Search
`
November 7, 2024

Posted on

PG&E Proposes Buildout of EV Charging Infrastructure

Pacific Gas and Electric announced plans Thursday to install infrastructure for 16,000 electric vehicle charging ports, including Level 2 and fast chargers, at public locations such as shopping centers and park-and-ride lots, as well as sites convenient for apartment residents.

Under the plan, which still must receive approval from the California Public Utilities Commission, PG&E would install electrical infrastructure to connect parking spaces to the electric grid or offer rebates for the electrical work. In some cases, the company would also install EV chargers.

PG&E would pay for some of or all the work, depending on the type of customer. For example, the utility would cover all costs for certain multifamily housing sites.

The company said that increasing the availability of public charging may boost EV adoption by reassuring drivers that they’ll be able to charge when they’re away from home. It also provides a place to plug in for drivers who don’t have charging at home.

Increasing Adoption

In a press release, PG&E noted that more than 360,000 EVs are registered in its service area, accounting for almost one-fifth of all EVs in the U.S. The company serves Northern and Central California.

“With this proposed program, we believe we can continue doing our part to expand EV charging infrastructure for our customers, which is a critical component of increasing EV adoption,” Aaron August, PG&E’s vice president of business development and customer engagement, said in a statement.

“Reducing vehicle emissions is good for our state and good for the environment,” he added.

PG&E’s proposal also includes measures to help promote equitable EV adoption. Those include gathering community input on where to install chargers and offering grants to community groups that have ideas on how to increase EV adoption.

EV car-share partnerships would be pursued as part of the program, and at least half the infrastructure spending would be earmarked for underserved communities.

Previous Program Completed

PG&E’s proposal would build on its first EV charging infrastructure program, called EV Charge Network, which began in 2018 and was recently completed.

Under that program, PG&E installed 4,827 Level 2 charging ports at 192 locations in 66 cities across its service area, the company announced this month. The cities included Bakersfield, Chico, Fresno, Grass Valley, Red Bluff and San Jose.

In the EV Charge Network program, PG&E paid for and built electrical infrastructure from the grid to the parking space at each site. The company also covered some of or all the cost of the charger for participating customers. The program included 1,859 charging ports in disadvantaged communities.

PG&E is running several other EV-related programs. Those include the EV Fleet program, in which the company will install or help cover the cost of electrical infrastructure for medium- and heavy-duty electric vehicles. The program is aiming for infrastructure at 700 sites by 2024 to support the adoption of 6,500 vehicles.

Another initiative is the EV Fast Charge Program, which aims to install more than 50 DC fast-charging plazas in highway corridors and urban areas.

Four fast chargers were installed this year at a 7-Eleven store in West Sacramento as part of the program.

Posted on

Potential for Green Hydrogen Hub in the Carolinas

The Carolinas region could become the site of the nation’s first largescale effort to decarbonize industry using hydrogen, both as a fuel for gas turbines and replacing diesel in heavy trucking.

But to do that, existing natural gas pipelines will initially have to move blends of methane and hydrogen, then eventually only hydrogen, an undertaking that will require some reengineering as well as changes in industry safety codes and government regulations — no simple tasks.

The efforts needed to make this happen were the focus of a webinar Thursday organized by the Energy Futures Initiative (EFI), an organization founded by former Energy Secretary Ernest Moniz.

During the event, Moniz, Duke Energy CEO Lynn Good and Vahid Majidi, executive vice president and director of the Savannah River National Laboratory, concluded that the Carolinas’ manufacturing base and high-tech industry could enable it to become a hydrogen “hub,” a new concept replacing the term “cluster” that dominated earlier industrialization when similar industries would gather in a region.

Good endorsed the hub concept as “a great opportunity to get us started.”

“We have a goal of achieving at least 50% carbon reduction by 2030, and net zero by 2050,” Good said. “We have a clear line of sight on how to get to 2030. It’s a matter of retiring existing coal assets; it’s putting in place more solar and battery and wind — existing technologies.

“But as we get beyond 2030, deeper into the 2030s, and begin really tackling that net-zero goal, then we begin looking for new technologies; we began looking for what we would call ‘load following zero carbon technologies.’”

And hydrogen is one of those technologies, which could be “versatile” for the needs of the electric and gas sectors, and also have applications for heavy industry, the military, long haul transportation and “a broad number of sectors that are also going after carbon reduction,” Good said

“And I think about the opportunity we have here in this decade, with supporting policy coming in place, with the [Biden] infrastructure bill, potentially tax credits as well. We could make real progress on technical feasibility and also on tackling cost competitiveness. So that as we get to the 2030s, it becomes a really valuable tool to reach net zero,” she said.

The hub concept originated at the DOE as a way to convert multiple industries rather than fund just one hydrogen concept at a time.

Moniz touted that concept at the start of the discussion.

Pointing out that if the Carolinas were an independent nation, their combined economies would be the 18th largest in the world, Moniz explained the idea as a kind of organic growth stemming from where the region’s industry is today.

