Market Design

Find papers and presentations on all market design topics;

Capacity Markets, Competitive Market Models, ELMP, Financial Transmission Rights, investment incentives, lessons from abroad, lessons from other industries, LMP, price formation, regional transmission organizations, retail pricing, and. scarcity pricing.

 

Capacity Markets

Weiss, Jurgen. “Who's afraid of 100%?Utility Dive, 2020. Publisher's VersionAbstract
The articles describes 100% renewable/clean energy systems and argues that they may be less costly and easier to achieve than is often argued in the industry.
Hogan, William W.CarbonPricing inOrganizedWholesale Electricity Markets .” In, 2020. Publisher's VersionAbstract

Excerpt from the Introduction:

Thank you for the opportunity to participate in this technical conference. My comments here and during the conference are my own and do not represent the opinions of anyone else. The focus of my remarks will be on carbon pricing and the interactions with short-term electricity markets as found in the organized wholesale markets in the United States. I do not address the design and implementation questions focused on investments and resource adequacy that underpin capacity markets.

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Competitive Market Models

Panagiotis, Andrianesis, Michael C. Caramanis, and William W. Hogan. “Computation of Convex Hull Prices in Electricity Markets with Non-Convexities using Dantzig-Wolfe Decomposition.” In, 2020. Publisher's VersionAbstract
—The presence of non-convexities in electricity markets has been an active research area for about two decades. The — inevitable under current marginal cost pricing — problem of guaranteeing that no truthful-bidding market participant incurs losses in the day-ahead (DA) market is addressed in current practice through make-whole payments a.k.a. uplift. Alternative pricing rules have been studied to deal with this problem. Among them, Convex Hull (CH) prices associated with minimum uplift have attracted significant attention. Several US Independent System Operators (ISOs) have considered CH prices but resorted to approximations, mainly because determining exact CH prices is computationally challenging, while providing little intuition about the price formation rational. In this paper, we describe CH price estimation problem by relying on DantzigWolfe decomposition and Column Generation. Moreover, the approach provides intuition on the underlying price formation rational. A test bed of stylized examples elucidate an exposition of the intuition in the CH price formation. In addition, a realistic ISO dataset is used to suggest scalability and validate the proof-of-concept.
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Financial Transmission Rights

Transmission Risk Hedging Products: Solutions for the Market and Consequences for the TSOs.” In, 2006.Abstract

Executive Summary

In the framework of the EC Regulation 1228/2003, the goal of this background paper is to provide a description of the different market based solutions available for transmission risk hedging in congestion management. This paper presents three different transmission risk hedging products that can be offered to the market in the field of cross-border trade and congestion management. Due to various facts several price zones exist within the overall European electricity market where the demand of each zone is met in real time by the production of the respective zone and a zone specific market price is found (e.g. on the respective Power Exchange). This raises the question of how a market player wishing to buy electricity in a certain price zone and to sell it in another one can hedge the risk of a price difference emerging between those zones. This paper describes the three main kinds of transmission risk hedging products identified by ETSO: • Physical Transmission Rights (PTRs); • Financial Transmission Rights (FTRs); • Financial Contracts for Differences (CfDs); The paper also provides a first evaluation of the different solutions adopting a markets’ perspective. From a practical perspective, the implementation of forward PTRs only requires a minimum of market infrastructure and contractual arrangements. This is probably the reason for this product to be widely and successfully implemented on most European interconnections. However, Market Splitting or Coupling or co-ordinated implicit auctions would be the main prerequisite towards the implementation of marketbased FTRs and CfDs in Europe. Vice versa, in case Implicit Auctions (Market Splitting or Coupling) are introduced FTRs form a reasonable complement to those schemes for transmission hedging.

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Investment Incentives

Joskow, Paul. “Incentive Regulation in Theory and Practice: Electricity Distribution and Transmission Networks.” In, 2006.Abstract

Modern theoretical principles to govern the design of incentive regulation mechanisms are reviewed and discussed. General issues associated with applying these principles in practice are identified. Examples of the actual application of incentive regulation mechanisms to the regulation of prices and service quality for “unbundled” transmission and distribution networks are presented and discussed. Evidence regarding the performance of incentive regulation in practice for electric distribution and transmission networks is reviewed. Issues for future research are identified.

