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March 10, 2023 Feature

The Critical Role of Transmission and Storage Capacity in Balancing Intermittent Generation and Transient Load

David K.A. Mordecai, PhD

Although investment in modeling, installation, and maintenance of scalable storage and transmission infrastructure is critical to grid modernization, other aspects are outpacing the measures and resources needed for reliable, resilient, stable, and secure grid balancing operations. The trade-offs that constrain scalability of grid networks compound economics with technical engineering and physical complexities of thermodynamics, electricity, and electromagnetism. For example, among other weather conditions, the volatility of temperature and humidity impact operating conditions for both generation and transmission capacity as well as electricity load (i.e., demand) variability.

In early 2022, the Wall Street Journal (WSJ) reported on the increasing number of power outages being experienced nationally, due in part to new stresses on the system caused by aging power transmission lines, changing climate, and increased adoption of renewables generation. See Katherine Blunt, America’s Power Grid Is Increasingly Unreliable, Wall St. J. (Feb. 18, 2022). Sustained outages are occurring with increasing frequency in the United States, having grown from fewer than two dozen major disruptions during 2000 to over 180 during 2020. According to the article, utility customers experienced just over eight hours of power interruptions in 2020 on average, more than double the amount in 2013. See id.

Since electric power is generally not storable, the electricity grid is widely considered to be the most complex mechanism ever engineered for which supply must match demand across the entire grid. It is reasonably apparent, though, that in the absence of adequate investment and broad adoption of reliable industrial grid–scale storage capacity coupled with transmission infrastructure, increasing electrification of transportation fleets and the proliferation of microgrids will further contribute to stresses on grid transmission capacity. The result is expanding exposure and increasing susceptibility to climate-related weather volatility and technological transition risks. This article will discuss the law, economics, and finance, as well as risk and regulatory implications of regional weather-dependent variability from transient electricity loads compounded by increasing intermittency of regional weather-dependent power production by renewables. The critical role of transmission and storage for scalable adoption of renewable power will be articulated in the context of policies, regulations, and strategies for balancing climate adaptation with the necessity of electricity resilience and reliability.

Transition Risks and Threats to Grid Reliability, Stability, and Security

As previously described, the data indicate that severe weather is an apparent primary contributor to power outages across the United States. Between 2003 and 2012, an estimated 679 widespread power outages occurred due to severe weather events, with weather-related power outages imposing annual costs between $25 to $70 billion. See Exec. Off. of the President, Economic Benefits of Increasing Electric Grid Resilience to Weather Outages (Aug. 2013). In September 2021, Hurricane Ida caused a massive blackout, leaving New Orleans in the dark for over two days, and a month prior, Tropical Storm Henri interrupted power to 100,000 households in Rhode Island. In early 2021, harsh winter conditions disrupted the Texas electricity grid, resulting in one million people without heat and electricity for days, and in September 2022, Hurricane Ian interrupted power to more than 2.5 million customers in Florida. And apart from storms, wildfires in the western United States have become perennial occurrences, and are now common sources of California outages.

Complex litigation increasingly accompanies grid outages (due to weather events and wildfires). For example, at the beginning of 2022, 131 insurance companies filed a lawsuit in Travis County, Texas, District Court against Eastern, Western, and Texas (ERCOT) and approximately 36 electricity generators for the power outage during Winter Storm Uri. See Robert Bryce, Texas Grid Operator Sued by 131 Insurers, Now Facing “Dozens” of Lawsuits over Blackout, Forbes (Jan. 2022). The civil and criminal liability exposure of Pacific Gas & Electric due to recent fires attributable to its operations has been extensively documented in the media.

Improvement appears incremental. In 2011, the Obama administration announced a four-pillared strategy for electricity grid modernization, directing billions of dollars toward investments intended to increase grid efficiency, reliability, and resilience; mitigate weather-related outage vulnerability; and reduce time to restoration after an outage occurrence. See Off. of the President, A Policy Framework for the 21st Century Grid: Enabling Our Secure Energy Future (June 2011). Yet as observed at the outset, aging U.S. electrical grid infrastructure and operations are being subjected to persistent and compounded stressors from increased weather volatility coupled with pervasive penetration of variable generation. As a result, unscheduled outages are occurring more frequently. Hotter, wetter summers and harsher winters require more reliance on heating and cooling utilities, placing higher stress on the electricity grid.

