The growth of renewable energy resources stemming from technological developments and the resulting cost reductions has caused more than a few skirmishes, FERC Commissioner Richard Glick said on Wednesday.
“We’re seeing growth on renewable energy, and we’re seeing conflict as well: friction between the states’ efforts to promote renewable energy … and FERC’s regulation of wholesale electric markets,” Glick said in opening the first day of Renewable Energy Vermont’s annual conference. This year, the group is holding the conference online and over the course of three months.
FERC Commissioner Richard Glick | Renewable Energy Vermont
“I don’t think there’s necessarily a natural competition or divergence there, but we’ve seen for a variety of reasons traditional electric generators, primarily natural gas and coal, fighting it out in regional electricity markets,” particularly in the Eastern RTOs, Glick said.
“States want their decisions to be heard in these regional markets,” Glick said. “From my perspective, FERC’s responsibility is to figure out a way to help these RTOs design their markets and oversee [these] design changes to ensure that state policies are accommodated, not blocked. If we don’t do that, I think we’re headed towards a bad situation in which some states are going to drop out of RTOs, and certainly states aren’t going to do anything further that would give FERC additional authority over resource decision-making.”
REV Chair Josh Bagnato asked what FERC is doing that impacts Vermonters who are pushing for the clean energy transition.
REV Chair Josh Bagnato | Renewable Energy Vermont
“The commission has quite a bit of jurisdiction over the New England electricity market through our oversight of ISO-NE, so almost all wholesale transactions throughout the region are subject to FERC regulation and oversight. So, the decisions we make have a great deal of impact on the resource mix, prices and on reliability,” Glick said.
“I don’t think the people at ISO New England … get up in the morning and say, ‘How can we frustrate or block state programs?’ I don’t think they do that at all, but they are looking at the markets from a different perspective. They want to make sure that the lights stay on and that they provide power at a relatively reasonable price.”
The federal government right now “is relatively AWOL on greenhouse gas emissions, [so] it’s really up to the states at this point to address those issues, and I don’t think the commission blocking state policies, whether it be intentional or inadvertent, is the way to go at this point,” Glick said.
He cited a recent Lazard analysis that said wind and solar are now the most cost-competitive energy technologies, not only in the U.S., but around the world.
“That’s certainly been a pretty dramatic change,” Glick said. Though federal and state policies have helped somewhat, he said, far and away the biggest driver has been consumer demand, and that will certainly continue in the future.
Individual consumers as well as corporate America have concerns about climate change and would like to see a much greener mix in their utilities’ resource portfolio.
FERC Commissioner Richard Glick cited a recent Lazard study that shows that when U.S. government subsidies are included, the cost of onshore wind and utility-scale solar is competitive with the marginal cost of coal, nuclear and combined cycle gas generation. | Lazard
At first it was just Big Tech companies, “but now we’re seeing it all over the place, with Proctor and Gamble, Anheuser-Busch, Walmart — companies that you wouldn’t normally think of in terms of the energy space,” Glick said. “They’re saying, ‘We want to be 100% green and have a 100% net-zero emissions portfolio as quickly as possible.’ And they’re demanding that of utilities, which are going out and substantially changing the resource mix.”
Bagnato asked what three magic buttons Glick would push to help the transition to renewable energy.
“The first is more of an esoteric one, which is follow the science,” Glick said. “The U.S. is the only country in the world having this debate. … Two, massively build out the transmission grid to be able to accommodate offshore wind and … onshore wind and solar. Third, we have to have a federal policy. States have been doing a great job, but whether on carbon pricing or whatever, cooperation on a regional basis doesn’t work without a federal overlay.”
NERC is set to begin training registered entities on its new Align software project and Secure Evidence Locker (SEL) by the end of the year. Training will follow a staggered schedule, with the Midwest Reliability Organization and Texas Reliability Entity going first.
Align — formerly known as the CMEP (Compliance Monitoring and Enforcement Program) Technology Project — is intended to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise. The SEL was conceived as a way to provide secure storage where potentially sensitive information collected as evidence can be kept separate from work papers managed through the Align tool itself.
NERC Planning 3-phase Rollout
In a joint webinar Tuesday, representatives from MRO and ReliabilityFirst provided more details about the timeline for Align’s rollout, currently scheduled to begin in the first quarter of 2021. The tool is to be released in three stages covering escalating levels of functionality:
Release 1 — Q1 2021. To be introduced as a pilot in MRO and Texas RE before expanding to other regions. Functionality includes allowing registered entities to create and submit self-reports and self-logs, create and manage mitigating activities and mitigation plans, and respond to requests for information.
Release 2 — Q2 2021. Includes technical feasibility exceptions, periodic data submittals, self-certifications and additional needed enhancements identified in Release 1.
Release 3 — Q4 2021. Includes compliance planning and audits, spot checks and compliance investigations.
NERC is finalizing training materials for RE representatives, who will train registered entity staff from their regions in turn. Training for Release 1 will cover functionality for the initial release and features of the SEL supporting that functionality, along with regional changes in business procedures and transition plans for legacy systems. All training sessions will be conducted remotely.
