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The costs that power interruptions impose on customers and society have emerged as essential considerations for decision-making about power system reliability and resilience. While the direct costs of localized and relatively short-duration power interruptions are well-understood, little is known about the full impact of widespread and long-duration power interruptions, especially the indirect costs and related economy-wide impacts of these events. As a result, the costs of widespread and long-duration power interruptions are generally not or only incompletely considered in utility planning activities. This paper describes a new approach for estimating the economic costs of widespread and long-duration power interruptions. This method involves using survey responses from utility customers to calibrate a regional economic model that can estimate both the direct and indirect costs of these events. Including better estimates of these costs will enhance both the comprehensiveness and completeness of the considerations relied on to support utility planning decisions, especially on grid-hardening strategies and other capital-intensive investments in electricity sector resilience.

This study explores the joint impacts across the power system of distributed energy resources (DER) that could be deployed in utility distribution systems through an analysis of generation, transmission, and distribution expansion and costs driven by DER adoption. We identify six adoption scenarios that combine deployment levels of rooftop solar photovoltaic modules (PV), electric vehicle charging (EV), and battery storage in residential and commercial customers connected to representative feeders in Indiana by 2025 and 2040. Indiana is a good proxy for many U.S. states with low current DER adoption but potentially high future growth. The economic value of DER is assessed by developing capacity expansion and power flow analysis of the generation and distribution segments, respectively, under future hourly demand assumptions based on each adoption scenarios. Results for the distribution system power flow simulations show that voltage violations are relatively rare. Voltage violations can be mitigated at a very low cost using a combination of smart inverters in future rooftop PV systems and voltage adjustments in the feeder heads. Line loading issues are minimal, with only 0.2% of simulation hours showing loading levels above 100% of capacity. Generation capacity impacts are driven by unmanaged EV charging and could be mitigated with charging management. We estimate that the incremental rate impact from power system investment and operation of increased DER adoption in Indiana will be between −1.6% to + 2% in 2025 and + 0.2% to + 15% in 2040 relative to the base case.

This study is the latest in a series of LBNL research into U.S. ESCO industry characteristics and market trends. The research is based on interviews with ESCO industry executives conducted during the fall of 2019 and the first half of 2020. Nearly all companies that identified themselves as ESCOs were contacted as part of this project.We find that after a period of little growth (2011-2014), industry revenues reached an estimated $6 billion in 2018, or a 3.4% annual average growth rate from 2015-2018. ESCOs primarily serve the public an institutional sectors (e.g., federal, state, and local governments; university and colleges; and K-12 schools). In 2018, project investments by public and institutional organizations accounted for over 90% of industry revenue, which is consistent with previous industry studies. ESCO activity in the Middle Atlantic, East North Central, and Pacific regions in the U.S. delivered the highest share of revenue in 2018, which is also consistent with earlier research. ESCOs reported that a majority of their customers use energy savings performance contracts (ESPCs) primarily for facility capital improvement needs and resilience rather than utility savings. In addition, the importance of non-energy benefits (e.g., water savings, avoided operations and maintenance costs, and avoided capital costs) accounted for in the project savings guarantee reportedly increased in all markets during 2016-2018 compared to previous time periods.The study found that the ESCO industry faces several key challenges, including: (1) increasing project development times due to more complex projects and other factors; (2) difficulty finding qualified subcontractors in some regions, including minority- women- and disadvantaged population-owned small business enterprises; and (3) difficulty accessing project documents and quickly fulfilling customer requests to justify project payments several years into the performance period of a project.

