Direct Air Carbon Capture Technology Set to Grow with Billions of Dollars in Funding

Published: June 30, 2022

By: Concentric Staff Writer

Direct air carbon dioxide capture technology is still in the stage of being somewhat unknown, but billions of dollars are being pumped into its research in the hopes of addressing climate change while keeping the electric grid reliable.

Last month the U.S. Department of Energy (DOE) issued a notice of intent to invest $3.5 billion into direct air carbon capture technology, which refers to removing carbon dioxide from the air, transporting it and storing it underground, or using it for other purposes such as making concrete. The DOE will fund four large-scale, regional direct air capture hubs that will comprise a network of carbon dioxide removal (CDR) projects.

The program will help decarbonize the economy and innovate widespread deployment of direct air capture technologies as well as CO2 transport and storage infrastructure, officials said. The hubs will have the capacity to capture and permanently store one million metric tons of CO2 from the atmosphere annually, either from a single unit or from multiple interconnected units. The appropriation comes through the Infrastructure & Investment Jobs Act signed by President Biden which also includes $2.5 billion for carbon sequestration, $115 million in direct air capture prizes, and $310 million for carbon utilization.

“For the purposes of implementation, only projects that result in carbon dioxide removal (i.e., atmospheric capture tied to permanent sequestration out of the atmosphere) will be considered,” the DOE said in its Notice of Intent to issue the funding. “These include CO2 captured from the atmosphere that is stored via durable conversion pathways or in dedicated geologic storage. Life cycle analysis of the entire project will be used as the basis for evaluating the CO2-equivalent removal potential from the atmosphere, including all mass and energy inputs and outputs required to construct, operate, monitor, and close the facility; emissions from land use change; and long-term retention of the CO2.”

Unlike direct air carbon capture, traditional carbon capture and sequestration technology removes CO2 at the point of emission, before it is released into the air. Direct air capture will need to be deployed on the gigaton scale to achieve a net-zero emissions goal by 2050, according to the DOE. The DOE says one gigaton of subsurface sequestered CO2 is equivalent to the annual emissions from the U.S. light-duty vehicle fleet, or about 250 million vehicles driven in one year. The DOE said in its effort the agency will “also emphasize environmental justice, community engagement, consent-based siting, equity and workforce development, and domestic supply chains and manufacturing.”

The funding follows a November 2021 announcement from DOE of a “Carbon Negative Shot,” program which aims to remove gigatons of CO2 from the Earth’s atmosphere and durably store it for less than $100 per ton of net CO2 equivalent. The Carbon Negative Shot program includes other performance elements such as robust lifecycle emissions accounting that ensures emissions created when running and building the removal technology are accounted for. Additionally, technologies that advance through the program must introduce high-quality and durable storage and demonstrate the costs associated with monitoring, reporting, and verification for at least 100 years. The technology must also enable necessary gigaton-scale removal, the DOE said. The Carbon Negative Shot will include research, manufacturing, and demonstration and “will also create tailored place-based approaches that meet the needs of individual communities that could participate in or be affected by CDR,” the DOE said. The effort will include “environmental and climate justice organizations, tribal nations, labor groups, industry and academia.”

In California, direct air capture is considered necessary to meet the state’s goal of carbon neutrality. In its 2022 scoping plan, the California Air Resources Board said the technology will need to be deployed at a large scale to achieve that goal, and Governor Gavin Newsom proposed $100 million for direct air carbon capture technology in his new budget.

California is attractive for direct air capture companies due to geology that is good for storing carbon and plentiful geothermal energy to power those operations, according to a staff presentation at a March 24 California Energy Commission business meeting.

Direct air carbon capture pilot projects in California include one by Climeworks, a company that manufactures modular carbon removal machines that can be combined through stacking. For every 100 tons of carbon removed, only 10 tons are re-emitted through the process, the company says. Climeworks, which has a pilot project underway in Palm Springs, announced in April that it raised $650 million from some of the world’s largest institutional technology and infrastructure investment companies. The company, launched in 2009, said the funding will unlock its next phase of growth which will scale direct air carbon capture “up to multi-million-ton capacity and [implement] large-scale facilities as carbon removal becomes a trillion-dollar market.”

Another company, Avnos has a direct air carbon capture pilot project in Bakersfield in conjunction with the Pacific Northwest National Laboratory. Avnos says it is commercializing the most advanced technology available to capture CO2 and produce water that is used to further drive CO2 capture, which eliminates heat consumption and reduces costs compared to other forms of direct air capture.

Another company in the direct air capture space is Heirloom, a venture backed by Bill Gates and others, which recently announced it has raised $53 million in funding. With the slogan “Our Planet Knows Best,” on its website, the company replicates natural processes by using minerals to reduce carbon and turn it to stone, a process that can be completed in days.

The company says it uses “widely available, low-cost minerals” to produce oxide that naturally binds to CO2 at ambient conditions. Then it passively exposes the minerals to the air rather than relying on energy-intensive and high-cost air contactors. The carbon is captured and processed, then injected into underground geological structures where it is permanently stored.