The current schedule for the release of the Align tool. The ERO Secure Evidence Locker is still under construction but planned to be introduced alongside Release 1. | NERC
“During the short time frame between Release 1 and Release 2, the information listed under Release 2 will be maintained in the current platforms, such as WebCDMS or any other platforms that [your regional entities] are having you work in now,” said Ray Sefchik, director of reliability assurance and monitoring at RF. “So there’ll be a couple of months’ gap where you may have to maintain [these platforms] for TFEs, periodic data submittals [and self-certifications] until rollout for Release 2 happens in Q2.”
Entities Free to Develop Private Lockers
The SEL is still under development, with plans to introduce it alongside Release 1 and expand it to store data for the functionalities covered under each subsequent release. NERC had initially planned to include this feature — which for security reasons is not part of the main Align tool — in an update, but the organization added it to the initial release because of concerns from registered entities over the software provider’s ties to a Hong Kong-based private equity firm. (See NERC Investigating Chinese Tie to Software Vendor.)
While all entities will be required to use a secure evidence locker to store relevant data, participants in the webinar stressed that they are free to deploy their own lockers if they prefer to keep potentially sensitive information in their own systems. This is already done by many entities for evidence associated with NERC’s Critical Infrastructure Protection rstandards, though Sefchik and MRO’s Desiree Sawyer said no entities have indicated definite plans to do so for CMEP information. (See FERC Approves NERC’s Align Spending Request.)
However, Matthew Thomas, RF’s director of compliance monitoring, emphasized that entity-developed lockers must be “authorized for use by CMEP activities” by NERC and the REs to ensure their reliability and security according to the specifications provided by NERC in April. A webinar is scheduled for Oct. 29 to answer entities’ questions about developing their own tools.
NextEra Energy’s recent acquisition of GridLiance and its three subsidiaries gives the company a greater voice in RTO transmission-investment decisions and renewables development, CFO Rebecca Kujawa said Wednesday.
“There are investment opportunities … we would have in GridLiance,” Kujawa said during NextEra’s third-quarter earnings call with financial analysts. “But it also positions us to have a seat at the table in these [RTOs] as they contemplate new transmission projects. And obviously, GridLiance would seek to compete effectively for those opportunities.
“As we think about a broad and substantial expansion of renewables across the U.S., it becomes important, and increasingly so over time, to continue to invest in the transmission grid across the U.S.,” she said.
NextEra Energy Resources’ Pinal Central Energy Center in Arizona, combining solar with storage | NextEra Energy Resources
NextEra Energy Transmission announced last month it will pay $660 million for GridLiance. The company’s three subsidiaries, members of both MISO and SPP, own 700 miles of high-voltage lines in Illinois, Kansas, Kentucky, Missouri, Nevada and Oklahoma. (See NextEra Buying GridLiance for $660M.)
The company said its NextEra Energy Resources subsidiary added nearly 2.2 GW of renewables since July to its now 15-GW backlog: 580 MW of wind, 911 MW of solar, 594 MW of energy storage and 86 MW of wind repowering.
The Juno Beach, Fla.-based company reported third-quarter earnings $1.23 billion ($2.50/share), compared to $879 million ($1.81/share) for the third quarter of 2019.
NextEra’s board of directors last month approved a four-for-one common stock split intended to make ownership “more accessible.” Trading on a stock split-adjusted basis will begin Oct. 27.
The company’s share price opened Wednesday at $299.06 but slowly lost steam during the day and was trading at $297.68 in the after-hours session.
New York on Tuesday held its final hearings on emissions standards, with Administrative Law Judge Molly McBride conducting two public comment webinars for the recently proposed statewide emissions limits for 2030 and 2050.
The limits are proposed as 60% and 15%, respectively, of estimated 1990 greenhouse gas emissions, a baseline that increased by 70% under new statutory requirements that include upstream emissions in the calculation. Final comments on the proposed (Part 496) emissions limits are due at the Department of Environmental Conservation (DEC) by 5 p.m. Oct. 27. (See NY Seeks Comment on Proposed Emissions Limits.)
The Climate Leadership and Community Protection Act (CLCPA) mandates, among other targets, that 70% of the state’s electricity come from renewable resources by 2030 and that generation be net zero, or 100% carbon-free, by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)
New York state annual net carbon emissions | NYSERDA
Climate Action Council Involvement
Robert Howarth, Cornell University professor of ecology and environmental biology, and a member of the state’s Climate Action Council, summarized his written comments, citing his own recent study for how New York should account for methane emissions under the CLCPA. (See NY Study Highlights Rising Methane Emissions.)
“I appreciate the difficulty in estimating greenhouse gas emissions for back in 1990, and given this difficulty, I feel the estimates derived for the new [GHG] emission limits are reasonable overall,” Howarth said. “I particularly commend DEC for their inclusion of the carbon dioxide emissions that occurred outside of the state but that were associated with the development, processing and transportation of fossil fuels used within the state in 1990.”
