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.”
Demand response aggregator Voltus filed a complaint with FERC on Tuesday challenging the state “opt-out” provision in Order 719, saying it is undermining MISO’s reliability and increasing ratepayers’ costs (EL21-12).
The complaint, filed on the company’s behalf by Earthjustice, asks the commission to revoke the opt-out provision of the 2008 order along with MISO Tariff provisions authorizing states to bar third-party DR providers from participating in the RTO’s markets.
| Voltus
Voltus said most states in MISO have used the opt-out provision, which it says insulates their utilities from DR competition and results in rates that are not just and reasonable. The company also said the provisions are unduly discriminatory because utility-run DR programs are permitted to participate in MISO’s markets and because FERC and the courts have rejected blanket opt-outs for energy efficiency, distributed energy resources and energy storage.
Voltus provides DR services to commercial and industrial customers in PJM, NYISO, ERCOT, CAISO and ISO-NE in the U.S., as well as Ontario’s Independent Electricity System Operator and the Alberta Electric System Operator. But in MISO the company says it can only operate as an aggregator of retail customers (ARC) in Illinois, Michigan (serving the 10% of load that is allowed to buy electricity from competitive suppliers), Texas, and a few municipal and cooperative utilities that have allowed the company to operate.
It said it could be delivering more than 9,000 MW of DR in MISO, which it said could save ratepayers $130 million and generate nearly $500 million in revenue for Voltus annually. The company asked FERC to consider its complaint on a fast-track schedule and deliver a ruling in time for the company to enter MISO’s 2021 Planning Reserve Auction in March.
“The failure to unleash demand competition poses an acute threat in MISO, where a combination of factors, including reduced reserve margins, increased forced outages and the integration of variable renewable resources has led to increased maximum generation emergency events, signaling increasing operational risk to the grid,” Voltus said.
MISO did not immediately respond to a request for comment, saying only that it was reviewing the complaint.
Order 719
In all but three of MISO’s 15 states, aggregators of DR that are not acting on behalf of a load-serving entity are barred from directly participating in the RTO, Voltus said.
Order 719 directed RTOs and ISOs to allow ARCs to bid DR on behalf of retail customers “unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate.”
On rehearing, the commission amended the order, saying RTOs cannot accept an ARC bid for small utilities that distribute less than 4 million MWh without the utility’s permission. For larger utilities, the grid operator must accept an ARC bid unless the relevant authority prohibits it.
Most states — Indiana, Iowa, Michigan, Minnesota, Missouri, North Dakota, South Dakota and Wisconsin — adopted restrictions on ARC participation around 2009 or shortly thereafter, following the commission’s rehearing ruling on Order 719, Voltus said.
Others — Kentucky, Louisiana and Mississippi — adopted ARC bans in 2017 and 2019, in response to efforts by aggregators to enter the markets, Voltus said.
In addition, Arkansas enacted a bill in 2013 restricting ARCs unless the Public Service Commission approved their participation as in the public interest. In August, PSC staff recommended that ARCs be allowed to participate; the case is pending.
Inconsistent with Recent Orders, Rulings
Voltus said court rulings since Order 719 was adopted “now [dictate] that the opt-out approach taken in Order 719 is inconsistent with the Federal Power Act’s basic jurisdictional divide, as states simply do not possess the authority to directly determine whether resources are permitted to participate in RTO/ISO markets.”
It cited both the outcome of litigation over Order 745 and Order 841 and the commission’s issuance of Order 2222 last month.
Order 745 in 2011 set rules for compensating DR. In its 2016 FERC v. EPSA decision, the Supreme Court rejected a challenge to the order, saying market operators’ payment of DR commitments directly affect wholesale rates and that the commission’s rulemaking did not intrude on state jurisdiction. (See Supreme Court Upholds FERC Jurisdiction over DR.)
In Order 841 in 2018, the commission refused to grant states the right to block energy storage resources (ESRs) from participating in wholesale markets, even when they are interconnected at the distribution-level. In July, the D.C. Circuit Court of Appeals rejected complaints that the lack of an opt-out provision violates states’ authority to regulate their distribution systems. “Nothing in Order No. 841 directly regulates those distribution systems. … States remain equipped with every tool they possessed prior to Order No. 841 to manage their facilities and systems,” the court said. (See FERC Storage Order Survives State Challenge.)
