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Limits of Electric Grid Load Factor

Mon, 16 Mar 2026 19:50:37 GMT

Increasing load factor does not necessarily mean lowering rates

With the large number of new data centers connecting to the electric grid, much recent discussion has centered on the concept of load factor. The idea is that data centers, many with generally high load factors, can spread the gird’s fixed costs across greater electricity consumption, thereby reducing electricity rates.

Load factor is a simple, longstanding, and sometimes useful metric. It applies not just to the grid but also to other infrastructure systems. It is defined as the ratio of average load to maximum permissible peak load. Increasing a system’s load factor may reduce per-unit average costs by using more of the system’s capability. We see this in early-bird specials, movie matinees, and discounted hotel stays. Businesses do this to spread fixed costs, such as rent, over more customers. From its earliest days, electric company owners increased load factors by combining different electric loads such as lighting, streetcars, industrial motors, and even household toasters.

In other situations, increasing a system’s load factor may increase costs or reduce performance. For example, sometimes, due to overcrowding, school districts use double-shift schedules in which a single school building and its facilities are used for two distinct sets of students and teachers at different times of the day. Double shifts double the school’s load factor but come at unacceptable costs: reduced educational performance and a poorer quality of life for students, teachers, and parents. This is why school districts generally avoid this strategy except when there is no other choice.

The same can occur with the electric grid. For instance, adding electric vehicle charging or heat pumps to the electric system can increase the system’s load factor but whether electric rates on average increase or decrease depends on multiple factors, such as the ability to schedule the additional consumption during off-peak periods, the need for new capital investments in generation to re-optimize the generation mix, and any additional investments needed in transmission and distribution to prevent overloading. In other cases, adding more transmission capacity can reduce congestion, improve reliability, and reduce rates but not materially change the load factor. In short, increasing an electric system’s load factor is not synonymous with decreasing rates, reducing the costs of unreliability, or reducing the costs associated with health and environmental impacts.

It would be great if a single, easily calculated metric could unlock lower costs for the electric grid or other infrastructure systems. Load factor is an important metric, but not the only one. Policymakers should focus on the desired outcomes – rates, reliability, and health/environmental costs – and insist that analysts use appropriate methods and models to evaluate claims instead of a single rule of thumb.

Modeling Transmission Expansion in U.S. Net Zero Electricity Expansion Scenarios

Fri, 06 Oct 2023 15:45:37 GMT

The call to expand the U.S. transmission system to achieve massive greenhouse gas reduction goals is widespread. Electricity expansion studies that achieve net zero emissions on paper find feasible and least cost expansion generation and transmission expansion plans that do so with little if any, increase in electricity prices.

The call to expand the U.S. transmission system to achieve massive greenhouse gas reduction goals is widespread. Electricity expansion studies that achieve net zero emissions on paper find feasible and least cost expansion generation and transmission expansion plans that do so with little if any,increase in electricity prices. These same studies expand the existing transmission system by 2 to 3 times in 15-25 years toachieve net zero goals.

One question is whether these studies include sufficient modeling of alternating current transmission flows, intra-regional constraints, demand-side management, microgrids, and grid-enhancing devices. Another question is do they capture the “siting-related difficulties” of transmission planning. Both questions go to the heart of whether such findings are both feasible and least-cost.

A terrific webinar by Bret Sumner, hosted by ESIG, walks through a long list of such siting issues, including federal statutes such as the National Environmental Policy Act, Endangered Species Act, National Historic Preservation Act, and the Clean Water Act; county and local siting, condemnation, compensation, and authorities and processes; federal and state permitting overlap, restrictions, and resource plans that limit development on federal and state lands, checkerboard land ownership and split surface and subsurface land rights; Tribal ownership; and wildlife restrictions on construction. This list does not do justice to Bret’s 2021(or thereabouts) presentation: https://www.youtube.com/watch?v=p528pDLjlMo .

As the next round of electricity expansion modeling occurs, modelers should consider, if not already doing so, enhancing these models’ capabilities along these two dimensions of better modeling alternating current flows and siting challenges. Furthermore, policymakers should press for consideration of viable alternatives that do not push the limits of what may be doable with new transmission.

Some Thoughts on Electricity Markets, Single Clearing Prices, and Planning

Fri, 02 Jun 2023 20:43:05 GMT

The single clearing price should not be the focus of electricity market reforms

Recently, many have called for reevaluating electricity markets. In the May 2023 issue of the Energy Law Journal , FERC Commissioner Mark C. Christie argues for a reconsideration of the single-clearing price mechanism in U.S. electricity markets, and his paper addresses electricity market issues beyond the clearing mechanism. Among a long and growing list,particularly given the recent events in Europe, some examples include Carl Pechman (2021), Antonio Conejo and RamteenSioshansi (2018), and Martin Bichler et al . (2022). Capacity markets have also been the focus of much discussion ( Aagaardand Kleit, 2022 ).

Behind the single clearing price discussion is a debate about whether markets or planning would better serve society given its goals concerning electricity. If the primary goal is efficiency, that favors markets; if the primary goal is directing outcomes, mainly driven by State policies, then that favors planning. One’s view also largely depends on where one stands on the tradeoff between inefficient government and inefficient markets.

In response to these calls to revisit the case for electricity markets, this blog reviews and discusses some of the issues raised (with some quotations from Shakespeare along the way).Topics include the goal of electricity markets, the need for central or organized markets, choice, the single clearing price, out-of-wholesale-market payments, and integrated resource planning. It starts with a list of priorities for reforming electricity markets.

Suggested Priorities of Electricity Market Reforms

“Something is rotten in the state of Denmark.”

Priorities for electricity market reforms, in rough order of importance, are the following (not including transmission and distribution-related issues):

• Price-responsive demand ( Borenstein, 2005 ): Price-responsiveloads increase efficiency, lower electricity bills, reduce the need for generation, transmission, and distribution infrastructure, and improve reliability.