Brown, Ashley. “Developing Sustainable Regulatory Institutions in Developing Countries: Some Long Term Considerations for Investors.” In, 1998.Abstract
A discernible, and potentially destabilizing, irony has emerged in the pattern of infrastructure
privatizations and establishment of regulatory regimes in developing countries. Investor and
lender fears of political and regulatory risk may well be leading to risk mitigation strategies that
may, in the medium to long term, exacerbate the very risks to which investors were adverse in
the first place. While there are clearly risks besides political and regulatory matters with which
investors need to concern themselves, it is in seeking to protect themselves against those two
categories of potential problems that investors may do more harm than good to themselves and
the framework within which they operate in the long run.
The context of the irony is two fold, conceptual and historical. The conceptual aspect is the
appropriate equilibrium between investor, consumer, and public interests. The historical aspect
is the spectrum of past events within which the current wave of infrastructure privatizations are
occurring.
[...]
The first, and the most obvious, step to take is to provide a high level of service, a higher level
than had heretofore existed in the predecessor, publicly owned enterprise. One of the arguments
that proponents of privatization almost always make is that private ownership is more efficient
and more responsive to consumers than parastatal companies. It is simply foolhardy to behave in
ways that disprove those arguments. That is particularly the case where privatization has been
accompanied by reductions in staff and/or increases in rates. The private investor is well advised
to view itself as having a fiduciary obligation to increase efficiency. Merely cutting costs may be
good for the bottom line in the short run, but it is a perilous course politically and regulatorily if
it is not part of an overall program to increase efficiency in delivering a higher quality of service
to consumers. It is very difficult, if not impossible, to establish a pricing regime for newly
privatized entities that makes the subtle distinction between incentivising efficiency and
incentivising mere cost cutting. It is incumbent, therefore, on the investor to see the “big picture”
and produce a better product at lower cost rather than simply reducing its own costs regardless of
the consequences. In short, the investor needs to see the overall public interest in high quality service as being its own enlightened self interest.
 

Lessons from Abroad

Green, Richard, and Iain Staffell. “Richard Green and Iain Staffell - The Contribution of Taxes, Subsidies and Regulations to British Electricity Decarbonisation,” Working Paper.Abstract

Great Britain’s carbon emissions from electricity generation fell by two-thirds between 2012 and 2019, providing an important example for other nations. This rapid transition was driven by a complex interplay of policies and events: investment in renewable generation, closure of coal power stations, raising carbon prices and energy efficiency measures. Previous studies of the impact of these simultaneous individual measures miss their interactions with each other and with exogenous changes in fuel prices and the weather. Here we use Shapley values, a concept from cooperative game theory, to disentangle these and precisely attribute outcomes (CO2 saved, changes to electricity prices and fossil fuel consumption) to individual drivers. We find the effectiveness of each driver remained stable despite the transformation seen over the 7 years we study. The four main drivers each saved 19–29 MtCO2 per year in 2019, reinforcing the view that there is no ‘silver bullet’, and a multi-faceted approach to deep decarbonisation is essential.

Moen, Jan. “Regional Initiative: Which Appropriate Market Design?” In, 2009.Abstract

Moen, Jan. Regional Initiative: Which Appropriate Market Design? European University Institute, Robert Schuman Center for Advanced Studies, Florence School of Regulation. November, 2009. 44 pages.

 

The European Union has a long experience and many success stories when it comes both to build a borderless Europe and to ensure that benefits are fairly distributed among producers and end-use customers. In some sectors results and benefits arise quickly, but sometimes borders remain difficult to cross despite numerous initiatives. A typical example of this is the completion of the single market for electricity. The process has been ongoing since the early 1990s and major progress has been made. However, we are still far from a borderless and truly competitive electricity market across Europe. A new legislative framework, the Third Package, will enter into force shortly and yield strong expectations. However, growing concerns become apparent among policy makers and in the market place on its ability to effectively foster the completion of the internal market and tackle market power issues. This paper argues that the approach adopted in the Third Package is not adapted to the challenges the European Union faces in electricity. The current lack of focus on implementing a better market design architecture leads the EU regulatory framework to overlooks important issues such as the promotion of power exchanges. The paper reviews the current state of the art on ‘smart’ market design in the economic literature and confronts it with the concrete experiences pursued at the regional level, in the European Union and beyond. Some of the issues discussed in depth include the TSOs’ roles and institutional design, generation adequacy and the design of capacity mechanisms and the development of demand-side response programs. It shows that the EU should learn from some of the on-going initiatives pursued at the domestic and regional level and that a sound market design based on a pool/TSO central dispatch is probably the way forward.