Resource adequacy (RA) is the ability of an electricity system to reliably satisfy loads using its available resources. Assessing and maintaining RA is becoming more challenging due to increasing coal plant retirements, penetration of wind and solar resources, reliance on bilateral and market transactions, and emerging technologies. RA evaluation and planning have traditionally been conducted by utilities and overseen by their state regulators using integrated resource planning (IRP) processes. However, the Northwest Power Pool (NWPP) is developing a proposal for a regional RA program in the Western U.S. that would set and enforce capacity obligations for member utilities, and achieve RA more cost-effectively by pooling resources and load profiles from across the region. In this paper, we investigate the policy implications of a regional RA program for existing IRP regulations, with the proposed NWPP RA program as our main object of study. We compile the RA assessment practices of Western U.S. utilities, the proposed NWPP RA program design, and lessons from the historical experience of the Southwest Power Pool's RA program. Our analysis reveals that the IRP components which would be most heavily impacted by the regional program are RA targets, load forecasts, capacity accreditation factors, and transmission upgrades. We conclude by discussing the policy issues that RA program design and state IRP policy would have to address.

LBNL collaborated with the Western Interstate Energy Board and the University of Texas-Austin to investigate the implications of a regional resource adequacy (RA) program on utility integrated resource planning (IRP). This report is focused on an active policy discussion to develop a novel voluntary program to share capacity resources and improve RA in the Western Interconnection. This report identifies two RA components of IRP that will be highly impacted by a regional RA program: resource capacity accreditation and RA targets. There are at least four resources that will require specific attention for their capacity credit calculations: (1) variable renewable resources, (2) demand-side resources, (3) hydroelectric resources, and (4) power purchase agreements. It will also be necessary to decide on a RA target reliability metric (e.g., a planning reserve margin) that is at least the minimum requirement in IRPs to ensure consistency in RA requirement calculations. The report finds that load forecasting and transmission expansion analyses will be moderately impacted, but that most of IRP components will be not significantly impacted.The report includes a review of traditional resource adequacy practices in IRP; a case study of an existing regional RA program that interacts with IRP (Southwest Power Pool) and it presents the Northwest Power Pool (NWPP) regional resource adequacy proposal that is a focus of this research. This paper addresses three research questions:•How would typical IRP processes change if a utility joined a regional RA program?•Which RA elements would remain local (i.e. within IRP) and which would become regional (i.e. within the RA program)? •How much control would utilities and states retain over their utility resource mixes considering the influence of a regional RA program? This paper is primarily written for state policymakers, public utility commission staff, and resource planners from states in the NWPP footprint that are pondering how their IRP guidelines and regulations may need to adjust to operate jointly with a regional RA program. The content of this paper may also help the NWPP RA program developer as it interacts with potential member states and utilities to understand what aspects of energy policy may be influenced by the program.This work was funded by the Energy Resilience Division of the U.S. Department of Energy’s Office of Electricity under Lawrence Berkeley National Laboratory Contract No. DE-AC02-05CH11231.

The risks of long-duration, widespread interruptions (LDWIs) in electrical power are a concern of U.S. regulators, the electric power industry, and stakeholders. Those responsible for making decisions about increasingly costly investments to prevent such interruptions and to facilitate rapid recovery when they do occur need relevant information on which to base those decisions. Although a number of studies have examined the physical and engineering impacts of extreme weather and other precipitating events on the bulk power system, decision makers evaluating investments in preventive strategies need information on the costs of past power interruptions and the benefits of preventing them in the future. This paper contributes to addressing this need by offering six case studies that detail the economics, at the level of the utility service territory, of power interruptions caused by extreme weather and lasting from a few days to several weeks. These intermediate-duration interruptions have been, and will continue to be, the most common type of major electric power disruption. They are longer than the short-term disruptions addressed in utility reliability planning, but not as long or widespread geographically as the national-scale interruptions with durations of many weeks, months, or longer that have been examined in some recent studies. Through case studies, we are able to address the following five questions that have important policy and long-term planning implications for reducing power system vulnerabilities:1. How do utilities assess the costs of system damage caused by extreme weather and the costs of recovering from this damage?2. How do utilities estimate customer costs of past power interruptions?3. How do utilities or others estimate the costs and benefits of investments to reduce power system vulnerabilities to future extreme weather events?4. How do utilities and regulators use the concept of resilience in economic assessments of extreme weather impacts and the value of preventive investments?5. How do regulatory processes influence utilities’ economic analysis related to power interruptions?Finally, the case studies reveal a number of areas in which further research could be beneficial to utilities and regulators dealing with risks associated with LDWIs.