“In the United States, a fully functioning market … begins with strategic regional investments to build out hydrogen infrastructure, connecting with existing industrial assets. The region has a history in hydrogen R&D, broad industrial capabilities, and an array of potentially amenable existing infrastructure to enable the growth and formation of a hydrogen hub,” he said.

Majidi said the Carolinas have strong academic research capabilities in addition to the national lab, where 80 hydrogen researchers are working.

“For seven decades, we’ve been working with hydrogen, in the form of tritium. Hydrogen has been ingrained into the DNA of Savannah River National Laboratory.” he said.

Majidi said of the top 100 institutions publishing on hydrogen in the U.S., six are in the Carolinas, including Savannah River National Laboratory, North Carolina State University, the University of South Carolina, Clemson, the University of North Carolina, Chapel Hill and Duke.

“With these organizations [working] together along with industry, we can really develop an ecosystem that feeds the growth of the hydrogen economy,” he said.

Later in the webinar the discussion shifted to the experiences of hydrogen advocates and institutional managers already trying to move regional economies to hydrogen.

The takeaway: be sure to identify hydrogen customers before developing the technologies to make the fuel and deliver it.

Posted on

Return of In-person ERO Compliance Audits Planned in 2022

Enforcement staff at the regional entities are prepared to return to in-person work in January after a year of remote audits caused by the ongoing COVID-19 pandemic, the ERO Enterprise’s 2022 Compliance Monitoring and Enforcement Program (CMEP) implementation plan (IP), released last week, indicated.

NERC and the regional entities develop the CMEP IP each year to identify “the ERO Enterprise’s high-level priorities for its CMEP activities” and provide “guidance to the employees of the ERO Enterprise involved with monitoring and enforcement.” Risk elements presented in the plan are chosen from a variety of sources, including NERC’s yearly State of Reliability Report and Long-term Reliability Assessment, as well as the biennial ERO Reliability Risk Priorities Report published by NERC’s Reliability Issues Steering Committee.

COVID-19 Enforcement Easing to End

The last two years have been unusual for the ERO Enterprise’s enforcement personnel: in May 2020, amid the surging COVID-19 pandemic, NERC and the REs announced an expansion of the self-logging program. FERC and NERC had already ordered the deferral of certain regulatory activities, including on-site activities by REs such as audits and certifications, in March. (See FERC, NERC Relax Compliance in Light of COVID-19.)

Those relief measures have been extended several times, though NERC announced in May that they would likely end for good at the end of 2021. (See NERC: Latest COVID Relief Extension Likely The Last.)

The authors of the CMEP IP noted that staff at the REs have adapted to the new environment by using “video technology and virtual meeting platforms” to carry out their enforcement duties.

“Throughout the pandemic, the ERO Enterprise recognized the importance of prioritizing the health and safety of personnel and the continued reliability and security of the BPS. We will continue to evaluate the circumstances to determine the need for additional guidance,” the plan said. “When conditions allow, the ERO Enterprise will prioritize monitoring activities and risks that benefit the most from on-site components, including some on-site activities deferred from 2020 and 2021.”

Range of Risks Noted

The priority risk elements included in this year’s implementation plan are:

  • Remote connectivity
  • Supply chain
  • Models impacting long-term and operational planning gaps in program execution
  • Protection system coordination
  • Extreme events

These risks are “not intended to be a representation of just ‘important’ reliability standard requirements,” according to the plan, but rather are meant to emphasize for registered entities where they should direct “collective focus within their operations” to address the biggest challenges to BPS reliability.

Remote connectivity and supply chain carry over from last year’s list, where they were listed as a single item. Their separation in this year’s implementation plan reflects the distinct challenges that have emerged with both.

In the case of remote connectivity, the danger arises from the many utility employees who have chosen or been required to work remotely amid the pandemic, creating the risk that employees may be tricked into giving up their login credentials to malicious individuals or ignore security procedures because of inconvenience. The plan authors urged compliance monitoring staff to “understand how entities manage the risk of remote connectivity and the complexity of the tasks the individuals perform” in order to spot areas where improvement may be needed.

Concerns about supply chain security, particularly in software, have risen over the past year, fueled by high-profile cyberattacks such as the SolarWinds hack in December that may have compromised thousands of companies in the U.S., as well as the ransomware attack on Colonial Pipeline in May. (See Experts Call for Cyber Shift in Response to Colonial Hack.) The CMEP IP noted that both events highlight the risk that similar attacks against electric utilities “collectively … could cause BPS cascading disruptions.”

The third item reflects concern about the lack of useful models for registered entities to use in planning future development, including the “integration and management of system assets.” This is especially important as utilities connect increasing amounts of distributed energy resources, which often behave very differently from traditional generators.

“With the recent and expected increases of both utility-scale solar resources and distributed generation, the causes of a sudden reduction in power output from utility-scale power inverters need to be widely communicated and addressed by the industry,” NERC said. “Entities with increasing inverter-based resources should be aware and address this within their models.”

