After achieving its Better Buildings goal in 2020 to its reduce energy use by 20% across its 9,000-store portfolio, Walgreens (NASDAQ:WBA) is looking ahead at new opportunities to make its operations more efficient.
Walgreens became a Better Buildings Challenge partner in 2011 and reached its goal last year by focusing on HVAC and LED retrofits and more recently launching a refrigeration replacement program, according to David Hughes, senior director of facilities and energy management.
Reducing energy “over 100 million square feet of Walgreens footprint is not an easy needle to move,” Hughes said Thursday during the closing plenary session for the U.S. Department of Energy’s Better Buildings, Better Plants Summit.
Now, the company is focusing on an internal smart buildings program that taps data for efficiency measures beyond retrofits.
“Managing thousands of stores across a huge footprint gives us a small city to make sure that we’re operating as efficiently as possible,” Hughes said. “Putting as much technology and automation in these stores over hundreds of thousands of assets and leveraging that data to help guide our decisions … is the best way to keep bending the curve on our consumption.”
Walgreens has rolled out about one-third of its smart buildings program and has a few more years to go before it is completed.
“Having an intelligent building platform is critical to setting the stage to identifying the right next strategies that are going to help us build upon our strong foundation of energy efficiency,” he said.
Walgreens, which debuted the net-zero store seen here in Illinois eight years ago, met its Better Buildings goal this year to reduce energy 20% across its 100 million-square-foot portfolio. | Walgreens
Walgreens hopes to look at the power it uses to understand its stores’ baseload requirements better. With that data, Hughes said, the company could deploy distributed generation technologies in the near term to ensure stores remain open during emergencies as critical infrastructure.
Based on its stores’ current power needs, Hughes said the right DG solution for smaller loads is not available yet.
“Many of the scale technologies that are out there operate in the 100-kW to 250-kW block, and that’s way above our load,” he said. “We’re at about 60 kW to 70 kW on average in a store.”
Procter & Gamble (NYSE:PG) is also looking at new energy challenges after 11 years as a Better Buildings partner. The company, which owns iconic brands like Downy, Head & Shoulders and Tide, is building on the success of collaborative efforts like the Renewable Energy Buyers Alliance.
P&G set a goal in 2010 of using 30% renewable energy by 2020, which it reached, according to Steve Skarda, GHG and energy director. But tackling natural gas emissions associated with manufacturing is a much bigger challenge than the transition to renewables was, he said.
“We’ve covered all the emissions that we can eliminate with renewable electricity and efficiency and [carbon] offsets this decade, so we are net zero today, but that’s not the long-term vision,” Skarda said.
P&G is participating in the Renewable Thermal Collaborative and trying to identify the role electrification will play in the organization and how best to tap new technologies, such as hydrogen and carbon capture.
Two recent orders illustrate how the Hawaii Public Utilities Commission’s growing frustration with Hawaiian Electric Company’s halting progress on clean energy development is matched with an increasingly weak hand in dealing with the utility’s delays.
A new round of back-and-forth between the PUC and HECO began with an April 29 order in which the regulator approved the proposed Kapolei Battery Energy Storage System (BESS), a 185-MW, 565-MWh system to be built on Oahu.
In approving the project, the PUC cited concerns about HECO’s two-year delay in developing other renewable energy projects, which could stall the decommissioning of AES’s coal-fired Hawaii Power Plant (37754). (See Discontent Mounts over HECO Coal Plant Closure Plans.)
“The Commission is approving this Project to provide further assurance that the ‘lights will stay on’ during the retirement of the AES coal plant in 2022 and future retirements of aging fossil-fueled plants in the next several years,” the PUC wrote.
The other order directed HECO to quantify the customer costs stemming from its delays in building renewable energy projects (37752). The PUC said that “due to the ongoing loss of customer bill savings resulting from these delays, the Commission finds it necessary to direct Hawaiian Electric to quantify the magnitude of those lost savings.”
The order requires HECO to “establish regulatory liabilities” to record costs arising from the delays of Stage 1, Stage 2 and Community Based Renewable Energy (CBRE) Phase 1 projects.
The PUC made its frustrations clear in the BESS order: “Despite the Commission’s multiple admonitions to utilize standalone storage fueled by fossil fuels as a last resort, Hawaiian Electric appears to continue ignoring the high costs of this Project and attendant risks of further dependence on fossil fuel by their representations throughout this docket.”
It added that “the urgency of this situation is largely a byproduct of Hawaiian Electric’s willful disregard of the Commission’s guidance and presents a number of concerning impacts to ratepayers.”
The PUC approval of the BESS came with nine conditions, including:
a prohibition on HECO seeking cost recovery through performance incentive mechanism (PIM) awards for Stage 1 projects;
removal of requirements for energy storage on Phase 2 CBRE projects on Oahu, expanded CBRE capacity, and removal of daytime export restrictions for existing and new distributed energy resources programs;
commitment to closure dates for fossil fuel units at HECO’s Waiau and Kahe facilities;
submission of monthly reports on the amount of fossil-fuel energy stored in BESS and how much the facility is being used;
adherence to a PUC-mandated minimum threshold for renewable energy charging for BESS, or face penalties for failing to do so;
prohibition of HECO affiliates from having a relationship with BESS;
creation of an annual utilization report that includes an explanation for any missed milestones;
creation of an “end-of-life management plan” for BESS;
crediting of all daily delay damages to HECO customers.
‘Highly Problematic’
HECO and BESS developer Kapolei Energy Storage I (KES) filed separate motions for reconsideration of Order 37754.
In its motion, HECO said while it understood the need for some of the conditions, “at least four are highly problematic for reasons that go well beyond the Project.” It argued that the PUC’s approval “is in title only” because the conditions would be tantamount to forcing HECO or KES to cancel the energy storage power purchase agreement (ESPPA).