The system is designed to minimize second-order impacts and reduce extraction, including a looping process that recycles minerals to limit reliance on mining, use fewer resources, and decouple the carbon capture systems from fossil fuels. The systems have a small physical footprint, which leaves more space to rehabilitate and preserve fragile ecosystems to reduce competition with agriculture and urbanization, according to Heirloom.

It is clear that state and local governments view direct air carbon capture as viable with the suite of technologies being deployed at a rapid pace to meet decarbonization goals. It’s safe to say the technology is poised for growth, and a potent amount of funding, research, and development is being poured into its future.

All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

U.S. Electric Grid Moving Toward Distributed Energy Resources to Address New Realities

Published: February 16, 2022

By: Concentric Staff Writer

The electricity grid in the United States—and across the globe—has undergone significant changes to the way energy is delivered over the past decade. The model has transitioned from one based on central station power plants delivering electricity over a sprawling network of wires to a more decentralized model consisting of distributed energy resources (“DERs”) delivering power closer to where they are located.

According to the North American Electric Reliability Corp. (“NERC”), the organization responsible for enforcing reliability standards on the electric grid, a distributed energy resource is any resource on the distribution system that produces electricity and is not included in NERC’s definition of the bulk power system (“BPS”).1 The growing presence of DER means that these resources must be accurately represented in planning, operating, and stability models, and is becoming “an important consideration for BPS reliability,” NERC said.

According to NERC, types of DERs include any non-BPS generating unit at a single location on the distribution system owned by a utility of commercial entity; behind-the-meter generation; energy storage on the utility side or customer side of the meter; aggregated DER, a virtual resource formed by multiple distribution generation, behind-the-meter or energy storage devices; microgrids; cogeneration formed as a byproduct of energy production; and emergency stand-by or back-up generation facilities.

DERs got a huge boost when the Federal Energy Regulatory Commission issued its Rule No. 2222 in September 2020, which has the goal of allowing DERs to compete alongside traditional energy resources in wholesale energy markets. The order is designed to increase grid resiliency, lower costs for consumers by enhancing competition, and create more innovation within the electric industry, FERC said.

The rule requires regional transmission organizations and independent system operators to revise their tariffs to establish DERs as an official category of market participant, FERC said, defining DERs as systems with capacity between 1 kW and 10 MW. The tariffs also must address technical considerations such as locational requirements for DER aggregations; distribution factors and bidding parameters; information and data requirements; metering and telemetry requirements; and coordination among the regional grid operator, the DER aggregator, the distribution utility and the relevant retail regulatory authority.

According to a report from FERC’s Energy Advisory Committee, the rule creates many new complexities to seamless integration into wholesale markets alongside large power plants. For example, RTOs and ISOs do not have visibility into utility distribution systems, requiring additional levels of coordination with distribution utilities, transmission utilities, and DER aggregators. The rule also created new requirements related to technology, operations, market design, regulation, and planning, the committee said. The committee said the U.S. Department of Energy (“DOE”) must take action to help entities comply with Order No. 2222, which required RTOs and ISOs to make compliance filings by July 19, 2021.

The DOE said that DERs and microgrids are “two ways to ensure continuous electricity regardless of the weather or an unforeseen event.” The DOE defines microgrids as localized electric grids that can disconnect from the main grid and operate autonomously. Such systems produce and distribute energy on a small scale and often employ solar panels, batteries, and/or diesel generators. Such systems can strengthen resiliency of the main grid, serve to mitigate grid disturbances, and function as a grid resource for faster system response and recovery, according to the DOE.

“DER could fundamentally change the way the electric grid works. With DER, power is generated right where it is used and can be connected with other DER to optimize its use. Households and other electricity consumers are also part-time producers, selling excess generation to the grid and to each other,” DOE said.

Facilities that need continuous power to operate are good candidates for microgrids, including hospitals, military installations, college campuses, and community microgrids that are used to keep specific neighborhoods and smaller communities powered up during storms.

According to a report from Frost & Sullivan, the global microgrid market will increase from $8.9 billion in 2021 to $19.6 billion in 2030, and North America and Asia-Pacific will be the leading markets. Asia-Pacific will, in fact, outpace North America with a focus on remote microgrids. Europe’s development will focus more on pockets such as physical islands and rural areas in Eastern Europe that suffer from grid reliability issues. The major global applications will be industrial, commercial/campus, and rural/island grids, with North America focused on commercial and campus applications, and rural and island grids showing the biggest growth in the Asia-Pacific region.

Green Mountain Power (“GMP”), a utility that operates in Vermont where fierce winter storms can occur, said in an integrated resource plan filed with the state in December 2021 that the electricity grid is evolving away from one that operates with a one-way flow of energy. Instead, the utility is developing DER to deal with an influx of more intermittent solar generation.

“This distributed energy future requires an approach to integrated resource planning that is more nimble, flexible, and incorporates distribution planning down to the circuit level,” GMP told the state utility commission. The utility said it is creating a more distributed grid with resources like battery storage, electric vehicles, and smart appliances that reduce the need for large infrastructure and associated costs of development and maintenance. DERs are fast-acting and flexible and improve efficiency, according to the utility, who is using a new DER management system that communicates with distributed devices over a secure cloud infrastructure. GMP is developing pilot programs, many of them employing DER, to meet the state’s energy goals, it said. The utility is planning a microgrid in Rochester near Route 100 that would serve facilities such as water pumps and an emergency shelter for an elementary school, and another microgrid in the town of Stafford to serve emergency shelters at a school, gym, general store, and post office.