For the fourth element, gaps in program execution, the authors noted that entities have had to make major changes to their procedures in the last two years because of the pandemic; although most had a contingency plan for pandemics, some of the planned measures had to be adjusted to the actual conditions, meaning that not all changes could be tested prior to their adoption. Enforcement staff were told to pay close attention to utilities’ inspection and maintenance programs, along with facility ratings that could become out of date caused by entities’ lack of care in logging system changes.

The risk in protection system coordination refers to entities’ awareness “of their protection systems and how they would react during extreme events.” In particular, the authors indicated that differences in how neighboring utilities address issues at their borders could present issues.

Finally, the report noted multiple extreme weather events, such as February’s winter storms in Texas and the Midwest and last year’s heat event in California. The authors warned that not only are such disasters becoming more frequent and severe, but “the grid transformation also heightens the effects and complicates mitigation of an extreme event.”

“Extreme events can stress the BPS and expose weaknesses such as poor coordination between neighboring entities in planning or operations,” the CMEP IP said, observing further vulnerabilities that could be exposed in this manner such as lack of proper spares, critical infrastructure interdependencies, and “aging infrastructure coupled with less than adequate maintenance.”

Posted on

Climate Conservatives: ‘COP26 is Going to Fail’

The global meeting of governments set to begin Sunday in Glasgow, Scotland, to negotiate national carbon dioxide emission limits in the coming years will fail, says a leading conservative thinker, because the carbon limits set by government just won’t work.

“I believe COP26 is going to fail. Climate policy globally is [failing] and is going to continue to fail unless they change their policy paradigm,” said Rod Richardson, co-founder of the Clean Capitalist Leadership Council and president of the Grace Richardson Fund, a North Carolina-based nonprofit dedicated to creating free-market policies to solve issues locked in partisan gridlock.

Speaking during a webinar presented by OurEnergyPolicy, Richardson continued, “I agree with Gretta Thunberg that the leaders are failing, but they are failing because they are using the wrong paradigms. They’re using market-based paradigms that are punishment-based.

“They impose costs on people. They raise prices. They raise inflation. They diminish the number of jobs. They make it so that throughout the economy, [fewer] businesses can succeed because their costs are higher.”

Richardson, a champion of “clean capitalism,” was responding to questions about the meaning of “free market” posed by moderator Edward Morse, managing director and global head of commodity research at Citigroup.

Drew Bond, co-founder and president of C3 Solutions (Conservative Coalition for Climate Solutions) and former chief of staff for the Heritage Foundation, argued that limited government is crucial to a “cleaner” environment.

Citing Heritage’s Index of Economic Freedom, Bond said that “over the course of almost 30 years, you see that countries around the world that are more economically free are actually also more clean. …

“I think there is a misperception that when we talk about free markets, we mean simply no government. That’s not the case. We’re talking about limited government. We’re talking about the appropriate roles for government. Fundamentally, the question is: Can businesses compete unimpeded by the government? When you see that happen around the world, you see tremendous prosperity. You see a great environment,” he concluded.

Katie Tubb, senior policy analyst at Heritage, backed up Bond’s assertions. “Data can tell you a lot of things. The data just bears out that economically free countries can afford to care about the environment. That is the trend that we need to pay attention to.”

Tubb pointed to the shale gas revolution that occurred in the U.S. Driven by small, independent drillers rather than the multinational oil and gas companies, its impact made national headlines beginning in 2009, less than a decade after natural gas prices hit record highs, setting off a national crisis that “basically disappeared,” she said.

The shale revolution has attracted a lot of overseas investment in the U.S., she added. “In the next year or two, we’re going to see three new hydrocarbon fracking plants open up in the United States, in parts of the country that could use some serious economic reinvestment.”

Tubb also pointed to the role that cheap natural gas produced in Pennsylvania — a state in which electricity markets are deregulated — in lowering power prices compared to the national average.

“Natural gas went from an irrelevant source of generation to now over half of the state’s power generation,” she said, a reference to the growth of combined cycle gas turbine plants that easily produced less expensive power than old coal power plants.

Posted on

Avangrid ‘Focused on Defeating’ NECEC Referendum

Avangrid (NYSE:AGR) is “focused on defeating” next month’s Maine ballot referendum designed to halt construction of the New England Clean Energy Connect (NECEC) transmission line, CEO Dennis Arriola said Wednesday.

Construction is “well underway” with more than 100 poles installed, Arriola said during a third-quarter earnings call, adding that towns in the path received the first tax payment from the project. A “grassroots campaign” is also underway to sway voters in Avangrid’s direction on the referendum.

Avangrid remains encouraged by the support for NECEC over the last several months as the company attempts to combat what it calls “misinformation” spread by “companies that own fossil fuel generation in New England,” he said.

“We’re focused on defeating the Nov. 2 referendum related to the project, and our growing grassroots campaign is working hard every day to help voters better understand the benefits of the project to Mainers, the economy, the environment and the region,” Arriola said.