HECO complained that the rejection of PIM awards for BESS amounts to a $1.7 million loss, what the utility calls a violation of its due process rights. It also contended that removing grid constraints for CBRE would require physical upgrades to the grid, while the “forced financial or operational retirement” of fossil fuel burning units raises financial and grid reliability concerns.
HECO expressed particular concern about the minimum renewable energy charge requirement, saying it would prevent BESS from charging at times when renewable energy is unavailable, and that the requirement for a minimum unlawfully exceeds targets in Hawaii’s renewable portfolio standard (RPS) rules. The condition renders BESS “largely unusable,” and if not removed, “it will mean that the KES Project will have been effectively terminated,” HECO said.
The utility expressed its frustration with the PUC, saying that it is “particularly troubled by the accusatory and derogatory statements from the Commission that have seemed to escalate as of late.” It says that the development of renewable infrastructure is complex and that missteps and differences of opinion can result.
In addition, HECO said that “the Company respectfully submits that the Commission’s unsupported and unnecessarily disparaging characterization of the Company’s planning efforts is erroneous, not supported by fact.” It said many factors contributing to delays were out of HECO’s control, including the PUC’s reviewing time.
“Simply put, this is a good project and one that is needed now,” HECO said.
KES Motion
KES’s motion noted that the ESPPA gives HECO sole discretion to determine whether a PUC approval order is satisfactory and that the PUC’s added conditions could pressure the utility to cancel the deal altogether. The company also expressed worry that the project could suffer additional delays if HECO requested a stay of the approval order. A delay or cancellation of BESS would further jeopardize the planned retirement of the AES coal plant, KES said.
KES also argued that the first five conditions in the order could constitute an abuse of discretion on the part of the PUC, citing a Hawaii Supreme Court ruling as saying such an abuse exists if “an agency’s sudden change of direction leads to undue hardship for those who had relied on past policy.”
The company additionally contended that the PUC took more than eight months to consider BESS, a timeline that forced the company to “redesign and renegotiate its construction and supplier plans and deadlines,” along with dealing with a “global supply crunch” for batteries.
KES also expressed frustration at the PUC’s characterization of the proceedings, saying the company “was deeply disappointed” to see PUC Chair James Griffin equate the charging of BESS with oil-fired generation with the use of crack.
HECO and KES both said that BESS is important for the decommissioning of the AES coal plant, and that the PUC’s conditions are better served in separate dockets rather than being tied to the approval of BESS.
PUC Yields
The PUC on Friday gave ground on most of the conditions, partially granting HECO’s motion for reconsideration while denying KES’s motion as moot.
The regulator’s response eliminated the first (PIM) condition entirely, while removing the second to be reused in corresponding DER and CBRE dockets. In modifying the third condition, the PUC still required HECO to shut down Waiau Units 3 and 4 while removing the requirements for the other units.
The PUC also agreed to modify the fifth condition to remove the minimum thresholds and will instead conduct an annual “prudence” review. The seventh condition will remain but with fewer requirements for HECO’s Annual Utilization Report.
The PUC also denied HECO’s request to strike the “offending” language used in Order 37754, saying it “used pointed language in describing its disappointment with being placed in the position of having few options to respond to the extremely serious situation that is developing as a result of the retirement of the AES coal plant next year” and that “the record in this proceeding clearly supports the Commission’s findings and conclusions.”
After reviewing the PUC’s changes to the modifications, HECO agreed to proceed with the project. However, the utility maintained that it “still disagrees with that certain language and those certain characterizations used” in order 37754.
Proposed rules that would require truck vendors in New Jersey to dramatically increase sales of medium- and heavy-duty electric trucks by 2035 faced vigorous criticism Wednesday, with opponents arguing they would do little to cut emissions because too few electric truck models are currently available and demand for them is low.
Statewide business groups and a national trade association for truck engine manufacturers were among the speakers at a three-hour public hearing on the rules proposed by the New Jersey Department of Environmental Protection (DEP). A key request was that the agency should slow its adoption of the rules so a more thorough assessment of their impacts could be undertaken.
Modeled on California’s Advanced Clean Trucks regulation, the DEP rules mandate that manufacturers meet an escalating series of electric truck sales targets, starting in 2025. Specifically, manufacturers would be required to increase their sales of zero- or near-zero emissions vehicles through 2035, reaching 55% of class 2b and 3 truck sales by 2035, 75% of Class 4 to 8 trucks and 40% of truck tractor sales.
The vendors would also have to comply with a system of credits and deficits based on the proportion of electric trucks manufacturers have to sell in the state, compared to the number of diesel vehicles.
Speakers opposed to the rules said the sales targets are too high, compliance would be too expensive for many businesses and the focus on EV trucks is too narrow and should include trucks that use low-carbon fuels such as renewable natural gas.
Hunter Griffin, policy analyst for New Jersey Business and Industry Association (NJBIA), said he did not expect the proposal to reduce emissions. He encouraged the DEP to extend the 60-day comment period, which ends June 18, by an additional 60 days, in part, to see “how well a California-based regulation applies to the conditions in New Jersey.”
“Technology does not currently exist at scale to allow for the conversion of our trucking fleets across all size categories in the timeframes required,” he said. “And more importantly, there are better options to achieve the emission reduction goals required.”
Heavy Truck Pollution
Yet dissenting voices accounted for only a small proportion of the nearly 40 speakers in the three-hour hearing. Many speakers — among them more than a dozen representatives of environmental groups — praised the DEP for taking a bold, and necessary, step to help mitigate climate change.
“This is exactly where we need to be going,” said Doug O’Malley, director of Environment New Jersey. “It’s critical that these rules are adopted as quickly as possible.”
O’Malley said that child asthma and cancer rates are higher in New Jersey cities than other parts of the state. “A big reason is because of dirty diesel trucks that are on our roads, especially in our cities, and diesel-powered vehicles are 10 times dirtier than gas powered vehicles,” he said.
| Daimler Trucks North America
Alli Gold Roberts, director of the state policy program for Ceres, a non-profit organization that advocates for corporate sustainability, said the rules are the “first of many steps” that the state needs to take to reduce emissions, and help the economy.
