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.

Proposed Federal Transmission Rules Create Optimism, Skepticism

Published: June 10, 2022

By: Concentric Staff Writer

Federal energy regulators are pushing forward with reforming rules around planning and siting new transmission lines needed to bring planned renewable resources online. Still, as with previous efforts, there are questions about how effective the initiative will be.

The Federal Energy Regulatory Commission’s (FERC) draft notice of proposed rulemaking on transmission planning and cost allocation (NOPR), issued on April 21, is garnering much attention across the industry. Stakeholders, including electric utilities, regional transmission organizations, state public utility commissions, and environmental groups realize that new transmission facilities are needed to maintain system reliability and deliver large amounts of new renewable generation to load centers. But scrutiny around the proposed rules is intense, with questions as to whether or not they will lead to new transmission build-out and how the initiative will meet the needs of states, transmission developers, and ultimately, electricity consumers.

The NOPR is intended to build upon and correct perceived deficiencies in its Order No. 1000, issued in July 2011 and affirmed in Order No. 1000-A in May 2012. Order No. 1000 (Order 1000) has been the primary federal directive regarding transmission planning and cost allocation, but there has been broad recognition that construction of new facilities in recent years has not kept up with the grid’s needs. The new federal rulemaking is intended to address long-running roadblocks and procedural issues surrounding new transmission, and the stakes are high for consumers and investors as the U.S. navigates the transition to cleaner electricity.

FERC Chairman Richard Glick laid out the goals of the rulemaking in a statement that coincided with the release of the NOPR.

“Transmission facilities provide a broad range of benefits,” Glick said. “Planning for those facilities with a longer-term forward-looking approach, in addition to fairly allocating their costs, is essential to ensuring we are developing energy infrastructure in a manner that reduces costs and enhances reliability.”

Transmission siting in the U.S. has gotten trickier in recent decades. New facilities are often opposed by local residents who do not favor large rights-of-way, and transmission infrastructure cutting through forests, plains or desert areas. Localities will also periodically oppose related projects connected to the transmission expansion, such as substation improvements.

In the area of new transmission planning, the NOPR would require public utility transmission providers to conduct long-term regional planning to meet the changing generation and energy storage resource mix and rising electricity demand that is occurring in many places in the U.S.

As part of the proposed process, transmission providers would be required to develop long-term scenarios, including accounting for high-impact, low-frequency events such as extreme weather.

Transmission providers would also be required to consider an expanded list of benefits related to proposed transmission infrastructure over a 20-year period, marked from the date the infrastructure is sited. Additionally, they must select transmission plans that most efficiently or cost-effectively meet the identified transmission need. The draft NOPR also proposed to require that public utility transmission providers more fully consider dynamic line ratings—as opposed to static line ratings that are currently used—and advanced power-flow control devices in regional transmission planning. Dynamic line ratings, a concept that has been in discussion for a long time, refers to classifying the capacity of a transmission line based on real-time, granular data, as opposed to a static rating that only accounts for heat and other factors. This allows transmission operators to maximize power flows over transmission lines.

Danielle Powers, a Senior Vice President and Board Member at Concentric Energy Advisors and a former employee of both an investor-owned utility and ISO New England, points out that very few proposed high-voltage transmission projects have been constructed in recent years, mostly due to local opposition, she said. The FERC is attempting to address this issue by requiring increased state involvement in transmission planning and cost allocation. It remains to be seen if this will lead to more support for new transmission at the state level.

“I know what they’re trying to accomplish,” Powers said. “I think they’re thinking: ‘if we get the states more involved, they’ll be able to be better informed and maybe have some role in garnering more local support.’ I think that is a high hurdle.”

States already participate in transmission siting because it is under their jurisdiction. State regulators as well as the public have also been wary of federal intervention when siting large transmission facilities that, in some cases, do not provide local benefits.

Regarding federal rights of first refusal, the draft NOPR proposes to amend Order 1000 “to permit the exercise of federal rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider establishing joint ownership of the transmission facilities.” This means that incumbent transmission providers will be permitted a federal right of first refusal as long as the facilities are jointly owned with unaffiliated, non-incumbent entities.

The NOPR would partially resurrect a federal right of first refusal that previously had been granted to transmission providers but was removed by Order 1000. Order 1000 required that public utility transmission providers eliminate a federal right of first refusal for an incumbent transmission developer with respect to entirely new facilities selected in a regional plan for purposes of cost allocation. But the Order 1000 right of first refusal elimination does not apply to local transmission facilities built solely within an incumbent provider’s footprint or to incumbents building, owning, and recovering costs of upgrades to its existing facilities. Order 1000 also does not remove or limit an incumbent provider’s use and control of its existing rights-of-way.1

In the new NOPR, FERC noted that there were also exemptions from the right of first refusal for reliability projects with an immediate need. FERC said that recent transmission investment trends suggest that despite increased investment in transmission facilities overall. However, in many planning regions there has been comparatively limited investment in transmission facilities selected in a regional plan for purposes of cost allocation as the result of a competitive process. Transmission development has largely been concentrated in local transmission projects that are generally not subject to competitive transmission development processes.