 

Anderson, Edward J. “Mixed Strategies in Discriminatory Divisible-good Auctions.” In, 2009.Abstract

Anderson, Edward J. , Pr Holmberg and Andrew B. Philpott. Mixed Strategies in Discriminatory Divisible-good Auctions. IFN Working Paper No. 814, 2009. 72 pages.

Using the concept of market-distribution functions, we derive general optimality conditions for discriminatory divisible-good auctions, which are also applicable to Bertrand games and non-linear pricing. We introduce the concept of offer distribution function to analyze randomized offer curves, and characterize mixed-strategy Nash equilibria for pay-as-bid auctions where demand is uncertain and costs are common knowledge; a setting for which pure-strategy supply function equilibria typically do not exist. We generalize previous results on mixtures over horizontal offers as in Bertrand-Edgeworth games, but more importantly we characterize novel mixtures over partly increasing supply functions.

 

 

Brown, Ashley. “Regulation and Electric Restructuring Policy Note: Follow Up to Moscow Visit of July 12-15, 2005 and Workshop of July 14, 2005.” In, 2005.Abstract

Excerpt from the Introduction:

In January 2004, a World Bank (WB) mission, including both WB staffers and two outside consultants, visited Moscow to review the proposal of RAO-UES, , the stateowned electric utility, to restructure the Russian power sector in ways that would promote competition and render the sector more efficient. The objective of the WB mission was to produce two Policy Notes, one on market design, and the other on regulation. After extensive review of documents and meetings with a broad array of critical players in the market, as well as interaction with Russian counterparts, the Policy Notes were written in June 2004. Those papers, based on the submissions of the two outside consultants (Larry Ruff for market design and Ashley Brown for regulation), were distributed within the Russian power sector.

Schubert, Eric, Sam Zhou, Tony Grasso, and Grace Niu. A Primer on Wholesale Market Design, 2002.Abstract

This white paper is a primer on wholesale market design and provides background for the open meeting workshop scheduled by the Public Utility Commission of Texas for November 1, 2002. The paper is divided into six sections:

1. Reasons for this rulemaking;

2. Measures of an efficient, sustainable market;

3. Architecture of power markets;

4. Elements of a power market;

5. Basic economics of congestion management and day-ahead markets;

6. Descriptions of wholesale electric markets around the world.

Fabra, Natalia, Nils-Hendrik von der Fehr, and David Harbord. “Designing Electricity Auctions: Uniform, Discriminatory and Vickrey.” In, 2002.Abstract

Fabra, Natalia, Nils-Hendrik von der Fehr and David Harbord. Designing Electricity Auctions: Uniform, Discriminatory and Vickrey. 9 November 2002. Paper, 37 pages.

Motivated by the new auction format introduced in the England and Wales electricity market and the recent debate in California, we charac- terize bidding behavior and market outcomes in uniform, discriminatory and Vickrey electricity auctions. The aim is to gain an improved under- standing of how different auction formats affect the degree of competition and overall welfare in decentralized electricity markets. We find that the uniform auction is (weakly) outperformed in consumer surplus terms by the discriminatory auction, but that uniform auctions are (weakly) more efficient. Vickrey auctions guarantee productive efficiency, but at the expense of large payments to firms. The overall welfare ranking of the auctions is thus ambiguous. The paper also clarifies some methodological issues in the analysis of electricity auctions. In particular we show that analogies with continuous share auctions are misplaced so long as firms are restricted to a finite number of bids. We also provide a characterization of multi-unit Vickrey auctions with reserve pricing.

 

 

LMP

Gavan, John C., and Rob Gramlich. John C. Gavan and Rob Gramlich - A New State-Federal Cooperation Agenda for Regional and Interregional Transmission, 2021. Publisher's VersionAbstract

Excerpt from the Introduction:

The experience of grid operators and planners in the United States and around the world has shown that both decarbonization and power system resilience will require large-scale regional and inter-regional trans- mission expansion. In the United States, transmission planning, cost recovery, and siting are all subject to both state and federal jurisdiction. To meet the challenge of expanding transmission to implement decarbonization, the Federal Energy Regulation Commission (FERC) and the National Association of Regulatory Utility Commissioners (NARUC) recently announced the Joint Federal-State Task Force on Electric Transmission to focus on this issue.1 Resolving issues of siting and cost recovery for interstate electric transmission lines will encourage constructive state-federal cooperation. The task force and related regional and national coordination among the states, FERC, the Department of Energy (DOE), and federally regulated transmission providers will be critical to ensuring a resilient and clean power system.

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.

