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

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.

New Transmission can Provide a Path for Renewables, but Hurdles are Significant

Published: October 25, 2021

By: Concentric Staff Writer

There is growing recognition among policy makers, industry, and environmental groups that more electric transmission lines will be needed across the United States to achieve the buildout of renewable energy infrastructure required to meet climate change goals.

The federal government along with states recently moved forward with major new efforts to build transmission infrastructure, but these initiatives have many hurdles that could cause them to sputter, as was the fate of previous attempts by the federal government to take more control over transmission siting.

The Federal Energy Regulatory Commission (FERC) took a major step toward reforming transmission planning, recently closing out its comment period from industry, state regulators, regional market officials, and others on its advance notice of proposed rulemaking (ANOPR) issued in July. The FERC proceeding, “Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection” will update FERC’s well-known Order No. 1000 on transmission and cost allocation by utilities, issued by the Commission in 2011.

“The electricity sector is transforming as the generation fleet shifts from resources located close to population centers toward resources, including renewables, that may often be located far from load centers,” FERC staff said in a presentation on the ANOPR. “The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources are creating new demands on the transmission system.” The Commission added that the priority in regional transmission planning is ensuring just and reasonable rates and maintaining reliability as the resource mix shifts to more renewables.

One prominent group, the Electric Power Supply Association (EPSA), which is the national trade association representing competitive power suppliers, told FERC in its filed comments that it is critical “that any reforms to transmission policies leverage the Commission’s commitment to competition to ensure that cost-effective transmission investments are signaled and supported by planning, cost allocation, and/or interconnection processes, including the use of competitive procurement processes. FERC’s previous landmark orders on transmission issues under its authority have been successful by ensuring that non-discriminatory open access transmission service supports and promotes competitive power markets.”

There was also a major new effort on state-federal cooperation for transmission planning in June: FERC’s creation of the Federal-State Task Force on Electric Transmission. The task force will hold its first meeting Nov. 10 in Louisville, Kentucky, a location and date chosen to coincide with an annual meeting of state regulators from around the country. FERC said this is the first in a series of such meetings, and an agenda will be issued Oct. 27. FERC recently selected 10 state regulators to the task force that were nominated by the National Association of Utility Regulatory Commissioners (NARUC).1

FERC is accepting agenda topics for the November meeting from interested parties (AD21-15). FERC notes that the development of new transmission infrastructure raises a host of issues, representing an area ripe for federal-state coordination and exploration by the task force.

The goal of the task force is to identify barriers to the planning and development of new transmission in order to facilitate achievement of state and federal policy goals such as renewable portfolio standards. The task force will also explore ways for states to use FERC-jurisdictional planning processes to achieve state policy goals. It will examine methods for states to voluntarily coordinate to develop regional transmission solutions and identify possible reforms to FERC regulations regarding planning and cost allocation of transmission projects.  Additionally, the task force will examine ways to connect resources more quickly to the electric grid and make transmission more cost-effective through enhanced state and federal coordination.

A large-scale effort by the federal government aimed at developing new transmission infrastructure ran aground more than 15 years ago, illustrating the tremendous difficulties in siting massive new transmission facilities, including state and local opposition. The U.S. Congress gave the Department of Energy (DOE) the authority to create “National Interest Transmission Corridors” in the Energy Policy Act of 2005. The legislation gave the DOE power of eminent domain to purchase property needed to build transmission if state and local government failed to issue permits.

But the effort received pushback from state and local governments, and ultimately the designation of two corridors in the Mid-Atlantic and Southwest in 2007 and a congestion study done by DOE in 2006 were vacated by the U.S. Ninth Circuit Court of Appeals in California after a lawsuit by the Wilderness Coalition against DOE. The court ruled that DOE had not adequately consulted with states and had not considered environmental impacts.

Any new effort by FERC could run up against the same opposition from some states. For instance, Arizona Corporation Commission Chairwoman Lea Márquez Peterson wrote to the U.S. Congress in July, expressing concern over a similar national-interest transmission corridor designation within the federal infrastructure bill. She objected to any involuntary regionalization of the Western electricity grid, pointing to blackouts in California last year and in Texas earlier this year.

“Taking the opportunity to provide direct public engagement and involvement in the process away from Arizona’s local leaders and residents, in order to send it to federal bureaucrats in Washington, DC, would only exacerbate the objections that communities already have for the siting of transmission lines,” Márquez Peterson said in the letter. “It’s hard enough to convince citizens to support transmission lines through their communities when the siting process takes place locally, let alone to convince them to support a project that will be heard and decided in Washington, DC.”