• Greenhouse gas pricing ( Nordhaus, 1992 ; Metcalf, 2009 ): Greenhouse gas pricing improves efficiency, lowers the cost of achieving a specific emission reduction, and can reduce, if not replace, the distortions that out-of-wholesale markets for renewables and nuclear power.

• Reducing out-of-wholesale market payments : Electricity markets, high penetration of wind and solar, and out-of-market payments ( Pollitt and Anaya, 2016 ; Felder, 2011 ) are discussed further below, but out-of-wholesale market payments undercut wholesale markets;

• Improving resource adequacy data, modeling, and metrics ( Felder 2004 ; Felder, 2001 ) and associated market mechanisms such as capacity and energy-only markets ( Aagaard and Kleit, 2022 );

• Extending reliability planning should include probabilistic reliability, resiliency, and adaptability ( Felder and Petitet, 2022 ) .

• Enhancing retail electricity rate design ( Borenstein , 2016; Felder and Athawale, 2014 ): New retail electricity rate design is needed to further price-responsive demand and to allow for the scalability of distributed generation while financially supporting the distribution system.

• Better consumer protections and information for retail and residential markets ( Fowlie, 2022 ; Kahn-Lang, 2022 ; Baldwin and Felder, 2019 ): Retail and residential markets are prone to unscrupulous practices by a few bad actors, and low- and moderate-income households are particularly vulnerable. Better consumer protections and information could help while allowing more choice with retail electricity purchases.

The rest of the blog discusses issues raised by some calls to reevaluate electricity markets.

Free Markets vs. Efficient Market

“Lawless are they that make their wills the law.”

There is an idea of a “free market” that maximizes fundamental choice beyond notions of efficiency. The consequence of this reasoning is that RTO markets are not markets but just anotherregulatory construct. Economists have acknowledged the tradeoff between regulation and markets ( Joskow and Schmalensee , 1988; Kahn, 1971 and 1988 ), and the choice is really about how to combine the two. A companion view to the “free market” position is that electricity markets undercut the democratic will of States, particularly given the role of States in determining generation ( Christie, 2023 ).

The goal of RTO/ISO markets is not a “free market/maximizing choice” but efficiency, and the means to achieve efficiency are a combination of regulatory and market mechanisms. Perhaps there is some higher political objective of having decentralized or “free electricity markets.” However, as discussed below, “free markets” introduce substantial inefficiencies with limited benefits. Furthermore, the critique of RTO/ISOs for having a single clearing price is overstated because they allow for choice,as seen in the prevalence of bilateral contracting in thesemarkets, as discussed below.

Deregulation, Restructuring, or Liberalization: Efficient Wholesale Electricity Markets Require Centralization

“A rose by any other name.”

When the “deregulation/restructuring/liberalization” of the U.S.power sector started in the 1990s, there was extensive debate regarding how electricity was similar and dissimilar to other products, particularly natural gas and other commodities. It was well-recognized that transmission and distribution should remain regulated.

After much debate, the prevailing view was that electricity’s loop/parallel flows and the need to balance supply and demand in real-time instantaneously distinguish electricity sufficiently from other commodities. A system operator conducting security-constrained economic dispatch and unit commitment would enhance reliability and efficiency over an utterly decentralized approach, such as contract paths (also referred to as “contract fiction”) and transmission loading relief (TLR) procedures. The tradeoff here is having a decentralized market that rarely gets available transmission right and, therefore, would be inefficient or a centralized one that uses the full capabilities of the transmission system without overusing them. Some of the numerous papers on this theme include Hogan, 1995 ; Baldickand Kahn, 1997 ; Rajaraman and Alvarado, 1998 . The contract path’s inefficient use of transmission is currently a motivational force in forming an organized Western wholesale electricity market .

Of course, no one word or short term captures this unique complexity of electricity’s loop/parallel flows, etc. However, the FERC’s use of the term “ organized markets ” to describe RTOs is sufficiently suggestive.

Bilateral Markets Provide Substantial Choice in RTO/ISO Electricity Markets

“A sympathy in choice.”

As noted above, the importance of choice is a common theme in the critique of organized markets. RTO/ISO wholesale electricity markets allow for bilateral agreements in which buyers and sellers negotiate contracts. Market participants can sign bilateral agreements for capacity, energy, financial transmission contracts, ancillary services, load response, and numerous risk management instruments through individual negotiations and over-the-counter platforms. Critics still raiseconcerns, however, with the lack of choice in the single clearing price, RTOs/ISOs administered markets of real-time energy, day-ahead energy, and capacity markets.

I have had clients that preferred bilateral contracts and conducted almost all their transactions within RTOs/ISOs outside of the administered capacity and energy markets and other clients that conducted all their transactions within the RTO/ISO markets. Having both sets of options seems to increase, not decrease, choice.

As an aside, casual observation of all walks of life/business sectors/areas of life confirms that we transact in numerous products and services without price negotiations. Of course, there are also many other examples in which prices are routinely negotiated. It is unclear why this definition of choice is essentialto electricity but not to going to the grocery store or why excluding or disfavoring the single-clearing-price option enhances choice or the underlying value that choice advances.

The Economic Reasoning for a Single-clearing Price in RTO/ISO Markets

“To be, or not to be, that is the question.”

Note that a single clearing price with locational marginal prices (LMPs) means that at a given location (busbar) at a given time for a given market (day ahead or real-time), the price that electricity is bought and sold is the same.

The claim that switching from a single-clearing price, also a uniform price, to some other unspecified mechanism could save electricity consumers substantial amounts of money is incorrect. Switching to a pay-your-bid approach changes bidding strategies away from suppliers bidding their marginal costs (in a competitive electricity market), thus reducing, if not eliminating,any potential savings. This lack of consumer savings is a notable finding ( e.g., Wolfram, 1999 ; Cramton, 2003 ; Kahn et al., 2001 ) but worth recalling the reasoning behind this result.

