Bulk Power Markets in the United States: Challenges and Recommendations

Report to the Office of Energy Policy and Systems Analysis U.S. Department of Energy Washington, DC. by The Boston University Institute for Sustainable Energy Peter Fox-Penner Courtney Guard

Rachel Eckles

June 10, 2016 working paper 16001

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

Report to the Office of Energy Policy and Systems Analysis U.S. Department of Energy Washington, DC.

by Peter Fox-Penner Courtney Guard Rachel Eckles

June 10, 2016

Acknowledgement: Thanks to Michelle Ben-Aroch and Heidi Bishop for assistance.

Table of Contents

I. Introduction and Summary 1

II. Brief History of the Bulk Power Marketplace 3

III. Overview of the Bulk Power Markets Today 5

IV. The Role of Bulk Power Markets and Other Elements of Agreement 8

V. Challenges Facing Today’s Bulk Power Markets 9

VI. Conclusion: Strategies and Options for the Department of Energy 17

Appendix 19

Bibliography 20

I. INTRODUCTION AND SUMMARY

For almost 150 years the United States has been powered by a large-scale power network consisting of large power plants and a high-voltage transmission network. This system generates and delivers nearly all of the power consumed in the U.S. today and similar amounts in most of the world’s developed economies.1 This system, often referred to as the bulk power grid, connects to approximately 4,000 low-voltage distribution systems that deliver power over the “last mile” and also integrate a growing number of relatively small “distributed energy resources” (DERs).

As explained further in Section Three, there are a wide variety of power market arrangements across our bulk power grid. In many parts of the country, power marketers and other market participants buy and sell power bilaterally and through exchanges and auctions. Long-term bilateral agreements are also made, often at market-based rates and sometimes as the result of competitive procurements. In seven regions of the country there are a staged series of short term energy markets often referred to as the “organized” or centralized power markets. These markets typically have a Day-Ahead, Same-Day, and Real-time energy market, each of which plays a specific but overlapping role optimizing the short-term use of the regional grid. Finally, in several organized markets there are also capacity and ancillary services markets created to assure resource adequacy (RA), i.e. that the total electric resources in a region will always be sufficient to meet immediate demand.

These markets and the system they support are now facing unprecedented challenges. The industry is in a period of technological upheaval sparked by the need to shift away from carbon- based fuels, the growth of distributed generation, and reductions in the cost of electricity storage. In addition, the industry is facing low-to-no growth in bulk power sales,2 cybersecurity and physical protection requirements, and greater demands for resilience. As FERC Commissioner Cheryl LaFleur recently noted, “this is probably the toughest time for markets since they were created 15 to 20 years ago. We’re in a major investment cycle that is testing both the centralized capacity markets that some of the eastern regions use to allocate capital to bring in reliability for the future and also stressing the energy markets that reflect real-time energy costs.”3 This White Paper reports on the results of an inquiry into the future of the bulk power markets as part of the second installment of the Quadrennial Energy Review (QER) of the United States. The main focus of the inquiry was a workshop held to solicit the views of a wide range of key stakeholders involved in the U.S. power

1 As of 2015, the grid delivered about 99% of all U.S. electrical energy consumed. International Energy Agency, PVPS 2014 National Report. 2 The total power delivered by the bulk power system and its markets will likely be diminished steadily over the next few decades by the growth of DERs, which use the local grid but not the bulk power system, and by continued progress in energy efficiency. While the total quantity of electricity services is likely to increase for the foreseeable future, growth in power supplied by the bulk power grid is highly uncertain. 3 “LaFleur Confident Wholesale Markets Can Evolve.” Jasmin Melvin, April 15, 2016. 1

sector.4 The workshop, as well as materials collected and circulated prior to and after the workshop, provide a very thorough picture of the current challenges and opportunities faced by large-scale markets. The purpose of this report is to:

 Summarize the views of stakeholders on the bulk power markets;  Discuss the points of consensus and disagreement on the challenges facing these markets; and  Provide options and directions the Department of Energy may consider incorporating into the forthcoming QER.