“The (rules) will drive local innovation and investment in clean technology development and manufacturing, creating new jobs, driving long-term cost savings and company value chains,” she said. Increased access to “cost effective, zero emission commercial transportation options helps businesses stay competitive.”
Kim Gaddy, the national environmental justice director for Clean Water Action, said that as a mother of three asthmatic children and a resident of Newark, home to a large chunk of the Port of New York and New Jersey, she had no doubt that the rules would help reduce emissions in her neighborhood.
“We suffer from 4500 trucks that travel on our local roads,” she said. “We are positive that the (rules) will work to establish zero-emission zones and zero-emission long haul trucks that we need today.”
The proposed rules are designed to help move New Jersey toward Gov. Phil Murphy’s goal of zero carbon emissions by 2050. Transportation accounts for 42% of carbon emissions in the state, and emissions from heavy trucks are a big contributor. The state’s master plan, released in 2019, assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050.
The DEP estimates that the rules will reduce carbon emissions by 2.6 million metric tons from 2024 to 2040. So far, few electric trucks are on the road in New Jersey, especially the largest models. Truckers and their trade associations say that electric trucks are still too expensive — two to three times the cost of a diesel truck — and the 250-mile maximum distance they can cover on a single charge is too short for many uses.
Truckers also say there is a very limited number of electric truck models on the market, and a similarly low number of heavy-duty charging points around the state to support the vehicles’ use. (See NJ Looks to Boost Heavy-duty Charge Points.)
However, recent studies have suggested that the lower repair, fuel and maintenance costs of an electric vehicle, mean that in the longer term they can be more cost effective.
Demand for EV Trucks
The proposed rules would apply to the manufacturers of all vehicles larger than 8,500 pounds who sell more than 500 vehicles in New Jersey annually. (See NJ Outlines Plan to Boost EV Truck Sales.)
Under the rules, manufacturers would accrue “deficits” based on their sales in New Jersey of trucks that are neither zero-emissions or near-zero emissions vehicles. The deficits are calculated based on factors including the model year, the weight class group and whether a vehicle is considered a tractor.
Echoing Griffin, Timothy A. French, of the Truck and Engine Manufacturers Association (EMA), urged the DEP to hold off adopting the rules for a year, until the full impact of the rules can be assessed, and it becomes clear whether President Biden’s administration will create a federal program to boost the uptake of electric rucks.
“New Jersey should be a leader in advocating for those federal programs,” French said. “Without them there’s a significant risk that New Jersey fleets will simply keep their older, higher emitting products longer,” or they will buy non-electric vehicles out of state, adversely impacting the New Jersey economy and environment.
He said that under the DEP proposal “there is no obligation on any fleet operator to buy the higher priced products that EMA members would be obligated to sell.” And he added that to achieve a sales increase, the state needs a stronger network of charging infrastructure, and an incentive program that will help offset the upfront cost of electric trucks.
Brett Barry, senior policy advisor for Clean Energy, a provider of natural gas motor fuels, was also skeptical that the rules would yield a dramatic increase in sales, saying that “you cannot simply increase demand by placing a mandate on the supply side of the market.”
“A sales mandate without a fleet adoption mandate ignores basic market principles,” he said, noting that the adoption of EVs of all types is still slow. He proposed a change in the rules, which he called a “safety net,” to allow the purchase of non-electric vehicles that use low-carbon fuels “if dedicated electric vehicle compliance is not feasible.”
The low-carbon option would enable the uptake of electric trucks in the state to grow “without foregoing emissions reductions in the near term, should EV technology in the heavy-duty sector not advance as quickly as some expect,” he said.
Barry added that Amazon has said it will be using renewable natural gas (RNG) trucks to reduce emissions, as has the Los Angeles County Metropolitan Transportation Authority and Metropolitan Transportation Authority in New York.
High Price Tag
Elvin Montero, director of communications for the Chemistry Council of New Jersey, said that while his members — including more than 60 manufacturers — support the goal of reducing carbon emission, the penalty for doing so under the proposed rule would be too high.
“Many of the companies we represent continuously spend capital modernizing their fleet of vehicles,” he said. “Many even have an electric truck or electric vehicles among their fleet.”
The fleets are already expensive due to the additional safety compliance rules they face and are “quite efficient,” he said. “The challenge comes when a regulation forces a business to abandon these efficient trucks for electric versions that can add up to $30,000 to the cost of just one new truck without any meaningful contribution to the reduction of emissions.”
Ben Mandel, northeast regional director for CALSTART, a nonprofit organization that works with businesses and governments to develop clean, efficient transportation solutions, welcomed the rules, but suggested the state could help reach the EV truck sales targets with a voucher system to provide financial incentives to support the purchase of electric trucks. That could be similar to the state’s Zero Emission Incentive program (NJ ZIP), which awards incentives of up to $100,000 for the purchase of medium-sized electric trucks, he said. The program would also benefit if the state enacted a “truck fleet purchase requirement,” to mandate the purchase of electric vehicles, he said.
“We feel that regulatory requirements,” such as the sales target rules, “send a decisive market signal that calibrates investment priorities for manufacturers, fleets and financiers alike,” he said.
PJM ratepayers will likely see capacity prices drop as a result of Dominion Energy’s decision to exit the market, according to a report released by the RTO’s Independent Market Monitor on the eve of the long-awaited Base Residual Auction.
Monitoring Analytics’ report, released Tuesday, a day before the beginning of the BRA for delivery year 2022/23, concluded that Dominion Energy Virginia ratepayers could see either dramatic cost increases or modest reductions as a result of the utility’s decision to leave the RTO’s capacity market and institute a fixed resource requirement (FRR).