The industry could switch to a “pay your bid, get paid your offer” pricing rule. What would happen? Well, for those offers to sell and bids to buy that are economical, they would be submitted at the best guess of the clearing price. So, we would be back to a single price outcome, except given that it is difficult to guess what that single price is, there would be inefficiencies due to incorrect guesses or the exercise of market power due to lack of price transparency. ( Bower and Bunn, 2001 ). Bower and Bunn, 2000 further find that a single clearing price mechanism produces the lowest prices compared to any other one.

I have also tried a pay-your-bid, get-paid-your-offer approachwith thousands of students in a course on electricity marketsusing a stylized bidding simulation model ( Farr and Felder, 2003 ), and they always adjust their bidding strategy to the pay-your-bid, get-paid-your-offer rule, which imperfectly mimics the single price outcome.

What about average cost pricing? Versions of average cost pricing have been tried in actual electricity markets. It is also the foundation of cost-of-service pricing in rate of return rate making and the economic critique of inefficiency. Average cost pricing was embedded in zonal congestion pricing for energy, which resulted in inefficiency and gaming, leading multiple RTOs/ISOs (e.g., PJM, ISO-NE, CA-ISO, and ERCOT) to convert to locational marginal prices (LMPs).

Also, the goal of marginal cost pricing (a redundant and seemingly contradictory term) is efficiency, not low prices. If prices for input fuels increase, such as somewhat recent natural gas prices in Europe and, to a lesser extent, in the U.S., then the wholesale price of electricity should reflect this input fuel scarcity.

Out of RTO/ISO Market Payments are the Issue, Not Zero Marginal Cost Resources

“There is occasions and causes why and wherefore in all things.”

A vast array of subsidies and incentives are designed to increase renewable energy. Much has been written about the wholesale price implications of large amounts of zero or near-zero marginal-cost renewable resources such as wind and solar. A common claim is that these zero marginal cost resources reduce wholesale prices requiring a rethinking of market design. Significant issues with RTO markets and surrounding policies need to be reassessed. Directly relevant to this discussion is out of wholesale market payments, such as renewable portfolio standards and subsidies, that suppress the wholesale market price. Low/zero marginal cost resources are not per se the problem, but they are the problem when they have these out-of-market payments.

This issue is not new to the industry. Hydroelectric resources have zero variable costs (although their opportunity costs could be substantial). Nuclear and coal units are examples of resources with low marginal costs (before including any negative externalities).

The problem is not with near zero or zero variable cost units; the problem is that these resources are receiving payments outside of wholesale electricity markets. Consider the following example, assume there is a resource whose total cost per megawatt-hour (MWh) equals its marginal cost. Also, assume that this resource receives an out-of-wholesale-market paymentequal to its total cost/MWh every time it generates, along with the going wholesale price. This out-of-wholesale-market payment could be from a state renewable portfolio standard, tax credits, direct subsidies, or other sources.

So how would this resource offer into the wholesale market? It would offer $0/MWh. The resource recovers its total cost if the market clears at $0/MWh. If the market clears above $0/MWh, the owner recovers its total costs plus the wholesale price. If the market clears below $0/MWh, the resource does not run and makes $0.

What is the impact of the out-of-wholesale-market payment on the market clearing price? When the market has cleared above the resource’s marginal cost, then the resource is economical to run, and this resource suppresses the market clearing price. (The market clearing price is affected by this resource since it is running instead of a more costly one.)

If the resource’s marginal cost is above the market clearing price, it depresses it by running (after all, it offered zero) to a lower level. Society is paying for a higher marginal cost resource to run instead of a lower marginal cost one. In the case of the wind production tax credit, society was willing to pay well above the wind’s marginal costs to run, resulting in wind resources bidding in negative prices ( Huntowski et al., 2012 ; Seel et al., 2021 ).

The cause is not zero or near zero marginal cost resources; instead, it is resources receiving payments outside of the wholesale market. Not wholesale market design but out-of-wholesale market payments should be rethought, and meaningful greenhouse gas pricing reconsidered.

Integrated Resource Planning is No Panacea

“Every plan breaks easily because the intention is a slave to memory.”

There are advantages to integrated resource planning (IRP). The challenges, however, are long-standing: gaming of the data and process, favoring utilities, difficulties in implementation, static and inflexible plans, and time-consuming approval processes. Many utilities have divested most or all their generation assetsand are no longer relevant entities for planners. Also, numerous utilities and states exist within a power system such as PJM, so integrating the individual IRPs across utilities and states is impractical.

A Hybrid of Markets, Mandates, and Out-of-Wholesale-Market Payments Combines the Worst of Markets and Planning

“Neither fish nor fowl.”

Both state and federal incentives and mandates direct the types and amounts of generation investment, the current model is neither IRP nor market-based, and we could end up with the worst of both worlds ( Felder, 2017 ).

Bearing the Risk of Bad Outcomes

“Put money in thy purse.”

Electricity markets have shifted some risks from consumers to suppliers, although not completely depending on one’s views of how organized markets are performing and the role of stakeholders in the RTO/ISO governance process ( Felder, 2012 ). Recall that under the cost-of-service model, the utility had an obligation to serve, accompanied by the social compact (i.e., if the utility acted prudently, it would have the opportunity to recover its investments). One motivation for electricity markets was to avoid ratepayers paying for out-of-market contracts, such as PURPA ones, partially completed power plants, and power plants with extensive budget overruns. How much ratepayers pay for these excessive costs was the stranded cost debate of the 1990s. Capacity markets have limitations, and perhaps, as Aagaard and Kleit ( 2022 ) find, they result in supplier overpayments but at least do not include partially built power plants or cost overruns. Market power and manipulation are significant concerns with electricity markets ( Kelliher, 2005 );overcapitalization and inefficiency are considerable concerns under a regulatory model ( Averch and Johnson, 1962 ).

Revisiting the motivations, structure, and consequences of electricity markets is an essential discussion as the industry incorporates more renewable resources, extends its reach into the transportation and other sectors, and seeks to improve its reliability and resiliency. Past debates and discussions can help inform these efforts to continue to improve the sector’s performance.