In summary, we conclude that the bulk power market landscape in the United States is functioning reasonably well despite its enormous complexity, diversity, and multiple challenges. Electricity continues to be quite reliable, affordable, and increasingly compliant with greenhouse gas and other environmental policies. However, in every section of the country, these markets face very large challenges that call for national policy improvements, research, and technical assistance. In particular, a considerable body of research and the Department’s stakeholders suggest that QER 1.2 consider the following recommendations: ● Increased focus on technical assistance and advocacy at FERC to promote better transmission planning, especially for interregional transmission projects that play an essential role assisting states and regions in their compliance with the Clean Power Plan, state and federal renewable policies, and other national policy goals. In this context, transmission planning includes the methods by which costs and benefits are considered in the planning process and improvements in the siting process. While not strictly a planning issue, assistance with cost allocation approaches for major transmission projects is also an area of potentially important Departmental support. ● Use of the Department’s convening and research capabilities to help stakeholders resolve the tensions that have emerged between the role of capacity markets, long term contracts, and environmental goals such as greenhouse gas targets. These three factors interact in different ways in different regions of the country, but in nearly every regions there are opportunities for important improvements. ● The Department should continue to provide R&D support for generation and transmission technologies, promote fuel diversity, and provide research and technical assistance on the application of markets and other policies to CPP compliance and other policy needs.

The remainder of the paper is organized in six sections. Following a brief history of the bulk power markets we provide a very brief overview of these markets as they exist today. The third section following, which is longest and most important, summarizes the challenges and opportunities stakeholders discussed during the workshop and in related communications. The fourth section of the white paper describes the points of consensus among stakeholders concerning these challenges

4 The workshop was held March 4 2016 at the National Press Club in Washington, DC. The workshop adopted Chatham House rules, so no speaker’s views described in this white paper will be associated with any individual’s name. The materials circulated prior to or at the workshop are all referenced in the bibliography. 2

and the Department’s contribution to addressing them. The final section offers additional options and considerations for the Department as well as concluding thoughts.

II. BRIEF HISTORY OF THE BULK POWER MARKETPLACE

From the very inception of the bulk power grid, utilities used it to trade large amounts of power for periods as short as an hour or as long as several decades. However, these trades were made exclusively at cost-based rates. Because they were trades between utilities, who would then resell the power to ultimate retail customers, these trades were considered wholesale sales, or sales for resale, and therefore subject only to regulation by the Federal Energy Regulatory Commission (FERC) rather than state utility regulators. The two most common products traded were bulk electrical energy, often loosely referred to as power, and electricity capacity, which is a guaranteed ability to provide energy on demand.

During the 1990s, the U.S. began to shift away from comprehensive cost-based pricing of wholesale trades towards a framework that allowed for markets and “market-based pricing” of bulk power. To do this, the FERC began requiring utilities to offer open-access transmission service and provide “ancillary services” that help grid operators facilitate trading while maintaining high levels of reliability. The FERC then allowed bulk sellers to sell at market-determined prices at locations on the grid where competition among generators was strong enough to make prices competitive. Open access was facilitated by regulated independent transmission system operators (ISOs or RTOs), who later also became regional market operators.

This period also saw the decontrol of retail power rates, which are subject to state authority, in about half the United States. In areas where “retail choice” was implemented, the distribution sector was significantly restructured into one in which multiple electricity retailers could purchase bulk power and resell it to retail consumers at prices determined by sellers rather than set by state regulators. In areas where retail choice was not adopted, distribution utilities retained their traditional role as price-regulated franchised providers of all electricity to all retail customers. However, these state-regulated distribution utilities made increasing use of the wholesale power markets as a source of power in addition to continued reliance on the ownership of generation and long-term, cost-based purchases.