In September, FERC also rejected a broad opt-out in Order 2222, which removed barriers to aggregations of distributed energy resources. Instead, the commission created an opt-in mechanism for small utilities, similar to that in Order 719-A for DR. (See FERC Opens RTO Markets to DER Aggregation.)
“The commission’s conclusion that its exclusive jurisdiction over wholesale market rates precludes states from barring participation of storage or distributed energy resources applies with equal force to demand response,” Voltus said. “Order 719’s anomalous treatment of demand response can no longer stand.”
MISO’s Need for DR
The complaint cites MISO’s acknowledgment of its increasing need for intraday flexibility as its region adds increasing quantities of intermittent and emergency-only resources.
“Though it had previously not experienced a maximum generation emergency since 2007, between 2016 and 2019, MISO experienced 27 such emergencies. It additionally declared a maxgen alert requiring conservative operation on Feb. 21, 2020, and again in July and August,” Voltus said.
“At the same time that MISO recognizes that the additional operational flexibility offered by demand response is critical to the challenges it faces now and for the foreseeable future, it considers the suite of demand response resources currently available insufficient to meet operational needs. In particular, although a large quantity of capacity participates in MISO as ‘load modifying resources’ (LMRs), MISO has found the historical performance and operating characteristics of existing LMRs to be inadequate to meet MISO’s changing needs.”
About 90% of DR in MISO are LMR resources — DR and behind-the-meter generation that clear MISO’s PRA and provide interruptible load services during capacity shortages. About 20% of LMRs require longer than a six-hour notification. “In contrast, emergency demand response products in PJM, CAISO and NYISO allow for only 30-minute to at most two-hour notice,” the company said.
Without incentives from their regulators, Voltus said, traditionally regulated utilities are unlikely to adopt ambitious DR programs. “Unsurprisingly, the operational capabilities of existing demand response assets in MISO lag significantly behind that of other organized markets, even though many utility-run programs are supported by significant subsidies through retail rate charges. Lack of competition brings exactly the lackluster results one would expect: high cost and poor performance.
“Worse, the absence of competition is holding back the full capability of demand response within MISO at a time when it is needed more than ever to provide the grid flexibility in the face of shrinking reserve margins and a changing resource mix. During some recent events, a mere hundred megawatts or so of demand response, available in the right location and able to respond quickly, could have alleviated tight supply conditions.”
It noted FERC’s conclusion that DR can mitigate generator market power and cited a PJM study that found “a modest 3% load reduction in the 100 highest peak hours corresponds to a price decline of 6 to 12%.”
Relief Sought
Voltus said MISO’s acceptance of opt-outs other than that of Arkansas — the result of legislation — violates Order 719.
“The commission should order MISO at minimum, and potentially all other RTO/ISOs, to incorporate consideration of demand response aggregators in the ongoing stakeholder work to implement Order 2222 coordination mechanisms,” it said. It also requested the commission issue a Notice of Proposed Rulemaking to eliminate Order 719’s opt-out.
“The tremendous potential of Order 2222 will remain unrealized while the demand response opt-out remains in place,” it said.
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.
The Department of Justice has brought criminal charges against six Russian military intelligence officers believed to be involved in multiple cyberattacks against targets around the world, including online assaults against the Ukrainian power grid in 2015 and 2017.
The indictment last week by a grand jury in Pittsburgh named Yuriy Andrienko, Sergey Detistov, Pavel Frolov, Anatoliy Kovalev, Artem Ochichenko and Petr Pliskin, all officers in Russia’s military intelligence agency, GRU — specifically Unit 74455, a notorious team of hackers dubbed “Sandworm” or “Voodoo Bear” by some security analysts. Each count in the indictment applies to every defendant:
conspiracy to conduct computer fraud and abuse
conspiracy to commit wire fraud
wire fraud (two counts)
damaging protected computers
aggravated identity theft (two counts)
The computer fraud charge carries a maximum sentence of five years; the charges of conspiracy to commit wire fraud and wire fraud each carry maximums of 20 years; intentional damage to a protected computer carries 10 years; and aggravated identity theft carries a mandatory two-year sentence. The indictment includes an allegation of false registration of domain names, which would add seven years to the maximum sentence for each wire fraud and damage to a protected computer count, and double the sentence for aggravated identify theft.