The direct emissions of carbon dioxide in New York state from the combustion of fossil fuels also seem well estimated by the DEC, he said. But its estimate of methane emissions associated with the use of fossil fuels is lower than what he estimated by about 16%.
Projected 2050 energy demand by fuel | NYSERDA
“I believe my estimate is a better one, as it’s consistent with the analysis by [Johns Hopkins University professor Scot] Miller, et al. published in 2013, and as I explained in a peer-reviewed paper in 2014, that estimate is based on data from the late 20th century using top-down estimates, and I believe those are more reliable than the estimates upon which DEC relies,” Howarth said.
The difference is relatively small, he said, but the DEC nonetheless should reconsider their choice.
“Moving forward over the next year to look at modern emissions, it becomes much more important to use the top-down approach,” Howarth said.
He commended the DEC for using the 20-year global warming potential as derived from the Intergovernmental Panel on Climate Change (IPCC) to compare methane and carbon dioxide emissions, which is consistent with the CLCPA requirement and his own recommendations.
“I would be happy to work with DEC and others as they work on their approach for modern emissions, and I strongly urge that the Climate Action Council be more directly involved in the process moving forward over the next year,” Howarth said.
Other Voices
Setting emissions limits is arguably one of the most difficult elements in implementing the CLCPA when it comes to the impact on people’s jobs and the state’s economic and environmental future, said Kevin Schwab, a vice president of CenterState CEO, an economic development organization in Syracuse.
“We’re really going to need a full and accurate baseline of CO2 equivalents to make sure that the work results that [the Climate Action Council is] trying to produce are going to produce the best outcomes for the environment,” Schwab said.
He noted concern among upstate businesses about the IPCC protocols as they relate to imported energy and fugitive emissions.
“Historical reporting in these areas is certainly going to produce some competing data, collection methods and estimates,” Schwab said. “For example, our overall emissions related to energy production have gone down since 1990, but there are estimates available that would suggest that our emissions from energy imported into New York have risen over that period … [which] requires more scrutiny.”
Reference scenario from NYSERDA data | NYSERDA
John Rath, director of operations for NY Geothermal Energy Organization (NY-GEO), said he had recently moved to New York from Texas and that “it’s great to be living in a progressive state that recognizes climate realities and the need for action. … In addition to the larger goals, I think it would be helpful to incorporate some interim targets along the way.”
Eric Weltman, a senior organizer in Brooklyn for the national advocacy group Food & Water Watch, said, “We want to send a message to Gov. [Andrew] Cuomo and the DEC that it’s time to match rhetoric with action and demonstrate the commitment, provide the resources and implement the policies necessary to meet the urgency of the climate crisis. Five years ago, Cuomo banned fracking in New York, but since then he’s allowed a buildout of pipelines and power plants that have increased our reliance on fracked gas, a dangerous inconsistency in policy.”
John Bartow, executive director of the Empire State Forest Products Association (ESFPA), said his organization is committed to addressing climate change in a way that recognizes the value of wood products and the role that private forest land owners contribute to climate resilience.
“The CLCPA does not require the DEC to report emissions related to bioenergy produced in another state and imported into New York, which could create a competitive disadvantage of bioenergy production in New York,” Bartow said. “For example, wood pellets produced in New York would be accounted for both their production and consumption emissions, while a Pennsylvania facility would only be accounted for their New York consumption emissions. Why would any bio-energy production facility want to produce in New York?”
Tara Vamos, a member of New Yorkers for Cool Refrigerant Management, said that setting the emissions limits is a tremendous opportunity to include all refrigerants, which are incredibly potent short-lived climate pollutants (SLCPs).
New York joined with other states to form the U.S. Climate Alliance, which issued the SLCP Challenge to Action to meet the goals of the 2015 Paris Agreement on climate change, she said.
“Page 19 of that roadmap says that states can take steps to support the global transition away from HFCs [hydrofluorocarbons], detect and repair leaks, and collect and destroy used refrigerants,” Vamos said. “By addressing all three areas, states can reverse trends in emissions from this fast-growing sector and reduce them by as much as 40 to 50% by 2030, which would be tremendous.”
Avangrid is poised to expand into the Southwest after announcing Wednesday that it will spend $4.3 billion in cash to acquire PNM Resources, which operates regulated utilities in New Mexico and Texas.
Connecticut-based Avangrid has agreed to pay $50.30/share for PNM, a 19.3% premium over its average closing price over the last 30 days, and will assume $4 billion in debt.
Avangrid’s parent company, Spanish energy giant Iberdrola, said the merged company would have assets worth $40 billion and generate around $2.5 billion in earnings and a net profit of $850 million.
PNM shareholders unanimously approved the transaction. Additional approval from state and federal regulators is needed, including FERC, the New Mexico Public Regulation Commission, the Public Utility Commission of Texas, the Federal Communications Commission and the Nuclear Regulatory Commission. The deal must also be cleared under the antitrust provisions of the Hart Scott Rodino Act and receive approval from the Committee on Foreign Investment in the United States. Regulatory approvals should take approximately 12 months.