The federal-state power struggle is as old as the United States itself, and modern transmission-system planning is no different, leaving the federal government with a challenging path ahead to get more transmission built and move renewable energy around the country.

For inquiries related to this article, please contact info@ceadvisors.com.

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 task force includes the four current members of FERC—Chairman Richard Glick, Allison Clements, James Danly and Mark Christie—as well as the 10 state commissioners nominated by NARUC earlier this year. The task force is chaired by Glick, with two state commissioners appointed to five different regional conferences: Mid-Atlantic; Mid-American; New England; Southeastern and Western. State commissioners on the task force include Gladys Brown Dutrieuille, Chair of the Pennsylvania Public Utility Commission; Jason Stanek, chair of the Maryland Public Service Commission; Andrew French, chair of the Kansas Corporation Commission; Dan Scripps, chair of the Michigan Public Service Commission; Riley Allen, chair of the Vermont Public Utility Commission; Matthew Nelson, chair of the Massachusetts Department of Public Utilities; Kimberly Duffley, chair of the North Carolina Utilities Commission; Ted Thomas,  chair of the Arkansas Public Service Commission; Kristine Raper, chair of the Idaho Public Utilities Commission and Clifford Rechtschaffen, a member of the California Public Utilities Commission.

Global Natural Gas Crunch Drives up Prices, U.S. Exports

Published: October 13, 2021

By: Concentric Staff Writer

A global supply crunch for natural gas and extremely high prices are rapidly changing market dynamics, causing food shortages and energy company failures in Europe and adding to a complicated energy picture in China, while the United States heavily increases its exports of the resource as domestic usage drops.

U.S. exports of liquified natural gas (“LNG”) are set to grow as demand ahead of winter is strong from Asia. China has experienced recent power outages and government curtailing of electricity during cold weather periods due to high prices for natural gas and coal. Europe is seeing extreme natural gas price spikes in its wholesale market, with a record high price of 155 Euros ($179) per MWh on Oct. 6  at the benchmark Dutch TTF hub.

According to the U.S. Energy Information Administration (“EIA”), U.S. exports of liquefied natural gas continued to grow in the first six months of this year, averaging 9.6 billion cubic feet per day. This is an increase of 42 percent, or 2.8 Bcf/d, from the same period in 2020. This increase illustrates a pattern of continued volatility from last summer, when U.S. LNG exports fell to record lows, but then rose to consecutive record highs in November and December 2020.

A colder-than-normal winter led to low LNG inventories in Asia and the U.K., pushing up demand for U.S.-sourced gas as prices at the benchmark Henry Hub in the U.S. fell below prices for international gas and LNG, EIA said.

“Similar to 2020, Asia remained the top destination for U.S. LNG exports from January through May in 2021, accounting for 46% of the total,” EIA said in a recent Today in Energy report. “Asia was followed by Europe, which had a five-month average share of 37%. Exports to Latin America also increased, particularly to Brazil, which is experiencing its worst drought in more than 90 years.”

According to the CEO of Russian gas company Gazprom, Alexey Miller, the Chinese gas market “is the most dynamic and fast-growing one, and it shows simply unbelievable consumption growth rates every year. “ Miller made his comments Sept. 20 at the General Meeting of International Business Congress in St. Petersburg.

According to Miller, in the first half of this year, Chinese gas consumption increased by 15.5 percent and imports swelled by 23.8 percent compared with the previous year. By the end of this year, consumption in China is expected to be 360 billion cubic meters and the volume of imports to be 160 billion cubic meters. Consumption in the Asia-Pacific region is expected to grow by 1.5 trillion cubic meters, 60 percent of which will be imported, he said.

In the United Kingdom, shortages of natural gas are leading to food shortages—beef and pork—as New York-based company CF Industries shut down fertilizer plants in Northern England. Natural gas is used in animal slaughtering, the production of chilled and baked goods, and carbonated drinks, according to the British Meat Processors Association.

The constrained market is also creating concerns in the U.S. On Sept. 17, Industrial Energy Consumers of America, a trade group for industrial energy customers, wrote to U.S. Energy Secretary Jennifer Granholm, urging her to take action under the Natural Gas Act (“NGA”) to prevent a supply crisis and price spikes for U.S. consumers by requiring LNG exporters to reduce export rates so U.S. inventories can reach 5-year average storage levels.

“U.S. consumers, the health of the economy, and national security should take priority over LNG export profits,” the IECA letter says. “Secondly, we urge you to place a hold on all existing, pending, and prefiling permits and approvals on LNG export facilities in the lower 48, and conduct a review of whether these facilities are in the public interest under the NGA. We are certain that they are not.”