Proposed Research Agenda for Probabilistic Risk Assessment of Power System Reliability, Resiliency, & Adaptability to Improve Policymaking

Thu, 11 May 2023 19:29:26 GMT

This blog reviews current research & discusses the next steps in developing a comprehensive probabilistic risk assessment of power systems to inform policymaking.

Introduction and Motivation

Improving power systems' reliability, resiliency, and adaptability (RRA) is an urgent priority. There is an overwhelming need for better models of the costs and benefits of policies and measures that compare the statistical distribution of existing and proposed solutions across affected populations ( Felder et al. 2021 ). Given limited resources, the social and economic benefits of enhanced RRA need to be compared to the associated costs of doing so ( NARUC 2023 ).

The rapidly changing context of the electric power sector is also increasing the need and urgency for improved RRA modeling to inform policymaking. The continued build-out of variable and intermittent renewables such as wind and solar PV, development and deployment of energy storage technologies, the occurrence of severe weather events and the changing climate, and increased electrification including electric vehicles (EVs), heating, and industrial processes all depend on reliable, resilient, and adaptable power systems.

Reliability refers to the power system's ability to function under typical conditions and contingencies without disconnecting firm load. It includes resource adequacy and operational reliability (historically called security). Resiliency refers to the ability of the power system to withstand severe but less frequent contingencies with minimal loss of load and the ability to restore service to all customers ( FERC 2018 ) quickly. Adaptability refers to the ability of customers to mitigate the loss of electricity to reduce the costs of not having power ( Felder and Petitet 2022 ).

Current Efforts to Improve Probabilistic Risk Assessments of Power Systems

Two significant ongoing efforts to improve the modeling capabilities to inform policymaking are resource adequacy modeling and resiliency modeling. Both can be subsumed under the umbrella term of probabilistic risk assessment of power systems. The research community has been actively developing and expanding these capabilities, focusing on reliability over the last several decades and, more recently, on resiliency.

Many textbooks codify these developments from resource adequacy to operational reliability ( Li 2011 , Billinton and Allan 2012 , Li 2013 , Li 2014 , Brown 2017 , Tuinema et al. 2020 ). The starting point was independent equipment failures using analytical techniques to calculate various adequacy metrics such as loss of load expectation (LOLE) and the amount of unserved energy (USE). The analyses expanded to include the transmission system, including interconnections and dependent outages, sometimes subdivided further to common-cause outages, component-group outages, station-originated outages, cascading outages, and environment-dependent failures ( Li 2014 ) . Other authors have used or are using different taxonomies. Wind and solar PV have spawned the concept of correlated events ( ESIG 2021 ). Recent efforts focus on improving and expanding reliability metrics, using chronological models based upon Monte Carlo simulations, incorporating common-cause outages and correlated events, including flexible energy resources such as load, storage, and EVs, and improving transparency and transparency consistency of modeling efforts ( ESIG 20 21 ). An important topic in improving resource adequacy models relates to capacity requirements and mechanisms, both regulatory and market-based, with the rising penetration of wind and solar PV and falls under the question of what is the effective load-carrying capability (ELCC) of resources ( Schlag 2020 ).

F rom the resiliency literature, one key concept is the resiliency trapezoid ( Petitet et al. 2022 ). The trapezoid captures the duration and magnitude of an event but not the frequency and timing. These four factors affect an event's social and economic costs. An extended blackout due to severe cold weather is much more damaging than a slight load reduction during a short period on an afternoon with mild weather. The trapezoid points to the limitations of commonly used resource adequacy metrics such as LOLE, which have received much attention ( e.g., Stenclik 2021 ) but the limitations of which have been well documented for decades ( Felder, 2001 ).

Another strand in both literatures links actual power outages and their causes to models. Resource adequacy issues do not cause many power outages due to independent failure modes, as recent and long-standing references have noted (e.g., ESIG 2021 , NARUC 2023 , Billinton and Allan 2012 and their 1984 edition, Felder 2004 ). A cursory review of New York Times articles regarding power outages or examining U.S. Department of Energy data on system disturbances also supports this finding. Work in linking the state of the power system to its capabilities and failure modes is ongoing.

Proposed Research Agenda for Probabilistic Risk Assessment of Power Systems

The resource adequacy and resiliency literatures are converging under the umbrella of probabilistic risk assessment of power systems. As resource adequacy analyses expand the types of failure modes they address, extend their scope to include transmission, distribution, and load, and enhance the reliability metrics, they will arrive at a complete reliability and resiliency model of the power sector.

The elements identified below are needed to be incorporated within an analytical framework to provide policymakers with a comprehensive and detailed set of tradeoffs among the benefits and costs of various policies and measures to reliability, resiliency, and adaptability.

Additional Modeling Capabilities

1. Include operational reliability failure modes that lead to cascading failures, which have caused major blackouts.

2. Incorporate power system state dependent failure modes and capabilities into models.

3. Develop location-specific analyses (e.g., subregions, nodes/busbars) on the power system in addition to aggregate system-wide studies, which can be done given the flexibility and detailed capabilities of Monte Carlo techniques but require substantial computational efforts.

4. Present results to include uncertainty distributions in addition to expected values of costs, benefits, and other metrics.

Additional Policy Options

5. Add adaptability measures such as emergency shelters, backup power supplies, etc. since these measures mitigate the cost of power outages.

6. Determine public safety, health, and economic costs as a function based upon resiliency trapezoids to account for the timing, frequency, duration, and magnitude of power outages instead of relying upon the singular value of lost load (VOLL).

7. Evaluate multiple policy options such as regulatory mandates, incentives, and market mechanisms to improve accountability? for regulatory and market incentives given the strategic behavior of firms, organizations, and regulators.

Better and More Data

8. Acquire more comprehensive and detailed data sets of failure modes and power outages, especially due to dependent failures.

9. Incorporate Bayesian updating of data to account for non-stationarity of climate change and emerging performance of new technologies, which requires multi-year data collection.

References

Billinton, R., & Allan, R. N. (2012). Reliability assessment of large electric power systems. Springer Science & Business Media.