Avangrid CEO Dennis Arriola will continue in that role for the combined company. In a statement, Arriola said the merger is “a strategic fit and helps us further our growth in both clean energy distribution and transmission, as well as helping to expand our growing leadership position in renewables.”
PNM’s utilities provide electricity to nearly 800,000 homes and businesses in New Mexico and Texas; Avangrid has 3.3 million customers in Connecticut, Maine, Massachusetts and New York. PNM also owns power plants and wind farms in New Mexico. Avangrid currently owns 1,900 MW of renewable energy in 22 states and has a pipeline of 1,400 MW of renewables assets in New Mexico and Texas.
Iberdrola CEO Ignacio Galán said during an earnings call Wednesday that the merger “fits our strategy and improves our position and growth potential significantly in the United States … one of our key geographies.”
It also creates one of the biggest clean energy companies in the U.S., with 10 regulated utilities in six states and renewable energy operations in 24 states. The enlarged company will be the third-biggest U.S. renewables operator, with about 7.4 GW of capacity, nearly all of which is onshore wind, and a growing pipeline of offshore projects including Vineyard Wind and Park City Wind in New England.
Vineyard is an 800-MW joint venture between Avangrid and Copenhagen Infrastructure Partners (CIP). The project’s expected in-service date has been pushed back to no earlier than 2023 because of delays from the U.S. Bureau of Ocean Energy Management in issuing its final environmental impact study and record of decision. (See BOEM Issues Revised EIS for Vineyard Wind.) Avangrid also partnered with CIP to develop the 804-MW Park City project, which has an expected in-service date of 2025.
“When nobody believes [that] the electricity can be produced with clean sources and everybody thought coal would remain for centuries, and the oil and gas are absolutely needed, we were already the only one saying that we can already generate and produce electricity with clean sources,” Galán said.
PNM has received regulatory approval to more than triple its renewable power capacity to 2 GW by the end of 2022, with a goal to be 100% emissions-free by 2040. There is also an approved exit plan for the 2022 retirement of the coal-fired San Juan Generating Station, of which PNM owns 66.3%, with securitization bonds used to recover the investment, a portion of decommissioning and other costs.
Pedro Azagra Blázquez, corporate development director for Iberdrola, said the company and its subsidiaries “will have no control of any coal asset” by 2022.
Combined heat and power (CHP) systems harbor great potential for small applications, but adopters face the current reality that system costs do not fall in proportion to size, according to proponents.
CHP systems, or cogeneration, are an efficient way to generate electricity and heat from a single fuel source, such as biomass or natural gas. CHP is fuel-efficient, as it uses otherwise wasted heat productively for heating or cooling. It also reduces the need to purchase distributed electricity from the grid, which increases energy security.
The Environmental and Energy Technology Council of Maine on Tuesday hosted a webinar to discuss emerging markets for the technology.
David Dvorak, director of New England Combined Heat and Power Technical Assistance Partnership and professor of mechanical engineering technology at the University of Maine, said more than half the 80.7 GW of CHP installed capacity in the U.S. are “typically very large-scale systems.” Dvorak said these types of CHP systems “work very well,” but they also need to be installed by on-site engineers.
In smaller applications, Dvorak sees changes. “Out of 4,000 sites that we currently have in our installation database, what we’re seeing is that in the past four years, there have been quite a few smaller-scale systems, for instance in multifamily [homes] and schools, that are put into place,” he said. “These tend to be smaller systems where there may or may not be in-house expertise to do a full engineering analysis.”
Combined heat and power installations through Dec. 31, 2019 | New England Combined Heat and Power Technical Assistance Partnership
Dvorak said this represents “technical potential” in New England.
Ian Burnes, strategic initiatives program manager for Efficiency Maine, said that CHP is “a great technology, but the upfront installation cost “is really challenging.” Large-scale CHP installed at an assisted-living facility can cost $300,000 for the total system cost and $80,000 for electrical engineering.
Dvorak added that even with small-scale or micro-CHP systems, the interconnection costs and associated expenses do not scale down with them.
“There’s a certain aspect of [cost] that’s fixed, and it becomes a larger fraction of the total cost, and this is a real challenge, but we see more and more opportunities in these smaller systems,” Dvorak said. “We’re hoping to find ways actually to see more of these small-scale systems installed.”
Burnes said Efficiency Maine offers capped financial incentives on total project costs and 50% coverage up to $20,000 for a technical assistance study and free scoping audit of utility data that includes a final report.
From top left: Adelaide Taylor, E2Tech; Martin Grohman, E2Tech; Eric Burgis, Energy Solutions Center; Ian Burnes, Efficiency Maine; David Dvorak, New England Combined Heat and Power Technical Assistance Partnership; Suzanne Watson, Watson Strategy Group; Lizzy Reinholt, Summit Utilities | E2Tech
Lizzy Reinholt, senior director of sustainability and corporate affairs for Summit Utilities, added that getting people to realize the benefits of CHP is “really important.”