Dominion confirmed earlier this month that it chose the FRR option for the 2022/23 delivery period for more than 60 of its generating units, totaling more than 18.1 GW. That number represents about 11% of the 163.6 GW that cleared in PJM’s 2021/22 BRA in May 2018, the last time the auction was run. (See Dominion Opts out of PJM Capacity Auction.)
The IMM report included a variety of scenarios, two of which it said bracket the likely impact of Dominion’s departure by assuming an FRR is established for the Virginia portion of the Dominion load-serving entity, with the rest of Virginia remaining in the PJM capacity market.
Chesterfield Peaking Station | Dominion Energy
If the Dominion/Virginia FRR area procures its entire capacity obligation at a rate equal to the 2021/22 offer cap for the Dominion Zone ($234.13/MW‐day), the IMM said net load charges for the area would increase by $559.7 million (60.1%) compared to the results of the 2021/22 BRA, assuming Virginia load paid capacity market prices prior to implementation of an FRR.
If the Dominion/Virginia FRR area procures its capacity at equal to the clearing price in the 2021/22 BRA ($140/MW‐day), net load charges would drop $39.9 million (4.3%) compared with the 2021/22 results.
In both scenarios, the Rest of RTO clearing price would drop by $13.21/MW‐day (9.4%) compared to the results of the 2021/22 auction, while the Duke Energy Ohio/Kentucky clearing price would decrease by $11.53/MW‐day (8.2%).
‘Unique’ Situation
The Monitor said its analysis used the same methodology as its earlier reports on the potential impact of the FRR option in Illinois, New Jersey, Ohio and Maryland. (See PJM Monitor Defends FRR Analyses in MOPR Debate.)
But Monitor Joe Bowring said the analysis of Dominion’s FRR is “unique” because it is vertically integrated and subject to cost-of-service regulation.
“The actual price for capacity in Virginia would continue to be the result of the regulatory process, and the actual impacts would be determined by the details of the state regulatory process,” the report said.
“Customers in Virginia pay a net cost of capacity that is a result of regulated cost-of-service rates net of the impact of the sale and purchase of capacity in the PJM capacity market,” the report said. “If customers pay the market price of capacity and receive offsetting revenues equal to the market price of capacity, customers are indifferent to the capacity market price and pay the regulated cost of capacity.”
But the Monitor said it “did not evaluate the extent to which customers currently pay more under regulated rates than the market price of capacity [or] the extent to which customers would lose benefits from the loss of revenues from the sale of capacity in the PJM capacity market.”
In an interview with RTO Insider, Bowring said it’s likely that Virginia ratepayers have paid more for capacity than the PJM market price in the past. “We know for a fact that the overall cost-of-service rate for any power plant is typically significantly greater than the capacity market price,” he said. “I think it’s a fair assumption that they are paying more, but we didn’t actually check that. The key point is they’re paying [cost-of-service rates] now … and the only question is the degree of the offset that the state regulators provide.”
BRA Opens
Wednesday marked the opening of the sell offer window for the 2022/23 BRA after delays resulting from FERC’s expansion of the minimum offer price rule. The auction is scheduled to run until May 25, with PJM posting the results on June 2.
PJM was encouraging participants to submit offers as early as possible, pushing for submissions by Friday so that they could more easily be revised by May 25. It encouraged participants to review the capacity exchange user guide to find more information.
Wednesday’s hearing before the House Energy and Commerce Subcommittee on Energy was nominally about the Department of Energy’s 2022 budget request for $46.2 billion.
But the issue clearly top of mind for many representatives and Secretary of Energy Jennifer Granholm, the hearing’s sole witness, was the recent Colonial Pipeline cyberattack and what actions will be needed to shore up U.S. cybersecurity.
Secretary of Energy Jennifer Granholm | DOE
The pipeline hack “was really a stark reminder of the imperative to harden the nation’s critical infrastructure against these serious and growing threats like ransomware,” Granholm said in her opening statement. “And in the face of an evolving array of 21st-century risks, we have to rethink our approach to security and to reassess the authorities that we can bring to bear.”
The full Energy and Commerce Committee already had responded to the attack — and resulting gasoline shortages — with a spate of bipartisan legislation, announced May 12.
Rep. Bobby L. Rush (D-Ill.), subcommittee chair, talked up the Pipeline and LNG Facility Cybersecurity Preparedness Act (H.R. 3078) he and Rep. Fred Upton (R-Mich.) had re-introduced in the House. Originally introduced in 2019, the legislation would, Rush said, “further strengthen DOE’s ability to respond to physical and cybersecurity threats.”
Under the Energy Emergency Leadership Act (H.R. 3119), sponsored by Rush and Rep. Tim Walberg (R-Mich.), responding to energy emergencies and cybersecurity threats would be elevated as a core function for DOE. The bill is another retread, in this case from 2020.
Rep. Frank Pallone (D-NJ) | DOE
But Rep. Frank Pallone (D-NJ), who chairs the Energy and Commerce Committee, believes more rigorous regulatory action may be needed, similar to the electric industry’s reliability standards developed by NERC and FERC. “No similar rigorous programs exist for pipelines, just a set of voluntary guidelines overseen by [the Transportation Security Administration], and this is a big gap,” Pallone said. “I believe it’s time to consider mandatory, enforceable reliability standards for our nation’s pipeline network.”
At the same time, Republicans such as Rep. Cathy McMorris Rodgers (R-Wash.), ranking member of the committee, framed the gas supply shortage as “a harsh reminder of how important reliable supplies of fuels are for America. It’s a reminder of how critical pipelines are for clean, efficient, secure delivery of the energy people and our economy need to thrive,” she said.
Biden’s “rush-to-green agenda” is a distraction, undermining DOE’s core mission to ensure energy security, Rodgers said.