But new DERs also need vastly different energy management systems than a traditional energy grid. The Department of Energy has a sizable portfolio of microgrid activities around the country with two areas of focus. One is “planning and design,” which addresses system architecture, monitoring and analysis, and system design; and “operations and control,” which addresses steady-state control and coordination, transient-state control and protection, and operational optimization.

Since 2000, the Lawrence Berkeley National Laboratory has been developing the Distributed Energy Resources Customer Adoption Model (“DER-CAM”), which has the objective of minimizing the cost of operating on-site generation and combined heat and power systems.

“Using state-of-the-art optimization techniques, DER-CAM assesses distributed energy resources and loads in microgrids, finding the optimal combination of generation and storage equipment to minimize energy costs and/or CO2 emissions at a given site, while also considering strategies such as load-shifting and demand-response,” the DOE said. The model can also be used for dispatching DER on day-ahead to week-ahead schedules, based on load and weather forecasting. The goal is flexibility to optimize a microgrid over a wide range of parameters, ranging from net-zero energy requirements to financial incentives, and subsidies for specific technologies and local utility tariffs, the agency said.

But DERs are not necessarily clean energy resources. For instance, in the San Francisco Bay area, back-up generators (“BUGs”) grew by 34 percent between 2018 and 2021, but 90 percent of those systems were diesel-fired. In 2021, BUGs numbered 8,722, reflecting 4,840 MW of capacity, according to a report from policy firm M.Cubed. Combining the Bay Area Air Quality Management District with the South Coast Air Quality District in Southern California, the total capacity of diesel generators is equivalent to 15 percent of the California electricity grid. The substantial particulate emissions and other pollutants are often produced in lower-income and disadvantaged areas, with the diesel generators often utilized as back-up power for computer data centers.

The DER transition will require policy changes and innovation across the board to develop this technology at a reasonable cost while maintaining reliability and affordability of energy for consumers. While there are complicated operational, regulatory, and business considerations surrounding DER integration, there is little doubt that the grid of the future will be more decentralized, more technologically advanced, and decarbonized.

All views expressed by the contributors are solely the contributors’  current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

1 The federally approved definition of the bulk power system includes all the larger elements and facilities that are necessary for the reliable operation and planning of that interconnected bulk power system.

Energy Storage Set for Massive Growth on the U.S. Grid

Published: September 23, 2021

By: Concentric Staff Writer

The presence of energy storage—dominated by lithium-ion battery technology—is surging across the U.S. electricity grid, particularly in the West, driven by new rules at the federal level and the need to balance renewable generation.

A wave of solar and wind energy coming onto the grid, plus escalating decarbonization efforts in the sector, are bolstering new installations of storage, which helps balance the grid by storing energy in the early afternoon for use in the evening. One of the hottest markets for energy storage is California, where a preponderance of renewables has led grid operators and state lawmakers to push storage as a solution.

The amount of energy storage in the California Independent System Operator’s interconnection queue has skyrocketed from 2.6 GW in June 2014 to 69.2 GW in June 2020 and 147 GW in July of this year, CAISO data shows. According to CAISO staff presentations and comments at a recent Board of Governors meeting, most projects in the interconnection queue are not actually constructed due to lack of financing or other reasons, leading to discussions among the ISO’s management as to how to make the queue process more efficient.

The vast majority of new storage due to come online in California is battery energy storage, with a few GW of pumped hydro storage mixed in. Planned battery storage is almost evenly split between stand-alone energy storage projects and hybrid projects that pair storage technology with generation, usually solar. Areas with a large energy storage presence include Kern County, an oil and gas producing area; Riverside County; Los Angeles and Orange Counties; San Francisco; and San Diego. Storage output crested 1 GW on the CAISO grid in early August for the first time in history. Storage reaches maximum charge level around 2 p.m. when solar is peaking and then typically discharges energy in the critical 7-9 p.m. period when the grid is most stressed with high demand after the sun goes down and solar is no longer producing, CAISO said.

In a February report on energy storage, the North American Electricity Reliability Corp. (“NERC”) noted that the benefits of storage technology include fast-ramping support for the grid when solar begins to decline in evenings, rapid frequency response, and assistance with addressing operational uncertainty caused by adding large amounts of renewables to the grid.

In the report prepared with the Western Electricity Coordinating Council, NERC said that bulk energy storage systems “are projected to grow at an increasing pace across North America.” Advances in technology, cost reductions, and new rules at the federal level and within wholesale energy markets are also driving the technology, NERC said. The organization, which enforces mandatory reliability standards, created an inverter-based working group to develop guidelines for the integration of energy storage systems. Strategically located battery storage systems could help prevent blackouts, the organization said.