During transmission planning, regional transmission organizations or independent system operators issue requests for proposals for competitive transmission projects. Transmission developers respond to the requests with project proposals, some of which are approved for interconnection studies. If the projects meet certain thresholds, they are included in regional transmission plans and once projects are selected, transmission developers move forward with getting state permits.

“Taken together, the reforms proposed in this draft NOPR would work to remedy deficiencies in the Commission’s existing regional transmission planning and cost allocation requirements,” FERC said in a statement. “This, in turn, would fulfill the Commission’s statutory obligation to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential.”

In light of the longer planning horizons, the draft NOPR also proposes to eliminate a construction work in progress financial incentive (CWIP Incentive) for transmission facilities that allows transmission providers to recover investment costs as the projects are being built. In the NOPR, FERC states that it had previously found the CWIP Incentive to be beneficial to ease financial pressures by providing up-front regulatory certainty, rate stability, and improved cash flow, which can result in higher credit ratings and lower capital costs. But those are benefits to corporations and shareholders, not utility customers who are not yet enjoying the benefit of the new facilities. If the facilities are not placed into service, ratepayers shoulder the cost without gaining any benefit, the NOPR says.

“We are concerned that the CWIP Incentive, if made available for Long-Term Regional Transmission Facilities, may shift too much risk to consumers to the benefit of public utility transmission providers in a manner that renders Commission-jurisdictional rates unjust and unreasonable,” FERC said.

One forum addressing the NOPR is the FERC Joint Federal-State Task Force on Electric Transmission, which includes state regulators from around the country and has several meetings remaining this year. The task force was formed in a partnership between FERC and the National Association of Regulatory Utility Commissioners.

FERC is taking comments on the NOPR and encouraged commenters to identify improvements to the proposal that will support development of more efficient and cost-effective transmission facilities (R22-32). Comments are due 75 days from date of publication in the Federal Register, and reply comments are due 30 days after the initial comment deadline. Members of the public requiring assistance in filing comments should email FERC’s Office of Public Participation at opp@ferc.gov, the agency said.

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 FERC’s Order 1000 distinguished between incumbent transmission developers and nonincumbents. An incumbent developer builds transmission within its own retail distribution territory or footprint, while nonincumbents are either developers that have no retail distribution territory or footprint, or a utility transmission provider that proposes a transmission facility outside its existing territory or footprint.

 

Observations on U.S. Inflation and its Effect on Regulated Utilities

Published: May 24, 2022

By: John Trogonoski, Assistant Vice President

Key Points:

Consumer prices for the 12 month period ending in April 2022 increased at an annualized rate of 8.3%, according to the U.S. Bureau of Labor Statistics. By comparison, the average annual inflation rate from 1926–2021 was 3.04%, and the median inflation rate was 2.75%.

Since 1926, the U.S. has only seen 12 years that had inflation rates of 7.0% or higher, including 2021.

Periods of high inflation have typically lasted 2–4 years and usually coincide with some external shock. Prior periods of high inflation include:

Examined over 1965 to 1982, economists characterize this period as the “Great Inflation”, caused by both external shocks and a failure of macroeconomic and monetary policies.1

Other years with inflation greater than 7.0% include 1942, 1951, and 2021.

Although inflation was initially characterized in 2021 as “transitory” by the Federal Reserve Board (Fed), the Fed now recognizes the inflationary pressure and expectations are more persistent. As a result, the Fed has recently started raising short-term interest rates from historically low levels, and the federal funds rate is currently within a range from 0.75% to 1.00%. As a point of comparison, the federal funds rate in 1981 averaged 16.39% to combat persistently high inflation that started in 1973 and continued through 1982.

Equity markets are also affected by higher inflation because stock valuations depend, to some degree, on the level of interest rates and on investor expectations for inflation.  Higher inflation has not always led to lower stock prices. In fact, the only years in which stocks were lower during periods of high inflation were 1946, 1973–1974, and 1981. But, the U.S. stock market in 2022 is off to its worst start in 60 years as investors adjust stock valuations to reflect higher interest rates, tighter monetary policy and supply chain disruptions from the Covid 19 pandemic and the War in Ukraine.

