TODAY’S STUDY: The Full Cost of Electricity
The Full Cost of Electricity...
Summary of the Full Cost of Electricity
The Full Cost of Electricity (FCe-) is an interdisciplinary initiative of the Energy Institute of the University of Texas at Austin to identify and quantify the full-system cost of electric power generation and delivery – from the power plant to the wall socket. The FCe- study employs a holistic approach to thoroughly examine the key factors affecting the total direct and indirect costs of generating and delivering electricity. The purpose is to inform public policy discourse with comprehensive, rigorous and impartial analysis.
As an interdisciplinary project, the FCe- synthesizes the expert analysis and different perspectives of faculty across the UT Austin campus, from engineering, economics, law, and policy. In addition to producing authoritative white papers that provide comprehensive assessment and analysis of various electric power system options, the study team developed online calculators that allow policymakers and other stakeholders, including the public, to estimate the cost implications of potential policy actions. A detailed prospectus of the research initiative, and a list of research participants and project sponsors are also available on the Energy Institute website: energy.utexas.edu.
The Full Cost of Electricity Findings Inform Stakeholders on Relevant Policy Questions within the Electricity Industry The white papers within the FCe- study contain information and insights that are relevant to many key questions facing the electric power industry, policy makers, and electricity consumers (see Table 1). Many questions can be addressed from multiple perspectives to promote communication amongst a diverse set of stakeholders.
For example: What is the cheapest technology for power generation?
Integrating Community Values into the Full Cost of Electricity (see pg. 23 for summary)
o Community values are increasingly being included in decisions about future supply and delivery of electricity instead of being solely driven by marketbased economic considerations. Unit-commitment, dispatch, and capacity expansion modeling of ERCOT (final paper forthcoming) The Past and Future of Net Metering for distributed Energy (paper forthcoming) Levelized Cost of Electricity of Microgrids across the United States (paper forthcoming) State-level Financial Support for Electricity Generation Technologies (paper forthcoming When full costs are included, every power generation option is more expensive than just the combination of their direct operational and capital expenditures.
o This answer depends upon not only fuel, capital, and operating costs but also …
where you construct the power plant, as resources, power plant utilization, and labor costs vary geographically ,
the health impacts from air emissions and CO2 which depend on the magnitude of exposed population and level of pre-existing pollution [4, 9],
requirements for new transmission interconnections to new power plants  and existing transmission lines  that connect multiple generators to load centers, and
financial support from the government that supports overall electricity production by 3-5 $/MWh .
Is the cost for electricity per technology, measured in ¢/kWh or $/MWh, the only way to consider for the cost of electricity?
o Short answer: No.
o Longer answer: While cost per unit of electricity is important assessing policy implications, through comparisons with customer rates (via regulatory policy) and prices (via markets), it misses many important perspectives:
Transmission, distribution, and administration (TD&A) costs are primarily driven by fixed cost factors, and thus TD&A costs are more accurately reflected as a cost per customer rather than a cost per kWh .
From a customer’s perspective, determining whether the cost of electricity is large or small depends upon total costs relative to income. That is to say, the consideration of a monthly or annual electricity bill provides a way to consider how many people are exposed to high energy costs .
Some consumers and communities do not use (lowest) cost as the sole criteria driving their desired source of electricity. The often consider “values” (such as clean, local, or resilient) and market externalities .
New technologies or categories tend to have higher per units costs (e.g., $/ MWh) that decline over time as they become more prevalent [5, 11].
Incentives do not consistently focus on one part of the electricity supply chain. For example, the U.S. government incentivizes the extraction of fossil fuels generally, but not as much the power generation facilities that burn fossil fuels. Incentives for renewables (e.g., wind and photovoltaics) are often focused on the power generation technologies themselves (e.g., there are no fuel costs to incent) .
Isn’t the cost of renewable electricity higher than thermal (natural gas, coal, and nuclear) because they require more investment for grid integration? o Short Answer: It depends. o Longer answer: There are a few major factors to consider:
Both thermal (e.g., dispatchable) and non-dispatchable renewable generation can dictate requirements for grid stability 
Operational reserve requirements of grid operators are influenced by generation technologies as well as market and non-market protocols. In ERCOT, recent protocol revisions reduced regulation reserves procurements even as installed wind capacity increased from 4 to 12 GW .