The U.S. winter strip natural gas price at the benchmark Henry Hub recently hit $5.50/MMBtu, more than double from a year ago, according to the letter. It cites EIA data that working natural gas stocks are around 3,006 Bcf, 17 percent lower than a year ago and 7 percent lower than the five-year average. The U.S. would need to inject more than 90 Bcf/week to hit the five-year average by November, a rate more than 40 percent higher than the current average weekly build-up. Rising natural gas prices also push up the price of natural gas liquids, a feedstock raw material for plastics and chemical production which is vital to the supply chain for thousands of products, adding to inflation, the group said.

Another factor driving up exports is decreased usage of natural gas in the U.S. for power generation. EIA, in a recent Short-Term Energy Outlook (STEO), said it expects gas consumption levels to decrease in 2021 and 2022 from 2020 levels.

“We expect U.S. natural gas consumption in 2022 to increase slightly from 2021 to 82.6 Bcf/d as increasing consumption in the industrial sector offsets declining consumption in the electric power sector, though total 2022 consumption still remains lower than the 2020 level,” EIA said in the STEO.

When natural gas prices are high in the U.S., utilities typically switch to lower-cost coal, EIA said, noting that higher prices at Henry Hub in the first half of this year pushed down gas usage in the sector compared with the same period last year. EIA expects the Henry Hub price to average $3.63/MMBtu this year, which is more than $1.60/MMBtu above than the 2020 average. This will drive a decline in gas consumption by the U.S. electric power sector of 2.7 Bcf/d or 8.3 percent from last year, driven by high Henry Hub prices and competition from renewable energy resources. EIA expects natural gas consumption in the U.S. industrial sector to increase next year to 23.8 Bcf/d from an average of 23.2 Bcf/d this year.

In China, pipeline and LNG imports in January-August were 79.3mn metric tons, a 22% jump from the same period last year, according to data from China’s customs department. The country imported 10.44mn mt of gas in August, up almost 12 percent from the previous year. Widespread power outages are being reported in early October in households, businesses and factories in China, with supplies tight and prices high.

Global supply chain issues are also affecting energy dynamics, with reported long lines for petrol in the U.K. and British troops on standby to deliver fuel amid a driver shortage, according to the BBC. According to press reports, there is fuel at refineries and ports but not petrol stations.

These trends illustrate how supply and demand dynamics in one country or region drive those in other regions and demonstrate the tightly woven relationship between energy resources in the U.S. and the rest of the world.

For inquiries related to this article, please contact info@ceadvisors.com.

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.

The Storm Is Over: What Happens Next? – Part 3

Published: March 24, 2021

Contributors: Ruben Moreno, Bob Yardley, Jim Coyne, Dan Dane, Danielle Powers, Forrest Small, John Stewart, and Mark Cattrell

This content is the third installment of a three-part series examining the aftermath of the historic winter weather events in February 2021.

In this third installment, we will provide an update on the financial consequences of the February winter storm. These consequences include bankruptcies and lawsuits, and financial impacts for electric utilities, natural gas utilities, and their customers. Investigations by federal and state regulators are under way, with pressure being applied by elected officials including Senators, Governors, and Mayors.

Several more utilities have disclosed extraordinary increases in electricity or natural gas costs, with the impact stretching from Texas and Colorado to several midwestern states including Oklahoma, Kansas, Missouri, Minnesota, and Iowa. Natural gas prices rose to unprecedented levels for five or more days resulting in several utilities reporting gas purchase costs for February that exceeded annual purchases in 2020.

For utilities and states that rely on natural gas as a fuel for electric generation, the bill impacts also extend to electricity customers. Texas’ electricity customers were uniquely impacted by service interruptions and high electricity prices because of well-documented issues within its single-state wholesale electricity market.

Texas also remains the epicenter of political activity. The last of three Commissioners appointed by Governor Abbott has been asked to resign.1 The discussion regarding the repricing of energy, ancillaries, winterization, and unaccounted for energy (“UFE”) in Texas continues.

There is a flurry of legislative activity, including a bill passed by the Texas Senate that supports the repricing of ERCOT market electricity over a 32-hour period, setting a deadline of March 20th for the Public Utility Commission of Texas (“PUCT”).2 The Lieutenant Governor has lent his support for this deadline. However, the House of Representatives is holding firm against repricing for the moment, with the Speaker referring to the bill as, “an extraordinary intervention into the free market.”3

Three energy retailers with operations in Texas and the largest generation and transmission cooperative in the country have declared bankruptcy.