Reinholt said local distribution companies have leadership roles in building a sustainable energy future. Summit — which operates in five states, including Maine — is focused on renewable natural gas and its role in reducing emissions and helping states meet their climate goals. She said Maine Gov. Janet Mills has been pushing an aggressive agenda around emissions reductions and creating the Maine Climate Council, which recently released a draft of its four-year Climate Action Plan that included recommendations for CHP.
It is an “exciting time to work in the energy field,” she said, adding that it is also a critical and transitional time, as regulatory and legislative frameworks need adaptation to better link to goals for reducing emissions and mitigating climate change impacts. Building strong partnerships with lawmakers and regulators is essential, she said.
“Right now, there is a strong push to find a silver bullet to solving all the problems we face, both reducing emissions and reducing costs, and there are no easy answers,” Reinholt said. “I feel grateful for the work that’s already been done that has stayed technology agnostic and instead focused on outcomes. How do we keep that moving forward so that we can be ready to seize on those innovations and emerging technologies in the marketplace?”
WECC will take an interconnection-wide approach as it analyzes the events stemming from the mid-August record “heat storm” that prompted CAISO to initiate California’s first rolling blackouts since the energy crisis of 2000/01, officials said Tuesday.
The regional entity sees the effort as a “subset” of its larger, ongoing focus on resource adequacy in the Western Interconnection, WECC Vice President of Strategic Engagement Jordan White said during a call with stakeholders.
WECC signaled that direction last month when Director of Reliability Risk Management Vic Howell told a group of stakeholders that the RE would examine the developments of Aug. 15-18 as a Western “heat wave event” rather than just a California load-shed event when it performs its event analysis submitted to NERC. (See CalCCA Seeks ‘Objective’ Review of Blackout Report.)
“Although much of the focus [around the event] has been California because the customers in that state lost power, this truly was a West-wide heat event that prevented neighboring states from being able to export surplus power to California to avoid shutting firm load,” White said Tuesday.
From the perspective of many California residents and outside observers, the heat wave climaxed on Aug. 14 and 15 when CAISO was forced to cut power to about 812,600 households, representing about 2.4 million people.
The call for blackouts immediately sparked a wave of finger-pointing, with CAISO blaming the California Public Utilities Commission for managing a “broken” resource adequacy program. The CPUC countered that the state’s investor-owned utilities had procured sufficient resources to meet forecasts, and it questioned why those resources had not been available in the ISO market to meet the heavy demand. (See CAISO Blames Blackouts on Inadequate Resources, CPUC.)
Five Western balancing authorities issued advanced energy emergency alerts on Aug. 18, along with one short EEA-1. CAISO is “BA-1,” but WECC declined to identify the others. | WECC
CAISO, the CPUC and the California Energy Commission earlier this month jointly published a “root cause” analysis that largely attributed the blackouts to constraints on interties into California, under-scheduling by load-serving entities and ISO market design flaws, among other factors. (See CAISO Says Constrained Tx Contributed to Blackouts.)
“It’s important to understand that the heat wave was not just experienced in California; it was a wide-area heat wave event … that prevented neighboring states from being able to export their surplus energy to California,” Howell said. “This event really illustrates the importance of the resource adequacy discussions that have been happening at WECC and across the interconnection.” (See WECC Seeks to ‘Invent’ Future with RA Forum.)
Howell noted that the five-day event saw 28 energy emergency alerts (EEAs) issued across the Western Interconnection, 65% of the total issued for all of 2019. The alerts range from EEA-1, in which a balancing authority has already curtailed non-firm loads and is still concerned about meeting its contingency reserves requirement, to EEA-3, in which shedding for firm load is imminent or in progress in order to maintain that requirement.
Tim Reynolds, WECC’s manager of events analysis and situation awareness, recounted how the event unfolded, pointing out that on Friday, Aug. 14, only CAISO issued alerts, quickly jumping from an EEA-1 to EEA-3 before shedding 1,087 MW of load. On Aug. 15, CAISO issued an EEA-2 late in the afternoon that escalated to an EEA-3 around 7 p.m., leading to the shedding of 692 MW. Only one other balancing authority area — left unidentified by WECC — issued an alert (EEA-1) that day, just before CAISO initiated rotating outages.
The picture began to change on Monday, Aug. 17, when five unidentified Western BAAs issued EEA-1 warnings. CAISO again issued an EEA-3 but avoided shedding load because of conservation measures put in place.
On Aug. 18, four BAAs — including CAISO — entered EEA-3 at some point during the afternoon or evening. Another BAA issued an EEA-2 that evening. That day also saw the Western Interconnection’s summer peak demand of 162,000 MW (a figure WECC is still verifying), potentially beating the interconnection’s previous all-time peak set in July 2018 by 100 MW.
“What was every interesting was that on the 18th … there were a lot of things happening regarding energy conservation and other things coming into play, where the Western Interconnection didn’t have to shed any firm load,” Reynolds said. “So, going from the beginning of the heat wave to … Tuesday, there are some lessons that have happened, things that we want to get out there and let other people know.”
RA Side of Things
“This event is a new one for us and my team in particular,” said Matthew Elkins, manager of WECC’s performance analysis and resource adequacy efforts, referring to the fact that his group usually focuses on transmission system performance when it contributes to the RE’s events analyses.