Grid stability corresponds to an equilibrium between supply and demand, i.e., balancing production and consumption across the network. Electricity generated must equal electricity consumed, and weather variability coupled with other disturbances disrupt this equilibrium. Centralized conventional grid configurations also struggle with intermittent energy production, since for a power grid to remain stable, it must adaptively adjust to volatility in voltage and frequency disturbances within an acceptable time frame in order to balance frequency disturbances and mitigate the risk of power outages (and the threat of cascade failures). Voltage, frequency, and current are intrinsically linked via physical laws (e.g., Kirchhoff’s current and voltage laws), and related thermodynamic principles underlie regional weather variability, as well as generation, transmission, and consumption of electricity across the grid.

Atmospheric conditions contribute to variability in intermittent generation. The output of solar generation, for instance, varies as insolation varies. (Also referred to as solar irradiance (SI), insolation represents the power per unit area received from the sun in the form of electromagnetic radiation measured in the wavelength range of the measuring instrument as watts per square meter.) Excess precipitation produces spikes in hydroelectric power and risks damage from overheating to generation and transmission infrastructure. Severe wind gusts similarly risk overspeed (i.e., overheating) damage to wind turbine generators. Temperature and humidity variations likewise influence power production and consumption, particularly with the efficiency of industrial, commercial, and residential equipment. Such power surplus and deficits correspond to deadweight loss with implications for the economic viability of the grid driving the need for supplementing storage and transmission capacity, as well as enhanced network analysis.

The base frequency threshold for the North American electricity grid is 60 cycles per second (i.e., 60 hertz) + 0.05 hertz, outside of which the grid begins to decouple in order to avoid catastrophic damage. Absent adequate reserve storage and transmission capacity, the variability of intermittent (or stochastic) generation triggers instabilities (i.e., imbalances with different time signatures), as frequency and voltage anomalies across the grid surpass the capabilities of grid-tie power inverters (which facilitate the accurate matching of voltage, frequency, and phase of the grid sine wave AC waveform) and other balancing components (e.g., synchronverters, phasor measurement units, current transformers) intended to monitor and adjust the system to frequency and voltage fluctuations. See, e.g., Ye Wang et al., Impact of High Penetration of Variable Renewable Generation on Frequency Dynamics in the Continental Europe Interconnected System, 10 IET Renewable Power Generation 10 (2016). These large frequency deviations can lead to complete system collapse. Increased loads during peak hour demand tend to strain existing transmission line capacity in matching the inflow and outflow of power across the grid. When surges occur with excess electricity production, and the specified capacity of transmission lines are surpassed, thermal loads can accumulate, resulting in damage.

Dating back to 1882, the grid has expanded from the first power plant at the Pearl Street Station in lower Manhattan and the original 59 customers served to hundreds of millions of users. The basic structure of the U.S. electricity grid, however, has remained the same. According to the U.S. Energy Information Administration (EIA), fossil fuel–based thermal power plants—coal, oil, or natural gas—generate approximately 60% of the nation’s power, with nuclear power accounting for nearly 20%. See James McBride & Anshu Siripurapu, How Does the US Power Grid Work?, Council on Foreign Rel. (2022). Electricity is transported across long distances via high-voltage transmission lines to substations, where local facilities convert high-voltage power to a lower voltage (a process referred to as stepping down) to be distributed to nearby businesses and residences. Intermittent generation coupled with transient load dynamics results in transmission line congestion and supply-demand imbalances, as well as service degradation related to voltage, frequency, and current distortions.

