Center for Energy Economics
October 23, 2017


Since the early 1990s, CEE has been widely recognized for our excellence in research and analysis of the natural gas and electric power value chains in the U.S. and several other countries. CEE has also been investigating distinct power market issues, including sector restructuring approaches, market design changes, competitive market performance indicators (wholesale and retail), regulatory actions, economics of infrastructure development, and impacts of energy and environmental policies on markets. We have trained energy sector professionals and advised government entities, private companies, and research organizations across the globe on the basis of our research to help them prepare for infrastructure investment analysis in restructured gas and power markets.

Our research approach is time-tested. We focus on placing the specific problem in the larger context of energy value chains with the help of stakeholders and outside experts; and work with collaborators from inside and outside UT-Austin to develop and test solutions that are widely disseminated for highest possible impact.

The agenda of CEE’s 2016 Mid-Year Meeting provides a quick look at the scope of electric power research at CEE


Gas-Power Linkages are the Main Thread of the CEE Electric Power Research Forum
CEE has been engaged in electric power value chain research since the 1990s when both natural gas and electricity markets transitioned towards more competitive frameworks. Following the energy policy changes initiated in the late 1970s, natural gas proved to be a preferred fuel for power generation initially by non-utility generators, but eventually utilities as well. Environmental regulations and increasing domestic availability of natural gas also encouraged this switch. When states started to introduce competition in their electricity markets, building gas-fired power plants turned out to be more commercially attractive than other types of generators, both for base-load and load-following.

Today, there is a long list of developments in the electricity sector from the increasing share of intermittent renewables to the emergence of demand-side resources and demand response that impact not only the market design in competitive markets, but also regulated utility business models. CEE is tracking many of these issues to assess their impact on gas use for power generation as well as their impact on competitive electricity markets, economics of merchant generation, and natural gas value chains.

Gas use in power generation has doubled since the 1990s and is expected to increase even further owing to cheap gas from shale production and new environmental regulations.

  • Almost 47 GW of coal units already retired in 2010-15, and about 14 GW expected to retire between 2016 and 2018.
    • CEE modeling of the power sector using AURORAxmp, an economic dispatch model of the U.S. electric power systems, indicates that gas-fired generation will compensate for the retired capacity. Our recent modeling updates to reflect current policies and renewables development indicate that cumulative gas burn in power generation between 2015 and 2030 can be 10 to 30 tcf larger than our 2012 analysis depending on different assumptions.
    • The new EPA Clean Power Plan rule might induce more gas-fired generation.
  • CEE also investigates the implications of increasing gas use for power generation at different locations across the U.S. on natural gas prices and deliverability. In a 2014 snapshot, CEE highlighted the importance of natural gas infrastructure for deliverability. A goal for future research is to complement AURORAxmp with a natural gas market model to investigate the feedback loops and infrastructure bottlenecks more effectively.

Nuclear Power is an Emerging Area of Research at CEE
CEE hosted three international roundtables since 2009 on nuclear energy developments and is diversifying into deeper analysis of nuclear energy development trends and issues. The third roundtable was held in January 2016 (agenda and summary).
In the U.S., almost all existing nuclear units are re-licensed to operate up to 60 years. However we see mixed activities across different markets:

  • 4.4 GW retired by 2015; about 5 GW of merchant capacity are slated to be retired prematurely between 2017 and 2019, owing to high repair costs and/or unattractive economics.
  • More nuclear capacity is at risk of early retirement. We modeled a hypothetical scenario of gradually retiring about 44 GW of nuclear capacity in the Eastern Interconnection (in addition to about 5 GW of announced retirements between 2017 and 2019). In this case, the call on natural gas is even larger than our estimates above.
  • On the other hand, some plant owners declared their intention to seek a second license 20-year license renewal with U.S. NRC for 4.3 GW in PJM market.
  • Only 4.5 GW of new capacity in two plants is under construction in the U.S. CEE is paying close attention to schedule and cost of ongoing projects, and more importantly implications for other potential new nuclear builds.

As the U.S. nuclear industry is calling for regulatory actions to recognize the importance of preserving existing nuclear generation facilities, CEE aims to answer a fundamental question: what is the value of nuclear generation in and beyond electricity markets?