The design of the distribution grid matters. The amount of distributed (e.g., rooftop) photovoltaics that can be integrated at no additional cost varies tremendously, ranging from 15-100% of peak load .
Depending upon the existing capacity of the grid and incremental quantity of generation added, transmission interconnection costs for new generation can be negligible to significant (e.g., 0-600 $/kW in ERCOT) .
No power plant (ultimately) has zero interconnection costs. All gridconnected power plants depend upon transmission and distribution to deliver electricity to consumers. The costs of building and operating the grid are non-trivial at 700-800 $/yr per customer, or approximately 3 cents/ kWh .
Highlights from each White Paper within The Full Cost of Electricity study: The History and Evolution of the U.S. Electricity Industry (go to pg. 8 for summary) o From its beginning, the U.S. electricity industry emerged as a function of technological advancements, economies of scale, effective financial and regulatory structures that fostered capital investment, and new electric-powered loads. Over a century, there have been successive waves of changes in generation, transmission, distribution, market design and regulation of the electricity industry. While we expect electricity to continue to be an essential public good and large scale centrally generated electricity to continue to be essential, traditional utility business and regulatory models will be under stress given:
Continued development of more cost-competitive and lower emission centralized generation such as windfarms, utility scale solar, and natural gas-fired combined cycle power plants. The traditional thermal generation technologies such as coal and nuclear plants are being challenged by new generation technologies that are more efficient, flexible (e.g., ramping), and modular (can be built at smaller scales) while having lower emissions, shorter development times (e.g., less than 2 years for a solar farm versus 10 years for a nuclear facility), and/ or no fuel costs (e.g., renewables).
Advancements in distributed energy resources (DERs) such as photovoltaic (PV) generation and storage.
Changes in load patterns from energy efficiency, demand response, and customer self-generation. New U.S. Power Costs: by County, with Environmental Externalities: A Geographically Resolved Method to Estimate Levelized Power Plant Costs with Environmental Externalities (see pg. 10 for summary)
o This paper explains a geographicallyresolved method to calculate the Levelized Cost of Electricity (LCOE) of new power plants on a county-bycounty basis while including estimates of key environmental externalities.
o For nominal reference conditions, the minimum cost option of a new power plant in each county varies based on local conditions and resource availability, with natural gas combined cycle, wind, and nuclear most often the lowest-cost options. Overall, natural gas combined cycle power plants are the lowest cost option for at least a third of US counties for most cases considered.
o Online interactive calculators (http:// calculators.energy.utexas.edu) are available to estimate LCOE per county and technology to facilitate policylevel discussions about the costs of different electricity options
Map-based LCOE calculator: http://calculators.energy.utexas. edu/lcoe_map/#/county
Side-by-side LCOE comparison calculator: http://calculators. energy.utexas.edu/lcoe_detailed/
Household Energy Costs for Texans (see pg. 21 for summary)
o This paper uses data from the Energy Information Administration’s Residential Energy Consumption Survey to understand how demographics describe household energy consumption.
o Twenty-two percent of Texas households are “energy-burdened,” spending more than 8% of their gross annual income on household energy. Integrating Photovoltaic Generation: Cost of Integrating Distributed Photovoltaic Generation to the Utility Distribution Circuits (see pg. 17 for summary)
o The quantity of distributed (e.g., rooftop) PV that can be integrated into distribution circuits is analyzed at three types of “hosting capacities” that assume
Range-1: there are no operational changes to the circuit or upgrades to the infrastructure,
Range-2: only operation changes can occur with existing infrastructure, and
Range-3: infrastructure upgrades are necessary (e.g., smart inverters). o The circuit topology is a very decisive factor as the “Range 1” PV hosting capacity varies greatly depending upon the circuit (e.g., from 15%-100% of peak load for three analyzed circuits). Even a circuit that necessitates smart inverters on all PV panels to enable PV to reach 100% of peak load can do so at modest cost (e.g., 0.3 $/W additional). Market-calibrated Forecasts for Natural Gas Prices (see pg. 20 for summary)
o This paper discusses a stochastic process modeling approach for developing spot price forecasts for natural gas. The forecasts include both expected future values and uncertainty bounds around the expected values.