Transition Risks and Grid Modernization Challenges

The aforementioned transition risks and challenges associated with electricity grid modernization require novel system-wide, grid-scale modeling, financing, and control paradigms. In other words, investment. The $1 trillion Infrastructure Investment and Jobs Act took steps in this direction, with more than $27 billion directed toward grid resilience and reliability. See Rachel Smith, The Grid Wins Big in the IIJA, Bipartisan Pol’y Ctr. (Sept. 23, 2021). In contrast, internet broadband infrastructure (which reason dictates cannot operate without grid reliability and resilience) received $65 billion. The administration has begun coordinating with state counterparts to facilitate upgrades, but with the continuing adoption of renewables and the proliferation of distributed generation, grid modernization will require additional support to accomplish the adaptations needed to address corresponding technical and economic challenges.

Another technical challenge concerns the planning required to integrate such resources in a reliable and cost-effective manner. The Federal Energy Regulatory Commission (FERC) regulates, among other things, the rates, terms, and conditions of electric transmission services, its charge being to ensure that such rates are just and reasonable and not unduly preferential. See 16 U.S.C. §§ 824d, 824e. Over time, FERC has used this authority to impose various requirements over the regional transmission planning and cost allocation activities undertaken by entities providing such services. See, e.g., Transmission Planning & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 76 Fed. Reg. 49,842 (Aug. 11, 2011), 136 FERC ¶ 61,051 (2011). More recently, the agency has embarked upon an extensive effort to update and expand upon those requirements.

First, in 2021, FERC established a joint federal-state task force to explore issues relating to electric transmission, including the identification of barriers that “inhibit” planning and development of optimal transmission necessary to achieve federal and state policy goals, as well as barriers to the efficient and expeditious interconnection of new resources through the FERC-jurisdictional interconnection processes, along with solutions. See Joint Federal-State Task Force on Electric Transmission, 175 FERC ¶ 61,224 (June 17, 2021).

Then in April 2022, FERC issued a notice of proposed rulemaking by which the agency proposed reforms to its electric regional transmission planning and cost allocation requirements. See Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 179 FERC ¶ 61,028 (Apr. 21, 2022) (Regional Planning NOPR). A repeated emphasis of the NOPR is that the proposals will better ensure that the national grid is able to meet “transmission needs driven by changes in the resource mix and demand,” and that, as a result, rates for transmission services will be just and reasonable and not unduly discriminatory. The pursuit of such ends, however, yielded more than 400 pages of proposals (and corresponding justifications), which themselves were predicated on advanced rulemaking from 2021 as well as feedback from the first two Task Force meetings. A final rule from the agency is not expected until later in 2023 (at the earliest).

Shortly after its issuance of the Regional Planning NOPR, FERC proposed additional, related reforms regarding the processes for generator interconnection. See Improvements to Generator Interconnection Procedures and Agreements, 179 FERC ¶ 61,194 (June 16, 2022) (Interconnection NOPR). FERC explained that the growth of new resources seeking to interconnect with the electric transmission system and the varying characteristics of those resources are creating large interconnection queue backlogs, potentially increasing costs for consumers as well as reliability issues. FERC also attributed the backlog to a lack of long-term regional planning, resulting in transmission expansion in an incremental and relatively localized fashion. Although not as extensive as the Regional Planning NOPR, the Interconnection NOPR included a number of proposals, including the imposition of penalties on transmission providers that fail to meet various interconnection study deadlines, as well as a requirement that transmission providers consider alternative technologies as part of their study processes, such as advanced power flow control, transmission switching, dynamic line ratings, and static VAR compensators.

Since its establishment, the Task Force has convened five times, with a sixth meeting scheduled for February 15, 2023. Of note, the first three meetings largely covered topics captured within the two NOPRs previously discussed. The fourth meeting focused on interregional planning and cost allocation—an area that many advocates for reform believe FERC needs to, and likely will, turn its rulemaking authority towards in the near future. The fifth meeting focused on addressing regulatory gaps and challenges in the oversight of transmission development. As of this writing, the agenda for the sixth meeting has not yet been announced.