Average authorized returns for electric and gas utilities have been below 10% in recent years. By comparison, the average authorized ROEs for electric and gas utilities from 1980–1982 were 15.12% and 15.03%, respectively. As inflation approaches levels seen in the early 1980s, pressures will mount to increase allowed equity returns to attract capital for both ongoing investment needs and the accelerated transition to lower carbon networks. While utility customers have the protection of regulation not afforded to other energy consumers, customers will ultimately bear the costs of higher inflation in their rates.

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 https://www.federalreservehistory.org/essays/great-inflation

An Organized Western Electricity Market – Who Would Run it and What are the Challenges?

Published: May 13, 2022

By: Concentric Staff Writer

Momentum is growing towards a wider wholesale electricity market in the Western U.S., but a rocky history and issues around who would govern such a market are among the many challenges to this effort.

Many of the utilities in the West operate outside an independent system operator (“ISO”) or regional transmission organization (“RTO”), but the need to integrate increasing amounts of renewable energy resources in western states is swinging the conversation back to a western RTO.

That conversation has heated up since last summer when the Federal Energy Regulatory Commission—which regulates wholesale energy markets—held a technical conference on  resource adequacy in the Western Interconnection. At that conference, Commissioner Alison Clements noted that extreme weather events attributed to climate change and the West’s changing energy resource mix is bringing more urgency to the western RTO debate. She also noted that historically, the federal government has allowed western grid planners to operate with relative freedom from burdensome mandates coming from  Washington D.C.

“The urgency of efforts towards broader regional integration has changed in the last year, even in the last six months,” Clements said. “Shared goals” and assuring reliability in the face of increased weather threats, as well as new state mandates and protecting consumers are other drivers towards regional integration, she added.

Clements added that she and FERC Chairman Richard Glick “believe that well-designed regional markets, in this case designed by westerners for westerners is the best path forward to protect customers and ensure reliability while addressing resource adequacy concerns and the other serious challenges facing the West.”

Last June, nine former FERC commissioners wrote to current agency members encouraging exploration of a western RTO, saying ISOs and RTOs “provide compelling platforms for renewable energy development and are achieving considerable consumer benefit.” More than 80 percent of renewable resources have been placed in regions with organized markets, the letter says. It was signed by former commissioners Nora Mead Brownell, James J. Hoecker, William Massey, Elizabeth Moler, John Norris, Robert Powelson, Branko Terzic, Jon Wellinghoff, and Pat Wood.

States throughout the West are exploring participation in an RTO. For example, Nevada passed legislation last year forming a working group to study the implications of the state’s utilities joining an RTO. A December, 2021 study by the Colorado Public Utilities Commission found that enhanced market participation through regional collaboration could save the state’s utilities four to five percent in costs per year, or about $230 million annually. And the Utah Governor’s Office of Energy Development, in partnership with State Energy Offices of Idaho, Colorado, and Montana received a grant from the U.S. Department of Energy to facilitate a state-led assessment of organized market options, a study that will last more than two years.

The discussion around a Western Interconnection-wide RTO is occurring as existing entities such as the California Independent System Operator (“CAISO”) and Southwest Power Pool (“SPP”) work to spread their footprints with regional balancing markets. These regional balancing markets do not include day-ahead power scheduling, a participatory governance structure, or other aspects of an RTO.

CAISO’s wider energy balancing market across the West is known as the Western Energy Imbalance Market (“EIM”), which CAISO recently announced has resulted in a cumulative $2 billion in benefits since its creation in 2014. In the first quarter of this year, the EIM resulted in more than $172 million in benefits to market participants, due to its ability to identify the least-cost resources to meet immediate power needs and manage transmission congestion, helping grid reliability, CAISO said.

CAISO is currently taking comments on a straw proposal to bring its existing day-ahead energy market across the EIM footprint, and by next year the EIM is due to have 22 utilities that serve about 80 percent of the electric load in the West. Expanding the day-ahead market is seen as an exploration towards a western RTO as it links CAISO with Northwest utilities such as the Bonneville Power Administration and others.

But the energy crisis of the early 2000s and the August 2020 blackouts in California, along with ideological and political rifts between the Golden State and other western states, have kept any regionalization of CAISO at bay. Leaders and market participants in other western states fear that an RTO operated by CAISO would spread many of California’s issues such as blackouts across the West. Legislation to regionalize CAISO has been introduced at the state level in California but has historically sputtered due to opposition by labor unions over fears it would take jobs out of California, as well as environmental and public interest groups that say it would take the state’s energy planning out of state hands.

