Market Design

This paper examines carbon tax design options in the United States using an intertemporal computable general equilibrium model of the world economy called G- Cubed. Four policy scenarios explore two overarching issues: (1) the effects of a carbon tax under alternative assumptions about the use of the resulting revenue, and (2) the effects of a system of import charges on carbon-intensive goods (“border carbon adjustments”).

Klein, Abram W. "Competitive Electricity Markets: Weening Markets from Rent-Seeking Subsidies and Capacity Markets," presented at Nodal Trader Conference, New York, NY, October 26, 2017

Bushnell, James; Flagg, Michaela; Mansur, Erin. Working paper: Capacity Markets at a Crossroads. Energy Institute at Haas, April 2017.

Bushnell, James; Flagg, Michaela; Mansur, Erin. Working paper: Capacity Markets at a Crossroads. Energy Institute at Haas, April 2017.

Centolella, Paul. The Impact of Missing Price Signals." Presentation to the Harvard Electricity Policy Group's 83rd Plenary Session. Cambridge, MA, June 2, 2016."

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

Terry, Cheryl. Hidden Value, Missing Money, and Electricity Markets." Presentation to the Harvard Electricity Policy Group's 79th Plenary Session, Washington, DC, June 2015."

EXCERPT FROM THE EXECUTIVE SUMMARY:

 

This paper is part of an effort to evaluate matters affecting price formation in the energy and ancillary services markets operated by Regional Transmission Operators (RTOs) and Independent System Operators (ISOs) subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC or Commission). It focuses on operator-initiated commitments in the RTOs and ISOs and the challenges in internalizing all relevant physical and operational constraints in the day-ahead and real-time market processes. This paper defines an operator-initiated commitment as a commitment that is not associated with a resource clearing the day-ahead or real-time market on the basis of economics and that is not a self-schedule. Deeming an action to be “operator-initiated” is not intended to confer any judgment that the action is not appropriate or necessary to maintain reliability.

 

—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.

Hogan, William. Electricity Market Design: Financial Transmission Rights." Presentation to the CIDE Electricity Policy Group. Mexico, April 14, 2016.

Wissman, Kim. "FERC’s Planning and Cost Allocation Guidelines: Will They Alter the Dynamics of Siting Multi-State Transmission Lines?" Presentation to the Harvard Electricity Policy Group Sixty-Fourth Plenary Session. Nashville, TN, September 22, 2011.

Coscia, Carl. Constellation Energy: Comments on Proposed OTC Reforms. Presentation to the Harvard Electricity Policy Group, Fifty-Ninth Plenary Session. Cambridge, MA. May 20, 2010. 10 pages.

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.

Bodmer, Edward. The Deregulation Penalty: Losses for Consumers and Gains for Sellers. A Report to the American Public Power Association, May 2009. 20 pages. Appendices, 25 pages.

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.

The Electricity Commission of New Zealand. Transmission Pricing Review. 2009.

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. , 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.

 

 

Hemmingway, Roy. Independence of Regulatory Decisions in New Zealand. 30 November 2006. Presentation, 8 pages.

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.

Andersson, Bo. Retail Competition: Experiences From Scandinavia. 22 September 2005. Presentation, 18 pages.

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. 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.

 

 

Fernandez-Ordonez, Miguel. Retail Competition in Spain. 22 May 2000. Presentation.

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.

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.

 

 

EXCERPT FROM THE INTRODUCTION:

On March 15, 2011, the Federal Energy Regulatory Commission released Order 745. The pur- pose of the Order was to require that demand response (DR) resources participating in RTO or ISO markets are paid at the locational marginal price when such resources contribute to the supply-demand balance as a substitute for generation and when the demand response resources pass a net benefits test defined in the order.

Bowring, Joseph. Challenges for Market Monitors." Presentation to Harvard Electricity Policy Group, 63rd Plenary Session, Washington, DC. June 2, 2011. 22 pages."

LaPlante, David. ISO/RTO Market Monitoring Structure and Challenges." Presentation to Harvard Electricity Policy Group, 63rd Plenary Session, Washington, DC. June 2, 2011. 15 pages."

Harvey, Scott. The Evolving Role of Market Monitors in the Electricity Industry." Presentation to Harvard Electricity Policy Group, 63rd Plenary Session, Washington, DC. June 2, 2011. 17 pages."

Patton, David. Independent Market Monitoring: Current Issues." Presentation to Harvard Electricity Policy Group, 63rd Plenary Session, Washington, DC. June 2, 2011. 6 pages."

MISO ELMP filing, December 22, 2011.