Building in Cybersecurity
Responding to questions from Rush and Pallone about what Congress can do to further support the DOE on cybersecurity, Granholm pointed first to President Biden’s recent executive order on the issue. Specific provisions include a requirement for information technology providers serving the federal government to share information on any system breach, and an “Energy Star” type pilot program to help identify software that has been developed securely, she said.
The executive order provides “a good signal to industry on what we at the federal level will purchase and use, and therefore may also be guidance for how we might think more broadly,” Granholm said.
Rep. Cathy McMorris Rodgers (R-Wash.) | DOE
She also pointed to efforts to beef up the DOE’s Office of Cybersecurity, Energy Security and Emergency Response (CESER), with the appointment of a new acting director, Puesh M. Kumar, formerly principal manager for cybersecurity engineering and risk management at Southern California Edison.
“CESER has been working on secure manufacturing and innovation, working with our Office of Fossil Energy to ensure cybersecurity is built into new technologies to support the next generation of oil and natural gas infrastructure and systems,” she said.
Rep. Jerry McNerney (D-Calif.) | DOE
Upton also asked if Congress should enact a “minimum standard for critical energy infrastructure” to help prevent future cyberattacks.
“If we had standards in place, would this particular ransomware attack have been able to happen? I’m not 100% sure,” Granholm said. “I do know that having good cyber hygiene, on the private side as well as on the public side, is a critical basic defense, especially for critical services like energy. I think it’s an important consideration for this committee.”
Upton then pressed her on permitting reform and the Democratic climate agenda, which, he said, “would essentially shut down oil and gas production and new pipelines.” Granholm quickly pivoted to transmission.
“We’ve seen so much lag time and so many hoops that have to be jumped through to get critical infrastructure in the ground,” Granholm said, pointing to hundreds of gigawatts of clean energy in transmission queues across the country. “We need to update government processes to make sure that we still protect what we intended to protect in the first place.”
Back to the Budget
Granholm also took some heat, again from Rodgers, on the lack of detail on budget figures in her written testimony for the hearing, and dodged the Republican’s request for a study on the impact of Biden’s climate plan on electric system reliability and consumer energy bills.
The figures available in Granholm’s statement include $1.9 billion for DOE’s Building Clean Energy Projects and Workforce Initiative. Another $8 billion is earmarked for clean energy innovation, and $7.4 billion will go to the Office of Science to increase understanding of climate change and develop new materials and concepts for clean energy technologies of the future. (See Granholm Lays Out DOE’s $46.2 Billion Budget.)
Other highlights include:
Increased funding for a “revitalized Office of Fossil Energy and Carbon Management” that will help advance “technologies and methods such as carbon capture and storage, hydrogen and direct air capture.”
Enhanced research funding for historically black colleges and universities and minority-serving institutions to help build labs and upgrade computer systems, while also creating opportunities for students to develop careers in science, technology, engineering and math.
Funding for DOE programs that “support fossil fuel workers translating their skills to new positions in various areas, from extracting critical minerals from coal mine sites and upgrading pipelines to reduce methane to building carbon capture and hydrogen systems on existing industrial and power plant facilities.”
The question of whether the Colonial Pipeline cyberattack will lead to the passage of bipartisan legislation is, in a sharply divided Congress, uncertain, leaving some — like Rep. Jerry McNerney (D-Calif.) — understandably frustrated.
“During the pipeline shutdown many Americans were waiting in long lines for gasoline, referring to this as a wake-up call to the cybersecurity vulnerabilities in our system,” McNerney said. “Each time an incident like this occurs, it’s called a wake-up call. How many wake-up calls is it going to take for us to get this right?”
Backed by state leaders, Charlotte, N.C.-based Duke Energy (NYSE:DUK) on Monday rejected hedge fund Elliott Management’s proposal to break up the company into three regionally focused, publicly traded utilities.
Elliott — whose management of funds invested in Duke make it one of the company’s top 10 investors, it claims — released an open letter to Duke’s board of directors on Monday critical of the company’s performance. It suggested that the board create three utilities, each with its own board and management, the Carolinas, Florida and the Midwest.
The separation “should create $12 [billion] to $15 billion of line-of-sight near-term value for shareholders,” the letter argued. Elliott manages about $42 billions in funds.
“Today’s announcement by Elliott is the latest in a series of proposals that the hedge fund has offered to Duke Energy since July 2020, the company said. “Throughout, Duke Energy’s board of directors has reviewed their proposals in depth and determined that they are not in the best interests of the company, its shareholders and other stakeholders.”
Oconee Nuclear Station on Lake Keowee near Seneca, S.C. | Duke Energy
Following the release of Elliott’s letter, Duke’s share price fell 2.4% over three days, closing Wednesday at $101.16, down from Friday’s close of $103.60. Usually, utilities targeted by Elliott see a gain in share price.
The essence of Elliott’s argument is that for its size — nearly 8 million electric customers in six states — Duke should be earning much more than it has over the last several years.
Elliott’s idea would make Duke’s Florida utility a separate company and create another company consisting of operations in Indiana, parts of Ohio and parts of Kentucky.
To accomplish this split, Elliott also suggested that the board create an “independent board committee, including new highly qualified independent directors, and assisted by independent outside advisers.” The hedge fund noted that it “has worked with major utilities in similar circumstances, collaborating with directors and management teams to deliver dramatic improvements in operating performance, enhance portfolio configuration and unlock shareholder value.”
In its response Duke pointed out that Elliott had initially suggested that the company issue “up to $7 billion of common equity … to Elliott, essentially transferring up to 10% of Duke’s value to Elliott.” The company rejected that.
Elliott then proposed the company spin off its Florida and Midwest operations, according to Duke.
“This ‘shrink-the company’ strategy that underlies all of Elliott’s proposals runs counter to the strategic direction of the entire industry at a time when scale is needed to efficiently finance the company’s unprecedented capital investment and growth opportunities,” Duke explained its opposition to that idea.