In addition to CAISO’s EIM, SPP formed the Western Energy Imbalance Service (“WEIS”) market in 2021, relying on its long history of operating a wholesale market across 17 states, and includes several participants.1  SPP is currently working on broader market efforts. In July 2021, SPP officials approved policy-level terms and conditions for RTO expansion in the Western Interconnection. Western entities considering participation in the effort include Basin Electric Power Cooperative, Colorado Springs Utilities (“CSU”), Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Wyoming Municipal Power Agency, and the Western Area Power Administration (“WAPA”). WAPA said its evaluation of full RTO participation in the Western Interconnection includes its Upper Great Plains-West region, Colorado River Storage Project, and Rocky Mountain region. All those organizations except Colorado Springs Utilities have joined SPP’s WEIS, with CSU planning on joining the WEIS this year.

Neither CAISO nor SPP has yet introduced a formal proposal for a full western RTO, although SPP has an offering known as Markets+ that includes centralized day-ahead and real-time unit commitment and dispatch, transmission service, and other services for entities that don’t yet want to join a full RTO.

An additional effort toward western energy market expansion is the informal Western Markets Exploratory Group (“WMEG”), dedicated to exploring additional market efficiencies in the West. Xcel Energy-Colorado, Arizona Public Service, Black Hills Energy, Idaho Power, NV Energy, Inc., PacifiCorp, Platte River Power Authority, Portland General Electric, Puget Sound Energy, Salt River Project, Seattle City Light, and Tucson Electric Power are members of the group, which was created in October 2021.

According to a blog post by PacifiCorp, the WMEG is exploring the potential for a staged approach to new market services, including a day-ahead market, transmission system expansion, and other power supply and grid solutions. PacifiCorp said the effort aims “to identify market solutions that can help achieve carbon reduction goals while supporting reliable, affordable service for customers.” Many of the companies in the WMEG also participate in CAISO’s EIM, but the WMEG discussions will not affect participation in that market in the short term, since WMEG is a long-term initiative.

Another west-wide effort is the Western Resource Adequacy Program (“WRAP”), operated by the Northwest Power Pool. The WRAP seeks to increase reliability for western entities “while maintaining existing responsibilities for reliable operations and observing existing frameworks for planning, purchasing, and delivering energy”.2 The effort includes 26 market participants representing an estimated peak winter load of 65,122 MW and an estimated peak summer load of 66,768 MW across 10 states and one Canadian province.3

With so many efforts underway to coordinate planning and generation dispatch across the West, establishing a Western Interconnection-wide market seems inevitable. Such a complex process requiring so much coordination among Western entities will be a challenge, but with so much market development underway and federal support, the effort appears to be gaining serious momentum.

 

Want to be the first to read more stories like this? Subscribe to the Concentric Connection here.

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 Basin Electric Power Cooperative; Colorado Springs Utilities (effective August 2022); Deseret Power Electric Cooperative; Municipal Energy Agency of Nebraska; Tri-State Generation and Transmission Association; Western Area Power Administration (Upper Great Plains West, Rocky Mountain Region. Colorado River Storage Project); and Guzman Energy.

2 https://www.westernpowerpool.org/news/wpp-to-be-led-by-transmission-expert-sarah-edmonds

3 https://www.westernpowerpool.org/news/wrap-announces-full-participation-of-phase-3a

Concentric Celebrates Twenty Years of Energy, Service and Trust

Concentric Energy Advisors is pleased to announce that it is celebrating 20 years of client service.

After working together as REED Consulting Group, which was formed in 1988, the team evolved into Concentric Energy Advisors in 2002. Concentric has been a part of some of the most significant events affecting the energy and water industries and has conducted over 2200 projects for more than 750 clients.

Over its many years, Concentric’s focus has never wavered from providing economic and financial advisory services delivered by the most passionate, experienced, and dedicated consultants in the energy space.

“As I reflect on the last twenty years of our industry, I am amazed by all we have accomplished together,” said John J. Reed, Chairman and CEO. “We built on the values and success of REED Consulting Group and created a consultancy that has helped guide the energy industry through the enormous changes of the past two decades, and this anniversary is a testament to that success. We are now positioned and eager to continue our role on the forefront of change for many more years.”

Mr. Reed added that, “Our clients are the heart of our business, and we would not be celebrating today without them. On behalf of the entire Concentric team, thank you to our clients who have continued to entrust us with their projects. As we look forward, I am reminded of how much the energy landscape has changed and the extraordinary depth of experience we offer our clients. I am confident that through the commitment of our employees we will continue to advance our mission of energy, service, and trust.”

Learn more about employment opportunities and life at Concentric by visiting the careers page, and stay in touch by subscribing to the Concentric Connection.