According to the report, entitled “Impacts of Electrochemical Utility-Scale Battery Energy Storage Systems on the Bulk Power System,” existing NERC reliability standards adequately reflect battery storage as a generator, ensuring that the NERC transmission-planning performance requirements, plus model and data standards, are applicable to the current number of storage systems on the grid. However, data on battery storage tends to be non-uniform and lacking in consistency among reporting entities, which will require better reporting mechanisms for energy storage data, the organization said.

“Because battery storage is an emerging technology, the development of utility-scale battery storage has lagged the integration of renewable resources,” the NERC report says.

The storage industry got a major boost in February 2018 when the Federal Energy Regulatory Commission, which regulates the bulk power system and wholesale energy markets, issued its landmark Order No. 841. The rule requires regional transmission organizations and independent system operators around the country to remove barriers to participation of electric storage resources in their capacity, energy, and ancillary service markets.

Each RTO and ISO in the U.S. was required to make compliance filings under the order, which mandated them to establish a participation model of market rules that recognizes the physical and operational characteristics of electric storage resources and facilitates their participation in the markets. The participation models must ensure that a resource is eligible to provide all capacity, energy, and ancillary services that it is technically capable of providing in the RTO/ISO markets, and that a resource can be dispatched and can set the wholesale market clearing price as both a wholesale seller and buyer. The participation models need to account for the physical and operational characteristics of energy storage resources through bidding parameters or other means. FERC has established a size requirement for participation in RTO/ISO markets that does not exceed 100 kW.

FERC rejected rehearing requests to Order 841 from state utility commissions that said storage integration was a state matter, and in July 2020 a federal appeals court upheld FERC’s Order No. 841, rejecting arguments that states should be free to control energy storage participation. Petitioners included the National Association of Regulatory Utility Commissioners, the American Public Power Association, the National Rural Electric Cooperative Association, Edison Electric Institute, and American Municipal Power, Inc.

“Because the challenged Orders do nothing more than regulate matters concerning federal transactions – and reiterate ordinary principles of federal preemption – they do not facially exceed FERC’s jurisdiction under the Act,” the U.S. Court of Appeals for the D.C. Circuit said in its decision.

Recognizing the limitations of four-hour battery storage technology, the U.S. Department of Energy launched a “Long-Duration Energy Storage Shot” research initiative. The goal of the shot is to “accelerate breakthroughs of more abundant, affordable, and reliable clean energy solutions within the decade,” DOE said. Having more long-term storage in place will help the country tackle the remaining barriers to addressing climate change and reach the Biden Administration’s goal of net-zero carbon emissions by 2050 more quickly while creating jobs, the agency said.

With new efforts at the grid operator level and at the federal government to integrate and develop new storage technologies, the resource appears to be here to stay on the U.S. grid and is poised to play a major role in integrating renewables and meeting climate goals.

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All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

A Note on Decarbonization of the United States Energy Sector

Published: June 29, 2021

Contributors: Bob Yardley, Forrest Small, Marisa Ihara, and Julie Lieberman

The United States and Europe have made great progress in decarbonizing electric generation. However, to achieve the 2050 decarbonization goals set by many states and local communities, it will be necessary to decarbonize transportation and building heating and cooling as well as energy production.

There are several alternative pathways to decarbonize an economy, including:

These pathways have varying technical challenges, timelines, costs, and impacts on greenhouse gas emissions. Under all pathways, maintaining the security of the energy infrastructure is of paramount importance. However, as with any transformative change, there will be winners and losers throughout all segments of the economy. The potential for big “winners” will drive innovation in the technologies that make decarbonization possible. In contrast, the potential for big “losers” will bog down policymaking and potentially lead to stranded costs, if not offset by opportunities to generate new revenue sources. Policymakers will need to consider these competing interests while maintaining the financial integrity of regulated entities and serving the broader public interest.

Under all pathways, reducing energy usage and/or shifting energy usage from peak to off-peak hours will be key to achieving decarbonization goals, while also improving the efficiency of the overall energy system and mitigating cost impacts. Shifting the timing of energy production through the strategic use of energy storage will also mitigate cost impacts as storage technologies develop.

Under the first pathway, residential and business customers are likely to incur substantial costs to convert their preferred method of heating, cooling, cooking, and other end-uses to electricity. Policymakers must consider affordability for low- and moderate-income customers, equity issues related to the siting of electric transmission facilities and other new infrastructure. A substantial buildout of electric transmission to deliver wind and solar energy will be particularly challenging under the current approach to siting in the most populated regions of the United States.

Transitioning from pipeline gas to renewable natural gas and hydrogen-based fuels distinguish the second and third pathways. This will require improvements in natural gas pipeline infrastructure to accommodate hydrogen, for example, and new appliance technologies.

The United Kingdom is leading the way with respect to research in the production and use of hydrogen and other low-carbon fuels and has provided ₤659m of innovation funding over a five-year period to its regulated energy distribution companies to support the transition to Net Zero.1 The UK is able to make strategic decisions due to its model characterized by a single regulator (Ofgem) and general alignment on decarbonization goals. As the UK’s hydrogen production and decarbonization of building heating and cooling get underway, the United States can benefit from these efforts and the many practical lessons learned.

