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NERC sees no reliability problems this winter but warns of fuel supply risks

November 23, 2020

by Peter Maloney
APPA News
November 23, 2020

There will be sufficient resources in service to meet electrical demand during the upcoming winter season, according to the latest reliability assessment by the North American Electric Reliability Corp. (NERC), but the organization also cautioned that there are continuing risks regarding supplies of natural gas in New England, California and the Southwest.

NERC’s 2020-2021 Winter Reliability Assessment covers December, January and February. The report found that anticipated reserve margins will meet or surpass reference reserve margins in all areas under normal conditions.

Sufficient fuel supplies, specifically of natural gas, remains a concern in some areas, however, as demand for natural gas, both as a fuel for power generation and for space heating, continues to grow, NERC said.

During particularly cold weather generating units that lack alternate fuel sources or that do not have contracts for firm fuel delivery may not be able to meet demand, the report noted.

In New England, where natural gas availability is limited, firm load would still be able to be served even under abnormally cold conditions, but under more severe conditions, such as those experienced in January 2018, limited oil inventories could lead to “eventual loss of generation and firm load shed,” NERC said.

The NERC report also noted that California and the southwest area in the Western Interconnection could face “fuel supply curtailment or disruption from extreme events that impact natural gas supplies,” as those regions rely on natural gas-fired generation capacity for over 60% of on-peak demand and have limited gas storage.

Overall, extreme weather conditions – such as wind generation blade icing, frozen coal piles, and curtailment of natural gas pipelines – continue to pose a risk to the bulk power system during the winter, NERC said. Unusually cold temperatures could result in increased demand and higher levels of generation forced outages and create conditions that would lead system operators to take emergency actions.

The NERC report also examined ongoing impacts from the COVID-19 pandemic, which it said is causing “increased uncertainty in electricity demand projections and presents cybersecurity and operating risks.” The reliability organization noted that no specific threats or degradation to reliability have been identified for the winter season. However, the report also noted that if maintenance operations on generation and transmission assets are not able to be performed because of the pandemic, “forced outages may escalate.”

The pandemic could also affect the accuracy of demand projections in the near term and have the potential to exacerbate or alleviate planning reserve shortfalls in areas that are below or near reference margin levels, NERC said.

NERC’s assessment also noted that restoration efforts in response to the recent hurricane season could continue into the winter. While restoration efforts in Arkansas, Texas, and north Louisiana have been completed, restoration work that is often characterized as a rebuild, continues in southwest Louisiana, primarily in and around the city of Lake Charles.

Lincoln Electric System board adopts 100% net decarbonization goal by 2040

November 23, 2020

by Paul Ciampoli
APPA News Director
November 23, 2020

The administrative board of Nebraska public power utility Lincoln Electric System (LES) on Nov. 20 adopted a 100% net decarbonization goal by 2040.

“LES acknowledges that the emissions of greenhouse gases from fossil fuel-fired power generating plants contribute to increased concentration levels of atmospheric carbon dioxide, which in turn contributes to climate change,” LES said in a news release. The board adopted this goal in response to the risks associated with climate change.

The board’s action came after participating in a year-long educational series on establishing a new carbon reduction goal and soliciting public opinion at the beginning of the month.

In 2019, the mayor of Lincoln began developing a new Climate Action Plan for the community. The board “recognized its role in helping to achieve a community goal while also maintaining high levels of electric system reliability and affordable retail electric rates to every customer in the area,” LES said.

In October, the city released a draft of its Climate Action Plan, in which a citywide goal to reduce net greenhouse gas emissions 80% by 2050, relative to 2011 levels, was announced.

At its Nov. 20 meeting, the LES Administrative Board committed to striving to mitigate its reliance on fossil fuels by establishing a goal to achieve net zero carbon dioxide production from its generation portfolio by 2040.

Moving forward, LES staff will continue its ongoing process of technological and financial evaluations to make prudent resource planning decisions.

Additional information is available here.

Another Nebraska public power utility, Omaha Public Power District (OPPD), has begun a decarbonization study to understand how it can make progress toward its goal of net-zero carbon production by 2050.

Meanwhile, based on a two-year rolling average from 2018 and 2019, 61% of the electricity that Nebraska public power utility Nebraska Public Power District provides to its customers is carbon-free “thanks to powerhouses like nuclear and green energy sources like solar, hydropower and wind,” wrote NPPD President and CEO Tom Kent in a blog this past summer.