Gribik, Paul. Investigation of Convex Hull Pricing at Midwest ISO. Presentation to the Harvard Electricity Policy Group, October 1, 2009. 16 pages.

Rothleder, Mark. Briefing on Exceptional Dispatch. Presentation to the Harvard Electricity Policy Group, October 1, 2009. 10 pages. 

An overview of the exceptional dispatch policies of the CAISO.

 

Pfeifenberger, Johannes, Kathleen Spees, and Adam Schumacher. A Comparison of PJMs RPM with Alternative Energy and Capacity Market Designs. Prepared by The Brattle Group for PJM Interconnection, LLC. September, 2009. 90 pages.

Compete Coalition. Study Finds Alternative Power Market Proposals Reflect Fundamental Misunderstandings of RTO Markets. News release, April 16, 2009.

IRC 2009 State of the Markets Report. September, 2009. 35 pages.

California ISO Launches New & Improved Markets. News release, April 1, 2009.

Kelly, Susan. RTO Performance, or - "What's My Motivation Here" Presentation to the Harvard Electricity Policy Group 53rd Plenary Session, December 11, 2008. 14 pages.

Ludwigson, Jon. Oversight of RTO's. Presentation to the Harvard Electricity Policy Group 53rd Plenary Session, December 11, 2008. 13 pages.

Electricity Restructuring: FERC Could Take Additional Steps to Analyze Regional Transmissions Organizations' Benefits and Performance. GAO Report to the Committee on Homeland Security and Governmental Affairs, U.S. Senate. September 2008, 96 pages.

Glazer, Craig. RTO Accountability: The Mission and the Measurement. Presentation to the Harvard Electricity Policy Group 53rd Plenary Session, December 11, 2008. 26 pages.

Bushnell, James. The Implementation of California AB 32 and its Impact on Wholesale Electricity Markets. August, 2007. Paper, 20 pages.

Woodfin, Dan. Competitive Renewable Energy Zones: Texas' Solution to the Poultry Dilemma? 16 March 2007. Presentation, 15 pages.

Excerpt from the introduction:

The New York Independent System Operator (“NYISO”) asked Analysis Group to conduct a study that would measure the costs and benefits associated with various aspects of the restructuring of the wholesale power market in New York. Our economic study focuses on certain key changes in operational performance of the power system during the initial years following the start-up of the NYISO. NYISO began operation at the end of 1999, as part of the larger process to restructure the electric industry in New York State. At the wholesale level, restructuring included both changes in the institutions responsible for grid operation and in the dispatch and market rules implemented by the NYISO, as well as major changes in the ownership of generation assets. These combined changes – especially the new market rules that paid generators market clearing prices – created strong profit incentives for improving operational performance of power plants. We look at the effect of these changes. There were many other changes in the industry as well, not all of which are amenable to quantitative assessment. To assess these larger changes in the economic environment, we examine broad measurable changes in wholesale power market performance, although we do not suggest that we have examined all factors comprehensively. Our spotlight focuses on the effects of changes in power plant dispatch rules and practices, and in incentives for improvement performance of generating units.

Ott, Andrew. Transmission Expansion Analysis. 31 May 2007. Presentation, 12 pages.

Adams, Kurt. Beneficiaries Pay: Why and How Much? 31 May 2007. Presentation, 14 pages.

Jaeger, Doug. Beneficiaries of Transmission Expansion: Who, Where, When and How Much? 31 May 2007. Presentation, 17 pages.

Moeller, Clair. Electrical Transmission Tariffs: Who Benefits, Who Pays, and Who Decides? 31 May 2007. Presentation, 8 pages.

Riousa, Vincent, Jean-Michel Glachant, Yannick Perez, Philippe Dessante. The diversity of design of TSOs.

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.

Ott, Andrew. HEPG Discussion: RTO: Fox or Hedgehog? 30 November 2006. Presentation, 10 pages.

Executive Summary

The potential benefits of wind power as a clean, renewable, economic, domestically avail- able power source have captured the attention of energy policy leaders, consumers, and the electricity industry. The United States (US) has tremendous wind energy resources. California is viewed as one of the leaders in the modern US wind industry in terms of capacity installed; however, 16 other states have even greater wind potential. Only a small portion of that potential has been tapped. The US currently derives approximately 1% of its electricity from wind power, whereas parts of Europe use wind power to meet up to 25% or more of their electricity needs.