These developments soon led to the formation of large centralized auction markets for spot power in many regions of the U.S. These markets set market-determined prices for electric energy at each location on the bulk power grid every hour or less, also known as locational marginal prices (LMPs). These spot markets largely replaced cost-based power pools and bilateral spot trading arrangements, which were the main prior practices.5

The role of power spot markets is to provide lowest-cost short-term energy to supplement power purchased or generated under longer-term arrangements. In contrast, electric capacity is purchased or owned to ensure long-term resource adequacy, i.e., that sufficient electric generating

5 Several regions of the U.S. without centralized spot markets operated by ISOs are also adopting spot power trading mechanisms similar to the ISO-operated central auctions. 3

capacity exists to serve all power demands at any one moment. After a period of operation, most of the organized market regions also created centralized, auction-based markets for electrical capacity. These markets are generally more recent than energy markets, less standardized, and generally more controversial, as confirmed by the stakeholder discussion in Section Three below.

III. OVERVIEW OF THE BULK POWER MARKETS TODAY

The bulk power markets today are a product of varied regional implementation of competitive market features, resulting in a spectrum of wholesale market structures, from centrally organized markets to traditional regulated markets. In traditional wholesale electricity markets, vertically integrated utilities are responsible for system operations and management, and wholesale physical power trade typically occurs through bilateral transactions. In centrally organized markets, Independent System Operators, or ISOs, deliver reliable electricity through competitive market mechanisms, and basic functions include real-time coordination of load and generation, operation of the transmission system, and planning to ensure reliable long-term system performance6. Currently, there are seven ISOs/RTOs in the United States (see Figure 1): ERCOT, ISO-NE, NYISO, PJM, CAISO, MISO and SPP.

Figure 1. ISOs in the United States

Source: PACE Global and Energy Velocity The ISOs fulfill a number of important roles in bulk power market operation and share many common features, but also differ in several important ways (see Figure 2). A key role of each ISO is to administer a centrally organized market, as a single Balancing Authority, to balance load and generation through market mechanisms. Each ISO balances electric supply and demand through day-ahead and real-time markets, though these markets have different characteristics. The NYISO and several other ISOs have an hour-ahead market. The ISOs generally fulfill RTO functions and are

6 See: Electric Power Markets: National Overview, FERC, 2/29/16.

subject to Order 1000 for transmission planning, except for ERCOT, and all have a market for transmission congestion rights.

Figure 2. Functional Roles of ISOs

NERC Functional Model ISO- ERCOT NYISO PJM CAISO MISO SPP Registration NE

Balancing Authority Interchange Authority Planning Authority Reliability Coordinator Resource Planner Transmission Operator Transmission Planner Transmission Service Provider

Source: 2011 Report to Congress on Performance Metrics for Independent System Operators and Regional Transmission Organizations. FERC.

One of the key differences between the regional markets is the degree of centralization of energy wholesale markets and resource adequacy requirements (see Figure 3). While all of the ISOs have a centrally competitive market for wholesale energy, they differ in how they manage resource adequacy requirements. ISO-NE, NYISO, PJM and MISO have centralized capacity markets; California, on the other hand, requires its investor-owned utilities to conduct a long-term resource competition process to ensure resource adequacy needs are met. Other major differences include the level of generation divested and the degree of retail choice. For example, in SPP and MISO only 20-40% of generation is owned by IPPs, while over 80% is owned by IPPs in ERCOT. There is a high degree of retail choice in ERCOT, ISO-NE, NYISO, a mixture of retail choice and traditional regulation in PJM, and a low degree elsewhere.

Figure 3. Spectrum of Market Categories

Source: PACE Global; 2011 Performance Metrics for Independent System Operators and Regional Transmission Organizations, FERC, April 2011.

IV. THE ROLE OF BULK POWER MARKETS AND OTHER ELEMENTS OF AGREEMENT

Reflecting a number of widely-held views amongst energy stakeholders, workshop participants agreed on a number of important issues. The foremost area of agreement was that the United States would continue to need, and to rely on, a robust bulk power marketplace that meets critical national needs. Electric power will remain the lifeblood of the U.S. economy for the foreseeable future, and it must remain universally available, affordable, and reliable.