The Economic Value, Modernization, Maintenance, and Replacement Cost of the Grid

The grid has been described as the largest and most complex machine in the world. In actuality, there are three separate U.S. grids, self-contained interconnections of power production and transmission: the previously mentioned Eastern, Western, and Texas interconnections. Together these systems comprise 11 thousand power plants, three thousand utilities, and more than two million miles of power lines. The current (depreciated) value of the U.S. electric grid is estimated at approximately $1.5 to $2 trillion, with a replacement cost approaching $5 trillion. See Joshua D. Rhodes, The Old, Dirty, Creaky US Electric Grid Would Cost $5 Trillion to Replace, The Conversation (Mar. 16, 2017). The implications of physical and engineering constraints on economic trade-offs for financing the modernization, maintenance, operational stability, reliability, resilience, and security of the grid at scale are profound, particularly in the context of risk management and economic viability trade-offs. And as previously indicated, power system stability requires constant balance between production and consumption. At the same time, electricity demand is affected by both weather (e.g., temperature, wind speed, precipitation) as well as the intensity of economic activity (on-peak versus off-peak hours, weekdays versus weekends, holidays), yielding price dynamics uncharacteristic of other markets and that exhibit daily, weekly, and annual seasonality with acute price spikes. Such extreme price volatility is up to two orders of magnitude higher than any other commodity or financial asset and is further compounded by intermittent supply from variable renewable generation subject to regional atmospheric conditions.

Transition Risks and Grid Viability

Increased adoption of renewable energy generation also poses operational and economic challenges for grid operations. On the operational side, the variability of the wind and solar insolation increases forecasting error for the supply and demand of electricity, which itself is further compounded by household adoption of independent electricity generation. Decentralized energy production, i.e., distributed generation, such as home solar production, has grown exponentially over the past decade, achieving 126.1 gigawatts of total capacity in 2022—enough energy to power more than 23 million homes. The adoption of distributed generation, coupled with smart metering, renders grid dynamics more complex. Residential smart meters are being widely adopted in urban homes for adaptive monitoring and billing of retail consumption based on device-level usage. Energy disaggregation research aims to decompose the aggregated energy consumption data into its component appliances. See Mengheng Xue et al., Energy Disaggregation with Semi-supervised Sparse Coding, RiskEcon® Lab for Decision Metrics, NYU (July 2020).

Utilities have also expressed concerns that distributed generation threatens their viability, particularly the policy of net metering, first adopted by Minnesota in 1983. Net metering requires utilities to purchase excess power from solar adopters at the full retail rate of electricity. Utilities assert that by receiving the full retail price of electricity, such users effectively avoid paying for grid maintenance on which the majority of homes and businesses using distributed generation still rely, and which solar adopters still use during periods of intermittency (i.e., during degraded or interrupted solar or wind production). By extension, a similar negative externality is related to net metering and the proliferation of commercial/industrial microgrids, a tragedy of the commons with regard to subsidizing the social cost of modernization and maintenance of the shared grid infrastructure. It stands to reason that in the transition to a distributed grid, reliability and stability will rely on adequate cross-subsidization of the shared grid infrastructure by its constituents.

With the proliferation of solar adoption and customer attrition, increased pricing in order to remain viable will drive more consumers off grid, a process referred to by the industry as the utility death spiral. According to an analysis by the Rocky Mountain Institute, an energy research organization, it is estimated that utilities in the northeastern United States could lose up to $15 billion by 2030 with the transition of consumers to distributed generation. See The Economics of Load Defection, Rocky Mountain Inst. (Apr. 2015). To compensate for lost revenue, some utilities have imposed new fees or restrictions on solar users, while other utilities have sought to enter the distributed generation space directly.