The Indiana Utility Regulatory Commission (IURC) retained LBNL to study the techno-economic impact of distributed energy resource (DER) adoption in the Indiana power system. For this study, LBNL developed a framework that employs a variety of methods to assess three components: the physical impact on distribution, transmission, and generation capacity; the economic and rate impact on customers; and the reliability and resilience impacts on the distribution system.LBNL used utility data from ~2800 distribution system feeders to determine representative feeders that could be used for in-depth analysis. We ran over 3400 simulation-hours on these representative feeders using distribution system simulation software Cymdist, covering a diverse array of DER adoption and net demand scenarios, over the short and long term (2025 and 2040). Feeder-level net demand was scaled up to the state-level and input into a capacity expansion and production cost models to assess the transmission and generation impacts of DER adoption levels and calculate rate impacts. Finally, LBNL used half a million historical outages in Indiana to simulate the impact of DER storage on reliability and resilience.The report finds that voltage regulation, line loading, and energy losses impacts in distribution systems are seldom and largely occur in the most stringent stress-test scenario. Generation impacts account for roughly 80% of the cost impacts in most scenarios. Overall, rates are higher for all DER adoption scenarios compared to the base case given the need to cover utility fixed costs with lower sales, or the need to provide substantial peak capacity to support unmanaged EV charging.

Distributed energy resources have been almost exclusively deployed and operated under a decentralized decision-making process. In this paper, we assess the evolution of a power system with centrally planned utility-scale generation, transmission, distribution, and distributed resources. We adapt a capacity expansion model to represent both centralized and decentralized decision-making paradigms under various electricity rate structures. This paper shows that a centralized planning approach could save 7% to 37% of total system costs over a 15-year time horizon using a Western United States utility as a case study. We show that centralized decision-making deploys substantially more utility-scale solar and distributed storage compared to a decentralized decision-making paradigm. We demonstrate how a utility could largely overcome the complications of decentralized distributed resource decision-making by incentivizing regulators to develop electricity rates that more closely reflect time- and location-specific, long-run marginal costs. The results from this analysis yield insights that are useful for long-term utility planning and electric utility rate design.

There has been a limited amount of peer-reviewed literature on long-term trends in electricity reliability including the underlying factors that impact reliability across the United States. In this analysis, we considered up to 16 years of data from 203 U S. utilities—representing about 70% of electricity sales. Annual frequency of interruptions for an average customer—at the regional and U.S. national-level—has generally decreased over this timeframe. But we do not find that there is a statistically significant trend in the annual duration of interruptions for an average customer. We find that more explicit measures of severe weather are correlated with reliability. We are able to explain 7% and 16% of past variation in the reliability metrics system average interruption duration and frequency indices, respectively, is due to severe weather—a significant improvement over earlier studies. We find that current year spending by utilities is correlated with worse reliability and that cumulative spending over the preceding three years is correlated with better reliability. Finally, we demonstrate that using a statistical instrument to represent the annual frequency of interruptions for an average customer can greatly improve analysis of trends in the annual duration of interruptions for an average customer.

Energy savings performance contracting (ESPC) enables building owners to implement facility upgrades and reduce energy and water consumption (often with operations and maintenance expenses) using the resulting annual stream of cost savings to cover project installation and financing costs. The size of the international ESPC market is ~$30 billion per year and growing. However, ESPCs still face myriad barriers to achieving their market potential. Barriers include lack of data standardization and transparency, lost data, and inconsistent project performance monitoring. These barriers have limited stakeholders’ ability to understand how projects perform. The inability to document and quantify past projects’ success has led to skepticism, aversion, and unnecessarily high transaction costs. This work discusses a standardized approach to develop and document ESPCs through eProject Builder (ePB), which involves a simple Excel-based set of financial schedules combined with an on-line data archiving and tracking system. ePB enables standardized collection, calculation and reporting of project data in a way that promotes greater transparency of ESPCs to facility owners and other stakeholders. Specifically, the key benefits of ePB are that it (1) minimizes redundancies; (2) eliminates data inconsistencies resulting from multiple data repositories; (3) increases transparency by preserving and providing access to data in perpetuity; (4) enables development of “what if” scenarios; and (5) standardizes data to allow for comparative analysis of ESPC projects. Accordingly, ePB increases confidence in the ESPC vehicle among prospective customers. The paper demonstrates one key aspect of ePB’s value by using it to conduct sensitivity analyses of key factors in hypothetical ESPC projects.