Communicating the strategies and tactics to customers and the public will be enormously challenging. It will require coordination among policymakers, utilities, and other organizations that will play a role in implementing decarbonization. There are many practical challenges to be addressed and communicated, including circumstances in which the gas company and electric company are distinct entities that must coordinate the overall program and each individual conversion.

In summary, the decarbonization of the energy sector is both incredibly challenging and infused with the public interest. At this early stage, it is essential to accelerate research and development to validate and improve the options that may be available. Policymakers will require information on cost and other customer impacts, public safety, contribution to emissions reductions, and a multitude of implementation issues to achieve decarbonization goals as efficiently and equitably as possible. Our team strives to bring solutions to regulators that will benefit customers and local economies and to help market participants implement these policies. We focus on the policy, financial, risk, pricing, market, affordability, resilience, and practical implementation issues at the intersection of utility planning, infrastructure development, and customer service delivery.

More from Concentric:

Pipe Replacement for a Decarbonized Future

All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

1See RIIO-2 Final Determinations – Core Document (December 8, 2020) at 5.

Bill Crediting Program for Host Communities of Major Renewable Energy Projects

Published on February 11, 2021

By: Wale Akanni, Senior Analyst

Concentric recently provided regulatory policy support to New York’s investor-owned utilities (the “Joint Utilities”) in response to a policy proposal from the New York State Department of Public Service Staff (“DPS Staff”).  The Joint Utilities are a collection of six public utility companies that serve approximately 7 million electric and 2.5 million gas customers across New York.

DPS Staff proposed that the Joint Utilities administer an annual bill crediting program for customers residing close to major renewable energy facilities that are key to achieving New York State’s decarbonized electricity grid mandates.

Concentric evaluated the scale of the proposed bill credits to illustrate that the effect on customer bills would vary widely across municipalities. The scale of the expected bill credit that would apply to an individual customer bill would depend on the benefit rate authorized by the Commission, the generating capacity of the applicable renewable facility, and the population density in the vicinity of the facility. The analysis indicated that applying DPS Staff’s proposed credits to individual customer bills on an annual basis may not be meaningful or even greater than the cost to administer the program. Consequently, the Joint Utilities have recommended alternative approaches that can create meaningful benefits for customers, such as directing funds toward community-led programs.

All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The author’s views are based upon information the author considers reliable. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.


Pipe Replacement for a Decarbonized Future

Published on August 19, 2020

By: Alexander Cochis, Project Manager and Javier Sola, Consultant

Environmental advocates are challenging whether it makes sense to continue with existing pipe replacement programs, arguing that the industry is investing in rate base that will be stranded long before it is fully depreciated.

Key Considerations

A pipe replacement framework that incorporates uncertainty attributable to:

Will meet the challenges of a changing environment.

A New Investment Framework

The existing pipe replacement decision-making process focuses on how fast LDCs can replace at-risk pipe and how best to prioritize and execute their pipe replacement programs. These decisions are driven by federal mandates and subject to oversight by state utility regulators that are concerned about safety and cost. Environmental advocates are opposing new pipelines but also suggesting that LDCs should be at risk for future pipe replacement investments, as they increasingly focus on gas planning processes and decisions. Regulators recognize that pipeline safety is paramount. How can LDCs adjust the decision-making framework to support pipe replacement decisions? Our current assessment is that the degree of policy change, technological advances, and the costs of alternatives or substitutes to natural gas all play a role in framing a response to the challenges of decarbonization on pipe investment decisions.

For a gas company to fulfill its public service mandate, it will make ongoing maintenance, monitoring, and operating expenditures to sustain the system and comply with safe operating practices (Figure 1). The LDC can also make investments to grow. As costs increase, operators will decide how long before those outlays are completely recovered.The Pipe Replacement Decision Framework in Figure 2 depicts areas that represent varying degrees of costs, recovery time, and risk for the project types in Figure 1.

Project types in the Pipe Replacement Decision Framework present risks that are the product of both the likelihood of being unable to sufficiently recover capital and the amount of capital exposed. The further investment decisions move away from the short payback and minimum expenditure programs, the closer decisions are framed by a “risk envelope” space depicted in the Framework. Trade-offs may begin to appear between lower cost pipe segments that have longer time horizons to recover capital (new branch lines with few customers) and larger capital investments with shorter paybacks (removal and replacements of entire mains in established and densely served areas). As undepreciated investments approach economic planning horizons or any other mandated useful lives, the potential for customer rate shock as obsolete capital is recovered or loss to shareholders from stranded cost presents an opportunity to look for innovative capital investment and recovery methods.

Decarbonization policies are likely to change the risk analysis. Environmental considerations may accelerate technological improvements toward lower carbon natural gas through targeted investments and state or provincial carbon intensity limits. While mandates and subsidies are by their nature distortive, they can also spur new delivery models. Power supply renewables, for example, are following a discernible cost decline as mandated investments lead to economies of scale.