In designing load adaptive and congestion pricing, as well as coordinated and collaborative investment and financing models to address peak power trade-offs, levelized cost analysis requires both primary (generation) and secondary (storage) costs to be incorporated to meet demand, inclusive of environmental costs and offsets. Levelized cost enables relative apples-to-apples comparison of the corresponding roles of transmission/distribution and diversified storage technology, as well as the increasingly important role (and corresponding value) of load, frequency, and voltage balancing, in conjunction with programmatic diversified technical investment in system-wide viability of solar, wind, and tidal generation capacity at scale. Among the scale limitations to be addressed are supply chain constraints, such as the availability of rare earth metals for generation and storage technology. See, e.g., Oliver Schmidt et al., Projecting the Future Levelized Cost of Electricity Storage Technologies, Joule (Jan. 2019).

A final complicating factor is the inherent dynamic instability and susceptibility of microgrid configurations to cascade failure from anomalous ramp-up/ramp-down scheduling caused by data contamination, or by data poisoning cyberattacks, as well as the threat of botnet attacks by coopted online appliances. Both the Department of Homeland Security (DHS) and the National Institute of Standards and Technology (NIST) document cyberphysical reliability and security risk incidents as a single point of failure for grid stability. See, e.g., Michael Bartock et al., Foundational PNT Profile: Applying the Cybersecurity Framework for the Responsible Use of Positioning, Navigation, and Timing (PNT) Services, NIST (June 29, 2022). In addition, given the growing role of satellites for monitoring weather conditions—as well as the prospective widescale adoption of satellite and drone surveillance of transmission lines and distribution network infrastructure—the vulnerability of the nation’s aging grid becomes particularly acute. See, e.g., DHS, Balance of Power—Building a Resilient Electric Grid (Dec. 2021). In 2015, Lloyd’s estimated insured losses from a cyberattack on the U.S. power grid up to $71 billion. The total impact to the U.S. economy was more than $1 trillion under its worst-case scenario. See Business Blackout, Lloyd’s (July 2015).

Reliably Bridging Critical Gaps Within Storage and Transmission Across the Grid

Most recently, an analysis conducted by National Grid highlighted the inherently coupled engineering and economic grid scalability constraints associated with charging station capacity necessitated by widescale electrification of trucking fleets. See, e.g., Electric Truck Stops Will Need as Much Power as a Small Town, Bloomberg L. (Nov. 15, 2022). According to the study, which analyzed fueling activity at each of 71 highway fuel stops of varied capacity along interstate corridors in New York and Massachusetts, electrification of a typical highway gas station will require five megawatts by the year 2030, as much power as a professional sports stadium, and by 2035, a large truck stop supporting electric rigs is forecast to require as much power as the peak power demand for an entire small town with a population of 10,000 residents.

In addition, recent analysis examined charging control and infrastructure build-out as critical factors shaping charging loads in order to evaluate grid reliability under rapid electric vehicle adoption with a detailed economic dispatch model of 2035 generation. See Siobhan Powell, Charging Infrastructure Access and Operation to Reduce the Grid Impacts of Deep Electric Vehicle Adoption, Nature Energy (Sept. 2022). The analysis determined that peak net electricity demand would increase by up to 25% with forecasted adoption, by 50% in a stress test with full electrification, and that locally optimized controls and residential EV charging can strain the electricity grid.

For reasons highlighted throughout this article, the critical roles for transmission and storage capacity in balancing intermittent generation and transient load are evident. Given transient load compounded by intermittent generation, in addition to price and quantity hedging strategies already employed, reliable and secure distributed grid operation at scale based on widescale adoption of renewables monitoring and control will require (1) significant financial support from the federal government, (2) strategic and directed regulatory policies from the agencies charged with oversight of these services, and (3) risk management and financing models that incorporate adequate distributed storage reserving and transmission capacity, based on (4) comparative levelized cost analysis that models capacitated transmission networks, environmental impact, and supply chain constraints.

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David K.A. Mordecai, PhD

Dr. Mordecai is president of Risk Economics, Inc.; co-managing member of Numerati Partners LLC; adjunct professor of Econometrics and Statistics at the University of Chicago Booth School of Business; and visiting scholar at Courant Institute of Mathematical Sciences, NYU. The author acknowledges editorial contributions by Scott B. Grover, Samantha Kappagoda, and Michael S. Kwak.