“But this one was more about the resource adequacy side of things, so my team is excited to put that other hat on and really look at different things that we could do better,” including how WECC can improve its forecasts, he said.
Elkins presented a series of slides illustrating that, during most of the heat wave, CAISO’s demand far exceeded WECC’s 50/50 — and even 90/10 — forecasts for the period.
“Are our [forecasts’] range of possibilities really looking into what could occur?” Elkins said.
Meanwhile, CAISO’s renewable output came up far short of forecasts during the event. Elkins said WECC is interested in learning more about the performance of all resource types against forecasts. It also seeks to gather similar performance data from all Western BAAs.
“We want to understand what each of the areas were facing at that time, and more than just understanding if the energy was available. We can go through this and say, ‘Yeah, there was energy available somewhere in the system,’ but we have to be able to understand if there was transmission available to move that energy,” Elkins said.
He said one of the “great things” about the Western system is that its constituent BAs peak at different times, allowing for mutual assistance, but WECC wants to know how that practice could have been constrained during the heat wave.
“We’re not trying to point any fingers,” Elkins said. “What we’re trying to get out of this is really just a better understanding of how we can model a heat wave event … that really impacts so many balancing authority areas. Everyone was being impacted in some way, and I just to make sure our models are picking that up and we can look at these types of scenarios.”
A new study from Columbia University puts forward a levelized cost of carbon abatement (LCCA) as a good way for investors and companies to compare technologies and policies that reduce emissions.
“Policymakers should recognize that one size doesn’t fit all,” Julio Friedmann, lead author of the paper from Columbia’s Center on Global Energy Policy, said in a webinar on Monday. “One technology may not be the best bet, or one action may not be the best pathway. You may need to do different things in different states to get the maximum CO2 reduction at the lowest cost.”
Two bankers, a global energy expert and a corporate carbon strategist joined a panel to discuss the merits of LCCA as a tool to measure how much CO2 can be reduced by a specific capital investment or policy, calculating costs on the basis of dollars per tons of emissions reduced.
Previous marginal or levelized cost methodologies often failed to consider the specific contexts that determine the real, all-in costs of a policy and the real, all-in impacts on emissions, according to the authors.
LCCA representation of electric power costs with and without the ITC | Goldman Sachs
“One example we ran is the investment tax credit [ITC], which is having a big impact on getting solar panels built, and that’s terrific,” Friedmann said. “It turns out that the value of the ITC was pretty different in different places. In California, $70/ton was the value; in New Jersey, it cost $105/ton; in Texas it was $31/ton — so a bargain in Texas, but not so much in New Jersey and Massachusetts.”
This approach also lets policymakers figure out who pays, he said. The ITC is generally viewed as a reduction in cost to the ratepayer, which is true. It also represents an increase in cost to the tax code, because it’s money coming out of the U.S. Treasury.
“The most important thing to think through is what is being displaced; that’s the hardest thing to get your brain around,” Friedmann said. “When anyone does this analysis, including us, we rarely end up with a point result; we usually end up for one issue with a table in order to explain how these things actually interact.” For example, if a clean energy source in India displaces a nuclear plant, that’s not as appealing compared to displacing the burning of biomass, he said.
Policy Signals
The Climate Leadership and Community Protection Act signed by Gov. Andrew Cuomo last year requires the Department of Environmental Conservation to establish a value of carbon, based on either abatement or damage cost estimates, for use by state agencies. New York’s policy sways the national debate because not only does the state have some of the most ambitious clean energy goals in the country — net zero by 2040 — but is arguably farther along the policy road to implementing a price on carbon emissions.
“We set ourselves a goal of being net zero by 2050, then things that might not have seemed possible on the outset suddenly become feasible,” said Jules Kortenhorst, CEO of the Rocky Mountain Institute.
“Integration happens; venture capital funding for new technologies gets rolled out; entrepreneurs roll up their sleeves and do things that were deemed impossible; and I think even in this exciting methodology, that is still an area that we haven’t captured yet,” he said. “What is the value of breakthrough innovation when we set ourselves a very ambitious goal and thereby start driving to net zero by the middle of the century?”
Clockwise from top left: Akshat Rathi, Bloomberg News; Jules Kortenhorst, Rocky Mountain Institute; Marisa Buchanan, JPMorgan Chase; Julio Friedmann, CGEP; Elizabeth Willmott, Microsoft; and Arjun Murti, Warburg Pincus | CGEP
Moderator Akshat Rathi of Bloomberg News said that regulations can make what seems to be economically sensible actually happen. He asked how they can help a large bank, for example, align its investment portfolio with the goals of the 2015 Paris Agreement on climate change.
“We know that we need better data,” said Marisa Buchanan, managing director and head of sustainability at JPMorgan Chase, which earlier this month announced it would align its financing to meet the Paris goal of net-zero greenhouse gas emissions by 2050. “We know that we need to increase the comprehensiveness of that data, and we need it to come from a broader swath of companies out there.”