Brown, R. E. (2017). Electric power distribution reliability (Vol. 1). CRC press.

ESIG. (2021). Redefining Resource Adequacy for Modern Power Systems.

Felder, F. A. (2001). "An Island of Technicality in a Sea of Discretion": A Critique of Existing Electric Power Systems Reliability Analysis and Policy. The Electricity Journal, 14(3), 21-31.

Felder, F. A. (2004). Incorporating resource dynamics to determine generation adequacy levels in restructured bulk power systems. KIEE International Transactions on Power Engineering, 4(2), 100-105.

Felder, F. A., Unel, B., & Dvorkin, Y. (2021). Modeling strategic objectives and behavior in the transition of the energy Sector to inform policymaking. The Electricity Journal, 34(8), 107009.

Felder, F. A., & Petitet, M. (2022). Extending the reliability framework for electric power systems to include resiliency and adaptability. The Electricity Journal, 35(8), 107186.

FERC. (2018). 162 FERC ¶61,012. January 8.

Li, W. (2014). Risk assessment of power systems: models, methods, and applications. John Wiley & Sons.

Li, W. (2013). Reliability assessment of electric power systems using Monte Carlo methods. Springer Science & Business Media.

Li, W. (2011). Probabilistic transmission system planning. John Wiley & Sons.

NARUC. (2023). Energy Resilience Reference Guide. February 23.

Petitet, M., Felder, F., & Alhadhrami, K. (2022). One Year After the Texas Blackout: Lessons for Reliable and Resilient Power Systems (No. ks--2022-dp09).

Schlag, N., Ming, Z., Olson, A., Alagappan, L., Carron, B., Steinberger, K. and Jiang, H. (2020). "Capacity and Reliability Planning in the Era of Decarbonization: Practical Application of Effective Load Carrying Capability in Resource Adequacy," Energy and Environmental Economics, Inc., August.

Stenclik, D. (2021). Beyond 1-day-in-10-Years: Measuring Resource Adequacy for a Grid in Transition. ESIG Blog, November 29.

Tuinema, B. W., Rueda Torres, J. L., Stefanov, A., Gonzalez-Longatt, F., & van der Meijden, M. A. M. M. (2020). Probabilistic Reliability Analysis of Power Systems. Cham, Switzerland: Springer International Publishing.

Limitations of the Loss of Load Probability/Expectation Criterion in Electric Power Systems

Wed, 26 Apr 2023 20:56:12 GMT

The deficiencies with the LOLP/LOLE criterion are well known and were raised many years ago

Recent U.S. blackouts in Texas and California and many international blackouts are leading many to reconsider the reliability and resiliency policies of the electric power system. One element that is being discussed is whether the loss of load probability (LOLP) or loss of load expectation (LOLE) criterion of “one-day-in-ten-years” or “one-time-in-ten-years” should be replaced , perhaps by an expected unserved energy criterion or set of other reliability metrics.

The deficiencies with the LOLP/LOLE criterion are well known and were raised many years ago, including noting that this criterion does not account for the magnitude of power outages. Other significant deficiencies were identified as well. In April 2001, more than twenty years ago, I published the following in the Electricity Journal under the heading “The LOLP Criterion Should Not Be Used for the Basis of Policy”:

The first limitation of the LOLP criterion is that, because it is defined by the assumptions made to calculate the LOLP, it is stricter or more lenient depending upon those assumptions. For example, not considering emergency generation ratings during capacity shortages makes it more difficult for a generation system to meet the one-day-in-10- years criterion than does considering these emergency ratings. There is substantial variation in how NERC regions and subregions calculate LOLP.

Second, the LOLP generation adequacy criterion does not consider the severity of a situation. The contribution to the LOLP is the same whether the system is short 1 MW or 1,000 MW. Other adequacy indices do measure the amount of unserved energy and the frequency and duration of periods in which demand is greater than supply. These indices, however, are not widely used as the basis for policy in North America.

A third limitation of the LOLP criterion is that it is not a useful index of widespread blackouts. Understanding quantitatively the contributors to widespread blackouts is likely to be more important to policymakers than knowing the LOLP. For example, assume that the LOLP is 0.1 and the average amount of the load curtailment is 100 MW out of a 20,000 MW system. Now assume that the probability of a blackout of the entire system is 0.01. On an expected MW basis, the blackout is 200 MW, 20 times greater than for load curtailment, which is 10 MW. Furthermore, recovering from a blackout is likely to take longer than would restoring specific parts of a system that were disconnected in a controlled manner. A blackout is also likely to have a higher cost per MWh of unserved load than a controlled and limited curtailment. For example, riots may be less likely to occur during a controlled and limited curtailment than during a blackout. Many factors contribute to the probability of blackouts in addition to generation adequacy, including operating procedures, operator training, security requirements, and the ability of the system to withstand transients. These factors are not incorporated into existing adequacy models and their LOLP calculations. To the extent that policy formation considers these factors, it does not do so formally, which may not result in consistent and rational policies.

The LOLP/LOLE criterion deficiencies are just the tip of the iceberg. The resource adequacy paradigm needs to be rethought, partly due to the changing nature of the electric power sector, but also to improve the efficacy of society’s reliability, resiliency, and adaptability policies .

Comments on New England Forward Clean Energy Market Proposed Market Rules, Version 1

Thu, 20 Apr 2023 21:44:22 GMT

Pursuing an FCEM may be a distraction and counterproductive to achieving public policy objectives

Summary

The Massachusetts Department of Energy Resources (MA DOER) issued its New England Forward Clean Energy Market: Proposed Market Rules, Version 1 (FCEM Proposal) in January 2023 with contributions from The Brattle Group and Sustainable Energy Advantage. The FCEM Proposal’s aim is to be a trading platform for multiple regional and state clean energy and capacity certificates consistent with the region's wholesale electricity markets, governed by the six New England states, and administered by the ISO-NE or a new affiliate.

