Electrical grids with high penetrations of inverter-based resources (IBRs), such as wind, solar, and batteries, located far from load centers can have transmission congestion during periods of high IBR production. Without additional transmission capacity, renewable generation curtailment and congestion will increase. We believe this is the first research to examine whether incorporating long-term load forecast (LTLF) uncertainties inherent in transmission expansion studies can affect the production cost savings of transmission expansion projects, a key factor in transmission expansion decision-making. We investigated the effect of LTLF errors on production cost benefits of three new transmission expansion options evaluated by the Electric Reliability Council of Texas (ERCOT) to increase export capability from West Texas to load centers to accommodate increasing IBR growth. We incorporated a distribution of LTLFs, developed using observed historical LTLF errors, on a nodal ERCOT model to compare each transmission expansion project's production cost savings and operational changes distribution. We found that when load forecast uncertainties are incorporated, production cost savings of two of the options are indistinguishable. When production cost savings differences fall within LTLF uncertainty bounds there is an opportunity to incorporate factors such as equity and ecological impacts into transmission planning that may be overlooked when basing decisions on deterministic production cost differences.

The expert and policy communities have invested enormous effort in debating what greenhouse gas (GHG) emissions target to aim for, or which decarbonization policies and technologies should be mandated or banned. Because multiple trajectories can achieve similar targets and timelines, some scenario analysis is useful. However, with many players involved, it will be impossible to remain on anyone's optimal trajectory. As one of the world's largest contributors to the climate crisis, the US should stop arguing about perfect solutions and get on with reducing emissions in ways that are feasible and affordable.

Electrification with heat pumps is often cited as a preferred pathway to decarbonize US space heating in the transition to a net-zero energy system. However, fully electrifying building heat may significantly increase peak electric system loads during cold weather, thus challenging extensive adoption. A hybrid home heating system uses both heat pumps and conventional natural gas furnaces, where the gas appliance operates during peak heating periods. Here, we assess the marginal abatement costs of fully electrifying peak heating demands as opposed to allowing hybrid heating in current gas connected and ducted homes. We use a least-cost energy system optimization model that considers household, electric, and gas system costs, including electric distribution system expansion and gas system cost recovery. To ensure the cost of sufficient low-carbon dispatchable electric capacity is captured, the model includes historical days with peak heating demands and low wind and solar availability. We find hybrid heat pumps can achieve substantial decarbonization, with US natural gas residential heating consumption decreasing 70% to 95% from 2020 levels at marginal abatement costs below $200 per tonne CO2e. The cost of fully electrifying heating in cold regions is very high, with the marginal abatement cost of eliminating the last 1% of natural gas consumption exceeding $1000 per tonne CO2e even in scenarios designed to be favorable to electrification. The robust value of hybrid heat pumps in northern cold climates indicates the importance of flexible building heat decarbonization policies such as clean heat standards.

Electric grids with high penetrations of utility-scale inverter-based resources (IBRs), such as wind, solar, and batteries, often have lower system inertia and need frequency support. One response is to keep traditional synchronous generators online to maintain adequate system inertia, which may reduce the number of IBRs on the system, increasing system emissions. However, IBRs can provide fast frequency response (FFR). If they can do so at low cost, the amount of conventional system inertia needed on the grid can be reduced, allowing higher penetration of IBRs. We examined an FFR requirement on utility-scale IBRs from a system price perspective. We used a unit commitment and economic dispatch (UCED) model to assess the competitiveness of wind and solar resources against batteries and thermal generators in the Electric Reliability Council of Texas (ERCOT) ancillary service market. We introduced an FFR requirement in the UCED model, focusing on energy and ancillary service price changes under actual 2020 and forecasted 2025 system conditions. Under 2020 conditions, which had low IBR penetration, adding an FFR requirement increases energy prices by 7% and introduces a high FFR cost, close to the price of energy. In 2025, which is expected to have high IBR penetration, an FFR requirement does not change energy or reserve prices, and the FFR price is approximately $0.3/MWh. FFR effectively replaces the need for inertia, which has no associated cost in today's markets. The low cost of FFR under high IBR conditions is an appropriate alternative to inertia, arguing for policies that incentivize IBRs to provide FFR.

Gas-electric interdependencies have contributed to several major electric system emergencies. Natural gas pipelines use both gas-powered and electric-powered compressor units; power outages at the latter can cause gas shortages. We make the first rigorous identification of the number of US electric compressor stations, finding that 10% are electric. California, the Midwest, the Gulf Coast, and the East have high installed electric compressor capacity. New hydraulic models, verified by past events, show that disrupting power to a single compressor station can force a loss greater than 2 GW of downstream gas generators. Such an outage can be larger than the most severe single-cause failure currently considered in electric reliability planning. Electric utilities should immediately incorporate the identified facilities into critical facility lists. Establishing a federal gas reliability organization, comparable to what is now done for electric power, could improve gas reliability by establishing appropriate reliability reporting, incident investigation, and minimum industry standards.