Elliott then demanded an unspecified number of new board seats as well as the initiation of a “strategic review” without further explaining the purpose of that review, according to Duke’s statement.
The fund’s letter spurred multiple responses from North Carolina, South Carolina and Indiana state officials, all in support of Duke.
“Beyond the pride of a home-state company, though, is the reality that Duke delivers reliable, cost-effective energy to millions of North Carolinians,” North Carolina Gov. Roy Cooper said in a joint statement with leaders of both houses of the state legislature. “There are natural concerns that come with putting our state’s energy future in the hands of a Wall Street hedge fund, and we would expect the North Carolina Utilities Commission to strictly scrutinize any such arrangement.”
Membership criteria for standard drafting teams (SDTs) are reliable sources of disagreement on NERC’s Standards Committee, and Wednesday’s meeting was no different.
The dispute this time revolved around the nominees to the SDT for Project 2021-03 (CIP-002 Transmission owner control centers). NERC initiated the project in March to “evaluate the categorization of transmission owner control centers (TOCCs) … performing the functional obligations of a transmission operator.”
The SDT is also intended to help NERC staff with whatever additional studies may be needed to determine the applicability of the Critical Infrastructure Protection (CIP) reliability standards to TOCCs, a function that sparked a debate at a previous Standards Committee meeting over the use of the words “field test” in the proposal. (See “CIP Proposal Amended over Process Concerns,” NERC Standards Committee Briefs: March 17, 2021.)
This time the proposal itself was not in question, but several committee members questioned NERC staff’s nominees for membership. Eight SDT members, including the chair and vice chair, were recommended to the committee, following a nomination period that garnered nine volunteers.
Objections first arose over the proposed chair and vice chair, who like other nominees were identified during the meeting only by number. Marty Hostler of Northern California Power Agency expressed confusion over why NERC seemed to have sidelined an apparently more qualified and willing candidate.
“I’m not clear on why candidate 4 [on the nominee list] was not selected to be chair, or at least vice chair. They represent multiple regions, [were] involved in the whole [CIP-002-6] process and actually hit the ground running on this,” Hostler said. “I would think that candidate has much more leadership qualifications based on what I see in the write-up: They’re much more experienced than [all] of them combined.”
Despite his dissatisfaction with the leadership candidates, Hostler did not make a formal motion to amend NERC’s nominees; that fell to American Electric Power’s Kent Feliks, who proposed moving the current candidate for chair, No. 1 on NERC’s list, to vice chair and naming a different nominee, No. 7, to head the SDT. He explained that he preferred to keep candidate 1 because of their previous SDT experience.
Responding to these complaints, NERC staff on the call — including Manager of Standards Development Latrice Harkness and Vice President of Engineering and Standards Howard Gugel — said they looked for leadership qualities in candidates for chair and vice chair. Gugel explained that NERC interviews candidates’ employers and references, preferring those who “can bring the group tougher for consensus and … understand industry issues,” even if others had more direct subject matter expertise.
Steven Rueckert of WECC added that NERC also considers candidates’ desire to head the team, suggesting that the committee should not assume the chair position can be passed around to whomever it prefers.
“I just wonder if it’s really up to us to change [the roster] without first reaching out to the people and seeing if they’re even willing to … be the chair,” he said.
However, most of the committee sided with Feliks, and his proposal passed with the addition of an amendment by consultant Philip Winston to add one more member to the SDT. The added member, a member of a consulting firm that provides technical, engineering and management assistance, was one nominated by industry. However, NERC staff did not initially include them because, as Gugel explained, they felt the candidate did not bring “any unique skills that weren’t presented by any other candidates.”
No Opposition for Remaining Approvals
The other two items up for approval at Wednesday’s meeting proved more harmonious. Committee members unanimously agreed to accept a standard authorization request (SAR) proposed by Glencoe Light and Power Commission to revise NERC reliability standard PRC-002-2 (Disturbance monitoring and reporting requirements); the next step is posting the SAR for a 30-day formal comment period and authorizing the solicitation of SAR drafting team members.
Members also approved the final SAR for Project 2020-05 (Modifications to FAC-001-3 and FAC-002-2), along with the appointment of the SAR drafting team as the project’s SDT. During the discussion of this item, Harkness acknowledged that FAC-002-2 has been replaced by FAC-002-3 (Facility interconnection studies) as the enforceable standard; therefore, the team will modify the newer standard going forward, which is reflected in the latest version of the SAR.
New Jersey is spending $5 million on two programs to train wind energy sector workers and educate 2,000 energy efficiency workers in a partnership with Public Service Electric and Gas, as the state gears up to reach for its ambitious carbon-free goals.
The New Jersey Economic Development Authority (NJEDA) last week announced a $1 million grant to go to the community college that submits the best proposal on how to prepare workers to provide operations and maintenance services for the state’s nascent offshore wind sector. The proposal followed NJEDA’s announcement in February of $3 million set aside to establish an industry-recognized safety training program and facility for the OSW sector.
Meanwhile, the New Jersey Department of Labor and Workforce Development announced on March 29 that it was offering $1 million for a partnership with PSE&G on a program to award grants to community organizations to train workers in skills needed to implement energy efficiency projects. Some of the 2,000 training positions will go to dislocated or laid off workers, the long-term unemployed, and ex-offenders. The program, which begins on June 1, will teach skills including workforce readiness and financial literacy.
The announcements are part of New Jersey’s effort to position itself at the forefront of the clean energy sector. Gov. Phil Murphy’s wants the state to use 100% clean energy and reduce carbon emissions by 80% below 2006 levels by 2050. His plans include the construction of a wind port in South Jersey to serve as a wind manufacturing and staging hub for New Jersey and nearby states, and the creation of a monopile manufacturing facility at a port in Paulsboro, which would build steel components for OSW turbines.
| Shutterstock
Murphy also wants the state to generate 7,500 MW of OSW by 2035. The New Jersey Board of Public Utilities in June 2019 approved its first project, the 1,100-MW Ocean Wind, and is expected this June to pick the winner of a second solicitation, with a goal of generating 1,200 to 2,400 MW.