JPMorgan works with a lot of big companies, she said, but also wants to extend the emissions reporting effort to medium-sized companies.
“We need long-term policy signals that are really focused on pricing carbon, in many cases, but also looking for other opportunities to reduce emissions,” Buchanan said. “We know that a price on carbon is really critical, but it’s also only one tool in the toolbox. … It’s important to think about the types of policy signals that are most effective, depending upon the sector or industry you are targeting.”
When making its Paris commitment, the bank targeted its activities in oil and gas, automotive manufacturing and electric power, but the business community cannot address climate challenge on its own, she said.
“We really need support and leadership from our policymakers, here in the U.S. as well as globally.” The new study “is going to be critical to informing that policy conversation,” Buchanan said.
Abatement Strategies
Elizabeth Willmott, carbon lead at Microsoft, referred to the “tapestry” of different strategies that optimize carbon removal and agreed on the importance of the new study.
Microsoft executives’ commitment to reduce and remove carbon emissions is supported by an internal carbon fee, in practice since 2012 and expanded to include all of the company’s value chain, Willmott said.
“What’s really important for us, being a data science and computer science company, is being able to have this crucial data to compare and contrast strategies, so that when we’re making these decisions, we’re not simply throwing money at the next bright, shiny thing,” Willmott said. “That’s why I think the levelized cost of carbon abatement is really a fantastic example of a way to drive good behavioral change and smart economics as a result of any company or government commitment to making swift reductions.”
Rathi asked how Microsoft would spur innovation in carbon removal.
“We see a clear need for a swift and profound abatement in greenhouse gas emissions, and we see policies that are effective on the surface that have little real impact, and so we need to take a holistic view on pricing carbon,” Willmott said. “From Microsoft’s perspective, when we even breathe a word of higher carbon removal costs internally, our internal business stakeholders interpret that as a carbon fee increase on the horizon two to five years out.”
Microsoft will be carbon negative by 2030, and it plans by 2050 to remove from the environment all the carbon the company has emitted since it was founded in 1975. | Microsoft
Using carbon removal for its own sake and as a price incentive creates a virtuous cycle, she said.
Asked what Microsoft’s internal carbon fee is per ton, Willmott said that when the company first established it in 2012, it was based on the budget needed to invest in renewable energy, as well as on carbon offsets at the time.
“But that wasn’t driving change, so we increased it two years ago to $15/ton, which was the point at which we knew our internal colleagues would be able to pay for their own renewable energy,” Willmott said.
The firm established that price as an incentive for its Scope 1 and 2 emissions, and it has driven the change desired, she said.
Scientists classify carbon emissions in three categories, or “scopes,” with Scope 1 emissions being direct emissions; Scope 2 meaning indirect emissions from power or heat production; and Scope 3 referring to indirect emissions from all other activities.
“Now with our Scope 3 carbon fee, which was instituted just this last January, we’re starting lower because the data quality is poor … [and] we’re starting to do the hard work of figuring out what the cost will be and is for this different Scope 3 category so we can then set the fee to be more of an appropriate incentive in just the way the LCAA talks about,” Wilmott said. “I’m not sure this is public, but you’ll all be the first to know our exciting Microsoft internal workings here: It’s about $5/ton.”
Arjun Murti, senior adviser at Warburg Pincus, said investors are trying to assess where a particular project lies on the cost curve and what is the market for it.
The crucial value of the new study is in its ability to help investors and policymakers understand the public policy implications of a given project.
“Is it going to have support over the long run? Does it actually enhance the societal goals, something that investors are now incorporating more explicitly in their analysis,” Murti said.
The private sector needs to act, and the investment bankers need to send price signals, RMI’s Kortenhorst said: “Capital is flowing away from the old companies who don’t see the writing on the wall.”
Placing solar arrays in urban areas would help Maryland reach its renewable portfolio standard while conserving productive farmland, according to a report issued Tuesday.
The report, released by Chesapeake Conservancy’s Conservation Innovation Center (CIC), lays out large-scale opportunities for solar placement on degraded land and underutilized industrial sites; the rooftops of commercial, industrial and residential buildings; and parking lots. It used geospatial analysis to identify optimal solar sites and determine if there are enough optimal sites for Maryland to reach its solar energy goals.
Solar panels cover the roof of a Target store in Middle River, Md. | Chesapeake Bay Program
The Maryland Governor’s Task Force on Renewable Energy Development and Siting estimates that the land needed to meet the state’s RPS will require between 7,000 and 35,000 acres of land across the state.
“This report is a timely reminder we can make real progress on our greenhouse gas reduction and environmental protection goals for a win-win with smart solar siting policies,” said Ben Grumbles, Maryland environment secretary and chair of the state’s Climate Change Commission. “We can expand our state’s homegrown clean and renewable energy supplies by utilizing rooftops, brownfields and waste sites, while avoiding prime farmland and ecologically sensitive lands and forests.”
Maryland is one of 30 states with an RPS to increase electricity production from renewable sources. The state’s mandate currently requires 50% of electricity sold by utilities to come from renewable sources by 2030, with 14.5% from solar in the Clean Energy Jobs Act of 2019 (SB 516).