NECEC supporters include current Democratic Gov. Janet Mills, former Republican Gov. Paul LePage, labor leaders including the AFL–CIO, Maine chambers of commerce and the Conservation Law Foundation, “just to name a few,” Arriola said.

“There are winners and losers” in the clean energy transition, he said.

“In this case, the winners from this project are going to be the people of Maine, the environment, the local economies, climate change [opponents] in total. But the losers in this are going to be those that basically are providing the fossil fuel generation.”

Energy infrastructure projects, including transmission, often face challenges, and “the challenge is that there are certain parties that may not want that because it impacts their livelihood,” Arriola said.

In addition to the referendum, the Maine Department of Environmental Protection (DEP) held a hearing recently to determine whether it should revoke the permit to construct the NECEC transmission line.

There is no deadline for the decision in the DEP proceeding. Still, the agency can temporarily suspend the construction permit or revoke it entirely, forcing an application for a new one. DEP Commissioner Melanie Loyzim opened the proceeding after a Maine Superior Court ruling in August vacated a 1-mile public land lease to Avangrid subsidiary Central Maine Power. Loyzim said the court’s decision represented a change in circumstance that could warrant a permit suspension. (See Maine Regulators Hear from CMP, Residents on NECEC Permit.)

PNM Merger, OSW Talk

Avangrid is “on track” to close its multi-billion dollar merger with PNM Resources by the end of the year, with just one approval remaining from the New Mexico Public Regulation Commission. Arriola said that 23 of the 24 filing interveners either support the merger directly or have decided not to oppose its approval.

Arriola also touted Vineyard Wind I securing $2.3 billion of construction and term loan financing with nine global lending banks, becoming the first commercial-scale offshore wind project in the U.S. to reach financial close. Construction already has started for the onshore substation and export cable routes, and Arriola said offshore construction will begin in the first half of 2022. “We’ll start delivering clean power to Massachusetts in 2023 and reach full commercial operation in 2024.”

Earnings

Avangrid reported earnings of $111 million ($0.29/share), up $24 million from the same period in 2020 ($0.28/share). Avangrid Networks earned $116 million during the quarter, up from $94 million in September 2020. Avangrid Renewables posted earnings of $12 million during the quarter, down from $25 million in September 2020.

For the first nine months of 2021, consolidated net income was $543 million ($1.56/share), compared to $415 million ($1.34/share) for the first three quarters of 2020.

Call transcript courtesy of Seeking Alpha.

Posted on

SPP, Members Begin Response to February’s Winter Storm

SPP staff and stakeholders agreed this week on the need for greater collaboration and coordination between the electric and gas industries as they begin the work of addressing the root causes that led to the first load sheds in the RTO’s 80-year history during February’s winter storm.

The discussion picked up where the Markets and Operations Policy Committee left off two weeks ago, when Texas-based stakeholders complained they had firm contracts for fuel deliveries that were negated by force majeure. (See SPP Markets and Operations Policy Committee: Oct. 11-12, 2021.)

“This happened in 2011, and it will happen again,” Southwestern Public Service President David Hudson said during Monday’s joint quarterly stakeholder meeting, referring to a less severe winter storm that also led to rolling blackouts in Texas. “That’s one of the biggest things hiding in the tall grass that’s not being addressed.”

“We can do everything we can to promote coordination between the industries, but better coordination only gets us so far,” Kansas Corporation Commissioner Andrew French said. “The winterization and the lack of production is the bigger issue.”

French said FERC’s and NERC’s preliminary report on the storm contained numerous “aspirational goals” that individual states begin winterizing all their equipment. The agencies’ joint inquiry placed much of the blame on the natural gas industry’s failure to perform. (See FERC, NERC Share Findings on February Winter Storm.)

“No state is going to step forward and place costs on their producers absent an act of Congress, and I don’t think we can rely on it,” French said.

North Dakota Public Service Commissioner Randy Christmann pointed out that northern energy facilities have been weatherizing for years, but that it doesn’t make sense to do so in southern states “because of the costs of winterization … for those few days when it’s needed.”

“We almost seem to be resigning ourselves that we can’t do much about gas weatherization,” said Dave Osburn, Oklahoma Municipal Power Authority’s general manager. “I just hope we as an industry don’t let the issue go. We have to continue to push this issue, because we certainly don’t want to live through another event like this.”

To that end, SPP COO Lanny Nickell said staff and stakeholders have begun developing recommendations addressing the February outages’ root causes. The Board of Directors ordered the work begin immediately when they accepted SPP’s report on the winter storm in July. (See “Grid Operator Releases Report on Performance During Winter Storm,” SPP Board of Directors/Members Committee Briefs: July 26-27.)

Arkansas Public Service Commission Chair Ted Thomas is leading a task force working on issues related to fuel assurance and resource planning and availability, which the report identified as a Tier 1 issue. The Improved Resource Availability Task Force (IRATF) will report to the board and the Regional State Committee and publish monthly status reports on its work. The group will review staff’s potential solutions and recommendations, provide direction and coordinate with other stakeholder groups as necessary.