As credit requirements and the cost of credit to support retail operations increase, more retail energy providers will likely suffer. Several utilities are looking for ways to finance and securitize debt to cover these charges10 without impacting credit ratings. According to its SEC filing of March 9th, Atmos Energy Corp. completed a public offering of $1.1 billion of its 0.625% senior notes due 2023 and $1.1 billion of its floating rate senior notes due 2023.11 It is expected that the company will use these proceeds to finance about $2.5 billion of natural gas purchased during the February 14th weekend.12

Texas is now entering the litigation phase. San Antonio’s mayor has expressed support for a lawsuit against ERCOT filed by CPS Energy, San Antonio’s large municipal utility. Regardless of the eventual sharing of gains and losses, the financial effects will be permanent for retailers that have gone bankrupt, and long-lasting for utilities that have been forced to take on more debt. As in all the affected states, Texas regulators must sort through the financial impacts as expediently as possible. The first step will be restoring public and market participant confidence in the PUCT and ERCOT.

Utility regulators in several other states have opened dockets to deal with the immediate financial issues and investigate the planning and performance of their electric and gas utilities. Some of these states experienced natural gas prices that exceeded $500/MMBtu and rose as high as $1,000/MMBtu during the mid-February cold snap.

In contrast to Texas, most utilities were able to maintain service to their customers throughout the period. The Southwest Power Pool’s Integrated Market experienced an all-time high day-ahead price of $4,274/MWh on February 15th, as compared to a 2020 average price of $17.81/MWh.13

Based on a review of commission documents, the main topics of interest relate to prudence, cost recovery, rate increases, and communications (Figure 1). The size of the text in the Word Cloud represents the frequency by which the topic is mentioned.

Figure 1: Word Cloud of Topics of Interest to the PUCs in Affected States

Source: Concentric based on PUC discussions in CO, MO, IA, OK, NM, MN, IL, KS, TX, and TN.

The regulatory approaches vary from state to state, reflecting distinct regulatory practices and philosophies as well as the respective impact of the storm in their jurisdiction. The following brief overview reveals these differences. Kansas and Colorado were early movers.

 

Meanwhile, the federal inquiries have begun. The Federal Energy Regulatory Commission (“FERC”) and the North American Electric Reliability Corporation (“NERC”) opened a joint inquiry into the operations of the bulk-power system during extreme weather conditions.16

The U.S. Senate held a hearing on March 11th on the reliability, resilience and affordability of the nation’s electric grid and discussed how resource-diverse and complex power grids pose challenges across the country. During this hearing, NERC’s President and CEO indicated that industry and policymakers must consider more investment in transmission and natural gas infrastructure to accommodate the growing share of U.S. generation from intermittent wind and solar energy.17

The authors expect that many lessons learned and associated policy and rule changes will result from the state and federal investigations. It is fair to say, and reasonable to expect, that utilities will face new planning and reporting requirements at a minimum when all is said and done. The Texas/ERCOT situation will be most interesting to see if there will be structural and governance changes related to the retail and wholesale markets, and the integration of natural gas and electricity markets.

More from Concentric:

The Storm Is Over: What Happens Next? – Part 1

The Storm Is Over: What Happens Next? – Part 2

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 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 March 16, 2021 Texas Tribune Article.

2 Senate Bill 2142 passed with a 27-3 vote. https://www.statesman.com/story/news/2021/03/15/bill-filed-texas-senate-could-undo-billions-ercot-overcharges/4701598001/

3 Financial Times, “Power producer NRG’s profit outlook wiped out by Texas storm”, March 17, 2021. The article also reports that market participants have defaulted on $3.1 billion in electricity purchases.

4 Brazos Electric Cooperative serves more than 1.5 million retail customers in Southern Texas. http://www.brazoselectric.com/pressrelease.pdf

5 https://finance.yahoo.com/news/just-energy-seeks-bankruptcy-texas-162232824.html

6 https://finance.yahoo.com/news/1-just-energy-voluntarily-delist-120610775.html

7 https://cases.stretto.com/Griddy

8 https://www.houstonchronicle.com/business/energy/article/More-power-companies-booted-from-the-market-after-16022459.php

9 https://www.electricchoice.com/blog/pjm-entrust-energy-default/

10 https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/gas-utilities-face-multibillion-dollar-financing-needs-after-storm-price-surge-62790289

11 https://www.sec.gov/ix?doc=/Archives/edgar/data/731802/000119312521074937/d56742d8k.htm

12 https://www.everythinglubbock.com/news/local-news/atmos-energy-talks-bill-prices-after-incurring-2-5-billion-in-winter-storm/