o The model is calibrated using market information, in the form of historical futures price data. As a result, it produces forecasts that are based upon the consensus of thousands of active market participants, rather than the subjective estimates and assumptions of individuals or small teams of forecasters. The current long-term forecast using this approach indicates that the market expects natural gas prices to remain relatively low (under $4.35 per Million Btu) through 2025. Trends in Transmission, Distribution, and Administration Costs for U.S. Investor Owned Electric Utilities (see pg. 12 for summary)
o This paper summarizes the cost trends for electricity transmission, distribution, and utility administration (TD&A) in the United States using data from the Federal Energy Regulatory Commission. o The number of customers in a utility’s territory is the single best predictor for annual TD&A costs. Between 1994 and 2014, the average TD&A cost per customer was $119/ Customer-Year, $291/ Customer-Year, and $333/CustomerYear, respectively, for a total of $700- $800 per year for each customer.
EPA’s Valuation of Environmental Externalities from Electricity Production (see pg. 24 for summary)
o This white paper details how the Environmental Protection Agency (EPA) performs cost-benefit calculations for pollution regulation using three example regulations governing air emissions from fossil-fueled power plants: the Cross State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), and the Clean Power Plan (CPP).
o For each of these three rules the estimated health benefits from the rules greatly exceed the costs of compliance. The White Paper explains the calculations in greater detail, and some of the controversial elements of the calculations. Estimation of Transmission Costs for New Generation (see pg. 15 for summary)
o There are three major transmission components to consider when connecting a new power plant to the transmission grid: spur line, point-of-interconnection, and bulk transmission expansion.
o Bulk transmission costs required to interconnect new generation in the Electric Reliability Council of Texas (ERCOT) can vary significantly, from $0–$600/ kW of generation capacity, depending on how much the bulk transmission system must be extended. The high end of that range represents ERCOT’s Competitive Renewable Energy Zone (CREZ) high voltage transmission lines that cost $6.9 billion and which were designed to transmit approximately 11,000 MW of additional wind power capacity. Federal Financial Support for Electricity Generation Technologies (see pg. 26 for summary)
o Total federal financial support for electricity-generating technologies ranged between $10 and $18 billion in the 2010s. When considering total electricity-related support on a $/MWh basis, renewable technologies received 5x to 100x more support than conventional technologies. Depending on the year, fossil fuels and nuclear receive $0.5-2/MWh. Wind received $57/MWh in 2010 (falling to $15/MWh in 2019) and solar received $875/MWh in 2010 (falling to $70/MWh in 2019).
o Renewable generation is supported by subsidies targeting R&D, electricity production, and capacity additions, while fossil fuel power plants are supported via subsidies for fuel sales, fuel production, and pollution controls. Nuclear power receives diversified support in the form of R&D funding, tax credits on electricity sales, and programs aimed at plant costs (decommissioning, insurance). Impact of renewable generation on operational reserves requirements: When more could be less (see pg. 27 for summary)
o The purpose of this report is to describe the impact of utility scale (wind) renewable generation on operational system requirements, such as procurements of particular ancillary services within the Electric Reliability Council of Texas (ERCOT). o The results suggest that the changes in requirements for procured reserves due to ERCOT protocol revisions performed during the transition from the zonal to a nodal market in 2010 have been more significant than the changes in requirements due to an increase in installed wind power capacity of approximately 8,000 MW from 2007 to 2013.
Integrating Community Values into the Full Cost of Electricity (see pg. 23 for summary)
o Community values are increasingly being included in decisions about future supply and delivery of electricity instead of being solely driven by marketbased economic considerations. Unit-commitment, dispatch, and capacity expansion modeling of ERCOT (final paper forthcoming) The Past and Future of Net Metering for distributed Energy (paper forthcoming) Levelized Cost of Electricity of Microgrids across the United States (paper forthcoming) State-level Financial Support for Electricity Generation Technologies (paper forthcoming)