The FCEM Proposal is unlikely to fulfill its stated objectives, will take several years to implement even under favorable assumptions, and faces multiple challenges that may further delay or undercut its implementation. The Proposal has the following significant limitations:

• Its claims of enhancing efficiency and maintaining reliability are unsubstantiated and depend on having regional clean energy and capacity certificates that are broadly accepted by states, regionally traded, and linked to cost-effectively reducing greenhouse gas emissions, whereas the FCEM Proposal likely traded products are state-specific and indirectly connected to reducing greenhouse gas emissions.

• It creates a complex web of multiple clean energy and clean capacity certificates overlaid with existing markets for energy, capacity, and emission allowances, subject to federal and state legal and regulatory uncertainty, particularly in the initial years of implementation.

• Its governance structure has yet to be determined, let alone finalized.

• To be implemented, many other vital components must be specified, including the auction mechanism, organizational structure, funding source and budget, credit and market monitoring policies, product definitions, and associated market rules.

Achieving substantial reductions in greenhouse gas emissions reliably and cost-effectively is necessary for the health and welfare of New England residents and creating the broad base of necessary political support. Pursuing a FCEM may be a distraction and counterproductive to achieving these more general policy goals.

The FCEM Proposal is Unlikely to Achieve its Stated Goals

The FCEM proposal makes some strong but unsubstantiated claims regarding achieving its desired goals:

1. “The competitive FCEM platform will offer a robust financial commitment sufficient to attract large-scale investments in new clean energy projects, utilize a forward auction structure to drive competition and innovation, and secure clean energy supply at affordable prices” (p. 1).

2. “The FCEM will offer a more competitive and transparent platform for consumers and policymakers to procure their clean energy requirements at lower prices and in a fashion that shifts risks from consumers to producers” (p. 3).

3. “Because clean electricity incentives will be incorporated into a regional market structure, the FCEM will substantially harmonize the investment signals provided by the ISO-NE electricity markets with the investment signals needed to achieve state policy requirements” (p. 3).

4. “Further, the FCEM and new regional clean attribute products transacted through the FCEM will be designed to offer incentives that are in alignment with operational dispatch incentives that meet reliability and policy requirements at the lowest combined cost” (p. 2).

The FCEM Proposal asserts but does not substantiate these claims. Perhaps the assumption is that these claims have already been demonstrated in the multiple FCEM reports and presentations that have been made over the last several years, some of which are identified below in the Reference section.

The underlying premises of these other documents are that regional clean energy and capacity certificates can be developed that are (a) broadly accepted by states and regionally traded and (b) linked to cost-effectively reducing greenhouse gas emissions. The economic value of a regional market for clean energy certificates is that they are accepted throughout the region and that they replace the fragmented and inconsistent, and perennial changing definitions of clean energy certificates among the six New England states. The FCEM Proposal does not, however, solve this underlying issue, and it retains the State-Defined Certificates (Table 2, p. 11) while proposing yet-to-be-defined regional certificates.

Specifically, neither of these assumptions (a) and (b) are valid per the FCEM Proposal. The FCEM effort has been underway for at least five years, and there is yet to be adefinition of regional clean energy and capacity products that all six New England states agree upon. Although the MassachusettsDOER had “interviews, comments, and discussions" (p. i) with the other five New England states in developing the FCEM Proposal, it does not claim agreement and, in fact, acknowledges that the Proposal needs to be refined "into a comprehensive market structure" (p. i).

Regarding assumption (a), the FCEM Proposal further underscores just how undetermined these regional product definitions are for the four regional products (New England Renewable Energy Certificate, Clean Energy Attribute Certificate, GHG Marginal Abatement Certificate, and Clean Capacity Certificate).

"Table 2 summarizes the general description and technologies eligible to sell each regionally-defined FCEM attribute product. The preliminary determination of eligible technologies under each product will be refined by representatives of New England states based on stakeholder input, consistent with the FCEM guiding principles to maximize the benefits that the FCEM can offer to the New England states" (p. 10).

Regarding assumption (b), the FCEM Proposal “does not include enhanced greenhouse gas (GHG) or carbon dioxide emission pricing but is designed to be forward-compatible with higher GHG pricing that may rise through other states, regional, or federal policies" (p. 2). Pricing GHG emissions is generally accepted (by economists at least) as the most cost-effective way to reduce them. Putting aside what “forward-compatible” means or why it is the case, at best the FCEM does not conflict with efficient GHG pricing.

The FCEM Proposal does contain a GHG Marginal Abatement Certificate using a "pre-defined standardized abatement rate" to reflect the marginal GHG reduction (Table 2, p. 11), which is determined three years in advance to accommodate the timeline of the FCEM auction (p. 12). The accuracy and cost-effectiveness of abatement certificates depend on the locational marginal emission (LME) rate and the administratively determined abatement rate. Moreover, it needs to be established whether these certificates will reduce GHG emissions beyond what would occur under the Regional Greenhouse Gas Initiative (RGGI).

The FCEM Proposal creates a complex web of multiple clean energy, and clean capacity certificates overlaid with existing markets for energy, capacity, and emission allowances, subject to federal and state legal and regulatory uncertainty, particularly in the initial years of implementation. Besides creating four new clean energy certificates, the FCEM Proposal has substantial variations for many of these certificates, such as three possibilities regarding resources (any preference for new or new required) (Table 5, p. 29) and accommodating phased entry of new clean energy projects such as large-scale offshore wind (p. 33). Moreover, some products are for multiple years, such as the "new resource price lock-in (p. 4) and the "10-year demand volume commitments" (p. 4), and allow up to ten distinct demand bid segments for some certificates (p. 28). The availability and definitions of these certificates could change annually (p. 9), new ones could be proposed (p. 10), and there would also be the existing and potentially changing state-defined products. The auction would accommodate both buyers and sellers indifferent to buying or supplying several cross-products (p. 24, Figure 4 Notes; p. 42), requiring the auction mechanism to track these requests and the substitutability and non-substitutability of different products. Furthermore, sellers can specify whether their offers can be partially cleared, including within segments (p. 42) and whether their offer is contingent on receiving a multi-year price and volume lock-in (p. 36). The FCEM Proposal acknowledges that multiple runs of the auction may be needed, a "clearing run" and a "pricing run" to work (p. 48, footnote 31).