“We’re participating in carbon capture and sequestration studies funded in part through a competitive grant from the U.S. Department of Energy. And this year, we were granted the authority to pursue the development of innovative carbon-free and carbon-neutral fuels,” Kent wrote.

“It speaks to our willingness to not just listen to and accommodate customer expectations for low-cost, reliable and sustainable energy sources, but also to take it upon ourselves to move toward further reducing our carbon footprint and adapting to this growing trend,” Kent said.

CAISO board moves to integrate storage resources and improve reliability for fall 2021

November 23, 2020

by Paul Ciampoli
APPA News Director
November 23, 2020

The California Independent System Operator (ISO) Board of Governors last week adopted market tools that it said will help integrate new battery storage resources and improve overall reliability for next fall.

The board’s approval of Hybrid Resources Phase 2 was expedited to accommodate more than 1,500 megawatts of storage capacity expected to connect to the grid by the end of next year.

The storage capacity is part of California’s procurement goal of 3,300 MW of battery resources by 2023 to help replace retiring fossil fuel generation.

The proposal adopted by the board:

In related news, the Federal Energy Regulatory Commission on Nov. 19 adopted CAISO’s Hybrid Resources Phase 1 tariff.

FERC’s order responded to a September filing made by the grid operator. In that filing, CAISO proposed revisions to its open access transmission tariff regarding modeling separate resources that are co-located at a single generating facility, and data requirements for hybrid resources that include a wind or solar generation component. 

The Board of Governors approved the first phase of the Hybrid Resources proposal at its July 27 meeting.

Implementation of Phase 1 is scheduled for fall 2020.

FERC affirms and clarifies final rule that revised regulations implementing PURPA

November 23, 2020

by Paul Ciampoli
APPA News Director
November 23, 2020

The Federal Energy Regulatory Commission on Nov. 19 affirmed a final rule it approved this summer that revised its regulations implementing the Public Utility Regulatory Policies Act (PURPA).

In its action at its monthly open meeting, FERC dismissed or disagreed with most arguments raised on rehearing but offered clarification of the final rule itself.

Order No. 872 granted flexibility to state regulatory authorities in establishing avoided cost rates for qualifying facilities’ (QF) sales inside and outside of the organized electric markets.  The July 16 final rule also gave states the ability to require that energy rates, but not capacity rates, vary during the term of a QF contract. The flexibility for state regulatory authorities also extends to public power and electric cooperative regulators.

The final rule also modified the “one-mile rule” for determining whether generation facilities are considered to be at the same site for purposes of determining whether a facility meets the 80 MW limit on qualifying small power production facilities.

It also reduced the rebuttable presumption for nondiscriminatory access to power markets, from 20 megawatts to 5 megawatts, for small power production, but not cogeneration, facilities.  This change will make it easier for electric utilities (including public power utilities) in certain markets to seek relief from PURPA’s mandatory purchase requirement for smaller QFs under PURPA section 210(m).

For a QF to establish a legally enforceable obligation for an electric utility to purchase the QF’s output, the final rule required that the QF must demonstrate commercial viability and financial commitment to build under objective and reasonable state-determined criteria.

FERC’s Nov. 19 order provided clarifications related to:

APPA, LPPC supported FERC plans to reform PURPA

The final rule largely adopted proposals in a September 2019 FERC Notice of Proposed Rulemaking (NOPR).

In response to the NOPR, the American Public Power Association and the Large Public Power Council in December said that the development of competitive power markets and the dramatic growth of a renewable power sector now largely independent of the boost once provided by PURPA justify significant changes in PURPA regulations.

Berkeley Lab report finds three policies most effective at solar PV adoption

November 20, 2020

by Peter Maloney
APPA News
November 20, 2020

A new study by the Lawrence Berkeley National Laboratory identified three policy and business models that boost “adoption equity” for solar power installations.

The authors of the study define adoption equity as the degree to which adopter incomes reflect the incomes of the general population.

“I think most people are aware that the benefits of solar energy have not been equitably distributed with respect to income,” Eric O’Shaughnessy, a Berkeley Lab affiliate researcher and the study’s lead author, said in a statement. The “key takeaway of our study is: It doesn’t have to be that way – especially now that solar is getting cheaper.”