Risk introduces elements of time-sensitive paybacks to traditional decision-making metrics like net present value, rates of return, and size of rate base. This may present more realistic prospects for pipe recovery for a gas company facing more ambitious decarbonization policies. The new investment decision framework should incorporate uncertainty. Decarbonization policy, the economics of electrification, customers’ preference to continue to use natural gas, and new safety protocols all change the investment views on how long new pipe will be needed.

Responses to Some Common Questions

Should the LDC continue, accelerate, or reprioritize its pipe replacement program?

Under the Pipe Replacement Decision Framework, the degree of decarbonization will be a significant driver of the answer to this question, with “net zero carbon” scenarios presenting the greatest risk, as will the timeline for phasing in the program. Pipe system integrity is regulated by the states, and federally by the Pipeline and Hazardous Materials Safety Administration (PHMSA) under the Distribution Integrity Management Program (DIMP). Given the duty to maintain a safe system, any decarbonization policy would need to support system safety to the extent the system or certain segments or subsystems remain in service. While an argument might be made for repairing, rather than replacing, the classes of leak-prone pipe (LPP) currently targeted under DIMPs, the trade-off would require careful risk analysis of the LPP in order to ensure that leaks are maintained on the system at a manageable level. Pipe replacement is usually triggered by integrity concerns or capacity needs. These investment decisions could be broadened to reflect decarbonization policies. Depending on the type of decarbonization policy adopted by the state, pipe programs may be reconfigured to include the consideration of the use of new technologies, including, for example, the use of geothermal district heating as an alternative to replacement of LPP lines.

If regulators place shareholders at risk for new pipe by ruling against stranded cost recovery, how can local LDCs manage that risk? 

A significant driver of the answer to this question will depend on the carbon scenarios mandated. Investment strategy will reflect the level of increased risk and the pace of decarbonization. Asset management and portfolios, market position, and performance metrics will shift in the LDC company space. Pipe investment moves from a series of cost of service approval exercises to a dynamic consideration of available alternatives, where market forces truncate useful lives, and the probabilities change once large investments are made.

For example, changes in public policy resulting in stranded costs would raise the business risk of the company and likely merit a higher allowed return. The degree of the decarbonization under new mandates would drive whether system investment strategy would change. To the extent that gas will still be needed for generation to balance higher levels of renewables that support decarbonization, for example, investment decisions may shift to supporting new generation rather than expanding residential service. If the decarbonization policy allows offsets, then investments could be made to support the offsets (e.g., reforestation programs) to maintain a status quo business plan in regulated operations. Should renewable natural gas (RNG) be available and competitive at scale and fall within the decarbonization policies, then a company could make investments to transition to RNG supplies.

Should the company propose a change to depreciation rates for existing or new pipe? 

Near-term increases in depreciation rates present ways to balance investment recovery with policy goals in an incremental manner and can be adjusted through a rate case, with due consideration to rate impacts. Future earnings levels could be relatively lower if decarbonization policy reduces rate base. For this reason, any change to depreciation or capital recovery must be made in concert with other variables such as rates of return, salvage costs, capital budgeting, or risk management. Higher depreciation rates would present a way to hedge some of the risk associated with the underutilization or early retirement of pipe. Should the type of decarbonization policy adopted lead to an early abandonment of pipe, then increasing the rate of depreciation would allow for the accelerated recovery of the investment, mitigating the risk of stranded assets.

All views expressed by the authors are solely the authors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The authors’ views are based upon information the authors consider reliable. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

Are Demand Charges Appropriate for Sending Price Signals for Electric Distribution Systems?

Published on June 26, 2020 

By: Team Concentric

This article is the second in a series addressing the changing environment for regulated utility pricing given advances in Distributed Energy Resource technology, data availability, and customer preferences. Part One, Renewable Distributed Generation and Pricing Challenges, addressed the issue of Net Energy Metering.

Demand charges have been a component of electric utility pricing design for many decades. The original arguments for demand charges were developed by John Hopkinson[1] and further summarized by James Bonbright:

“The full rationale of this Hopkinson, two-part rate is far from simple. But the rationale usually given (although it will serve only as a first approximation) is that the two-part rate distinguishes between the two most important cost functions of an electric-utility system: between those costs that vary with changes in the system’s output of energy, and those costs that vary with plant capacity and hence with the maximum demands on the system (and subsystems) that the company must be prepared to meet in planning its construction program.”[2]

However, industry experts are now debating whether demand charges are an appropriate pricing mechanism, in particular for smaller customers (e.g., residential customers). Some compelling arguments against demand charges to consider:

·         Demand charges do not send proper price signals to customers.

·         Demand charges are expensive to implement.

·         Customers do not understand demand charges.

·         Customers cannot react and/or respond to demand charges.

·         No cost support exists for demand charges; they do not reflect the incremental cost to use the distribution system.

·         Distribution investments should be recovered by some form of energy charge.

In this article, we limit the debate to electric distribution systems. We will assess the arguments for and against demand charges and determine if demand charges are an appropriate mechanism in an electricity pricing design.

The Economics of an Electric Distribution System

One of the traditional arguments for the regulation of utilities is the existence of natural monopolies. A natural monopoly is defined as an industry with economies of scale, which results in the long-run marginal cost below the average cost for a single producer. Given the economies of scale associated with electric distribution systems, it is only economically efficient for a single system to exist within a given geographic area.