The result of all these market elements is potentiallyilliquid markets that result in volatile prices that are hard to interpret and not signal efficient future buying and selling behavior given the complex interaction among multiple certificates with the wholesale electricity markets and ever-changing products and definitions. The FCEM Proposal permits the banking of certificates, which would help reduce price volatility from "end price effects" (p. 21, footnote, 21), but would not completely address all the causes of illiquidity. Some of the desired features in the FCEM Proposal introduce mathematical difficulties, "non-convexities," into the problem that makes it difficult to solve in theory let alone in practice.

The FCEM Proposal Will Take Multiple Years to Implement and Faces Implementation Challenges

Since November 2017, the FCEM has been under discussion in New England (see date of Brattle et al. presentation in the Reference section). Assume that all six New England States agreed on January 1, 2024, the governance structure, certificate definitions, stakeholder processes, market monitoring, mitigation, and budgeting and administration; at best, the first 3-year forward auction would occur in 2025, with delivery in 2028. This schedule assumes a very optimistic one year to standup a board of directors, create an organization, workout the myriad of legal and jurisdictional issues between the states and the Federal Energy Regulatory Commission (FERC) and the FCEM and the ISO-NE, and test and validate its complicated auction mechanism.

This schedule is optimistic for several reasons. First, the most compelling one is that even after five years of discussions, the FCEM Proposal has major, open-ended questions about its governance, product definitions, and auction mechanism. The FCEM Proposal does not provide a reason to believe that in 2023, six states with different approaches to clean energy policy, different politics, and priorities will suddenly agree upon a meaningful regional solution that garners even some of the benefits the FCEM Proposal claims.

Second, the list of legal agreements that would need to be reviewed and potentially modified is extensive: the region’s Open Access Transmission Tariff (OATT), the NEPOOL Participants Agreements, and the NESCOE Memorandum of Understanding (p. 8), the first two require FERC approval along with extensive procedural and time-consuming process requirements. "Through the market would be FERC-jurisdictional, state representatives would take the primary role in developing and approving new FCEM market rules through appointing the six members of the FCEM-NE Board of Directors" (p. 7). This approach is a significant reordering of the political power structure of the region's electricity markets. Regardless of what one thinks of this current governance structure, changing it to shift power from the FERC to the states and from NEPOOL to the states will take work.

Third, as noted in the prior section, the auction mechanism is complicated, given the multiple products and their variations. The FCEM Proposal provides a qualitative description of the FCEM Auction Clearing Optimization Formulation (Equation 3, p. 48). Until the actual mathematical formulation is provided (which requires finalizing certificate products and definitions), tested to demonstrate that it is both solvable under a wide range of market conditions and strategic offering and bidding behavior and scalable to being implemented, there is little reason to believe that this is auction is workable.

Fourth, the startup financing of the FCEM organization needs to be specified. The FCEM Proposal states that it "will be funded through a surcharge on transactions with the FCEM” (p. 9). Still, these transactions will not occur after at least four years, one year of organizational startup, and three years for the first forward capacity market to settle financially. Taking the annual cost of RGGI as a rough guide, which is $3.4 million for 2023, $13.6 million would be needed to start up the FCEM, assuming that everything goes to plan on a very tight schedule. The RGGI budget estimate may need to be higher, given the complexities of the FCEM auction design discussed above. The FCEM Proposal also envisions a trial phase "to serve modest volumes of demand in the initial years" (p. 2). Suppose there are insufficient FCEM transactions to recover the startup and ongoing expenditures. In that case, a vicious cycle could occur in which more and more costs are allocated to fewer transactions grinding them to a halt.

There are several other significant implementation challenges. The FCEM's Board of Directors would substantially influence the pricing and payments to many clean energy investments requiring extensive and transparent conflict of interest protections. Developing a Market Monitoring and Mitigation capability for many new products that interact in complex ways with each other and with wholesale electricity products would be a new endeavor. Cross-product market manipulation is a significant issue within wholesale electricity markets, and the FCEM would introduce more opportunities for such behavior. Credit policies, stakeholder engagement processes, and coordination with the ISO-NE must also be developed and honed.

The FECM Proposal characterizes itself as "draft rules" (p. 1), which is inaccurate. It is a framework with many open-ended issues to be agreed upon in principle, let alone finalized at the level of details needed to be market rules, such as NEPOOL's Market Rule 1, as the FCEM Proposal intends (p. 8).

Conclusion

The clean energy transition of New England’s electricityand broader energy sector requires a comprehensive and workable policy so that it can be accomplished economically and reliability. The FCEM Proposal, while directed at these goals, falls short due to being incomplete, vague, and fluid while also being potentially unworkable and counterproductive. New England and the broader Northeast region have in place the appropriate policy framework consistent with the design of their wholesale electricity markets to achieve decarbonization goals efficiently and reliably by further reducing the regional cap on carbon dioxide emissions over time.

References

Brattle Group, Transition to New England’s Future Grid, Forward Clean Energy Market: A Market-based Option for States to Achieve their Clean Electricity Goals, July 2020 (with links to full studies)

Brattle Group and Coalition Partners, A Dynamic Clear Energy Market in New England, November 2017

MA DOER, New England Forward Clean Energy Market: Proposed Market Rules, Version 1, January 2003

Regional Greenhouse Gas Initiative, Inc. Meeting of the Board of Directors, December 2, 2022

See also: https://www.iso-ne.com/committees/key-projects/new-englands-future-grid-initiative-key-project/

How to Think About Investing in the Grid for Reliability and Resiliency

Thu, 20 Apr 2023 21:15:34 GMT

Utility executives, investors, business developers, and policymakers are confronting a wave of suggestions for improving the power sector's reliability and resiliency

The electric power sector is rapidly changing, adopting new technologies, such as energy storage, renewables, and digital technologies, expanding its service to include transportation and energy-intensive industrial applications, and enhancing reliability and resiliency in changing physical and regulatory climates. Utility executives, investors, business developers, and policymakers are confronting a wave of suggestions for improving the power sector's reliability and resiliency. How should decision-makers think about the competing and never-ending list of to-dos?