13 Staff Report, Appendix A to March 1, 2021 Order in Docket No. 21-GIMX-303-MIS.

14 KCC, Order dated February 15, 2021 in Docket No. 21-GIMX-303-MIS.

15 Iowa Utilities Board press release, March 12, 2021.

16 https://www.ferc.gov/news-events/news/ferc-nerc-open-joint-inquiry-2021-cold-weather-grid-operations

17 https://www.c-span.org/video/?509678-1/senate-energy-committee-hearing-electric-grid-reliability

 

The Storm Is Over: What Happens Next? – Part 2

Published: March 12, 2021

Contributors: Ruben Moreno, Jim Coyne, Bob Yardley, Dan Dane, Danielle Powers, Forrest Small, John Stewart, and Mark Cattrell

In Part 1 of this series, we discussed the urgent financial challenges facing energy regulators in Texas, Colorado, Oklahoma, and Minnesota as customers are confronted by the prospect of high electricity and natural gas bills now that power has been restored. Wholesale costs of electricity in ERCOT were $50.6 billion over a 3-day period, compared to $4.2 billion for a seven-day period ending immediately before the crisis began. We also noted the financial challenges facing utilities and retail suppliers that purchase electricity and natural gas in wholesale markets to serve their customers.1

The outcry and calls for investigations from elected officials have been swift, leading to the resignations of the ERCOT CEO and several Board members, and two commissioners serving on the Public Utilities Commission of Texas (PUCT), including the Chair. Regulators in the most affected states are under tremendous pressure to either unwind transactions or adopt “cost-sharing” solutions. In an upcoming installment (Part 3), we will return to the urgent financial challenges and provide an update, focusing on the actions by utility regulators.

In this installment, we will focus on the role of regulation in addressing the resilience of energy infrastructure and mitigating the consequences of extreme weather events.2 Resilience has received more attention over the past decade as the frequency and consequences of major events have increased.

It is apparent that electricity and natural gas infrastructure did not perform as expected during the February storm. In response, the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) have initiated a joint investigation that will examine the impacts of the 2021 winter storm on grid performance and reliability issues.3 The FERC also closed a controversial 2018 inquiry into resilience that focused on the contribution of coal and nuclear power, signaling its intent to take a fresh look at the resilience of the electric power grid.4

The contributors anticipate that resilience will become the focus of legislative and regulatory attention in most states. That said, addressing resilience presents unique challenges to distribution utilities and state regulators. Three main challenges need to be addressed to enhance the resilience of energy infrastructure, detailed below. We will use the electric industry as our example.

Regulatory Response: The Value of Resilience

The value of resilience as a distinct goal of regulation begins with understanding the difference between “reliability” and “resilience.” These distinctions are significant from a regulatory perspective.

Establishing the value of resilience is also important for regulators that prefer to rely on Benefit-Cost-Analyses (BCAs) to inform investment decisions. BCAs are increasingly relied upon as tools that can evaluate investments that produce environmental benefits.

Regulatory Response: Infrastructure Planning

Regulators are increasing their attention on transmission and distribution planning processes, with encouragement from environmental organizations and other stakeholders. New York, as one example, requires electric utilities to file Distributed System Implementation Plans (DSIP) every two years that describe the actions that they are taking to enhance their forecasting and planning processes. This provides regulators and other stakeholders insight into how investment decisions are made before the utility seeks cost recovery for specific investments in a rate case.

Distribution system planning is a resource intensive process that relies on sophisticated planning models. Areas of the network and specific circuits that have been experiencing performance issues are the subject of detailed studies. Increasing the importance of resilience as a regulatory goal (along with reliability and integration of distributed resources) will impact infrastructure planning and recommended actions. Most potential investments address multiple objectives (e.g., the reconfiguration and automation of a circuit). Thus, investments to address resilience are assessed as part of an integrated exercise that delivers the most value to customers relative to cost.

It may also be appropriate for regulators to request, review, and compare materials standards that utilities apply when purchasing poles, wires, and other equipment. These standards serve an important role in enhancing resilience.

Regulatory Response: Investment Decisions

A third regulatory challenge relates to deciding which investments to make each year, given that enhancing resilience will require investments made over several years. Regulators are accustomed to balancing the need for investment with rate impacts. Investment decisions that enhance resilience and reliability are particularly challenging for the utility and regulators because they require prioritization among competing constituencies. For example, should urban areas serving large populations be prioritized over rural areas?

In summary, there is a growing consensus that resilience is an important regulatory goal and recognition that it will require infrastructure investments. However, deciding how much to spend and where to direct investments will present some unique challenges for both utilities and regulators.