“It’s like Thanksgiving when all the food hits the table at the same time,” Thomas said. “You keep the wet stuff wet, the hot stuff hot and the cold stuff cold.”

He said the IRATF’s first efforts could include identifying crucial gas infrastructure that is connected to the electric system, similar to Texas’ attempt to map critical infrastructure.

Nickell said the report’s 81 Tier 2 and Tier 3 initiatives are all in progress, except for those related to transmission planning. The work will be prioritized, tracked and reported through SPP’s comprehensive roadmap process, which sets the grid operator’s initiatives over the next two to five years.

“We don’t want to wait on FERC and NERC,” Nickell said, noting that SPP’s effort “aligns pretty well” with the agencies’ final report.

Completing all the initiatives is expected to last several years, Nickell said.

“As we go forward with the initiatives, we’re going to have to be clear about what SPP can do and cannot do and who has authority over the gas system,” Nebraska Power Review Board Member Dennis Grennan said. “We’re going to have to be very, very clear about how far SPP can go with its solutions.”

SPP Sets New Summer Peak

Bruce Rew, SPP’s senior vice president of operations, told stakeholders that the RTO set a new summer peak load of just over 51 GW on July 28, surpassing the previous record of 50.7 GW set in August 2019. 

SPP called for conservative operations July 29-30 as summer heat continued to bake the Great Plains. Wind energy reached a high output of 20.7 GW on Aug. 8, accounting for 52.2% of SPP’s load at the time. Wind penetration reached 65.3% of the RTO’s generation mix on Sept. 26, when wind produced 14.8 GW of the total load of 22.7 GW.

Rew said 30.5 GW of wind generation is registered in the market, although only 25.8 GW was available as of Oct. 1. He said SPP currently has 283 market participants, with financial-only players outnumbering asset-owning participants, 181-102.

The Western Energy Imbalance Service market’s second quarter saw average hourly load trended slightly downward by 0.2 GWh. The WEIS market is consistently settling an average of 4 to 5 GWh of net energy imbalance generation per day, Rew said.

Sugg: In-person Meetings Soon

SPP CEO Barbara Sugg teased a potential return of in-person meetings in January in acknowledging that “we all have Zoom fatigue.”

Sugg said the MOPC and Strategic Planning Committee will meet Jan. 10-12 in Oklahoma City, and the board and Members Committee will meet Jan. 24-25 in Little Rock, Ark.

“We hope to see you there,” Sugg told stakeholders.

SPP is once again in a return-to-office mode after a previous attempt was scuttled by the COVID-19 Delta variant’s emergence. Staff have begun a hybrid workplace format that allows more flexibility to work from home while still coming to the office. Employees must spend 50% of the time in the office and managers 75% in the voluntary program. Chief People Officer Kelly Carney said an average of 70 staffers can be found daily on the SPP campus.

Sugg also said SPP has begun preparing to claw back and refund $138 million in transmission-upgrade credits, dating as far back as 2008, as it waits on a response to its rehearing request of the D.C. Circuit Court of Appeals’ August ruling that FERC was correct in reversing a retroactive waiver it had granted the RTO over collecting transmission upgrade costs under the tariff’s Attachment Z2. (See “SPP Asks for Z2 Rehearing,” SPP Markets and Operations Policy Committee: Oct. 11-12, 2021.)

“Our favorite topic from years gone by that we can’t get rid of … the gift that keeps on giving,” she said. “This will be a major undertaking for SPP and our stakeholders.”

RSC Elects New Leadership

The RSC met briefly before the quarterly stakeholder reports and elected its leadership for 2022.

SPP’s state regulators approved North Dakota Commissioner Christmann as their president. He succeeds South Dakota Public Service Commissioner Kristie Fiegen, who will remain on the committee.

KCC Commissioner French will serve as vice president, and Iowa Utilities Board Member Geri Huser will remain treasurer. The committee will lose Grennan, who was honored with a resolution for his six years of service. Grennan was the RSC president in 2020 and also served on several high-level SPP stakeholder groups.

“The last six years on the RSC have gone by so fast it’s really unbelievable,” Grennan said.

Grennan is term-limited, and his tenure on the NPRB will end Jan. 1. He is expected to be replaced on the RSC by NPRB Vice Chair Chuck Hutchison.

Oklahoma Corporation Commissioner Dana Murphy said the Seams Liaison Committee’s rate-pancaking subgroup has sent surveys to 100 MISO and SPP stakeholders and the RTOs themselves as it attempts to resolve rate issues on the RTOs’ seam. The SLC meets again Nov. 18 to discuss the survey’s results.

Murphy volunteered to represent SPP on the SLC subgroup when former Texas Public Utility Commission Chair DeAnn Murphy resigned from the commission earlier this year.

Posted on

DTE, CMS Oppose Michigan Community Solar Legislation

LANSING, Mich. — Solar energy advocates squared off against Michigan’s largest utilities this week when a legislative committee heard testimony on legislation requiring the state Public Service Commission to promulgate rules for community solar projects.

