Our History and Approach
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 around the world. CEE has 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.
Gas-Power Linkages are the Main Thread of the CEE Electric Power Research
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.
Gas use in power generation has doubled since the 1990s but there is a wide range of uncertainty around the future gas burn for power generation. Our 2016 scenario analysis implies a range of 8.5 trillion cubic feet, or 23 billion cubic feet a day, in 2030. Already, the prospects for pricing CO2 is dimmer, forcing us to consider the bottom half of the range.
Today, there are many technological and policy developments that can cause more or less natural gas to be burned in the power sector. Some impacts are easier to identify and quantify. For example, coal and nuclear retirements can only be substituted by more gas-fired generation at least in the near term. Other impacts are less clear. For example, the increasing share of out-of-market, intermittent renewables do not necessarily lead to more gas-fired generation as some assume. In fact, it is almost certain that more renewables means less revenue for merchant gas generators. Despite best efforts by FERC and NAESB, "gas-power" harmonization remains an elusive goal as generation portfolios around the country continue to change from the traditional model of central dispatchable plants to a portfolio of dispersed, intermittent and variable resources.
There is more uncertainty about some of the newer technologies, especially those on the demand-side such as rooftop solar and battery storage. "Smart grid" technologies can further dampen load growth, which has been very low, and even negative, in some regions.
Although all of these technologies are potential game-changers, it is difficult to ascertain how quickly and at what pace they can penetrate the electricity markets.
- There are regulatory and market design challenges such as net energy metering, real-time pricing, and distribution system operation.
- The cost of manufacturing PV panels and batteries have declined rapidly in recent years but scaling up production will likely mean supply chain bottlenecks from mining of critical minerals (e.g., lithium, cobalt, cadmium, copper, indium, molybdenum) to their processing and global transportation. CEE started tracking these and related issues in 2014: Critical Minerals.
These developments also impact regulated utility business models. However, one possibility is for most of the policy initiatives such as higher penetration of renewables, storage, distributed resources and such to be moved into the rate base as it is becoming increasingly difficult for competitive market designs to absorb all of these technologies. 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. See our research snapshots and notes in our Think Corner. Our published articles are available to our Partners. Also, see Publications for a complete list.
Competitive Electricity Market Designs Vary and Evolve but Face Growing Challenges
Competitive electricity markets are complex; market designs vary across jurisdictions for political, technical, and socioeconomic reasons. Many countries rolled back some of their reforms and others cancelled their move towards competitive markets. 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.
Comparative efficiency of energy-only versus capacity markets, role of real-time pricing and its challenges, efficacy of regulators in restructured electricity markets, and incorporation of out-of-market uplift payments into price signals ("price formation") 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.
Only some of the questions we raised at that time have been addressed and only to some extent and only in some organized markets. At the same time, emerging technologies on both supply and demand sides of the industry have been forcing stakeholders to re-visit some of the market design principles.
Hypothetical competitive market has been elusive. With every design change, we are moving towards IRP in one form or another.
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.
"Resiliency" has been recently added as a new attribute that markets have failed to price transparently. Many interpreted the DOE NOPR in September 2017 as the end of the competitive electricity markets if FERC were to implement a market design change that would subsidize coal and nuclear plants. We would agree with that sentiment. But, we see this NOPR not as a unique threat but rather the proverbial last nail on the coffin of competitive electricity markets, which have been diluted, practically from day one. The first nails were hammered in the early days: energy price caps, limits on demand-side participation (driven by politics and/or lack of technology), and renewables mandates and subsidies just to name a few suspects. We have been working on system integration costs of renewables, diversion of retail costs from wholesale prices, and alternative structures for efficient and transparent costing of electricity provision. Contact us if you want to support this research.
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 penetration 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, see above the discussion on our AURORA modeling of future gas burn range.
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 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 federal and state financial support mechanisms (i.e., subsidies) 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.
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?
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.