Despite growth in distributed generation, stakeholders did not foresee any diminution of the need for bulk power markets and a strong high-voltage grid. Maintaining or even improving current levels of reliability and resilience remain essential. Participants also agreed that the power sector would need to continue its trend towards lower greenhouse gas emissions irrespective of the specific legal status of the Clean Power Plan and its key deadlines. Many participants emphasized that a price signal on carbon emissions was one of the most important policy measures necessary for a successful bulk power sector, and it would particularly helpful where markets are already creating increased transparency into power prices and costs.

Participants also noted that efforts to meet national and international climate and environmental objectives alongside other national priorities would require substantial additional investment, including increases in energy research and development. Participants agreed that the Department would continue to play a critical role promoting R&D on low-carbon electric resources as well as improvements in delivery and use technologies. Across the entire electric value chain, and in all types of regions and markets, improved technologies were seen as extremely valuable.

One of the reasons why continued R&D is valuable is that a diverse electricity resource base was viewed as universally important. The bulk power sector as a whole and the markets for wholesale products both benefit from a more diverse set of technologies and resource options than are currently cost-effective in many markets. Many participants noted that additional low-carbon generation options, especially including gas and coal CCS and new modular nuclear plants, would be very helpful additions for both planning and markets if they could be constructed in a timely and economical manner.

V. CHALLENGES FACING TODAY’S BULK POWER MARKETS

A. Jurisdictional Complexity

Workshop participants recognized the unassailable fact that the United States contains an extremely diverse group of bulk power participants, including state-regulated, publicly-owned, customer- owned, and deregulated, privately owned sellers and buyers.7 In general, this diverse group can be grouped into the centralized or organized markets of PJM, New England, New York, ERCOT, SPP, with the Pacific Northwest and Southeast in more traditional structures. The Midcontinental and California ISOs, while something of a hybrid, each contain auction-based energy markets. Indeed, one important development in this landscape is the emergence of a greatly expanded western market for very short term or “imbalance” energy, the EIM.

7 See the section below. Wind industry stakeholders also note the diversity of market structures as an impediment to development. Gramlich and Goggins (2009). 9

The Energy Imbalance Market in the Western U.S.

The Western United States energy imbalance market (EIM) is the latest major development in the structure of US bulk power markets. The market is run through a voluntary 5-minute and 15-minute automated optimization system that selects the lowest cost resource available to participating Balance Authority Areas (BAAs) given available generation and transmission resources across the PacifiCorp and ISO BAAs. The EIM uses the ISO’s state-of-the-art market software system to allow transfers to occur.8 The current participants range from CAISO to small electric co-ops.9

The market is designed to reduce balancing authorities’ expenditures on reserves and energy in peak demand periods.10 The first two months of the implementation of the first half of the market, November and December of 2014, saved CAISO and PacifiCorp $6 million.11 Since then, five more utilities have joined the market and total savings are projected to be $64.6 million for participants in California, Oregon, Washington, Nevada, Utah, Idaho, Wyoming and Nevada.12

While the new market did provide savings for the participating groups, transfers pushed constraints on the transmission system that had to be resolved through out-of-market mitigation measures and price volatility.13 This issue was resolved when NV Energy joined in December of 2015, alleviating the stress on the market by increasing transmission capacity for transfers.14

The EIM is by no means a traditional ISO or RTO, but rather a BAA-to-BAA spot market exchange mechanism. However, many stakeholders view it as a step towards the creation of a multi-state Western RTO. There is no agreement among stakeholders favoring such an RTO, but the potential to turn 38 of the West’s BAAs into an RTO is being investigated by a CAISO hired team of consultants as a means of contributing to the state’s goal of going 50% renewable by 2030.15

8 “Taming the Wild West: CAISO begins study of a full regional electricity market.” Herman K. Trabish. February 22, 2016; “Taming the Wild West: CAISO begins study of a full regional electricity market.” Herman K. Trabish. February 22, 2016. 9 “PacifiCorp Offers Lessons for Future EIM Participants.” Robert Mullin. April 11, 2016. 10 “How the West's new Energy Imbalance Market is building a smarter energy system.” Herman K. Trabish. February 19, 2015. 11 See Trabish (2015). 12 “Western EIM Benefits Increase With NV Energy Participation.” May 2, 2016.