Quantifying factors giving rise to temporal variation in forest fires is important for advancing scientific understanding and improving fire prevention.We demonstrate that eighty percent of the large year-to-year variation in forest area burned in California can be accounted for by variation in temperature, precipitation, housing construction, electricity transmission, and ocean surface temperatures in the North Atlantic, North Pacific, and Equatorial Pacific.California is of particular interest because of its large acreage burned and proximity of fires to human populations.We believe our model is the first unified treatment of climatic factors and human activities that affect forest area burned.

Areas with sparse transmission lines are common in regions with high solar energy potential and need voltage support. This may require installing expensive voltage compensators, such as static synchronous compensators (STATCOMs). This expense can increase the cost and decrease the acceptance of large-scale adoption of solar power. Unlike current photovoltaic (PV) inverter controllers, which provide voltage support only during the day, commercially available augmented voltage controllers can provide voltage support at night. We examine whether PV inverters improve nighttime voltage on the grid and how much such an operation would cost compared to a STATCOM. We ran grid contingency analyses on a model for West Texas within the Electric Reliability Council of Texas (ERCOT) jurisdiction under spring and summer conditions to determine if PV inverters can support nighttime voltage under varying reactive power demand. The cost of reactive power has not been defined previously, especially in the context of the United States. Our methods and application provide a way to determine the cost of reactive power for both PV project developers and system planners. Allowing PV inverters to provide reactive power can reduce system costs by millions of dollars, or 4–15 times less costly than installing a STATCOM. We determined inverter voltage support costs by calculating the cost of earlier inverter replacements due to increased reactive power output and voltage controllers. The net system savings argue for ERCOT changing their voltage support policies to incentivize PV plants to provide voltage support at night.

We conduct a consequential lifecycle analysis (LCA) of greenhouse gas (GHG) emissions from North American liquefied natural gas (LNG) export projects, estimating the change in global natural gas and coal use resulting from the market effects of increased LNG trade. We estimate that building a 2.1 billion cubic feet per day (Bcfd) LNG export facility, equivalent to one of the larger LNG projects under development in the US today, will change global GHG emissions -39 to 11 Mt CO2e (90% range) with a median value of -8 Mt CO2e. Previous attributional LCA methods for electricity generation with LNG replacing coal find a much larger benefit of LNG exports, a median value of -36 Mt CO2e for this size project. The smaller decrease in GHGs is attributable to higher domestic coal use and a smaller decrease in international coal use than assumed by previous methods. Net global emission change estimates are most sensitive to the uncertainty in economic elasticities outside of North America. Given the scale of planned and proposed LNG export terminals, project regulators and policymakers must account for market effects to more accurately estimate the global net change in GHG emissions.

Chapter Summary: Large electric power outages of long duration are more common than one might expect. This chapter discusses the causes of such outages – including outages resulting from extreme events made worse by climate change, such as heat, cold, and tropical cyclones. It describes the pioneering work we did with a huge database of all the generator failures in the largest portion of the U.S. grid, showing that, contrary to the assumption that grid operators make, that failures will be random, when they calculate how many reserve generators must be online, many generators have failed all at once during hot or cold weather. That lesson became obvious in the 2021 Texas blackout. The chapter then describes our work on assessing the likely cost of large outages of long duration and strategies that could be adopted to enhance resilience in the face of such outages.

A fundamental policy question for distributed energy resources (DER) is whether they create system benefits shared by all utility customers in addition to being profitable for the installing customer. This question has received considerable attention in “value of DER” and net metering reform proceedings for behind-the-meter solar photovoltaics in recent years. Commercial customer-sited lithium-ion batteries with a primary use case of demand charge management are forecast to greatly increase in the coming decade due to falling storage costs, making comparison of their customer and system benefits a timely topic in DER valuation. We conduct an overview of the system benefits of standalone commercial customer-sited storage on United States’ electric tariffs and find system benefits will not be realized for many standalone commercial customer-sited storage installations in the absence of incentives for storage dispatch during the top 50–100 annual hours that drive grid infrastructure investment. Regulatory implementation of default peak pricing during a small subset of annual hours for customer-sited storage can realize additional system benefits and offer Pareto improvement. Additional transparency in regulatory estimates of these system benefits helps catalyze longer-term visions for increased competition at the retail level using DERs.

•Gas shortages at New England generators have accounted for up to ¼ of all failures.•A $3−7/MWh premium could mitigate ∼2 GW of gas shortages using oil dual fuel.•A $7−16/MWh premium could mitigate ∼2 GW of gas shortages using CNG storage.•Battery costs must decrease by 75 % to be competitive with fuel storage for mitigating gas shortages.

Using 2012–2018 power plant failure data from the North American Electric Reliability Corporation, we examine how many fuel shortage failures at gas power plants were caused by physical interruptions of gas flow as opposed to operational procedures on the pipeline network, such as gas curtailment priority. We find that physical disruptions of the pipeline network account for no more than 5% of the MWh lost to fuel shortages over the six years we examined. Gas shortages at generators have caused correlated failures of power plants with both firm and non-firm fuel arrangements. Unsurprisingly, plants using the spot market or interruptible pipeline contracts for their fuel were somewhat more likely to experience fuel shortages than those with firm contracts. We identify regions of the Midwest and Mid-Atlantic where power plants with non-firm fuel arrangements may have avoided fuel shortage outages if they had obtained firm pipeline contracts. The volume of gas needed by power plants to fuel the lost MWh in those regions was only a small fraction of the total volume delivered to potentially non-essential commercial and industrial pipeline customers in those regions and modest prices there at the times when power plants failed indicate gas was available.