Let Us Help You Drive Your EV Program

Do you need assistance assessing your Electric Vehicle (EV) program offerings?

We support the development of EV-specific rates, the design and implementation of EV incentive programs, and the overall evaluation of the EV market size and associated charging needs.

Below are summaries of a few of our specific EV-related capabilities:

Cost of Service Rate Design

Most states have, or are evaluating, the budgets required to implement EV programs, the recovery of associated costs, and other steps needed to initiate and implement EV programs for residential and commercial accounts.

Concentric has direct experience working with utilities on developing program budgets and providing regulatory support. We offer a team of experts on all ratemaking matters, including load analysis, revenue requirements, cost allocation, cost of capital, and rate design to help assure that program costs are recovered in a reasonable manner.

Charging Program Design

Regulators are now consistently requiring utilities to design and implement customer rebates approaching 100% of utility and customer make-ready capital costs. With early programs focused on residential and public-use charging fully implemented in many states, many regulators are now looking for ways to increase adoption in the medium-heavy duty (MHD) segment and through fleet conversions.

Concentric can help utilities determine the appropriate size of these MHD utility programs through detailed forecasting of vehicle charging requirements based on existing and forecasted vehicle registration data. This information is used to project charging infrastructure costs applicable to fleet operations.

Commercial Strategy

Some regulators are limiting the role of utilities in providing EV charging incentive programs, so utility holding companies have begun to explore direct investment in charging infrastructure through competitive affiliates. Evaluating such investments requires a detailed analysis of market potential, estimated charging revenues, capital requirements, and operations costs. As an illustration, because utility make-ready costs, electricity rates, and charging revenue potential are often highly site-specific, EV charging investments must be evaluated at the site level.

Concentric has performed such evaluations of EV charging investments, including developing multi-site screening tools and detailed costing proformas for specific sites, formulating site-host pricing structures, and projecting future electricity rates applicable to EV chargers.

Fleet Management

Utilities are finding that the role of the commercial account representative is expanding to include helping customers evaluate and manage fleet electrification. This enhanced role requires a detailed understanding of anticipated fleet operations (e.g., routes and mileage) and the charging needs of various types of vehicles under specific operating circumstances to determine the optimal charger configuration (e.g., DCFC at varying voltages versus Level 2 chargers).

Concentric has undertaken these analyses to assess the charging requirements to support medium and heavy-duty fleet operations at both depots and on-route charging requirements.

Concentric is uniquely able to support clients as they navigate the emerging opportunities and challenges of adding EV programs to their offerings. Please contact Michael Kagan to learn more about our EV services.

The Regulatory and Physical Climate is Transforming for Utility Return on Equity

Published: March 25, 2022

By: Concentric Staff Writer

The regulatory climate around utility return on equity (“ROE”) proceedings is rapidly changing amid a reconsideration of both near-term and longer-term industry risks. Factors affecting today’s regulatory environment include the continuing impact of the COVID-19 pandemic, extreme weather patterns, the clean-energy transition, inflation, and increasing concerns around cybersecurity, a roundtable of experts from Concentric Energy Advisors (“Concentric”) said in a recent interview session.

Concentric is involved with a variety of ROE proceedings at the state/province and federal level, including gas and electric distribution, electric transmission, oil and gas pipelines, and water infrastructure, both in the U.S. and Canada. A utility may have several types of ROE cases, including retail rate cases regulated by the local authority and transmission rate cases overseen by the Federal Energy Regulatory Commission, which sets ROE for transmission owners.

“At least in the rate cases that I participated in,” said Jennifer Nelson, an Assistant Vice President at Concentric, “there certainly was a strong position among intervenors and customers around the effects of COVID-19 and rate impacts to customers.” Nelson is an expert witness on cost of capital and alternative ratemaking proposals. Some utilities that had postponed rate cases in 2020 due to the COVID-19 pandemic rescheduled in 2021. Factors driving the average range of ROE include which utilities go in for a rate case in a given year, and the regulatory environment in the state or jurisdiction, she said.

The trend of declining interest rates for government bonds over the past 15-20 years is another factor in utility rate cases, according to John Trogonoski, also an Assistant Vice President at Concentric and former commission staffer. Trogonoski has filed expert testimony for U.S. and Canadian utilities on return on equity and performs risk analysis for Canadian and U.S. utilities, including reviewing peer groups to study relative risks and regulatory protections that help to mitigate those risks. Two decades ago, 30-year treasury bonds yielded about 6 percent, but they are now about 2.5 percent, Trogonoski said during the discussion. Treasury bond rates are often used in calculating ROE, plus a risk premium.