Executives for CMS Energy (NYSE:CMS) and DTE Energy (NYSE:DTE) said their companies support and are developing solar energy. But they told the Michigan House Energy Committee Wednesday they opposed HB 4715 and HB 4716 because the bills would increase costs to consumers and weaken consumer protections.

The bills’ supporters, who numbered in the dozens before the committee — though most did not testify — said the legislation is needed to ensure smaller projects are developed in rural and poorer areas the utilities might be less interested in developing.

Committee Chair Rep. Joe Bellino (R) has not indicated yet when and whether he will move forward on the bills. In comments during the hearing, Bellino seemed sympathetic to the bills’ idea and urged fellow committee members to tour a community solar project built by Lansing’s municipal utility, the Board of Water and Light.

Bellino, DTE and CMS have been criticized for holding up a separate bill that could expand rooftop solar in Michigan. Bellino’s campaigns have been supported by utility political PACs and individual executives. In the 2020 election, his campaign got $6,000 from the CMS Energy Corporate Employees PAC. Some 30 utility executives, including the then-presidents of both CMS and DTE, contributed from $250 to $1,000 to his campaign.

The two bills are a bipartisan package, with HB 4715 introduced by Rep. Rachel Hood (D) and HB 4716 by Rep. Michele Hoitenga (R).

Hood said the bill give residents a “real opportunity to save on energy bills,” and “equally important” it lets consumers choose the type of energy they use.

HB 4715 requires the PSC to write rules allowing for the creation and financing of community solar facilities and providing bill credits to subscribers. The bill also allows utilities to recover “reasonable interconnection costs” for projects and for handling a community solar subscription base.

HB 4716 creates a new section in Michigan utility law covering community solar facilities and requires a utility to provide bill credits for at least 25 years of the community solar project’s operation.

Two days before the committee meeting, CMS and DTE held a press conference to announce the “MI Community Solar Program,” which would provide subscriber credits to any customer who signs up for the projects run by the utilities. CMS has two in operation, one at Ferris State University and the other at Western Michigan University, with a third being developed in the northern city of Cadillac. DTE has several in metro Detroit. The utility is also developing a community solar project in Ann Arbor that was announced earlier this month.

Spokespersons at the press conference raised some of the issues, such as out-of-state developers coming into Michigan, they would repeat at the committee hearing. When asked about HB 4715 and HB 4716 at the press conference, Knox Cameron, a DTE manager of renewable energy, said, “We’re supportive of the growth of renewables” but that the utilities’ program is already deploying projects.

DTE Vice President for Renewables Chuck Conlen told the committee the bills were not needed and would “expose Michigan to the pitfalls of deregulated electric” suppliers. The utilities can produce power at lower cost, he said.

Sara Nielsen, CMS’ director of transportation, renewables and storage, said the bills “will effectively force the utilities to subsidize other projects at less defined prices.”

In all, she said, the bills will create a “less equitable, less affordable” system.

Also opposing the bills, but not speaking at the hearing, were the Michigan Manufacturers Association, the Mackinac Center for Public Policy, and the Utility Workers Union of America.

Ed Rivet, head of the Conservative Energy Forum, said the two bills help fill in gaps left by the utilities’ projects. What DTE and CMS are doing is needed, Rivet said, and they will create cheaper energy.

But the bills will assure that smaller areas can take advantage of solar energy too. The big utilities “won’t go into the small places where we need them,” Rivet said. “They won’t go into the niche places.

“This legislation empowers both big and small” projects, he added.

Among those supporting the legislation, but not speaking, were officials from the Michigan Catholic Conference, the Associated Builders and Contractors, the Michigan Municipal League, the Michigan Chemistry Council, the Citizens Utility Board of Michigan and the Michigan United Conservation Clubs.

Posted on

Xcel Continues Focus on Carbon Reductions

Xcel Energy (NASDAQ:XEL) CEO Bob Frenzel revealed Thursday that there is little space between him and his predecessor when it comes to the clean energy transition.

Speaking with financial analysts during the company’s third-quarter earnings conference call, Frenzel noted Xcel’s leadership position in clean energy under Ben Fowke, who retired earlier this year, and promised more to come.

“We expect, over the next decade, to close the majority of the coal plants on our systems across the country. We’ll be out of coal in the Upper Midwest by the end of this decade,” he said. “We have plans and approved plans to close a coal plant almost every single year this decade.”

Asked how Xcel’s plan to be carbon-free by 2050 could be accelerated, Frenzel said the Democrats’ proposed budget reconciliation bill includes production tax credits for renewable energy that offer a 10-year window to manage the transition.

The company’s integrated resource plan recently filed with Minnesota regulators envisions a full exit from coal by 2030, balanced by the addition of 3.2 GW of universal-scale solar and 2.7 GW of wind. Xcel has targeted an 85% carbon-reduction in Colorado, its other major market, by 2030 with a similar plan.