The study, “The impact of policies and business models on income equity in rooftop solar adoption,” published in Nature Energy earlier this month, analyzed five policies and programs that have been used to spur solar photovoltaic (PV) adoption:

The report found that the first three types of interventions – targeted incentives, leasing, and PACE – are effective at increasing adoption equity.

“The results for those three interventions are pretty strong,” O’Shaughnessy said. “And the research also provides evidence that these interventions are leading to both deepening, or expanding in existing markets, and broadening, or moving into new markets – low-income areas where there traditionally was not solar.”

The authors argued that when solar installations enter a new market or neighborhood, it can have a spillover effect. “If a system is installed in a neighborhood that had no solar before, then the neighbors are going to see that system, and that makes them a little bit more likely to adopt themselves,” O’Shaughnessy said. “There’s lots of research on these peer effects. So, if the market broadens and solar deployment moves into new markets, the potential indirect effects are more significant than if the market only deepens by installing systems on lower-income households in existing markets.”

In addition, as the solar power market grows and costs continue to decline, the decision to install a system is driven less by environmental concerns and more by financial benefits. “Surveys suggest that roughly half of people who adopt nowadays are really doing it primarily for economic reasons,” O’Shaughnessy said.

And, for low- and middle-income households, financial benefits can make more of a difference. “Many low- and moderate-income households have a large ‘energy burden,’ which is the fraction of a household’s income that gets spent on energy and utility expenses,” Galen Barbose, a Berkeley Lab research scientist and one of the authors of the report, said in a statement. “There’s growing interest now in solar PV as being another arrow in that quiver of helping to reduce the energy burden of low-income households.”

The authors also noted that low- and middle-income housing accounts for 42% of PV-viable rooftop space in the United States.

In the study, the authors tapped household-level PV adopter income data covering more than 70% of the U.S. residential PV market. The study covered the period from 2010 to 2018 and included data on more than 1 million residential rooftop PV systems installed on single-family homes in 18 states. The researchers compared modeled household-level income estimates for PV adopters with area median household incomes, based on U.S. Census data.

California PUC opens proceeding to address extreme weather events

November 20, 2020

by Paul Ciampoli
APPA News Director
November 20, 2020

The California Public Utilities Commission (CPUC) on Nov. 19 launched a rulemaking that it said will address how to increase energy supply and decrease demand during peak hours if a heat storm occurs in the summer of 2021 so the state does not experience a repeat of rolling power outages.

Through the proceeding, the CPUC will implement temporary changes to existing processes, programs, and rules for demand response, and other initiatives, it said.

The CPUC will focus on near-term actions that can be adopted by April 2021 and that the utilities can implement before the summer of 2021.

The proceeding will consider multiple options, including, but not limited to:

The CPUC also said it will address whether particular measures may extend beyond calendar year 2021. Moreover, the CPUC will consider whether specific measures would be triggered only in emergency conditions to ensure continued access to utility services.

In mid-August 2020, the western U.S. experienced an unprecedented, prolonged heat storm, which led to a variety of circumstances that ultimately required CAISO to initiate rotating power outages to prevent sustained, wide-spread service interruptions.

On October 6, 2020, the California Energy Commission, CAISO, and the CPUC issued a preliminary report on the causes of the August rotating outages, which outlined short-term and longer-term actions to mitigate electricity shortages and ensure delivery of clean, reliable, and affordable energy.

The proposal is available here.

New Jersey BPU authorizes PJM to solicit potential offshore wind transmission solutions

November 19, 2020

by Paul Ciampoli
APPA News Director
November 19, 2020

The New Jersey Board of Public Utilities (NJBPU) on Nov. 18 authorized the PJM Interconnection to solicit potential offshore wind transmission solutions from qualified developers on behalf of NJBPU.

The move makes New Jersey the first state to engage in a competitive solicitation process managed by PJM for such critical planning, the NJBPU said in a news release.

In late 2019, New Jersey Gov. Phil Murphy signed an executive order raising New Jersey’s offshore wind goal from 3,500 megawatts of offshore wind-generated electricity by 2030 to 7,500 MW by 2035. The executive order will deliver renewable energy generation needed to help meet the state’s goals of 50 percent renewable energy by 2030.

The NJBPU formally requested the inclusion of this state public policy into the transmission planning process of PJM through a competitive solicitation process in what is known as the “State Agreement Approach.”