“That’s one of the factors that gets taken into account in the models that we use to estimate the ROE for a utility,” he said of government bond yields. “It’s not the only factor, but it’s an important factor, and it’s one that’s easy for utility commissioners to look at and digest.” Commissioners want to know if treasury bond yields are declining, why a utility’s bond ROE wouldn’t also decrease, he said, adding that there are reasons why there isn’t always a direct relationship between the two.

The impact of climate change is another risk factor that is increasingly being considered in utility ROE cases, according to Jim Coyne, a Senior Vice President and Board Member at Concentric who regularly testifies in utility rate cases and cost-of-capital proceedings. “We’re seeing the nature of the discussion surrounding utility rate cases has shifted significantly in the last several years to include discussions around new risks to the utility industry,” including wildfires in the West and natural disasters in areas such as the Southeast and Florida, Coyne said.

The rating agencies and equity investors are keeping a close eye on these risks and “they are becoming a more important part of the dialogues about what is the appropriate cost of capital for utilities. Most regulators are not at the point of making specific ROE adjustments based on these risks, depending on the progressiveness of a particular jurisdiction. But all parties are beginning to understand that they need to be considered because they affect access to capital and cost of capital,” Coyne said.

Gas utilities are also facing a public policy environment with strong carbon reduction goals as early as 2030, and states with stronger environmental mandates understand that those policies have some impact on gas utilities.

“I’d say we’re at the early stages of that dialogue,” Coyne said, as regulators are just beginning to understand these climate impacts.

“ESG and sustainability are becoming a bigger part of the dialogue,” said Lisa Quilici, a Senior Vice President and Board Member at Concentric. Quilici has expertise in M&A, regulatory analysis, policy formation, and resource planning. There is a growing sensitivity to those issues, she said.

“These are big issues that are having a holistic effect on the industry,” Quilici said, adding that holistic considerations are very important to looking at ROE recommendations and benchmarking. There is a balancing act that takes place when formulating an ROE recommendation driven by sound analytics and methodological results, she said.

In 2019, a California electric and gas utility was trying to decompose the specific cost of wildfires in a cost of capital proceeding, according to Coyne, which required looking at other risk-exposed sectors such as oil and gas companies and what types of returns their investors require. There is a huge risk-return tradeoff with exposure to new downsides that are difficult to quantify, he said.

Insurance premiums also help estimate the premium on the cost of capital and the cost of risk-reduction through those insurance premiums, Coyne said. California regulators recently found that a risk premium was not justified in a utility proceeding but approved an ROE at the upper end of the scale to account for these risks.

There is an expectation among debt and equity investors that the commission will provide reasonable rate recovery of prudent plans to mitigate and address issues that occur as a result of extreme weather, Quilici said. Climate change is similar to other adjustment mechanisms that, a decade ago, were just starting to be considered and were uncommon, but over time were embraced as part of the normal course of business, she said.

Utilities are also planning more than ever for wholesale changes to their generation mix, such as bringing on large amounts of renewables to replace fossil-based generation, Coyne said. New methods of generation require significant investments due to a growing number of proposals to build renewables and more directives from the state level to retire fossil-fuel assets.

Renewables integration is also leading to new levels of cooperation between players that were previously more adversarial, Coyne said.

“We’re seeing a bit of an alliance between environmental groups that want those investments made, utilities that want to make the investments, and ratepayer advocates that understand customers need to be protected by ensuring utilities can make investments in a way that is acceptable to them from a rate perspective,” Coyne said. There is also more agreement around retiring assets earlier than planned and negotiation in these matters in the regulatory process, usually through settlements.

Utilities are facing many of the same issues other sectors are facing when it comes to COVID-19, such as supply chain issues and labor shortages. Interest rates and inflation are also increasing and causing more frequent rate cases, according to Coyne.

“I think utilities and regulators, for the most part don’t like more frequent rate cases,” because of the time and resources involved, he said. There will be more multi-year rate cases and certain costs will be indexed between rate cases to help manage those risks, he said.

There have always been technological risks with generation assets, but policy risk is also rising in terms of these assets. Generation carries more risk than transmission and distribution, as utilities move into compliance with federal, state, and corporate emissions-reductions plans.

Cybersecurity is also increasing costs, with regulators seeming to understand these are reasonable expenses and part of the modern ROE environment. But cybersecurity is not yet a central item in ROE proceedings, according to Coyne.

On the issue of formula-based rate determinations, some commissions rely on formulas to set rates. Despite the benefits of a formulaic approach in rate cases, “in general it hasn’t worked that well,” Coyne said. The formulas are often tied to government or utility bond yields, but government bond yields have decreased while equity costs have moved in a different direction. The federal government’s stimulus policies and Federal Reserve policies have driven interest rates lower.