“Come 2024, we’d have another bite at the apple to think about the remaining assets on our fleet in those transitions,” Frenzel said. “I think what we need is another type of emissions-free generation.”

He said legislation pending on Capitol Hill would expand the U.S. Department of Energy’s funding for research and development. “I think that’s critical for the industry to progress past where we expect to be,” Frenzel said.

Xcel reported earnings of $609 million ($1.13/share) for the quarter, compared to $603 million ($1.14/share) for the same period in 2020.

The results missed analysts’ average expectations of $1.18/share. Xcel said higher electric and natural gas margins and lower operations and maintenance expenses offset additional depreciation and lower allowance for funds used during construction.

The Minneapolis-based company narrowing its 2021 earnings guidance to $2.94 to $2.98/share and issued 2022 guidance of $3.10 to $3.20/share.

Xcel’s share price gained 94 cents Thursday, closing at $64.33.

AEP Earnings up over 2020

American Electric Power (NASDAQ:AEP) also released its third-quarter results Thursday, reporting earnings of $796 million ($1.59/share), above last year’s third quarter of $748.6 million ($1.51/share).

AEP CEO Nick Akins highlighted the energizing of the 287-MW Maverick Wind Energy Center, the second of three proposed North Central Energy Facilities. The three wind farms will eventually provide 1,485 MW of clean energy. (See AEP a Go with $2B North Central Wind Project.)

The company also announced Tuesday it has entered into an agreement to sell its Kentucky operations to Algonquin Power & Utilities for $2.85 billion. (See AEP to Sell Kentucky Operations to Algonquin.)

“Transforming the way energy is generated, delivered and consumed is necessary to support the needs of a clean energy economy, and AEP continues to drive that transformation for the benefit of our customers and communities,” Akins said.

The company’s share price was trading at $84.77 in after hours Thursday, a gain of 47 cents on the day.

Posted on

Heat Pump Market Flourishes in Maine’s LMI Communities, Official Says

Maine is hitting a “tipping point” in its campaign to deploy 100,000 air source heat pumps by 2025, and much of that success has been in low- to medium-income households, according to Michael Stoddard, executive director of the Efficiency Maine Trust.

“We’re concentrating a lot on equity issues and how we can make sure that this [technology] is accessible to LMI homes and small businesses,” Stoddard said Thursday at the New Buildings Institute’s Getting to Zero Forum.

In January 2020, Gov. Janet Mills announced a suite of expanded heat pump rebates, including $2,000 for LMI homeowners in the Low Income Home Energy Assistance Program. That amount is double what other homeowners can receive for installing a qualified high-performance heat pump.

“We’re installing thousands per year for the LMI community,” Stoddard said, which is evidenced by a study of installation rates by region.

The densest heat pump penetrations are in the northern, sparsely populated areas of the state, where the median income is low, according to Stoddard. That outcome, he said, “is attributable to savvy customers, who are motivated to think about how they’re going to heat their homes.”

Maine surpassed 75,000 total heat pumps last year and installed 28,000 in 2020 alone, he said, adding that the state is on track to reach 180,000 installations by 2025. But it has a loftier goal of 500,000 installations by 2030, so Stoddard says market momentum is critical right now.

“The good news is that we’ve established that we can get on the trajectory we need to be on,” he said. “The big question is going to be, can we sustain it?”

To ramp up Maine’s heat pump market, Efficiency Maine had to demonstrate that the technology works in cold climates and establish a strong installer network. The agency has more than 1,000 registered heat pump vendors, according to Stoddard. Vendors must be trained and certified and sign a code of conduct, he said, and Efficiency Maine set “very high standards” for approved heat pump models.

“There are many models out there that won’t do well in cold weather,” he said, adding that approved systems can make heat down to ‑20 degrees Celsius in some cases and are highly efficient above 0 C.

An Efficiency Maine survey found that 20% of newly constructed homes in the state over the last three years had heat pumps as the sole heating source. Another 17% had heat pumps with a fossil-fuel system as backup.

For retrofits, Stoddard said, people are putting in one or two heat pumps to displace as much of their central system as possible but keeping the central system as backup. The different systems, he added, compete with each other.

“It would be vastly more economical and better for the environment if the heat pumps would run all the time, and then the central heating would only come on as needed,” he said. “But the thermostats call when they call, and we have to teach consumers how to optimize that.”

Relatively low electricity prices in Maine have helped show the economic benefit of choosing heat pumps. The state’s rates have been at 17 to 18 cents/kWh, while other parts of the Northeast pay 23 to 24 cents/kWh, Stoddard said.

Heat pumps also are competing with high-priced heating fuels.

“A lot of our homes and businesses are heated with oil and propane, and that makes the economics of heat pumps quite strong,” he said. “It’s much tougher against natural gas prices, but given the price swings that we’ve experienced in our state with oil and propane, customers are quite interested in options.”

If heat pumps are going to continue to compete on price, Stoddard says policymakers need to be cautious about how they seek to pay for climate solutions.