Group, Energy Policy. “Competition in Bilateral Wholesale Electric Markets: How Does It Work?” In, 2016.Abstract

Intorduction:
In one of the first laws establishing regulation of the electric utility industry, the Federal Power Act of 1920 (FPA) there was a recognition that there were two types of transactions commonly entered into in the industry that would be subject to regulation - with a different regulatory regime for each. Retail sales, or sales directly to customers who consumed the power themselves were deemed to be intra-state sales to be regulated by the states. But any sale for resale, i.e. a sale from any generating entity to a second entity that resold the power, was deemed to be an inter-state sale subject to regulation by the Federal Energy Regulatory Commission (FERC). This paper deals with the latter type of electric sale – wholesale sales regulated by the federal government. Up until the mid-1990’s, most wholesale sales were between vertically-integrated and state-franchised utilities, either short-term to take advantage of one utility having cheaper power at a moment in time than another utility, or longer term to provide needed capacity to the purchasing utility. Both of these types of transactions were mostly conducted under bilateral contracts between the buyer and the seller – the contracts being submitted to FERC for approval according to the statutory framework of the FPA.1 Until the mid-1990’s, short-term transactions were typically conducted on a split-savings basis, meaning the savings resulting from the transaction were evenly split between the buyer and seller. Longer-term transactions were typically cost-based, with the seller allowed to earn a regulated return on the sale.

For a variety of reasons beginning in the mid-1990’s there was a development of a new type of market, made possible by the deregulation or restructuring process which for the first time allowed retail customers in some states to choose their electric supplier. It was thought at the time that effective retail competition required utilities to divest all or some of their power plants to third parties. At the same time, changes in Federal law and regulation were making it considerably easier for third parties to enter generation markets and have guaranteed access to utility transmission systems. Thus new wholesale markets began to be developed in many regions of the country

Because of concerns about fairness, these new markets formed around independent system operators or regional transmission organizations independent of the transmission and generation owners in their regions. These regional operators also adopted a new form of wholesale market for their regions, a centralized market based on bids submitted to the market operator from individual generators. These bid-based centralized markets utilized locational marginal pricing (“LMP”), whereby generators bid at their location into a centralized market and bids are accepted or rejected based on projected electricity needs for the relevant period. While 

generators are dispatched from lowest-cost bid to highest-cost bid up until the point that expected demand plus a reasonable margin is satisfied (and reliability constraints are recognized,) all successful bidders receive the highest priced successful bid at their location.

Another feature of these new LMP markets is that rather than charging for transmission service based on a contract path, users of the transmission system were to pay congestion charges based on the difference in locational prices between the point of injection and the point of receipt (i.e., the location of the seller and the location of the buyer). Market participants were either allocated, or had to buy through auctions, so called financial transmission rights (“FTRs”) which give them rights to use the transmission system without paying congestion charges. In this way, market participants could hedge their transactions by owning FTRs.

The theoretical basis of LMP markets is that individual generators bid into the market at their marginal cost (the cost of producing their next kilowatt-hour) because to bid less would result in their losing money if they were to win the bid and have to generate and to bid more might mean that they don’t get dispatched even though the transaction would be profitable to them. The market operator (RTO or ISO) chooses winning bidders based on the lowest cost combination of bids that can be dispatched in real time within reliability constraints. Thus, in theory, generators presumably will have incentives to operate as efficiently as possible, because only the lowest cost generators get paid, and their profitability depends on getting dispatched and having costs below the LMP. Profits are simply the difference between the LMP paid to all generators at a given location and the generators actual cost for the period for which its bid was submitted. These bid-based LMP markets are most often referred to as “organized” wholesale markets or “centralized” wholesale markets. This paper refers to centralized markets, as the term “organized’ gives a false impression that other markets types are not organized.

 

 

Brown, Ashley, and Jim Rossi. “SITING TRANSMISSION LINES IN A CHANGED MILIEU: EVOLVING NOTIONS OF THE “PUBLIC INTEREST” IN BALANCING STATE AND REGIONAL CONSIDERATIONS.” In, 2008.Abstract

Excerpt from the Introduction:

The paper proceeds in four parts. Part I, of course, is the Introduction and Background. Part II describes the existing arrangements in the States of Colorado, New Mexico, Utah, and Wyoming for siting new transmission lines, and the coexistence of those arrangements with a conventional understanding of the public interest in determining need and addressing environmental concerns under traditional state siting laws affecting transmission. Part III discusses transmission issues related to the competitive wholesale market and increased attention to climate change and highlights how federal law has expanded to accommodate some of these concerns. Part IV emphasizes the need for a new definition of the public interest which might better reflect these new market circumstances and opportunities, and highlights the two main barriers to this: 1) legislative and/or regulatory inertia and 2) an outdated cost-allocation model. The public interest under most state siting statutes is sufficiently capacious to give regulators some flexibility to evolve, but in other instances legislative action may be needed. In addition, the state cost-of-service ratemaking model must evolve to a more regional approach to allocating the costs of new transmission.