Clean Energy Workforce
Yet the state will need to work fast to create a workforce ready to handle that rapid transition. New Jersey ranked 23rd in the nation by the number of clean energy jobs in 2020, according to the Clean Jobs America 2021 report. It was compiled by E2, a national, nonpartisan group of business leaders and investors, and BW Research Partnership, a California research firm. California ranked first, with 484,980 clean energy jobs.
The report also said that New Jersey has 1.33% of its workforce employed in clean energy, a smaller share than every state except Oklahoma: 50,096 jobs in 2020, of which about 66% were in the energy efficiency sector and 17.5% were in solar or wind. Like other states, however, New Jersey’s clean energy employment dipped in 2020, as the pandemic squeezed the economy.
Still, New Jersey’s employee base should provide a solid foundation on which to build a clean energy workforce, according to a study commissioned by Murphy to assess what the state would need to do to support the development of a wind energy sector in the state and its neighbors. The state has significant labor market strengths to help meet the demand for clean energy workers, including a sizeable trade sector, with a recent growth in the numbers of iron and steel workers, electricians, and crane and tower operators.
The report added that “it is important that we act quickly to provide opportunities for workers to obtain offshore wind-specific knowledge, skills and qualifications.”
Training New Workers
In response, NJEDA reached out to academic institutions, training providers and unions to submit proposals for the $3 million safety training program. The program will be taught in line with the standards of the Global Wind Organisation, a nonprofit body founded by wind turbine manufacturers and operators that aims to support an injury-free environment in the wind industry. NJEDA is expected to announce the successful program proposal over the summer.
The agency is soliciting proposals for the community college program. The goal is to create an “industry-recognized, credit-bearing certificate program and pathway to an associate degree or higher” that will teach subjects that could include wind power technology, information technology and software programs, and turbine operations and maintenance. Other potential topics include renewable energy and electrical and mechanical systems, NJEDA said in an outline of the project.
“It’s a mix” of skills, said Jenifer Becker, managing director of developing NJEDA’s WIND Institute. “We’re really looking at this as a career development program, not just as [training for] a single job, but really looking to help support people in their careers in offshore wind [and] clean energy.”
The Labor Department initiative with PSE&G is aimed at developing workers, especially those from New Jersey’s urban areas, in what the utility sees as a growing employment sector in the future. The need for these jobs is partly being driven by customers seeking to cut their bills and mitigate climate change, the company said. They will include entry and mid-level jobs, such as weatherization apprentice, weatherization technician and residential energy auditor, the company said.
“If you look at the U.S. energy economy, energy efficiency is the No. 1 source of jobs growth,” PSE&G President David M. Daly told a forum on held by the governor’s Office of Climate Action and the Green Economy on May 13. “It represents half the jobs growth in the energy sector.”
Shaun Keegan, CEO of Asbury Park-based Solar Landscape, said the solar panel installation company has developed its own training programs to ensure that it has a steady flow of new employees, in part because of the relative paucity of training programs elsewhere. About half of the company’s 100 employees are in relatively unskilled positions, for which the company has a two-day training program, Keegan said. The company also provides that training in conjunction with roofing materials manufacturer GAF, he said.
Solar Landscape also runs an apprenticeship program for employees who are learning the highly skilled electrical side of the business, Keegan said. He added that he expects the company to continue training its own employees, even if more formal education programs for the solar industry emerge.
“I think our background, having been on the install side for 10 years now, makes us the most qualified to actually go out and effectively train,” he said.
With another active Atlantic hurricane season expected for 2021, participants in SERC Reliability’s spring extreme weather webinar on Tuesday urged utilities to invest time and effort into preparation now, in order to prevent delays in restoration when natural disasters hit.
The hurricane season runs from June 1 to Nov. 30, and a recent forecast from the Weather Channel predicted 19 named storms; that total includes eight hurricanes, four of which are projected to be major hurricanes of Category 3 or higher. By comparison, there was a record 30 named storms last year, including 14 hurricanes — the most since the 15 hurricanes of 2005, with six of them major.
The National Oceanic and Atmospheric Administration has not released its own predictions for 2021 yet, but the agency noted last month that its estimate of an “average” hurricane season now means 14 named storms and seven hurricanes, three of them major. The average is calculated based on the last 30 years of storm data and revised every 10 years — most recently this year to reflect 1991 to 2020. NOAA identified several possible causes for the increase: a “warming ocean and atmosphere … influenced by climate change,” but also longer-term climate patterns and better observation technology.
Growing Grid Challenges
Combined with increasingly destructive hurricane seasons is the ongoing challenges from the COVID-19 pandemic. Despite progress in vaccinations, attendees at Tuesday’s webinar are expecting social distancing measures and use of personal protective equipment to be as prevalent in 2021 as they were last year. (See Pandemic Adds to 2020 Hurricane Season Challenges.)
Several participants, including SERC Vice President of Operations Tim Ponseti, noted the frequent occurrence of one-in-100-year events in recent decades — such as the pandemic, February’s extreme winter weather in Texas and the Midwest, and last year’s wildfires in California and earthquake in North Carolina — as indications of the growing risks facing grid planners and operators.
Charles Long, Entergy | SERC
In his keynote, Charles Long, vice president of transmission planning and strategy at Entergy, referred to a quote commonly attributed to Dwight Eisenhower (“Plans are useless, but planning is indispensable.”) to illustrate the benefits of aggressive preparation even in the face of unpredictable events.
“Just know, going into these events, that your plan isn’t going to be perfect; in fact, you may discover in the heat of battle that your plan isn’t really that good at all,” Long said. “But the fact that you did the planning diligently will pay off and help you shorten the restoration … [and] after each event, you can incorporate what you learned … to improve the areas you struggled in for the next one.”