We present a solar-centric approach to estimating the probability of extreme coronal mass ejections (CME) using the Solar and Heliospheric Observatory (SOHO)/Large Angle and Spectrometric Coronagraph Experiment (LASCO) CME Catalog observations updated through May 2018 and an updated list of near-Earth interplanetary coronal mass ejections (ICME). We examine robust statistical approaches to the estimation of extreme events. We then assume a variety of time-independent distributions fitting, and then comparing, the different probability distributions to the relevant regions of the cumulative distributions of the observed CME speeds. Using these results, we then obtain the probability that the velocity of a CME exceeds a particular threshold by extrapolation. We conclude that about 1.72% of the CMEs recorded with SOHO LASCO arrive at the Earth over the time both data sets overlap (November 1996 to September 2017). Then, assuming that 1.72% of all CMEs pass the Earth, we can obtain a first-order estimate of the probability of an extreme space weather event on Earth. To estimate the probability over the next decade of a CME, we fit a Poisson distribution to the complementary cumulative distribution function. We inferred a decadal probability of between 0.01 and 0.09 for an event of at least the size of the large 2012 event, and a probability between 0.0002 and 0.016 for the size of the 1859 Carrington event.

Competitive electricity markets can procure reserve generation through a market in which the demand for reserves is administratively established. A downward sloping or stepped administrative demand curve is commonly termed an operating reserve demand curve (ORDC). We propose a dynamic formulation of an ORDC with generator forced outage probabilities conditional on ambient temperature to implement scarcity pricing in a wholesale electricity market. This formulation improves on common existing methods used by wholesale market operators to articulate ORDCs by explicitly accounting for a large source of observed variability in generator forced outages, whereby for a fixed load, more reserves are required during times of extreme heat and cold to maintain a constant risk of reserve shortage. Such a dynamic ORDC increases social welfare by $17.1 million compared to current practice in the PJM Interconnection during a high load week in a welfare-maximizing electricity market with co-optimized procurement of energy and reserves. A dynamic ORDC increases reserve prices under scarcity conditions, but has minimal effects on total market payments. The results are directly relevant to the modeled two-settlement electricity market in PJM, which is currently undergoing enhancements to its ORDC.

Current grid resource adequacy modeling assumes generator failures are both independent and invariant to ambient conditions. We evaluate the resource adequacy policy implications of correlated generator failures in the PJM Interconnection by making use of observed temperature-dependent forced outage rates. Correlated failures pose substantial resource adequacy risk, increasing PJM's required reserve margin from 15.9% to 22.9% in the 2018/2019 delivery year. However, PJM actually procured a 26.6% reserve margin in this delivery year, translating to excess capacity payments of $315 million and an implied value of lost load of approximately $700,000/MWh, a figure two orders of magnitude greater than typically used in operational contexts. Capacity requirements vary by month, with more than 95% of loss-of-load risk accruing in July. Setting monthly capacity targets could reduce annual PJM procurement by approximately 16%. We examine the resource adequacy implications of the ongoing replacement of nuclear and coal in PJM with combined-cycle gas generators, finding moderate benefits: approximately a 2% reduction in capacity requirements. We identify modest resource adequacy risks from potential future climate scenarios, modeled as temperature increases of 1 and 2 degrees C relative to our study period. Holding loads fixed, these scenarios increase capacity requirements by approximately 0.5% and 1.5%, respectively.

The variability of wind and solar power is much less at high frequencies than at low frequencies, so that slow-ramping generators such as combined-cycle natural gas and coal can compensate for most of the variability. Geographic aggregation of wind and solar power has been proposed as a method to smooth their variability; for both wind and solar photovoltaic power it has been shown that there is little smoothing at times scales where the magnitude of variability is strongest. It has also been shown that the point of diminishing returns is reached after a relatively few wind plants have been interconnected.

India will add 100 GW of solar electric power generation by 2022. This report examines the performance of four annual solar photovoltaic production models against actual generation data from utility-scale plants in Gujarat, India.

Most current approaches to resource adequacy modeling assume that each generator in a power system fails and recovers independently of other generators with invariant transition probabilities. This assumption has been shown to be wrong. Here we present a new statistical model that allows generator failure models to incorporate correlated failures and recoveries. In the model, transition probabilities are a function of exogenous variables; as an example we use temperature and system load. Model parameters are estimated using 23 years of data for 1845 generators in the USA's largest electricity market. We show that temperature dependencies are statistically significant in all generator types, but are most pronounced for diesel and natural gas generators at low temperatures and nuclear generators at high temperatures. Our approach yields significant improvements in predictive performance compared to current practice, suggesting that explicit models of generator transitions using jointly experienced stressors can help grid planners more precisely manage their systems.