changes, and what has actually happened in the subsequent years. We argue that the greatest political motivation for restructuring was rent shifting, not efficiency improvements, and that this explanation is supported by observed waxing and wan- ing of political enthusiasm for electricity reform. While electricity restructuring has brought significant efficiency improvements in generation, it has generally been viewed as a disappointment be- cause the price-reduction promises made by some advocates were based on politically-unsustainable rent transfers. In reality, the electricity rate changes since restructuring have been driven more by exogenous factors – such as generation technology advances and natural gas price fluctuations – than by the effects of restructuring. We argue that a similar dynamic underpins the current political momentum behind distributed generation (primarily rooftop solar PV) which remains costly from a societal viewpoint, but privately economic due to the rent transfers it enables.

Caplan, Elise. Responding to Prof. Hogan: APPA questions the benefits attributed to organized power markets." Fortnightly Magazine, February 2013

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.

Excerpt from the Executive Summary:

Organized wholesale electricity markets were created to address burgeoning costs of new power generation under the traditional regulatory scheme and to encourage innovation through free-enterprise competition. The discipline of the marketplace promised lower costs and greater efficiencies. Two decades of experience and numerous studies have demonstrated competitive wholesale markets in PJM and elsewhere bring increased operational efficiency and innovation, resulting from transparent market prices and the benefits of single, independent dispatch across a broad region. These benefits are realized through economies of scale that permit optimization of a large and diverse set of resources and load. The resulting efficiencies are measured in reduced heat rates and increased capacity factors.

However, as a host of organic and external factors change the power supply landscape, some have questioned the efficacy of competitive wholesale markets at promoting the most efficient entry and exit of resources – especially compared to traditional utility regulation with administrative planning and direction, such as under a state-integrated resource plan. Various forces, including federal and state public policies, low-priced domestic natural gas and static or declining levels of wholesale electricity consumption, have challenged incumbent or “legacy” generation resources by increasing operating costs, creating capital investment needs and reducing revenues realized in PJM’s energy, capacity and ancillary service markets. For the least efficient of these resources – older, small coal units, single-unit nuclear stations and older, high-heat-rate natural gas and oil-fired generation – these cost and revenue pressures have threatened their ongoing viability and not unexpectedly have led to retirements in many cases.

Consequently, some observers have questioned whether wholesale markets have forced premature retirements of viable legacy generating resources and whether markets can be relied upon to ensure adequate power supplies in light of the retirements. The questions raised with regard to decisions and outcomes related to the changing nature of the supply portfolio in PJM can be summarized as:

Can we rely on PJM’s organized wholesale electricity market to efficiently and reliably manage the entry and exit of supply resources as external forces create tremendous uncertainty and potential industry transformation?

The goal of this paper is to answer this question. In doing so, this paper does not present itself as an exhaustive or scientific analysis of what are complex issues characterized by numerous variables. In some cases, the value proposition brought to the generation investment decision by competitive markets can be shown with a high degree of confidence. In other cases, the relative advantage of a competitive versus a regulated paradigm in efficiently bringing in new generation and exiting inefficient generation is more arguable. Finally, certain challenges and difficult outcomes necessarily result from the operation of PJM markets in driving investment decisions – challenges and difficulties involving choices between often-competing social and political interests. In contrast, when investment decisions are driven by utilities and their regulators, a trade-off between diverging policy interests can be made directly and explicitly, though not necessarily from a well-informed understanding of the trade-off.

Excerpt from the Executive Summary:
This white paper (paper) describes the design of a new, distribution level market for energy and related electric products from Distributed Energy Resources (DER) and of a statewide digital Platform to animate and facilitate the financial transactions in that market. Tabors Caramanis Rudkevich (TCR) has prepared this paper as an input to the Reforming the Energy Vision (REV) proceedings of the New York State Public Service Commission (the Commission). The paper presents the rationale for establishing this new market structure, explains how the establishment of a digital platform would support the operation of the market, and describes the steps required to implement the Platform and Platform Market.

Detroit Edison's suit to halt the Michigan Commission's
limited retail wheeling experiment could result in two
ironies: (1) Edison may still be required to wheel power to
retail customers, but at rates less likely to be fully
compensatory, and (2) its generation will be more devalued
than it would have been without the suit.

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.

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.