Unlike competitive markets, where prices are established at the marginal cost of production, a natural monopoly must set prices above the marginal cost. The revenues generated by marginal cost prices are insufficient to financially support the system. Therefore, the challenge for a natural monopoly is to determine how to recover the additional needed revenue in a manner that is considered equitable and sends a proper price signal to the customer.

In the energy industry, experts have argued that distribution systems are not constructed to serve demand and that their cost structure is fixed. To address such arguments, the authors consulted on the design of electric distribution systems with Anthony (Tony) Hurley. Mr. Hurley is an electric distribution system expert with over 30 years of experience. He is currently a Consultant at Critical Preparedness, LLC and previously held a leadership role in Electric Distribution at FirstEnergy as Vice President of Operations at Jersey Central Power & Light. Mr. Hurley stated:

Every customer on a distribution circuit, whether residential, commercial, or industrial, has a load profile that mirrors their load usage and peak demands, with the data being captured by the utility. From this demand information, distribution engineers are able to make investment decisions and reconfigure circuits if loads may exceed equipment ratings, and forecast the need for capital projects, including equipment upgrades and possibly new substations to address peak loads. To accept the premise that demand information is not used in Distribution Planning is incorrect.

Ultimately, the planning function for a distribution system is based upon expectations of demand growth within that system. For a system operator to send the correct price signal to customers, the distribution system should be priced at the long-run marginal cost.

Definition – What is Demand?

Traditional definitions of demand, (e.g., the maximum level of consumption by a customer averaged over a time period such as a one-hour or 15-minute interval), imply a one-way flow of power from the utility to the customer. However, the traditional definition of demand is no longer applicable in a world with Distributed Energy Resources (DER). The growth of DER means that a utility is now required to plan not only for an inflow of electricity to the customer, but an outflow from that same customer to the distribution system if their DER output exceeds consumption at a given point in time. A specific example of this is a customer with a small residential solar array who draws energy at night when the panels are not generating power, but during the day may produce more than they consume. Therefore, a pricing mechanism designed for demand could be characterized as an “option.” Customers would purchase an option designed to allow them to use a system up to a certain quantity of demand, either received or injected into the distribution system. This behavior would provide proper production signals to the utility, guiding better-informed investment.

Arguments Commonly Made Against Demand Charges

Argument 1: “Demand Charges Do Not Reflect the Incremental Cost of Using the Grid”

An argument is often made that demand charges do not reflect the incremental cost to serve customers, but instead are based upon average embedded costs. As a result, they would send a false price signal to customers. Some truth can be ascribed to this statement if the pricing design follows an embedded cost of service approach.

However, the development of long-run marginal cost of service is possible; such studies have been performed by many utilities in the last several decades. A traditional approach to developing demand charges based upon average embedded costs can be problematic. Still, recent innovations have included a more detailed analysis of the distribution cost structure and the impact of DER.

Argument 2: “Demand Meters are Expensive to Implement

To create and implement a demand charge, the customer premises must be outfitted with metering equipment, which is capable of measuring that customer’s demand in real-time. A traditional argument against implementing demand charges for residential and small commercial customers is that the incremental cost of this metering technology is expensive, and it is not cost-beneficial to install the metering technology on a system-wide basis.  Although this may have been true in the past, it is no longer accurate.

Metering technology costs have dropped dramatically in the last several decades.  The replacement of electromechanical technology with today’s Advanced Metering Infrastructure (AMI) equipment has reduced costs and increased reliability in many instances. Further, the cost of data management has decreased, allowing for more complex billing structures to be easily processed and delivered to customers. Modern metering equipment associated with AMI generally has the capabilities to provide revenue quality demand charges as well as other, more advanced pricing designs.

Argument 3: “Customers Do Not Understand Demand Charges”

Many parties have argued that customers, especially residential customers, are unable to understand the complexities of demand charges. They claim that traditional utility tariffs for smaller customers, based solely on two-part pricing designs (i.e., a fixed charge and an energy charge), remain appropriate.

We believe a discerning customer is able to navigate demand charges for the following reasons:

Underestimating the ability of customers to understand electric tariff designs is a mistake that simply reduces the number of service and pricing options available to residential customers. Given that such options are in many cases feasible, the result is fewer choices for residential customers, increased cross-subsidization, and potential increases in the utility revenue requirement, which could be avoided.

We agree that the introduction of new tariff designs, including demand charges, should include an education process for customers, but advanced pricing concepts should not be written off solely due to the perception that customers will not understand them.

Argument 4: Customers are Unable to React to Demand Charges

Some parties argue that customers cannot react to demand charges given the tariff design.  We reject this argument because:

Argument 5: Distribution Investments Should be Recovered by an Energy Charge

The last argument proposes to recover the costs of the distribution system through an energy charge.  Recovering distribution costs through an energy charge is deficient on several fronts and should be rejected for the following reasons:

 How Should the Non-Incremental Cost of the Distribution System be Recovered?