“The State Agreement Approach was written broadly to accommodate the breadth and diversity of policies that different states might pursue,” said Manu Asthana, President and CEO of PJM. “It is an existing tool that states can use to leverage PJM’s regional transmission planning expertise. In this case, we are pleased to be able to help New Jersey advance its offshore wind objectives.”

The NJBPU is asking that PJM integrate the state’s offshore wind transmission policy goals into the grid operator’s transmission planning process through the State Agreement Approach established by the Federal Energy Regulatory Commission’s Order No. 1000, which aimed to open the building of new transmission lines to competition.

By making this formal request, the NJBPU said it can utilize the State Agreement Approach to explore options for an optimal long-term solution for offshore wind transmission that otherwise may not have been available at this stage of development.

Through the solicitation process, the NJBPU will examine details on a wide array of ready-to-build transmission options, including key factors such as cost, siting, environmental impacts, and the timeframe for construction, it noted.

“The process will also allow NJBPU to determine how a coordinated approach can lead to more cost-effective, efficient transmission solutions that minimize the environmental impacts of bringing wind energy ashore,” it said in the news release.

There are no financial or ratepayer obligations with the announcement, which goes into effect after the state’s second offshore wind solicitation.

Additionally, the competitive solicitation process “contains extensive consumer protections, including the ability to control cost and timing implications by incorporating transmission upgrades in a phased manner,” the NJBPU said.

The NJBPU directed its staff to work with PJM to seek potential solutions for three interrelated components of an open access offshore wind transmission facility: (1) onshore upgrades, (2) beach crossings with potential offshore “collector” platforms, which collect energy from multiple wind farms, and (3) an ocean transmission “backbone” to connect multiple collector platforms or lease areas.

The NJBPU said it will assess whether proposals for any of these components can meet the state’s offshore wind policy goals in an economically efficient, environmentally sensitive, and timely manner.

The NJBPU intends to work with PJM to open the solicitation in 2021 and evaluate competitive project proposals in concert with the grid operator, including any cost considerations.

At the end of the process, NJBPU will decide whether to proceed with any combination of the proposed transmission projects, but it reserves the right to terminate the process at any time without making a selection.

Additional information about New Jersey’s offshore wind program is available here.

TVA board approves utility’s first rates for commercial EV charging stations

November 19, 2020

by Peter Maloney
APPA News
November 19, 2020

The Tennessee Valley Authority’s (TVA) board of directors recently approved a new commercial rate structure aimed at supporting the expansion of electric vehicle charging infrastructure across the region.

TVA conducted a pilot program for electric vehicle rates about a year and a half ago, but the new rate would be the first at the utility that is useable for everybody, Joe Hoagland, vice president of innovation and research at TVA, said.

The new rates apply to any commercial, level-three fast charger, but not to residential charging. “The new, commercial rate is simpler,” Hoagland said. “It takes out almost all of the demand charge, so there is a simple rate based on kilowatt hours (kWh), so it looks similar to gasoline on a cents per gallon basis.”

Hoagland said TVA did a lot of work with stakeholders to understand what needs to happen to facilitate electric vehicle adoption in the Valley and identified four barriers: a lack of infrastructure and concerns about range anxiety, a lack of supporting rate policies, the relatively high costs of electric vehicles, and a low level of awareness regarding electric vehicles among customers. The new commercial rates structure “is the first step in addressing those barriers,” Hoagland said.

The new commercial rate will apply to the wholesale rate TVA charges its 153 local utilities. While all the details of the wholesale rates are not yet worked out, it will be competitive with rates offered by third party charging stations, Hoagland said.

Electric vehicles represent a “huge opportunity for us to continue with our mission of economic development” in the Valley, Hoagland said.

In late October, General Motors said it plans to invest nearly $2 billion in its Spring Hill, Tenn., manufacturing plant to build fully electric vehicles. Volkswagen, which already manufactures electric vehicles in Tennessee, last week said it has begun construction of a new, laboratory for electric vehicle batteries in the state. Nissan also has a factory in Nashville where it produces its LEAF electric vehicle.

In addition to manufacturers, wider use of electric vehicles could be a draw for other companies looking that are focused on their sustainability goals and are looking to relocate, and electric vehicles also represent “an opportunity for a significant amount of carbon dioxide reductions,” Hoagland said.

For TVA, electric vehicles also represent a sales growth opportunity and could improve the utility’s ability to balance its load, Hoagland said. “There is value in this for everybody, the consumer, the local utility and TVA,” he said.