13 See Trabish (2015); Mullin (2016); “Idaho Power will be sixth utility to join CAISO's western Energy Imbalance Market.” Herman K. Trabish. April 13, 2016. 14 See Mullin (2016). 15 See: Trabish (2015) and Trabish (2016).

However, each of these markets operates with slightly or significantly different rules, especially for products other than imbalance energy. A second area mentioned by stakeholders was the jurisdictional divide between states and the federal government in the power sector. The dividing line now enshrined in the Federal Power Act is based largely on the voltage level of the portion of the power grid. This division originally served as a good boundary between the portion of the grid housing most of the generation, and thus required an active balancing function, and the portion of the grid that was largely a passive delivery vehicle. With the growth DERs, the distribution system now requires more active management. In addition, because both systems are active, new methods of interaction between the two parts of the system are necessary. The fact that the distribution and transmission systems are each regulated by different entities, with different statutory duties, creates challenges exemplified by the fact that there are now several Supreme Court cases pending or recently decided on this question.

Stakeholders noted that the varied patchwork of market and industry structure sometimes reduced the ability to deploy innovations at scale, though it also enables a higher degree of differentiated experimentation (the so-called state “laboratories of democracy.”)

B. Transmission Planning

Regardless of the degree of vertical integration or the structure of the regional bulk power markets, adequate transmission capacity is essential for proper performance, reliability, and the addition and integration of large-scale renewables. It should be recognized that sustained efforts on the part of the federal government and the industry, including FERC’s Order 1000 and concerted interagency transmission siting reform, have dramatically improved the pace of new transmission construction from about $4 billion/year to $10 billion/year. However, there is also widespread agreement that transmission planning is not yet working as well as it should, and that QER 1.2 should make this one of its areas of focus. Even where two adjacent markets operate similarly, many participants agreed that operational coordination could improve, and coordination for planning and system expansion was very difficult. One workshop participant, a transmission owner with extensive regional interconnections, stated quite bluntly that interregional transmission planning was simply not working properly. He indicated that his company was no longer willing even to try planning and siting additional capacity across the boundaries of two transmission planning regions. Another participant noted that regional transmission planning did not properly consider tradeoffs between “strategically located generation” and transmission. While workshop participants were not nearly as uniformly negative

as this individual, no one defended interregional planning as working sufficiently well to serve the bulk system adequately.16

A recent report by WIRES, the transmission trade association, summarized three specific, primary areas of concern: 1. Planners and policy makers do not account for the high costs and risks of an insufficiently robust and insufficiently flexible transmission infrastructure on electricity consumers and the risk-mitigation value of transmission investments to reduce costs under potential future stresses. 2. Planners and policy makers do not consider the full range of benefits that transmission investments can provide and thus understate the expected value of such projects. 3. The interregional planning processes are ineffective and are generally unable to identify valuable transmission investments that would benefit two or more regions.

The WIRES report goes on to conclude that “these deficiencies collectively create significant barriers to developing the most valuable and cost-effective regional and interregional transmission projects and infrastructure.” It should also be noted that robust transmission planning processes must consider non-transmission alternatives, and appropriately assess non-monetized social costs, to best serve the national interest.