A question that has challenged the utility industry for many years is how to recover costs which exceed the long-run marginal costs to operate the distribution, or “Residual Costs.” That question will be addressed in the next paper in our series “The Application of Access Charges.”


For more information on the topics discussed in this article, please contact Tom O’Neill.


More From Concentric:

Renewable Distributed Generation and Pricing Challenges

All views expressed by the authors are solely the authors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The authors’ views are based upon information the authors consider reliable. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

[1] Hopkinson, John R., 1892. On the Cost of Electricity Supply, Transactions of the Junior Engineering Society. Vol. 3, No. 1, p1-14.

[2] “Principles of Public Utility Rates”, Public Utility reports, Inc. by James C. Bonbright. First edition 1961, page 310.

Renewable Distributed Generation and Pricing Challenges

Published on May 28, 2020

By: Team Concentric 


In April 2020, the Kansas Supreme Court (KSC) overruled the Kansas Corporation Commission and a lower courts order on a tariff which Evergy, the local power utility, explicitly developed for customers operating behind the meter Renewable Distributed Generation (RDG) systems. The KSC opinion stated that the requirement for RDG customers to take service under a separate tariff from their non-RDG peers constituted discrimination under K.S.A. 66-117d of the Kansas Public Utilities Act, which states:  

“No electric or gas utility providing electrical or gas service in this state shall consider the use of any renewable energy source other than nuclear by a customer as a basis for establishing higher rates or charges for any service or commodity sold to such customer nor shall any such utility subject any customer utilizing any renewable energy source other than nuclear to any other prejudice or disadvantage on account of the use of any such renewable energy source.” 

This emphasizes how legal venues such as the KSC offer opinions based upon legal interpretations and not the broader policy issues that state and federal regulators consider in evaluating pricing designs proposed and implemented by regulated utilities. Provided below is a discussion of many of the various issues that should be addressed in developing a pricing design that fulfills the needs of current and potential RDG customers while limiting the adverse impact on other customers. 

Evergy’s Proposed Tariff

Evergy’s proposed Residential Standard Distributed Generation tariff (the “DG tariff”) differs from their typical Residential Service tariff in that it is a three-part tariff. The pricing design contains a fixed monthly charge, a volumetric energy charge, and a demand charge. Evergy’s existing Residential Service tariff contains only a monthly fixed charge and an energy charge. Both tariffs are seasonally differentiated with a higher energy charge during high-usage summer months than during winter months.

Given that the fixed monthly charge for these two tariffs is identical, the main differences between them are:  

  1. The DG tariff contains a demand charge 
  2. The Residential Service tariff has a higher energy charge, which captures the capacity costs as well as usage

Is a Pricing Design Specifically for DG Customers Discriminatory? 

Traditional pricing design theory looks at the following attributes to determine if customer groups should be split into different tariffs: 

Since these questions must be answered by any utility proposing such a tariff, most analyses have found different load shapes and load factors between DG and non-DG customers. Further, a difference exists in the type of DG equipment being utilized. These conclusions are logical if you assume that a customer has installed photovoltaic (PV) DG, which operates when the sun is shining; the resulting load shape would undoubtedly differ from a customer without PV DG equipment installed 

Does Cost Shifting Occur? 

Most jurisdictions require that the rates charged are “just and reasonable.” Though the definition of “just and reasonable” is broadly defined and subject to various interpretations, a commonly accepted simple explanation is the equitable treatment of all classes of customers. Equity is often measured through an allocated cost of service analysis or, less frequently, through a marginal cost revenue study.

Many studies have identified significant cost differentials between DG customers and non-DG customers when they are served under the same tariff. For example, a study performed by the author in Puerto Rico produced a revenue deficiency approximately 500 percent greater for DG customers compared to non-DG customers.

Cost shifting can occur when simple DG compensation approaches, such as Net Metering, are implemented as a substitute for a more sophisticated (i.e., unbundled) pricing design. Many jurisdictions adopted Net Metering as straight forward pricing approach, which is often predicated upon a limit to the number of DG customers who are allowed to receive service under such tariffs. When rooftop PV technologies were a novelty, the impact of the cost shifting on other customers was less significant. However, as DG saturation has increased, the cross-subsidization problem inherent in approaches like Net Metering has grown 

What is the Solution? 

As a foundation, we suggest revisiting Bonbright’s[1] Criteria for sound rate design. Bonbright suggested pricing solutions that treated all customers equitably and promoted the efficient use of resourcesWhile Bonbright first proposed his principles almost sixty years ago, they remain applicable today. 

Ultimately, there are existing pricing solutions that could help mitigate the challenges of DG adoption. The key principles are rooted in the efficient usage of the electric power system and sending price signals that promote the adoption of technologies to achieve societal goals.


For more information on the topics discussed in this article, please contact Tom O’Neill.


More From Concentric:

Are Demand Charges Appropriate for Sending Price Signals for Electric Distribution Systems?

[1] “Principles of Public Utility Rates,” Public Utility reports, Inc. by James C. Bonbright, Albert L. Danielsen and David R. Kamerschen. Second edition March 1988, pages 383-384.

All views expressed by the authors are solely the authors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The authors’ views are based upon information the authors consider reliable. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

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