Texas / ERCOT has been Central in CEE’s Electric Power Research
When Texas was debating electricity sector restructuring in the late 1990s, CEE worked with the Public Utility Commission of Texas to prepare for the implementation of the fully competitive market. Our Guide to Electric Power in Texas became the model for similar efforts in other locations (Mexico, Ghana). Dr. Gülen co-authored with Pat Wood, chairman of PUCT at the time of Texas electricity restructuring, a chapter on the history of this process in Electricity Restructuring: The Texas Story. In 2009, CEE evaluated the performance of the renewable portfolio standards (RPS) program in Texas for the State Energy Conservation Office.

The competitive electricity market in Texas is often considered one of the most successful with its energy-only structure. However, extreme weather during the summer of 2011 raised concerns about resource adequacy in Texas’ electricity market. Using AURORAxmp, we demonstrated that raising the energy price cap to $9,000/MWh as proposed would help improve prospects for achieving a higher reserve margin in the future. It is important to evaluate resource adequacy within the context of new environmental regulations and increasing peneetration of renewables; some of these developments undermine the benefits expected from the higher energy price cap while a capacity market (mandated reserve margin) postpones retirements.

As part of the Full Cost of Electricity project managed by the UT Energy Institute , we modeled long-term capacity expansion scenarios for ERCOT that contrasted new builds, retirements, prices, reserve margins, capital and operating costs under different policies, technology and cost assumptions, and generation portfolios.

National Policies and Differences in Wholesale Markets Complement ERCOT Research
We evaluate the impact of federal environmental regulations, the addition of large amounts of renewables, and significant market design changes at the national level. For example, our modeling results since 2012 have been confirming coal retirements expected by many over the past several years, but looking into the future, a lot depends on the assumptions regarding the price of natural gas the cost of renewables (especially solar PV), changes in market design (for example, capacity markets), as well as trends in energy conservation and efficiency, and demand response as they impact electricity demand growth.

We investigate the upward trend of residential electricity prices at a time of low wholesale electricity prices. Early analysis suggests that states with relatively higher prices tend to have more aggressive renewable energy targets and competitive markets. This research area overlaps with our tracking of developments in smart grid, demand response, and distributed resources.

As part of the Full Cost of Electricity project, we have participated in long-term capacity expansion modeling in ERCOT using AURORAxmp, assessment of levelized cost of electricity at a county level across the U.S., estimation of levelized avoided cost of electricity under various scenarios using the results of dispatch modeling, and cataloguing of financial support mechanisms for generation technologies.

In 2010, CEE organized a forum in Washington, D.C. focusing on challenges associated with siting new transmission lines. This forum was built on the RPS analyses for Texas and comparison of various state and proposed federal programs and their challenges.

Competitive Electricity Market Designs Vary and Evolve
Competitive electricity markets are complex; market designs vary across jurisdictions for political, technical, and socioeconomic reasons. Over the years, CEE research covered restructuring processes and market designs in several jurisdictions in the U.S., Argentina, Australia, Bangladesh, Chile, Colombia, Ghana, India, Mexico, Nigeria, Peru, South Korea, Taiwan, Thailand, and Turkey among others. This comparative research was partially driven by CEE’s international energy sector development assistance efforts.

Energy-only versus capacity markets or payments, real-time pricing , efficacy of regulators in restructured electricity markets, and locational marginal pricing and out-of-market uplift payments are among the market design issues analyzed by the CEE team over the years. These are dynamic issues; the CEE team continues to analyze design changes to evaluate their potential impact of market efficiency, generator economics and system reliability, which has been at the center of our approach to electricity markets as the nearby schematic from circa 2001 depicts. Perhaps surprisingly, only some of the questions we raised at that time have been addressed and only to some extent and only in some organized markets. Clearly, emerging technologies on both supply and demand sides of the industry have been forcing everyone to re-visit some of these issues. Without a doubt, the reliability remains a central issue as we continue to work on how best to value this service as provided by different technologies and market designs.

Carbon capture and sequestration
BEG houses one of the premier research programs on carbon capture and sequestration: Gulf Coast Carbon Center. CEE researchers have been involved in evaluating the economics of the CO2-EOR value chain. Capturing carbon in coal-fired power plants is costly. In the absence of a carbon tax, selling captured CO2 to oil companies for enhanced oil recovery and permanent storage of captured CO2 can provide at least some of the revenues required to make the investment in capture facilities.


Dr. Michelle Michot Foss, Chief Energy Economist and Program Manager
Center for Energy Economics, Bureau of Economic Geology, The University of Texas at Austin
Tel 713-654-5400 Fax 713-654-5405