To meet this goal, the CIC estimates the state will need six times the current solar energy production as siting becomes more difficult as the amount increases. The projects can include everything from small rooftop to utility-scale systems.
State incentives for renewable sources, including solar | DOE
Susan Minnemeyer, vice president of technology for the CIC, said the analysis sought to identify enough opportunity sites to produce Baltimore County and Baltimore City’s share of the state’s solar goal. Minnemeyer said based on energy consumption, that share is 1,967 GWh/year of electricity, or about 18% of the statewide goal of 9,000 GWh/year from solar.
Baltimore city and county parcel and building footprints for ideal solar facility locations | Chesapeake Conservancy
Through the analysis, Minnemeyer said that more than enough optimal sites were identified in the Baltimore region: 22,789 GWh/year. She said only 8.6% of the optimal sites identified would need to prove viable to meet the region’s share of solar energy needs.
“Our analysis demonstrates significant opportunities to scale up solar energy development through optimal siting in Baltimore county and city, making use of rooftops, parking canopies and degraded lands to grow Maryland’s solar electricity generation,” Minnemeyer said. “Providing incentives for solar energy development on optimal sites may be one of the best ways to minimize the amount of land needed for solar and avoid potential adverse impacts of development.”
Teresa Moore, executive director of the Valleys Planning Council, who commissioned the study, said her organization supports renewable energy efforts but has been concerned that a lack of siting regulations would lead to farmland being the main target for large-scale solar projects. Moore said almost all the applications in Baltimore County for the first three years of the community solar pilot program have been focused on farmland and not on optimal sites in urban settings.
Moore said her organization would like to see Maryland follow the example of a state like New Jersey that has mapped out optimal solar sites and created a ranking system.
“This helps achieve other goals included in Maryland’s solar legislation calling for job creation and benefits to low- and moderate-income residents, in addition to avoiding conflicts with long-established programs and policies to protect our best farm and forest lands,” Moore said.
Texas’ Public Utility Commission has exercised the 30-day severance clause in its reliability monitoring contract with Texas Reliability Entity.
In a letter to Texas RE CEO Lane Lanford, PUC Executive Director J.P. Urban said the commission is terminating the contract, at the NERC regional entity’s request, effective Nov. 16.
A Texas RE spokesperson acknowledged receiving the letter — which ERO Insider obtained through an open records request — but declined further comment.
As the reliability monitor, Texas RE audited and investigated ERCOT market participants’ compliance with the grid operator’s protocols and operating guides. It reported potential noncompliance with reliability-related regional rules to the PUC and provided the commission testimony and support in enforcement cases, leading to nearly $1.9 million in penalties during the last five years.
Texas RE devoted four of its 64 employees to the monitor’s responsibilities. Its primary mission remains serving as the NERC RE for the Texas Interconnection.
Urban has formed a task force to work with ERCOT staff in ensuring market participants’ data is still evaluated until a new monitor is hired. PUC legal staff will exercise the agency’s enforcement authority.
The termination follows the PUC’s Sept. 24 open meeting, in which commissioners raised the possibility of ending Texas RE’s monitoring contract. They said they were not sure the commission was getting its money’s worth from the RE and questioned whether there was enough transparency for ratepayers. (See PUC Reconsidering Texas RE as Reliability Monitor.)
Lanford said at the time that his organization would “continue to assist if needed to ensure the mutual goal of a highly reliable and secure bulk power system within the Texas Interconnection.”
Andrew Barlow, the PUC’s director of external affairs, said “things are moving forward on the preferences expressed by the commissioners.”
The commissioners have questioned whether they have the authority to make Texas RE its reliability monitor, citing language in the state’s Public Utility Regulatory Act (PURA). During the Sept. 24 meeting, Chair DeAnn Walker said the statute “clearly says” the commission “may delegate” the reliability monitor’s function to an “independent organization.”
That “independent organization” would be ERCOT, not Texas RE, she said. The PURA repeatedly refers to ERCOT as “the independent organization,” never “ERCOT,” Barlow said.
Commissioner Arthur D’Andrea also said he supported giving 30 days’ notice to Texas RE. Commissioner Shelly Botkin requested more time to consider the issue.
Commission staff have drafted amendments to how the PUC implements the PURA that would give it discretion over whether to appoint a reliability monitor and broaden the eligibility criteria when it selects the monitor (50602).
ERCOT served as the reliability monitor until Texas RE was created in 2010. Barlow has pointed out that Texas RE uses ERCOT data for analysis rather than generating its own.
The $5.3 million, four-year monitoring contract was to extend through 2023, up from $4.3 million for the previous four-year term. The increase was another sticking point for the PUC.
The contract was funded through ERCOT’s system administration fee. Because Texas RE was paid through the fourth quarter of this year, it will have to return a pro rata share of the payment.
Barlow said the PUC can’t take the reliability contract out for bids until it knows what the scope of work will be.
“The one thing we do know from the commission’s open meeting discussion is that the future work will be handled differently,” he said.