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Regional Transmission Organizations (RTO)

The Clean Power Plan Endangers Electric Reliability: RTO and ISO Market Perspectives.” In, 2015.Abstract

Excerpt from the Executive Summary

Background

The Environmental Protection Agency’s proposed Clean Power Plan (CPP), published in June 2014, raises substantial operational challenges for regional transmission organizations (RTOs). In the CPP, EPA specifies emission reduction targets for 49 of the 50 states, based on EPA’s modeling that purportedly shows that each state can achieve the specified reduction targets through the use of four “building blocks.” States are to develop plans to meet the targets between 2020 and 2030, and are offered “flexibility” to use any combination of the four building blocks specified and/or other means (if approved by EPA) to achieve these targets. The State plans – required by June 30, 2016 (unless an extension is granted) - must specify how each state intends to meet the targets.

While there are many issues, questions and concerns with the ability of states and utilities to meet EPA’s emission reduction targets based on the use of EPA’s four building blocks (or through other means), building block 2, in particular, raises substantial issues for systems operators and RTO/ISO market operations because it involves changing the current methods of how electricity is dispatched throughout the nation’s bulk power systems.

Either FERC or the states have always overseen how security constrained economic dispatch is conducted to maintain reliability while cost-effectively serving customers. But, if EPA’s proposed rule becomes final, it, and not the system operators that federal and state regulators have entrusted, will make such critical decisions for our nation’s utility customers regardless of costs.

NYISO Governance.” In, 2015.Abstract
Bie, Ave. NYISO Governance." Presentation to the Harvard Electricity Policy Group 78th Plenary Session, Half Moon Bay, CA, March 2015."
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Retail Pricing

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Scarcity Pricing

Kelly, John. “Dynamic Pricing.” In, 2016.Abstract
Kelly, John. Dynamic Pricing." Presentation to the Harvard Electricity Policy Group's 83rd Plenary Session. Cambridge, MA, June 2, 2016."
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Uplift

Gavan, John C., and Rob Gramlich. John C. Gavan and Rob Gramlich - A New State-Federal Cooperation Agenda for Regional and Interregional Transmission, 2021. Publisher's VersionAbstract

Excerpt from the Introduction:

The experience of grid operators and planners in the United States and around the world has shown that both decarbonization and power system resilience will require large-scale regional and inter-regional trans- mission expansion. In the United States, transmission planning, cost recovery, and siting are all subject to both state and federal jurisdiction. To meet the challenge of expanding transmission to implement decarbonization, the Federal Energy Regulation Commission (FERC) and the National Association of Regulatory Utility Commissioners (NARUC) recently announced the Joint Federal-State Task Force on Electric Transmission to focus on this issue.1 Resolving issues of siting and cost recovery for interstate electric transmission lines will encourage constructive state-federal cooperation. The task force and related regional and national coordination among the states, FERC, the Department of Energy (DOE), and federally regulated transmission providers will be critical to ensuring a resilient and clean power system.

Green, Richard, and Iain Staffell. “Richard Green and Iain Staffell - The Contribution of Taxes, Subsidies and Regulations to British Electricity Decarbonisation,” Working Paper.Abstract

Great Britain’s carbon emissions from electricity generation fell by two-thirds between 2012 and 2019, providing an important example for other nations. This rapid transition was driven by a complex interplay of policies and events: investment in renewable generation, closure of coal power stations, raising carbon prices and energy efficiency measures. Previous studies of the impact of these simultaneous individual measures miss their interactions with each other and with exogenous changes in fuel prices and the weather. Here we use Shapley values, a concept from cooperative game theory, to disentangle these and precisely attribute outcomes (CO2 saved, changes to electricity prices and fossil fuel consumption) to individual drivers. We find the effectiveness of each driver remained stable despite the transformation seen over the 7 years we study. The four main drivers each saved 19–29 MtCO2 per year in 2019, reinforcing the view that there is no ‘silver bullet’, and a multi-faceted approach to deep decarbonisation is essential.

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