Load Serving Entities (LSEs) can procure electricity from their owned generation or purchase it on bilateral or centrally organized markets. Electric utility procurement decisions have important implications for resource adequacy, which is gaining attention especially in the Western U.S. However, there is little or no research on trends of utility procurement practices, and the role that wholesale market transactions can have for resource adequacy and other applications. This paper leverages information from the U.S. Department of Energy’s Energy Information Administration, Berkeley Lab’s Resource Planning Portal, and structured interviews with regulatory and utility staff. We find that use of market transactions to meet electric energy needs has been increasing across U.S. LSEs. The reasons for this trend include a general stagnation in building owned resources, a preference towards contracting renewable energy resources to meet RPS targets, and the lower relative cost of wholesale market electricity. Among market transactions across different time scales, short-term transactions were prevalent in Western U.S. LSEs until the 2008 recession, and thereafter declined to about a quarter of total purchases. In contrast, long-term market transactions have become more prevalent and resource planning reports project the share of these transactions in the procurement mix may continue to increase. Results suggest resource adequacy obligations may drive preferences for asset ownership more than a profit incentive. We also recommend improving the planning to procurement connection by reflecting in planning assumptions the operational constraints of market transactions. These results provide insights on key issues in electric utility procurement that could improve overall market efficiency, respond to rapidly changing industry conditions, and identify practices that LSEs and regulators should consider incorporating into their long-term transmission and capacity planning processes.

BackgroundLichens, encompassing 20,000 known species, are symbioses between specialized fungi (mycobionts), mostly ascomycetes, and unicellular green algae or cyanobacteria (photobionts). Here we describe the first parallel genomic analysis of the mycobiont Cladonia grayi and of its green algal photobiont Asterochloris glomerata. We focus on genes/predicted proteins of potential symbiotic significance, sought by surveying proteins differentially activated during early stages of mycobiont and photobiont interaction in coculture, expanded or contracted protein families, and proteins with differential rates of evolution.ResultsA) In coculture, the fungus upregulated small secreted proteins, membrane transport proteins, signal transduction components, extracellular hydrolases and, notably, a ribitol transporter and an ammonium transporter, and the alga activated DNA metabolism, signal transduction, and expression of flagellar components. B) Expanded fungal protein families include heterokaryon incompatibility proteins, polyketide synthases, and a unique set of G-protein α subunit paralogs. Expanded algal protein families include carbohydrate active enzymes and a specific subclass of cytoplasmic carbonic anhydrases. The alga also appears to have acquired by horizontal gene transfer from prokaryotes novel archaeal ATPases and Desiccation-Related Proteins. Expanded in both symbionts are signal transduction components, ankyrin domain proteins and transcription factors involved in chromatin remodeling and stress responses. The fungal transportome is contracted, as are algal nitrate assimilation genes. C) In the mycobiont, slow-evolving proteins were enriched for components involved in protein translation, translocation and sorting.ConclusionsThe surveyed genes affect stress resistance, signaling, genome reprogramming, nutritional and structural interactions. The alga carries many genes likely transferred horizontally through viruses, yet we found no evidence of inter-symbiont gene transfer. The presence in the photobiont of meiosis-specific genes supports the notion that sexual reproduction occurs in Asterochloris while they are free-living, a phenomenon with implications for the adaptability of lichens and the persistent autonomy of the symbionts. The diversity of the genes affecting the symbiosis suggests that lichens evolved by accretion of many scattered regulatory and structural changes rather than through introduction of a few key innovations. This predicts that paths to lichenization were variable in different phyla, which is consistent with the emerging consensus that ascolichens could have had a few independent origins.