Finally, we note that it is neither accurate nor productive to attribute these deficiencies to any particular entity or stakeholder group, such as an assertion that “Order 1000 has failed.” The industry is changing rapidly, placing new demands for greater flexibility, resilience, integration, and long-distance delivery than ever before. Partly because markets have created greater transparencies, stakeholders are more focused on quantifying and allocating the multiple benefit streams from new transmission projects, and this can be a time-consuming and sometimes contentious exercise. In short, a wide variety of factors contributes to the need to bring transmission planning to a more robust level commensurate with the grid transformation challenges facing the industry.

C. Renewables Integration and DER Valuation

In general, participants agreed that the most overarching challenge facing bulk power markets today is the integration of increasing amounts of renewable energy, both large and small scale. While this challenge can be characterized as a single, broad challenge, it is more accurately viewed as a series of interlocking challenges. For example, the jurisdictional complexity in section A is often characterized as an integration challenge.17 In addition, the classification of these solutions and the options for policy solutions varied considerably among participants.

16 Inadequacies in transmission planning were mentioned by the Edison Electric Institute in its formal comments at Public Meeting no. 1 on DER 1.2 (statement of Thomas R. Kuhn, 2/4/16 and are also discussed by Chang and Pfeifenberger (2015) and Scott and Bernell (2015). 17 See Gramlich and Goggin (2009). 12

Increasing amounts of renewable energy resources present several physical/operational challenges that clearly and directly affect U.S. bulk power markets. First and foremost, the reduced dispatchability, high volatility, and high ramp rates for these resources create highly volatile spot prices and a need for much larger amounts of fast-ramping dispatchable resources.

Participants agreed on the importance of expanding the products bulk power markets provide to include fast-ramping energy and other new types of services some called essential reliability services (ERSs). Increased renewables also are increasing the need for reactive power, which may be supplied by either large- or small-scale resources, but for which bulk power markets are generally not formed.

The expansion of centrally traded power products to include ERSs was widely supported, but the workshop did not explore the specific resource definitions, the degree to which competitive markets could be created for these products, and other related questions. However, one workshop participant provided a useful illustration of the FERC’s recent efforts to establish a market for one ERS service, reactive power.

Participants also noted that the further unbundling and productization of the different types of services provided by DERs would help stimulate better markets at both the distribution and bulk power levels. At present there are few accepted approaches to unbundling and valuing DER service streams, and this was an area many participants viewed as important for further improvements to electric policy and markets at all levels.

D. Resource Adequacy, Diversity/Resilience, and Capacity Markets

Increased renewables also affect the bulk power markets through the reduction of energy market revenues. Because most forms of renewable generation have near-zero (and sometimes negative) marginal costs, larger amounts of such renewables offered into LMP markets uniformly lower market prices by shifting the supply curve to the right. Reduced market-clearing prices in LMP energy markets lower the revenues earned by all types of traditional resources, whether baseload, peaking, or in between. In some cases, this reduces the viability of operating marginal traditional resources and building new traditional plants.

This phenomenon leads to additional tension over the role of bulk power markets in the provision of resource adequacy (RA). Reflecting divisions in the broader power stakeholder community, workshop participants generally supported two different policy directions directed at preserving RA. The first group supported a continued expansion of centralized markets by creating and expanding locational short-term markets for ERSs and new capacity products. These product markets would be designed to provide the revenue necessary to encourage wholesale suppliers to sell products that would provide revenues targeted at resources necessary for integrating renewables but unable to build and operate profitably on energy revenues alone. One workshop participant called this the “unfinished business of electric deregulation.”

The further unbundling of the resource attributes contained in various types of electric capacity is clearly a critical area for further federal research and technical assistance. The designers of existing capacity markets often remind us that these markets were designed solely to produce resource adequacy – they were not market substitutes for multi-dimensional integrated resource planning. To the extent that state, regional, and national policies want to rely on markets for other attributes associated with capacity new market mechanisms and products must be developed. In the alternative, markets must be meshed with policies that provide these attributes without undoing the efficiency benefits of the market.