“Actively supporting the electrification of transportation multiplies our own carbon reduction efforts and moves the entire region toward greater sustainability and economic opportunity in the future,” Jeff Lyash, TVA’s president and CEO, said in a statement. “TVA has reduced carbon emissions by nearly 60% since 2005, and we have concrete plans to reach 70% by 2030.”

At the board meeting, TVA noted that it in fiscal year 2020 it’s provided nearly 60% of the region’s electric power from carbon free sources, which it said is the largest percentage of clean power produced by any Southeastern utility.

TVA also noted that it has increased solar energy capacity by nearly 70% with nearly 1,200 additional megawatts of solar energy under contract that is due online in the next two years.

Also at the board meeting, TVA said that despite restrictions imposed to help stop the spread COVID-19, it managed to conduct scheduled maintenance and capital improvements, resulting in improved system performance and decreased fuel costs.

So, while its operating revenue was down about 5% due to a combination of weather and pandemic impacts, TVA said the shortfall was offset by “improved operational performance that lowered operating and maintenance costs, reduced fuel costs and exceeded TVA’s debt reduction target by more than $400 million, reducing debt to its lowest level in 30 years.”

TVA estimated its fiscal year net income at $1.4 billion.

Senate Energy and Natural Resources Committee advances FERC nominees

November 18, 2020

by Paul Ciampoli
APPA News Director
November 18, 2020

The Senate Energy and Natural Resources Committee on Nov. 18 favorably reported the nomination of Allison Clements and Mark Christie to be members of the Federal Energy Regulatory Commission.

The committee held a hearing to consider the nominees on Sept. 16. The committee approved both nominees by a voice vote.

The nominees now await further consideration by the full Senate. Should they be approved by the Senate before the end of the year, Clements would serve a FERC term expiring June 30, 2024, and Christie a term expiring June 30, 2025.

In other recent FERC-related news, President Donald Trump on Nov. 5 named James Danly as Chairman of FERC. He will replace Neil Chatterjee as head of the agency.

Danly has served as a Commissioner since March 2020. Prior to that he served as general counsel to the Commission since joining FERC in 2017.

Chatterjee, who joined the Commission in 2017 and served as Chairman from August to December 2017 and since October 2018, congratulated Danly on his appointment and said the Commission will be well-served by Danly’s leadership.

Chatterjee will remain a FERC Commissioner, along with Commissioner Richard Glick.

CARB and Calif. public power utilities partner to offer consumers up to $1,500 off EVs

November 18, 2020

by Paul Ciampoli
APPA News Director
November 18, 2020

A large number of California public power utilities are teaming up with the California Air Resources Board (CARB) to offer the California Clean Fuel Reward (CCFR), a point-of-sale price reduction of up to $1,500 for the purchase or lease of any eligible new battery electric or plug-in hybrid vehicle from a participating automotive retailer.

Starting on Nov. 17, consumers will be able to purchase an eligible vehicle from an enrolled retailer and receive an instant reduction in the purchase price, CARB noted.

The CCFR will help support California Gov. Gavin Newsom’s Executive Order phasing out gasoline-powered cars and requiring 100 percent sales of zero-emission cars in 2035.

Southern California Edison, a subsidiary of investor-owned Edison International, is administering the program on behalf of, and in collaboration with, all participating utilities. The CCFR is available to all California residents, regardless of utility provider and participation.

The participating public power utilities are:

Investor-owned utilities participating Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric.

When consumers make an EV purchase at an enrolled retailer in California, the retailer will include the reward in the transaction at the point of sale. The customer will not need to do any paperwork after the sale to receive the reward. “The CCFR is one of the most straightforward and inclusive rewards in the market, as it is available to everyone in California,” CARB said.

The lists of enrolled retailers and eligible vehicles will be continually updated as new retailers and EV models are added.

The CCFR can also be combined with existing post-sale federal, state and local incentives, such as the Clean Vehicle Rebate Project, Clean Cars 4 All, and the Clean Vehicle Assistance Program, to make EVs even more affordable.

The CCFR is funded by electric utilities participating in CARB’s Low Carbon Fuel Standard (LCFS) program. The LCFS is a key part of a comprehensive set of programs in California to cut greenhouse gas emissions and other smog-forming and toxic air pollutants by improving vehicle technology, reducing fuel consumption, and increasing transportation mobility options.

Additional information about the CCFR is available here.