It is no longer the case that one can easily predict the movement in a utility’s equity costs using a government or utility bond yield, Coyne said. Since 2009 the Canadian province of Ontario has used an approach including government bond yields and a spread between utility bonds and government bonds that has worked pretty well, with limitations, he said.

The political make up of an agency such as FERC and/or what kind of administration is in the White House are also factors in federally regulated ROE. Incentives and policies put in place years ago have promoted greater infrastructure investment such as electric transmission lines.

But there has been an evolution of a movement among ratepayer advocates that argue on a consistent basis that FERC should revisit some of the policies and evaluate whether they are too generous, Coyne said. There is a chance that investors will pull back from transmission investment because of incentives being reduced, but so far, that has not been prevalent.

“FERC’s policies by and large seem successful for promoting an environment for infrastructure investments,” Coyne said.

In February, FERC revised its policies for considering proposed natural gas infrastructure, expanding consideration of economic and environmental impacts, including greenhouse gas emissions. The policy statement covers infrastructure such as interstate pipelines and liquefied natural gas terminals. Proposed projects with greenhouse gas emissions of 100,000 metric tons annually or higher will now require an environmental impact statement.

The policy statement is part of an ongoing shift at the federal and state level where it is more difficult to build new infrastructure, especially on the gas pipeline and gas distribution side, Coyne said.

“It sends a signal to investors that these projects are more difficult to get built, and the inevitable result is increased cost of capital for infrastructure investment,” Coyne said, adding this is not yet a well-understood or well-litigated factor in cost of capital. Required returns and equity ratios need to edge up to provide ongoing capital, he added.

With so many new factors in play, utility ROE cases are only becoming more complex. A changing and evolving world requires constant change, however gradual, in determining a utility’s costs and what is a fair return on its investments.

To learn more about Concentric’s ROE services and meet our team of ROE experts, please click here.

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.

Concentric Announces the Appointment of Michael Kagan to the Board of Directors

Concentric is proud to announce the appointment of Michael Kagan, Senior Vice President, to the Board of Directors.  

Mr. Kagan joined Concentric in 2013 and has more than 26 years of experience in management roles and consulting to utilities, independent power producers, large energy users, retail energy suppliers and infrastructure investors. His recent consulting work has included investment due diligence, litigation support, and regulatory and commercial strategy with a particularly focus on the renewables and electric vehicle space. 

“I am proud to welcome Michael to the Board of Directors,” said John J. Reed, Chairman of the Board and Chief Executive Officer of Concentric. “Michael brings diverse expertise and insight, and he has demonstrated an exceptional commitment to serving our clients. I look forward to his continued leadership.”  

Prior to joining Concentric, Michael served in a variety of leadership roles with Constellation, Exelon and AES Corp. including as president of Constellation NewEnergy. He has also been an adjunct professor at the George Washington School of Business. 

Mr. Kagan earned an M.A. in economics from the University of California, Santa Barbara and an undergraduate degree in economics and business from Skidmore College.

December Storms Ease Crippling Drought that Hindered Hydroelectric Output in 2021

Published: January 14, 2022

By: Concentric Staff Writer

A December storm that brought a deluge of rain and snow to the western U.S. coast rang out a year of intense drought that had hydroelectric project reservoir levels plummeting to alarming lows, illustrating the complex relationship between weather and energy output in all regions.

The close-out of December and the end of 2021 brought much-needed precipitation, particularly to the Sierra Nevada and the Pacific Northwest, which is heavy with hydroelectric generation. But California’s water agency warned that the La Niña season storm is not quite enough to ease concerns about drought in 2022. The California Department of Water Resources’ (“CADWR”) first snow survey of the winter season at Phillips Station west of Lake Tahoe on Dec. 30 showed 78.5 inches of snow depth and a snow water equivalent of 20 inches, which is 202 percent of average for that location on that date.

“We could not have asked for a better December in terms of Sierra snow and rain,” CADWR Director Karla Nemeth said in a Dec. 30 written statement. “But Californians need to be aware that even these big storms may not refill our major reservoirs during the next few months. We need more storms and average temperatures this winter and spring, and we can’t be sure it’s coming. So, it’s important that we continue to do our part to keep conserving – we will need that water this summer.”

The U.S. Drought Monitor said on Dec. 30 that the heavy December precipitation, snow water equivalent numbers (the amount of water if the snowpack melted all at once), and Standardized Precipitation Index figures point to large improvements in the drought for California, parts of Nevada, and Utah. Precipitation between Dec. 21-27 exceeded two inches liquid-equivalent across much of California and western parts of Oregon and Washington state. Temperatures in that period were also below normal across California and the Pacific Northwest, and a more favorable snowpack was building from the Cascades to the Sierra Nevada.