The power system's reliability and resiliency are fundamental to society’s physical, health, social, and economic well-being. The power system directly provides the electricity needed for society's essential services. It is the cornerstone of other critical infrastructure such as water, shelter, food, health delivery, communication, financial services, and transportation. Nonetheless, society has many different pressing needs besides having a reliable and resilient power system, and therefore it can only allocate finite resources to it.

The first step is to clearly define the criteria of a reliable and resilient power system based on the social costs of not having electricity. Blackouts are damaging in terms of human lives, health, and economic costs, and these damages depend on a blackout’s timing, frequency, duration, and magnitude. Measures to reduce a blackout’s impact are costly. The key consideration is determining whether any measure’s cost is less than the costs it avoids by decreasing a blackout’s frequency, duration, and magnitude.

This determination is not trivial and requires a sophisticated and detailed model of the power system's threats, components, topology, and operational and planning practices. Recent blackouts worldwide, particularly in Texas during the winter of 2021, have revealed that the current modeling approach used by the industry needs to be narrower. The models do not sufficiently consider resiliency, that is, the ability of the power system to withstand and bounce back from severe events such as extreme weather, physical sabotage, or a cyberattack. Furthermore, the models do not account for common-cause failures, that is, a single event that leads to multiple equipment failures, whether within the power system or supporting infrastructure, such as fuel supplies and transportation or communication and control systems.

Once improved models are developed that include reliability and resiliency engineering and blackout costs, decision-makers can consider alternatives to improving the power system’s performance.From a public policy perspective, such a capability should enable policymakers to be more comfortable in making informed decisions knowing that both costs and benefits are being considered and that the best use of limited resources is being pursued. Utilities have a framework for business planning, which inevitably involves public policy considerations since utility commissions regulate them. Developers of new and emerging technologies also have a framework to direct their investments and justify their products and services.

Enhancing the reliability and resiliency of the power system needs to occur concurrently with decarbonizing the sector and maintaining affordability. These three societal objectives are sometimes called the energy trilemma and can be applied more broadly to energy policy. Furthermore, achieving these three goals for the power sector must be aligned with the broader changes across the entire energy landscape. But the same underlying principles that are the foundation of cost-effective reliability and resiliency decision-making apply. Identify cost-benefit economic criteria that include society's broader public safety and health, develop tractable and informative models that assess the tradeoffs among competing objectives, and evaluate individual technologies and policies based on their cost-effectiveness.

Political Economy of U.S. Offshore Wind

Thu, 20 Apr 2023 19:11:37 GMT

Internationally, offshore wind has contributed to the energy transition in Europe and is poised to do so in the U.S., starting in the Northeast

Internationally, offshore wind has contributed to the energy transition in Europe and is poised to do so in the U.S., starting in the Northeast. Undoubtedly, offshore wind is an essential component of decarbonizing the power sector.

To date, offshore wind proponents have successfully built a political argument and coalition to spend a hundred billion dollars – the total is not in sight – for offshore wind, offshore transmission, onshore transmission, seaport expansions, and tax breaks for supporting vessels. They have linked the real and significant threat of climate change to create a new manufacturing industry onshore. The mantra is that offshore wind is necessary to avoid a climate disaster and will create good-paying jobs. The Biden Administration wants to reach 30 gigawatts by 2030, and eight east coast states have committed to 39 gigawatts by 2040 . This is quite impressive.

The offshore wind coalition of climate change advocates, developers, supporting industries and trades, and consultants have been successful for several reasons. First, their case is plausible. An overhaul of the electric power system requires the rapid build-out of all good options, and offshore wind has a successful track record in Europe.

Second, the coalition bifurcated offshore wind development from transmission expansion . States committed to offshore wind farms before developing supporting offshore and onshore transmission plans. They suspected that if wind farms and transmission expansion costs were considered together, the total would likely be too much for the public to accept.

Third, when discussing jobs and economic development, the coalition ignored the drag on the economy of increasing electricity rates to support offshore wind . Like a laser beam, the focus was on the economic development benefits of offshore wind investments, not the financial costs of financing them. The result is clear: the economic benefits and the employment gains are much more significant when doing so.

Fourth, foreseeing additional offshore and onshore transmission costs to support such a significant addition of offshore wind will likely be extraordinary; the coalition has focused on how much can be saved if transmission planning is done right. What the coalition calls anticipatory transmission planning, i.e., determining the needed transmission of all projects collectively instead of individually, is estimated to save tens of billions of dollars . It is unclear whether these claimed savings are meaningful, as opposed to being a strawman, because transmission planning would consider multiple options and, therefore, would have rejected vastly more expensive approaches.

Given the success of this coalition, expect to keep hearing the mantra: offshore wind is necessary to combat climate change, it creates good-paying jobs, and proper planning will save money. Even if this mantra is correct, proponents of offshore wind, if their case is to have real public policy merit, must answer the following questions:

• What are the total costs and the costs per megawatt-hour of the offshore wind farms and additional offshore and onshore transmission (for different levels of offshore wind commitments)?

• What is the cost of the next best alternative of onshore wind, solar, energy storage, and nuclear power (along with any needed transmission)?

• What are the economic gains of offshore wind investments and the economic losses of higherelectricity rates to fund offshore wind and associated transmission?

• What is the total cost per ton of carbon dioxide avoided due to offshore wind, and how does it compare to the social cost of carbon?

So far, offshore wind advocates have a winning political message and coalition. At some point, however, when the public is asked to start paying the bill, and other greenhouse reduction strategies are crowded out due to offshore wind’s dominance, the coalition will have to answer these questions or risk their ambitions being terminated.