More from Concentric:

The Storm Is Over: What Happens Next? – Part 1

The Storm Is Over: What Happens Next? – Part 3

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 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 Customers that have elected fixed price electricity options may be protected, with their retail suppliers bearing the risk of spiking wholesale prices.

2 Legislators may also decide to take action, providing direction to regulatory agencies or expanding their authority if necessary.

3 https://www.tdworld.com/smart-utility/outage-management/article/21155438/ferc-nerc-to-open-joint-inquiry-into-2021-cold-weather-grid-operations. See also reporting in the March 4, 2021 issue of the Foster Report.

4 https://www.jdsupra.com/legalnews/ferc-sustains-prior-termination-of-grid-4717692/

5 DOE has been working on developing a resilience metric that can be applied broadly. See https://gmlc.doe.gov/sites/default/files/resources/GMLC1.1_Vol3_Resilience.pdf

The Storm Is Over: What Happens Next? – Part 1

Published on: March 5, 2021

Contributors: Ruben Moreno, Jim Coyne, Bob Yardley, Dan Dane, Danielle Powers, Forrest Small, John Stewart, and Mark Cattrell

Customers in several states, including Texas, Colorado, Oklahoma, and Minnesota, are facing the prospect of unprecedented levels of electricity and natural gas bills.

Utilities that rely on wholesale markets to purchase electricity and natural gas are required to pay for supplies each week (electricity) or each month (natural gas). These bills are coming due, creating a financial emergency for many utilities. State regulators have two equally challenging and important responsibilities:

This article deals with the immediate challenges facing customers, utilities, and state regulators.3

What Happened: At a Glance

Focusing on Texas first, a severe winter storm hit over the weekend of February 14th delivering the lowest temperatures in more than 30 years accompanied by record snow accumulations. While the assessment is ongoing, demand for electricity exceeded historical levels which, combined with electricity infrastructure failures, resulted in electricity generation operating margin levels that were lower than ERCOT’s planning assumptions.

ERCOT reported generation capacity outages that peaked at 52% for natural gas, 57% for wind, 44% for coal, 12% for solar, and 13% for nuclear. As a result, ERCOT entered the weekend with a generation shortfall of approximately 45% and was forced to implement rolling blackouts on February 15th to keep the system from experiencing cascading failures.4

Wholesale costs of electricity in ERCOT spiked to a total of $50.6 billion for just a 3-day period. To put this in context, total wholesale costs of electricity were $4.2 billion for the seven days ending February 9, 2021.5 Electricity prices cleared at the maximum energy offer price of $9,000/MWh, and ancillary prices exceeded $20,000/MWh.6 Electric bills from ERCOT have already been issued, and ERCOT reports a shortage of $2.1 billion in payments after the freeze, approximately a 17% delinquency.7

The full account of the financial impact is not yet known, but utilities and retail suppliers have begun disclosing losses with at least one utility estimating a payment obligation to its wholesale market operator approaching $3.5 billion.8 Coming up with the liquidity to pay these invoices will be very challenging, and credit-rating agencies are already putting many utilities on a negative credit outlook before the final accounting is in.9

Retail electric suppliers in ERCOT are also facing an uncertain future as they look for ways to shore up their finances. On Friday, February 26th, ERCOT effectively shut down Griddy Energy LLC (an energy retailer) when it suspended Griddy’s access to the state’s power network due to unpaid bills.10 Brazos Electric Power Cooperative, Inc., which describes itself as the largest generation and transmission cooperative in Texas,11 filed for bankruptcy facing more than $2.1 billion in sudden bills stemming from the extreme winter weather.12 Based on ERCOT’s rules, retail power providers who do not pay within 72 hours can have all their customers reassigned to other providers.­

Natural gas markets experienced similar disruption as residential heating demands increased while gas was also being relied on to fuel the gas-fired generation that remained on-line. Natural gas experienced its own contingencies that exceeded design conditions as production was adversely impacted by extreme temperatures in Texas and across the Southwest and the Midwest.

Natural gas prices increased from $2.30/MMBtu during the first two weeks of February to as high as $1,065.50/MMBtu for delivery in Tulsa, OK (ONG at Tulsa) on February 18th, 2021. Gas price impacts reverberated throughout the country, affecting locations from California through Chicago, while gas from the Marcellus area acted as a buffer for prices in the Northeast (Figure 1).

