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.

 

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.

 

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

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

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.

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

Published: September 23, 2021

By: Concentric Staff Writer

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

How Transmission Planning & Cost Allocation Processes Are Inhibiting Wind & Solar Development in SPP, MISO, & PJM

The American Council on Renewable Energy (ACORE) commissioned a report by Concentric entitled How Transmission Planning & Cost Allocation Processes Are Inhibiting Wind & Solar Development in SPP, MISO, & PJM.

Click here to access the report on ACORE’s website.

Concentric Recently Served as Market Advisor in Key Basalt Infrastructure Partners Acquisition

Solar panels and solar farm with sunrise or sunset

Published on November 20, 2020

Michael Kagan, Senior Vice President at Concentric, recently led a team that served as Market Advisor to Basalt Infrastructure Partners LLC (“Basalt”). In this capacity, Concentric supported an investment by Basalt Fund III in a residential solar portfolio owned by funds managed by Ares Infrastructure and Power. This transaction is notable in that it includes approximately 11,000 existing residential solar installations and the capacity to support additional solar installations across the US through a new entity, Habitat Solar.

As Basalt’s Market Advisor, Concentric evaluated state-level regulations pertaining to net energy metering, the supply-demand balance of solar renewable energy credits in various states, and anticipated regulatory changes that will impact the economics of the residential solar market in the coming years. “With so many transactions contemplated within the on-site solar space, it’s great to support a client executing on a platform investment with long term growth potential,” said Michael Kagan.

In addition to assisting Basalt, Concentric has recently assisted numerous other clients complete acquisition due diligence, including advising a solar developer in the acquisition of a retail power and gas supplier, advising several private equity investors in their acquisitions of retail energy providers, and assisting utilities evaluate investments in the energy efficiency space.

Concentric is often selected for these engagements given our capability to quickly mobilize an experienced team that has a comprehensive understanding of the competitive energy landscape and wholesale and retail energy regulations, and an understanding of the specific diligence needs of debt and equity investors.

More information is available regarding Concentric’s due diligence and retail services here.

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.

Pipe Replacement for a Decarbonized Future

Published on August 19, 2020

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

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

Key Considerations

A pipe replacement framework that incorporates uncertainty attributable to:

Will meet the challenges of a changing environment.

A New Investment Framework

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

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

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

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

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

Responses to Some Common Questions

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

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

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

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

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

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

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

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

COVID Impacts Depend on Sales Trends and State Ratemaking Policies

Published on August 6, 2020

By: Bickey Rimal, Assistant Vice President

The most recent electricity consumption data from the U.S. Energy Information Administration (“EIA”) reveals that the COVID-19 pandemic is significantly impacting electric utilities throughout the country. A continuing decline in sales during the peak summer period coupled with misaligned rate design and structures does not bode well for the utilities. The most adversely impacted utilities are those that:

U.S. Electricity Sales Since COVID-19

Based on the most recent monthly data published by EIA, total electricity sales in April of 2020 was the lowest level experienced since 2003, despite the fact that residential sales were their highest levels since 2001. [1] Commercial and industrial sectors experienced their lowest April sales since 2003. The following graph shows the monthly sales by sector over the last few years.

U.S. Utility Sales by Sector

State-Specific Sales Since COVID-19

We can learn more by looking at sales patterns at a more granular level. We examined sales in April 2020 for each sector compared to the sales for the same month over the past five years at the state level. Generally speaking, the results were as expected for the commercial and industrial sectors. For most states, April 2020 had the lowest sales from commercial and industrial sectors when compared to the last five Aprils due to the slowdown caused by the pandemic. The April 2020 sales were 16% and 12% lower than April 2019 sales for the commercial and industrial sectors, respectively. The chart below shows commercial sales in each of the last four Aprils by state.

Utility Commercial Sales by State

April 2020 versus Average April 2017-2019

We wanted to analyze how April 2020 sales compared to the average April sales in the prior three years (i.e., 2017-2019) for each sector. As shown by the graphs below, April 2020 sales for the residential sector was higher than the April 2017-2019 average sales for all but four states. The percentage change in sales ranges from a high of approximately 15% to a low of roughly -3%.

April 2020 sales rates for the commercial and industrial sectors were lower than the April 2017-2019 average sales for all but one state for the commercial sector and all but seven states for the industrial sector.

Utility Residential Sales in April 2020

Utility Commercial Sales in April 2020

Utility Industrial Sales in April 2020

Revenue Impact of COVID-19

After establishing that residential sales had moved in the opposite direction to commercial and industrial sales, we analyzed the overall net impact on the revenues collected. We examined how much, if any, the loss in revenues from the commercial and industrial sectors would be offset by the increase in revenue from the residential sector. When we compared the change in total April 2020 revenues to the average April revenues in 2017-2019, the change in revenues followed a similar pattern as the change in total sales. It is important to note that non-payments may be driving a portion of the reduction in total revenue in April 2020 in addition to reduced load.

COVID Revenue Impact on Utilities

The critical question is: how will the change in load driven by the pandemic impact regulated utilities? The answer depends on each utility’s unique circumstances, some of which are listed below:

As next steps, we plan to analyze monthly data beyond April 2020 as it becomes available. The data for these later months, especially the summer months, will be crucial because those are the peak electricity sales months and peak revenue collection months. Drastic changes to sales during the summer months will have significantly more impact on revenues as compared to the months. Additionally, we also want to explore the various options available to utilities, regulators, and other stakeholders to address the COVID-19 related issues discussed herein.

More From Concentric:

COVID-19 Related Shutdowns Are Flattening the Curve of Electricity Demand: Experience in New York City

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

[1] Data was obtained from EIA using EIA’s API and the analysis was conducted in R, a free statistical software. The data used in this analysis is based on Form EIA-861M “Monthly Electric Power Industry Report”, which collects sales of electricity and associated revenue, each month, from a statistically chosen sample of electric utilities in the United States.

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

Published on June 26, 2020 

By: Team Concentric

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

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

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

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

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

·         Demand charges are expensive to implement.

·         Customers do not understand demand charges.

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

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

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

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

The Economics of an Electric Distribution System

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

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

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

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

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

Definition – What is Demand?

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

Arguments Commonly Made Against Demand Charges

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

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

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

Argument 2: “Demand Meters are Expensive to Implement

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

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

Argument 3: “Customers Do Not Understand Demand Charges”

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

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

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

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

Argument 4: Customers are Unable to React to Demand Charges

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

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

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

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

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

 

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

 

More From Concentric:

Renewable Distributed Generation and Pricing Challenges

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


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

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

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