The second group of stakeholders advocated a much different approach to RA and fuel diversity. This group argued that centralized markets, while useful for coordinating short-term dispatch decisions, were not the best approach to optimizing diversity and integration. Instead, this group advocated the continuation of portfolio-based or integrated resource planning and the use of competitively-awarded long term contracts as the centerpiece of bulk power markets. 18 One stakeholder group, the National Rural Electric Cooperative Association, labels this approach the “customer-centric utility.”19

The differences between these two stakeholder groups was also motivated by disagreements over the degree to which the organized short-term capacity markets were “working well.” Several participants argued that these markets were working properly, as evidenced by a general absence of reliability problems and current capacity shortages in the territories covered by organized markets. Other participants pointed to the closure of nuclear units, high capacity price volatility, and a loss of portfolio value measurement as disadvantages not present in regions continuing to rely on planning and competitive contracting. Moreover, these stakeholders argued that the regions less reliant on centralized commodity markets could treat electricity more easily as a multifaceted customer service rather than a commodity product, incorporating unpriced attributes, policy goals, and externalities markets cannot yet effectively balance.

These differences were often characterized by participants as difference in the size and scope of bulk power markets in both the geographic and product definition sense. The larger the geographic market for any one product, the more uniform and barrier-free the market; conversely, such structures eliminate alternative approaches that use markets differently. A larger product scope for the market creates a large set of traded products, moving system attributes that are otherwise

18 While it is correct that this second model relies more on price-based regulation and the integrated ownership and operation of assets, it is incorrect to assert that this model does not rely on bulk power market mechanisms. The market mechanisms in this model can readily include a centralized spot market, but rely more on longer-term markets and procurements. The differences between these two models with respect to markets is larger at the distribution system level (as exemplified by the two models in Smart Power (Fox-Penner, 2010)), but distribution system business models are not the focus of this white paper. However, because interaction between the distribution and transmission systems will be heightened as the industry evolves, these distribution system differences will have a larger impact on the bulk power markets going forward. 19 51st State Phase II Report, NRECA, 3/23/16. 14

dealt with by planning and regulation alone into a mode where these attributes can be priced and exchanged.

The nature of the market approach to resource adequacy interacts with two other important and closely-related issues, fuel diversity and resilience. With respect to fuel diversity, participants widely endorsed the view that bulk power markets should not rely too heavily on any one form of generation. Because many of the generation resources that help integrate renewables also add fuel diversity and optionality to the markets, the twin goals of diversity and integration are often both served by integration policies. However, as noted above, the two main approaches to RA embed similarly different approaches to ensuring diversity.

Roughly the same is true for resilience, which is loosely defined as the ability of power systems to avoid, or restore service quickly after, electric outages. Systems with more diverse sources of supply (both within and across prime movers) are inherently more resilient. Markets can improve resilience by defining and creating a required market for resilience-promoting features, but this was not discussed much by workshop participants.

E. Policy Uncertainty, Carbon Pricing, and the Clean Power Plan

Many participants expressed regret at the degree to which U.S. long-term climate policy was now in an uncertain posture due to the Supreme Court stay and the general legal posture of the Clean Power Plan (CPP). Most also agreed that the best climate change policy for the bulk power marketplace would include a carbon price signal. While the precise form of the signal was not discussed in any detail, there was a high degree of support for such a signal regardless of the rest of the structure of the marketplace.

While supporting the overall goals of the CPP, many participants noted that the plan presented challenges of its own and also exacerbated the challenges of integrating greater amounts of renewable energy and transmission planning (both discussed above). The CPP adds an additional layer of compliance atop the general challenge of reducing greenhouse gases in the power sector, which intensifies the need for more economical non-fossil generation options, more R&D, more compliance planning tools, and more progress integrating renewables. One participant also noted that allocating the costs of the CPP to wholesale and retail customers was especially complex.