In 2005, wind power in the US grew rapidly and became more competitive as volatile natu- ral gas prices increased and crude oil prices reached record highs. Improved technology, federal tax credits and public policies that encourage utilities to use clean energy sources helped fuel the growth from coast to coast. Projections are that US wind capacity could reach 100 gigawatts (GW) by 2020, meeting 6% or more of national electricity needs.1

The objective of this paper is to examine the transmission policy issues around wind and renewable sources of generation. Reliability and commercial issues are reviewed, both in the US and abroad, and recommendations are provided for effective integration of wind sources into the US electric system. Key findings of this paper are:

■ Over-reliance in the US on any one fuel type results in reliability and economic consequences, highlighting the benefits of diversified energy resources.

■ Wind generation is becoming an economic power source, and has the further benefit of mitigating environmental climate change concerns.

■ In order to tap the vast potential of new generation sources such as wind power in the US, we must address the existing challenges in generator interconnection and trans- mission cost and planning policies.

■ The current US transmission system was not built to support competitive regional markets nor is it sufficient to integrate planned and potential new generation sources; additional transmission infrastructure will be required.

■ Operating techniques for intermittent generation resources, properly structured market rules, and effective transmission policies for regional planning, cost allocation, and cost recovery and incentives will help to facilitate wind power as well as other new sources of generation.

■ Transcos (for-profit independent transmission companies) focus on delivering low-cost reliable energy to consumers by facilitating robust electricity markets and providing transmission access to new generation sources including renewable energy. Because of their for-profit structure, a further advantage is that Transcos can be held firmly accountable by regulators for system performance and operating costs.

■ Robust transmission infrastructure policies in countries outside the US have helped them progress toward achieving their goals for renewable sources of energy while maintaining system reliability. The challenges to effective integration of wind power in the US are not insurmountable; they can be addressed with industry, public, and regulatory commitment.

■ Several countries, including Denmark, Germany, Spain and the UK have had coordinated government efforts and policies to facilitate wind power, and these are proving very effective. Some areas of North America, such as Alberta and Texas, are also employing planning and cost allocation policies that are helpful to new generation sources.

Specific recommendations for changes needed to take advantage of US renewable resources to the benefit of electricity market users and customers are:

■ Employ greater use of available operational techniques, such as wind forecasting tools, for reliable operation of wind resources;

■ Properly structure market rules to address imbalance and capacity value in a manner that reliably and economically facilitates renewable generation sources;

■ Engage industry and stakeholders in long-term, robust, and comprehensive regional planning for transmission infrastructure, including infrastructure needed for new sources of generation;

■ Incorporate economic and customer cost metrics, in addition to reliability, into regional planning processes;

■ Implement workable cost-allocation and recovery mechanisms to recoup the costs of transmission infrastructure improvements;

■ Provide regulatory incentives for transmission infrastructure investment and independent ownership/operation of the nation’s transmission system.

Mohre, David. The Need For A Changed Vision For RTOs. 2 June 2006. Presentation, 14 pages.

Laughlin, Kenneth. Regional Transmission Organizations. 2 June 2006. Presentation, 14 pages.

Mansour, Yakout. RTOs/ISOs: The Creature and the Creator; The Benefit/Cost of Having Children. 2 June 2006. Presentation, 5 pages.

Excerpt from the Introduction:

The ERCOT Independent System Operator (ISO) is the independent, not-for-profit organization responsible for the reliable transmission of electricity across Texas' interconnected 37,000-mile power grid. The ERCOT ISO has the responsibilities of ensuring reliable power grid operations in the ERCOT region jointly with the electrical energy industry organizations that operate within that region, ensuring open access to transmission ERCOT wide and distribution systems in areas permitting competition, ensuring the timely conveyance of market information to market participants, and ensuring accurate accounting of power produced and delivered.
To support these roles the ERCOT ISO focuses on the development, implementation, and ongoing management of reliable market and operating systems, transmission planning, retail mechanics supporting retail choice, accountable and reliable wholesale settlement and billing systems, and financial risk strategies. 4 ERCOT members serve about 85% of the electrical load in Texas, and have an overall generating capacity of approximately 75,000 Megawatts (MW). Because ERCOT is located entirely within Texas, the Public Utility Commission of Texas (PUCT) is the principal regulatory authority. As of January 2005, ERCOT membership consists of 17 Industrial Consumers, 3 Retail/Commercial Consumers, 41 Electric Cooperatives, 16 Independent Generators, 19 Independent Power Marketers, 36 Independent Retail Electric Providers, 8 Investor Owned Utilities, and 19 Municipal Owned Utilities.

Centolella, Paul. The Impact of Missing Price Signals." Presentation to the Harvard Electricity Policy Group's 83rd Plenary Session. Cambridge, MA, June 2, 2016."

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