Long emphasized that incident response is a “continuous process” that requires “preparing well in advance and then practicing either through drills or real events.” In his experience the most effective planning begins months in advance of an event, when organizations engage the entire workforce in building reserves of critical equipment and developing incident response plans.
During the days and hours before impact, as the specific threat becomes more clear, entities can implement unified communication strategies so that external and internal messaging is cohesive; stage personnel and equipment; and prepare to document all decision-making. The last step ensures a record that can be used after the event as utilities analyze their successes and failures.
TVA Shares Staging Success Story
A 500-kV substation in Alabama, operated by the Tennessee Valley Authority, served as an example of the way post-event analysis can assist in future recovery. After a tornado damaged the facility in 2014, TVA found itself without convenient access to spare parts for repair.
Casey Scoggins, Tennessee Valley Authority | SERC
Typically the organization would find such equipment from construction projects going on elsewhere in its footprint, but at the time there were no such projects underway — at least, not in the quantity needed for this restoration.
“That forced us to have to order this material basically from scratch,” said Casey Scoggins, manager of substation physical engineering at TVA. “So, based on the fact that we had long leads, we had vendor issues because we [were] trying to rush them. … It took basically a year to get this station back to normal.”
After this costly experience, TVA management saw improving the spare parts supply chain as a “no-brainer.” The organization undertook a multiyear overhaul of its practices, focusing on both acquiring and storing the needed parts. Equipment is now kept in large warehouses in Alabama, Tennessee and other states, from which it can be distributed quickly to areas where it might be needed ahead of potential incidents.
This process did not go entirely smoothly: TVA did have to work out some kinks in delivery. One issue arose when the organization found out that some vendors had mixed various parts in the same package for more efficient delivery, which could have caused difficulties if the packages had been deployed to field crews without inspection. TVA is currently working with vendors on their packaging procedures to prevent such mix-ups in the future.
TVA’s East Point 500-kV substation in Alabama after it was hit by a tornado earlier this year | SERC
However, even with these complications the supplies were in place by last year. The preparation paid off this March, when the same substation was once again hit by a tornado, causing comparable damage to the 2014 incident. This time, the needed parts were available within days, and the facility is expected to be fully restored to service by the end of this month, preventing another long delay in restoring service during a critical time of year.
“This was one of our first rounds of severe storms for this year, and you don’t really know how many more rounds could be coming, especially having all of April and May to go,” said Michael McAmis, principal engineer at TVA. “So [when] getting this station back … one of the primary drivers was system resilience.”
California’s job growth in the electric transportation (ET) sector is accelerating, a trend that could be further fueled by extraction of lithium from the Salton Sea, according to a new report.
ET-related employment in California is expected to grow by 79% from 2020 to 2024, reaching 68,400 jobs, says the report from Advanced Energy Economy (AEE).
From 2019 to 2021, the electric transportation sector added 7,700 jobs, an increase of roughly 20%, which the report attributed to an increase in electric vehicle sales despite the COVID-19 pandemic.
AEE hosted a webinar last week to discuss the findings of the report, titled “Electrifying California: Economic Potential of Growing Electric Transportation.” Webinar guests included California Energy Commission Chair David Hochschild, and California Assemblymember Eduardo Garcia.
“I think this validates the notion that transportation electrification is one of the single biggest opportunities for the state of California,” Hochschild said during the webinar.
Hochschild noted that 34 companies are now making EVs in the state. Companies such as BYD and Proterra are shipping electric buses from California to 40 other states.
And EVs became California’s top export for the first time last year, Hochschild said.
Lithium Opportunities
In addition, California has untapped economic opportunities from the Salton Sea, which is in Imperial and Riverside counties in Southern California and is the state’s largest lake. The lake, which is drying up and becoming saltier, is a rich source of lithium that could potentially be extracted and used in EV batteries.
Garcia authored legislation enacted last year to create the Lithium Valley Commission, a 14-member panel that will explore lithium opportunities and report to the state by October 2022. The Salton Sea lies in Garcia’s district. (See California Lithium Extraction Plan Advances.)
“We have a unique opportunity to address both the economic challenges of this region but also address some significant environmental challenges that have been hanging over our heads for many decades that are in and around the issue of the Salton Sea,” Garcia said during the AEE webinar, noting the high levels of unemployment in his district.
Hochschild said that by some estimates, the Salton Sea has enough lithium to satisfy 40% of global demand for the element. He said having a “Lithium Valley” in California could bring battery manufacturing back to the state.
In addition to an in-state market for EVs, Hochschild said a 10-fold increase in battery storage is planned in California this year to increase electric grid resilience. Much of that will be lithium-ion batteries.
“We have the raw material in Assemblyman Garcia’s district; we have the market here in the state,” he said. “We’ve got to kind of bring back those intermediate links to the chain. That’s really part of the vision.”
Jobs Across the State
The AEE report was prepared by BW Research Partnership, a research and consulting firm.
BW Research compiled a database of 21,000 California businesses potentially involved in the ET supply chain. Of those, 4,500 companies were examined more closely to assess their involvement in electric transportation.
The results were used to estimate the total number of ET-related businesses and jobs in the state.
In 2019, California was the top state in electric transportation, with 3,900 ET-related businesses, the report found. Although the jobs are concentrated in the Bay Area, Southern California and capital region, ET-related jobs can be found in 55 of the state’s 58 counties.
“The EV industry growth is unfolding in nearly every corner of the state,” Claire Alford, a policy associate with AEE, said during the webinar.
The ET sector includes a wide range of jobs, from assemblers and fabricators to car mechanics, salespeople, and engineers.
The AEE report also includes policy recommendations for the state, such as developing a skilled workforce, tracking employment trends, and creating long-term policy and market certainty.
“Clear, durable market signals from the governor’s office, California Legislature and state agencies will help ensure California remains a global EV leader as the industry continues to mature,” the report said.