Energy GPS noted on Dec. 30 that the current weather pattern is bringing cooler temperatures across the Midwest, East, and South-Central regions going into 2022. This will increase the marginal cost of energy in those regions, but there are no signs that a similar situation exists to February 2021, when Winter Storm Uri propelled drastic increases in natural gas and electricity prices and led to widespread grid outages, human suffering, and fatalities in the Electric Reliability Council of Texas region.1

However, in the East, the Drought Monitor’s Dec. 30 assessment showed declining soil moisture and an expansion of moderate drought across eastern West Virginia. Abnormal dryness persisted across the northern Mid-Atlantic, where 60-day precipitation deficits range from 2 to 6 inches. Moderate drought also expanded in northern and western parts of Virginia, with short-term precipitation deficits, and there was an expansion of dry conditions across parts of Alabama, Georgia, and the Florida Panhandle.

Experts say that despite the stormy December, it will take an exceptional water year to beat back the devasting drought of 2021, which brought many hydroelectric reservoirs to critically low capacity. For example, low reservoir levels at the 646-MW Edwards Hyatt Power Plant at Lake Oroville, California, caused the hydro plant to shut down in August for the first time since it began operating in 1969. After the storms, the plant resumed operation on Jan. 1, 2022. Over the summer, power production also dropped heavily at Lake Shasta in California’s Central Valley and at the 2000-MW Hoover Dam on the Colorado River.

At the peak of summer, 100 percent of California was experiencing some degree of drought, the snowpack was severely below normal, and melting water from the snowpack often didn’t reach western reservoirs, according to the U.S. Energy Information Administration (“EIA”). EIA expects that data from 2021 will show it was a lower year for hydroelectric output, which was down by 37 percent in the first four months of the year compared with 2020, and 71 percent lower than the same period in 2019. EIA projects that hydroelectric output in California will be down by 19 percent over the entire year from 2020, decreasing from 16.8 million MWh in 2020 to 13.6 million MWh in 2021.

The reduced hydropower output offset an increase in solar and wind generating capacity nationally. This effect put the share of all renewables in the U.S. electricity capacity at about 20 percent in 2021, about the same level as 2020 despite the addition of new renewable projects, EIA said. National renewables output is expected to be about 22 percent of U.S. electricity generation in 2022.

As of Dec. 15, before a strong surge of rainfall caused by the La Niña season, the snow-water equivalent was at 18 percent of the April 1 average and 73 percent of a normal read for the Dec. 15 date. The Central Sierra’s snow-water equivalent was at 87 percent of normal for the Dec. 15 date, and the Southern Sierra was at 97 percent of normal for that date, according to CADWR.

The Drought Monitor reported that dry winter seasons in 2020 and 2021 have created concerns about the Sierra Nevada snowpack, which serves as the “blood supply” for the state’s water system. CADWR announced Dec. 1 that the “initial water allocation” to state water contractors would be at zero percent for the first time. For comparison, the initial allocation in 2020 was 10 percent, and the final allocation in May was 20 percent.

But strong snowfall was predicted for the remainder of the year in the Sierra Nevada, the Cascades in southern British Columbia and the Pacific Northwest, the Great Basin—which includes the Great Salt Lake, Pyramid Lake, and the Humboldt Sink—and the 3000-mile Rocky Mountains that stretch from western Canada to New Mexico.

This will replenish hydroelectric reservoirs that serve Pacific Northwest utilities and electric grids as far away as Arizona, which imports a good portion of Northwest hydropower.

But even as the West shows signs of recovery, drought was still prevalent as 2021 closed out, although precipitation had improved. As of Jan. 4, two to locally six inches of precipitation was reported from the Cascades westward to the West Coast in the Pacific Northwest and parts of California, “further reducing dryness and drought in areas where such conditions have already been removed,” the Drought Monitor said. Some areas in California received more precipitation in the past three months than they had in the prior 12 months, the agency said.

The surge in rain and snow in December shows that weather systems work in cyclical ways, but the impact of drought on power production and water allocations for agriculture and other activities serious. However, for the time being, it seems that the parched soil in the West and throughout the country is beginning to experience some relief.

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 Subscriber-only content: https://www.energygps.com/Newsletter/b/Newsletter-Opposite-End-of-the-Spectrum-2060038

Newsletter Sign Up
 
Search
 
Follow

 

Contact Concentric using the form below

  • Accepted file types: pdf, doc, xls, Max. file size: 50 MB.
    Attach File (.PDF, .XLS or .DOC only)