“If policymakers and advocates think they’re going to load up all the solutions for climate change by putting that cost on ratepayers, you have to ask yourself if that’s going to be sending the right price signal to electrify,” he said. “I’m not convinced that that’s the best way to pay for it.”

And rebates cannot be a long-term solution either.

When it’s “politically palatable,” Stoddard said, states should put codes and standards in place that call for heat pumps over polluting systems that “frustrate” climate goals.

Posted on

NJ Launches Grid Modernization Study

Rapidly growing solar and offshore wind generation will require a modernization of New Jersey’s distribution interconnection process, the Board of Public Utilities (BPU) said Tuesday as it held the first hearing in a seven-month study of how best to prepare for the extra stress.

The agency said it plans to conclude the study in May with recommendations. The topics to be studied will include an assessment and modernization of the processing of interconnection requests, identifying the challenges with the current connection system and looking for ways to improve coordination with PJM, said Guidehouse, a global energy consultant hired to lead the project.

The BPU’s hearing notice said the scope will include “the current distribution grid interconnection policies and process, and potential improvements that will enable faster grid modernization and higher levels of distributed energy resource (DER) absorption.”

New Jersey law sets different review procedures for electric distribution companies: Level 1 for inverter-based customer generation of 10 kW or less; Level 2 for customer generation of 2 MW or less, and Level 3 for customer generation that doesn’t qualify for Level 1 or 2.

The second hearing, on Nov. 16, will be devoted to testimony from environmentalists, energy developers, trade groups and other stakeholders on potential improvements. The BPU expects to have a draft report prepared for public review on March 1.

The initiative stems from the state’s Energy Master Plan, and Gov. Phil Murphy’s commitment to set the state on a path for 100% clean energy by 2050, said Jim Ferris, the BPU’s bureau chief for new technology.

“To enable clean energy to be generated at an accelerated pace, and as effectively and efficiently as possible, New Jersey’s interconnection rules and processes require updating,” Ferris said as he opened the hearing. Modernization strategies outlined in the masterplan include “requiring utilities to establish integrated distribution plans and the modernization of interconnection standards,” he said.

Clean Energy Growth

The 290-page master plan describes grid modernization as the “backbone on which all other efforts to transition to a clean energy economy will rely.” The plan sets a goal of 32 GW of solar generated electricity, 11 GW of offshore wind and 9 GW of storage by 2050.

The state currently has about 3.65 GW of solar energy generating capacity, and the BPU has awarded offshore wind contracts totaling 3.758 GW, including 2.658 GW awarded in June. (See NJ Awards Two Offshore Wind Projects.) The BPU expects to make three more rounds of offshore wind awards by 2033 for a total of 7.5 GW.

Industry stakeholders, among them developers and environmentalists, welcomed the BPU’s initiative in seeking stakeholder input into the modernization process.

Under the current process, a customer proposes a clean energy project and submits an interconnection application and agreement to tie the resulting project into the grid. The electric distribution company (EDC) then identifies and installs network upgrades, if needed, and the customer receives approval to install the project. After a final inspection, the developer seeks approval to operate.

Eric Miller, energy policy director in New Jersey for the Natural Resource Defense Council, encouraged the BPU to look beyond the interconnection process and consider a broader array of issues. Factors such as the charging load from electric vehicles and building electrification, energy storage, demand response, and peak load reduction should all be considered in the modernization discussion, he said, adding that “it touches on everything that’s grid connected or could interact with the grid.”

Steven S. Goldenberg, representing the New Jersey Large Energy Users Coalition, said one difficulty for solar developers is that while the BPU initiates a two-year timeline from the start of a project to approval, PJM operates on a timeline as long as three years. “So, the disconnect can be critical for certain project developers.”

Questions over Resources, Timelines

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said a key concern of his members is what they see as the lack of resources at EDCs to handle the growing number of solar connections that need to be made, which results in significant project delays.

“It’s a huge problem because of the number of applications,” he said. While the EDCs are responsible for interconnections, the resulting increase in solar energy could reduce demand for the EDC’s power, he said.

“What we’re asking them to do is to hire more people and to put resources in so that they can get less revenues,” he said. “It’s an irrational process.”

DeSanti said his organization would also like the hearings to focus on “cost sharing,” with an aim of creating a set of standardized per-KW fees paid by developers, with the understanding that costs not covered by that would be borne by ratepayers.

Scott Elias, senior manager of Mid-Atlantic state affairs for the Solar Energy Industries Association, said that as the number of projects arriving at the EDCs grows — especially larger and more complex developments — there is a need for the utilities to “pre-screen” them to assess the interconnection costs in advance.

“We’ve seen this play out in other states where this helps reduce the number of speculative applications and it also helps prioritize projects,” he said. He also suggested that the state set up a uniform set of interconnection fees for solar projects based on market segment type and size.

“What we need is to provide certainty to developers of big systems, that their interconnection costs will be manageable and give them the security they need to move forward with their projects,” he said.