One observer of the issues, Professor William Hogan, has prepared a particularly detailed analysis of the interaction between the CPP and bulk power markets. Professor Hogan writes that:

Some versions of implementation plans for the CPP would be compatible with the operation of electricity markets and be easy to achieve. For example, a national carbon tax would be a preferred policy that would reduce carbon dioxide emissions and produce little or no unwanted distortion in the electricity market. By contrast, other possible policies could undermine the foundations of RTOs and cause electricity markets to collapse... The challenge for the nation is to develop an efficient policy for reducing carbon emissions. The challenge for RTOs and their regulators is to make clear how environmental policies 15

could mesh well with the necessary electricity market design. Environmental policies that put an explicit price on carbon would fit naturally with efficient markets. Absent an explicit price on carbon, RTOs should be alert to avoiding many variants of seemingly innocuous implementation mechanisms that would lead to fundamentally undermining the operation of electricity markets.20

Although it is beyond our scope to detail the remainder of Professor Hogan’s analysis, his work makes it clear that the integration of markets and the CPP requires strong ongoing attention.

20 Hogan (2015). 16

VI. CONCLUSION: STRATEGIES AND OPTIONS FOR THE DEPARTMENT OF ENERGY

The workshop, associated reading materials, and further research by the QER team preparing this report suggest a number of important conclusions and potential next steps by the Department in furtherance of QER II.

First, it is evident that there are a number of areas of consensus on bulk power markets issues and related policy actions that merit emphasis in the QER and additional departmental action. These include:

● Unanimous support for a consistent, nonpartisan energy policy ● Encouragement of a diverse mix of generating resources, including economical forms of CCS and nuclear power; ● Continued R &D into additional generating technologies; ● Consistent, long-term carbon price signals; ● A strong policy role for DOE interacting with EPA, FERC, and other federal and state agencies; and ● Continued strong support for highest levels of reliability, affordability, and universal service. These points of consensus support the value of doing the QER itself and many of the fundamental roles of the Department. While the focus of this workshop was limited to assessing and improving the bulk power markets, the clear message emerging from the workshop was that these markets will work better, now and in the future, with attention to these basic imperatives.

Certain areas of the bulk power landscape, however, are not areas of consensus, notably the future structure of bulk power markets with respect to integration and the form of the markets providing resource adequacy, ERSs, and other long-term attributes that are less commonly priced. In these areas, the Department can play a valuable role promoting discussion, sharing of best practices, and objective analyses from the standpoint of the national interest.

This general area of disagreement presents an important opportunity for the Department. There are two very different views of the future of bulk power markets, one based on disaggregated and primarily short-term markets and one centered on longer-term contracts and markets and integrative planning processes. It is exceedingly unlikely that either of these organizational models will disappear over the horizon of this QER, if not longer. Moreover, even within regional markets there is evolution towards or away from the two primary models. As a result, federal policies must enable both models to co-exist successfully in both the short and medium-run – a challenge of the highest order.

One related area that clearly merits attention is improved transmission planning and the seams between regional markets. While these seams are operating reasonably well, interregional planning and line construction was not seen to be working well. Improvements in these dimensions of the marketplace will unquestionably improve the size and scope of bulk power trading, improving market function and providing more options for meeting essential environmental and fuel diversity goals. Due it is unique capability and credibility, the Department can contribute technical and convening resources to help improve these critical elements of the market landscape.

Similarly, there is a strong case for continuing the Department’s role in providing resources to states and other stakeholders involved in planning for CPP compliance. Stakeholders also widely support strengthening DOE’s ongoing efforts to assist the FERC and the EPA with other policy processes that greatly impact bulk power markets. As in the case of seams, the Department is unique in its ability to represent the full range of interests and issues in bulk power markets and to provide valuable technical and convening resources.

The bulk power markets serving the nation are working reasonably well in the immediate run. Without the policy improvements discussed in this paper they will undoubtedly continue to provide reliable service with continued environmental improvement, affordability, and efficiency. However, there is also clearly a very large scope for increasing efficiency, fuel diversity, resilience, environmental performance, and many other essential electric policy goals with renewed, properly focused efforts. The incorporation of these considerations into QER1.2 is the logical next step in this direction.

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