Figure 1: Maximum Observed Prices Natural Gas Spot from Feb 11 Feb 23, 2021 ($/MMBtu)

Source: Concentric analysis based on data from S&P Global Market Intelligence

Public Officials Respond to a Call for Action

Governors in multiple states have called for regulators to begin investigations. Jared Polis, Governor of Colorado, is encouraging the Colorado Public Utility Commission to define clear and specific actions utilities must take to protect Coloradans from excess costs resulting from fluctuating commodity prices. Governor Polis indicated that utilities may have failed to alert customers to take action to conserve energy during the cold snap.13

Greg Abbott, Governor of Texas, has vowed to overhaul ERCOT, mandate weatherization of infrastructure, and provide economic relief to customers.14 We expect that many regulatory agencies will need to address the financial impacts of this event and that regulators in most states will examine the likelihood and potential impacts of extreme weather events in their states.

The Immediate Challenge

Utilities are in the position to compile the financial information that regulators will need to assess the immediate implications for both customers and utilities. This is an urgent demand as the public clamors for information about the potential impact on customer bills. It is also an urgent need for credit agencies that assess the financial strength of the nation’s utilities.

Regulators have a strong interest in customer impacts and utility financial conditions, and emergency actions to address customer impacts and utility financial conditions are likely. These could include deferrals, short-term borrowings, and a transition to a longer-term cost recovery approach, including securitization. At the same time, it will be critical for regulators to communicate how they will address prudence questions to avoid creating additional financial uncertainty that harms both customers and utilities.

There will be prudence investigations to determine what happened and how the adverse impacts can be mitigated in the future. Investigations that consider whether the utilities acted properly will take time and need to avoid the use of hindsight to judge the actions of the parties involved. However, urgent actions, including decisions on the deferral of cost recovery and the authorization of borrowings to maintain financial integrity should not be held up by a desire to look backward or identify future policy actions.

It is the authors’ view that any issues of prudence should be separated from the immediate financial issues that must be resolved to keep markets operating, maintain energy service to customers, and maintain credit quality for utilities. The subsequent investigations are equally important as regulators, utilities, customers, and other stakeholders will want to understand and assess actions by the utility related to short- and long-term planning, procurement, hedging, risk-sharing, operation, preparation for the emergency, and communication during the event.

More from Concentric:

The Storm Is Over: What Happens Next? – Part 2

The Storm Is Over: What Happens Next? – Part 3

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 at the time. 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.

Disclaimer Notice: Reproduction of any information, data or material, including ratings (“Content”) in any form is prohibited except with the prior written permission of the relevant party. Such party, its affiliates and suppliers (“Content Providers”) do not guarantee the accuracy, adequacy, completeness, timeliness or availability of any Content and are not responsible for any errors or omissions (negligent or otherwise), regardless of the cause, or for the results obtained from the use of such Content. In no event shall Content Providers be liable for any damages, costs, expenses, legal fees, or losses (including lost income or lost profit and opportunity costs) in connection with any use of the Content. A reference to a particular investment or security, a rating or any observation concerning an investment that is part of the Content is not a recommendation to buy, sell or hold such investment or security, does not address the suitability of an investment or security and should not be relied on as investment advice. Credit ratings are statements of opinions and are not statements of fact.

 

1 https://www.nytimes.com/2017/08/28/climate/how-hurricane-harvey-became-so-destructive.html

2 https://gov.texas.gov/news/post/governor-abbott-announces-fema-approval-of-additional-18-texas-counties-for-major-disaster-declaration#:~:text=The%2018%20counties%20include%20Atascosa,Trinity%2C%20Webb%2C%20and%20Willacy.

3 The Federal Energy Regulatory Commission will focus on questions related to whether any actors engaged in market manipulation or price gauging in wholesale markets that are subject to their jurisdiction, a role they performed in the aftermath of the 2000-01 California energy crisis.

4 Testimony of Bill Magness, then-President and CEO of Electric Reliability Council of Texas, Inc. State Senate Committee on Business and Commerce hearing. February 25th, 2021.

5 Texas Senator Nathan Johnson. State Senate Committee on Business and Commerce hearing. February 25th, 2021.

6 https://www.bloomberg.com/news/articles/2021-03-01/texas-market-monitor-recommends-price-cap-for-ancillary-services

7 https://www.wsj.com/articles/texas-power-market-is-short-2-1-billion-in-payments-after-freeze-11614386958

8 https://www.dallasnews.com/business/energy/2021/02/22/deep-freeze-brings-winners-and-losers-among-energy-suppliers/

9 https://www.fitchratings.com/research/us-public-finance/fitch-places-texas-public-power-utilities-electric-cooperatives-on-rating-watch-negative-24-02-2021

10 https://news.yahoo.com/texas-electric-firm-griddy-loses-002356449.html

11 http://brazoselectric.com

12 Texas Blackout Bills Plunge Power Supplier Brazos Into Bankruptcy – WSJ

13 Jared Polis, Governor of Colorado. February 23, 2021. Letter to the Public Utility Commissioner.

14 https://gov.texas.gov/news/post/governor-abbott-delivers-televised-statewide-address-on-power-outages-winter-weather-response-in-texas

Leveraging Competitive Markets to Unlock the True Value of AMI

Distribution electric substation with power lines and transformers, at sunset

Published on October 27, 2020

An important new report authored by Michael Kagan for the R Street Institute indicates that leveraging the use of Advanced Metering Infrastructure (AMI) in competitive markets could potentially save $250 million per year for residential consumers currently on competitive supply while also reducing energy consumption, improving grid resiliency and supporting new products and services for consumers. To achieve these goals, regulatory commissions must require that both new and existing AMI implementations provide retail suppliers revenue-grade customer usage data on at least a daily basis.

AMI has the potential to empower consumers to better manage their electricity usage and select competitive rate plans that best meet their needs. In developing the report’s conclusions, recent research and various market trends were considered. This research included a survey conducted by the American Council for an Energy-Efficient Economy (ACEEE) of the energy savings achieved in existing time varying rate programs. Recent trends considered include new competitive supply products and advances in the use of real-time AMI data.

“Achieving this level of savings will require regulatory commission actions that ensure competitive market participants have greater access to new and existing AMI investments so that they are able to create additional benefits for consumers and advance specific policy objectives,” stated Mr. Kagan, Senior Vice President, Concentric Energy Advisors.  “As we approach full AMI deployment in the United States, we have a unique opportunity to foster a series of innovations that will generate significant cost savings and environmental benefits for consumers. These direct savings in the competitive markets alone could top $250 million per year for residential consumers and we could realize far greater savings from deferred utility investment and the environmental benefits of reductions in demand peaks.”

The report was produced for the R Street Institute. Mr. Kagan extends his gratitude to R Street Senior Fellow Michael Haugh for his contributions to the report.

Opportunities for Nuclear Decommissioning Trust Funds and Other Long-Term Investments: Qualified Opportunity Fund Investments

Published on October 22, 2020

By: Lisa Quilici, Senior Vice President, and Daniel Dane, Senior Vice President

U.S. nuclear plant licensees are required to provide financial assurance for Nuclear Regulatory Commission (NRC) Radiological Decommissioning while a facility is operating. Nuclear Decommissioning Trusts (NDTs), which for an investor-owned utility are funded through rates and invested for future decommissioning, are the most common method of satisfying this requirement.[1] NDTs have very long investment horizons, and trust managers generally employ a portfolio approach to investing these funds. Given the long-term holding period of NDTs, Qualified Opportunity Fund investments offer NDT managers an investment vehicle with potential tax advantages. Given the potential for increases in taxes, these advantages are particularly compelling for investors able to benefit from them in 2020.

Map of nuclear reactor locations in the United States

The median NRC license life of the nation’s 95 operating nuclear reactors is approximately 18 years. Subsequent License Renewals (SLRs) are granted by the NRC and allow reactors to operate an additional 20 years beyond their license lives. Four reactors, Turkey Point Units 2 and 3 and Peach Bottom Units 2 and 3, have received SLRs.[2]  Investment horizons for these reactors extend to 2055.

Qualified Opportunity Zone Investments

The Tax Cuts and Jobs Act of 2017 created the Opportunity Zones tax incentive to spur economic development and job creation in distressed communities.  8,764 communities have received certification as Qualified Opportunity Zones (QOZs).

QOZs provide potentially substantial tax benefits to investors who re-invest long-term capital gains into a Qualified Opportunity Fund (QOF).[3] Investors in a QOF may benefit from:

For more information on NDTs and related QOF investment opportunities, please contact Daniel Dane, Senior Vice President, CE Capital Advisors, (617) 515-3739, ddane@ceadvisors.com and Lisa Quilici, Senior Vice President, Concentric Energy Advisors, (617)872-0248, lquilici@ceadvisors.com.

More from Concentric:

Is there a Silver Lining in Nuclear Decommissioning?

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] See 10 C.F.R. § 50.75. See also 10 C.F.R. § 50.82 for regulations regarding the decommissioning process and use of decommissioning funds.

[2] https://www.nrc.gov/reactors/operating/licensing/renewal/subsequent-license-renewal.html

[3] https://www.irs.gov/newsroom/opportunity-zones

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