John Demers, Department of Justice | DOJ
In addition to the Ukraine cyberattacks, the men are alleged to have carried out “computer intrusions and attacks” against elections in France, Georgian government and media entities, the 2018 Winter Olympics in South Korea, U.K.-based investigators of the poisoning of Russian dissident Sergei Skripal, and others. Assistant Attorney General John C. Demers called the hackers’ activities “the most disruptive and destructive series of computer attacks ever attributed to a single group.”
“Their [Olympics] cyberattack combined the emotional maturity of a petulant child with the resources of a nation-state,” Demers said at a press conference on Monday.
Ukraine Targeted in Multiple Attacks
The six Russian military intelligence officers indicted by the Department of Justice | FBI
The department’s chronology of Unit 74455’s campaign begins with the Ukraine power grid attack, in which the group gained access to the computer systems of three Ukrainian energy distribution companies using spearphishing emails. Once they had access, the team deployed a variant of the BlackEnergy malware to steal user credentials, which they used to access the utilities’ supervisory control and data acquisition (SCADA) networks.
With SCADA access, the attackers were able to disconnect about 225,000 customers with nearly simultaneous attacks against all three companies. Following the attack, the hackers used KillDisk malware to render the infected computers inoperable. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)
The hackers’ next attack on Ukraine’s energy sector began in April 2016 with the compromise of an unidentified electric company’s computer network. The intruders lay low inside the network until the following December, when they triggered a new malware, later dubbed “Industroyer” by researchers, tailored specifically to attack electric grids by targeting their industrial control systems. (See Experts ID New Cyber Threat to SCADA Systems.)
The most devastating attack began in June 2017 when the hackers unleashed the NotPetya malware. Though this intrusion again targeted Ukrainian organizations including “banks, newspapers and electricity companies,” NotPetya’s unique design enabled it to spread outside of the networks where it was initially activated. Within hours the malware had propagated through networks around the world, including to companies in the U.S. The indictment alleges that “for just three U.S.-related victims … monetary losses reached nearly $1 billion.”
Russia Dismisses Charges as ‘Cliches’
Russia’s Ministry of Foreign Affairs pushed back against the indictment on Tuesday, with spokeswoman Maria Zakharova, in a commentary quoted by Russian news agency Tass, calling the allegations “hackneyed cliches” lacking evidence.
“Russia’s government agencies have nothing to do with any malicious activity in the internet, contrary to what Washington tries to assert,” Zakharova said. “Apparently, behind this there are time-serving political considerations and intentions of Russophobic forces in the United States to keep afloat the agenda of a Russian threat at a time when the presidential election campaign has reached its peak.”
Perhaps anticipating such a reaction, Demers emphasized the work of DOJ’s partners in the private sector — including Cisco, Facebook, Google and Twitter — to “investigate and disrupt the Unit 74455 cyber threat.” Law enforcement and intelligence agencies from counties including Ukraine, Georgia, South Korea, the U.K. and New Zealand also contributed to the investigation.
“All of these partnerships send a clear message that responsible nations and the private sector are prepared to work together to defend against and disrupt significant cyber threats,” Demers said.
In a 142-page ruling Thursday, FERC partly affirmed an administrative law judge’s decision on Pacific Gas and Electric’s proposed increases to its transmission rates, reversing the judge on the utility’s cost of long-term debt and other issues (ER16-2320).
The commission directed further briefing on PG&E’s return on equity and told the utility to recalculate its tariff rates based on the ROE and other factors.
PG&E filed its 18th revised transmission owner tariff in July 2016, which was followed by numerous objections. After an evidentiary hearing, the judge ruled in October 2018 on 11 disputed categories including ROE, capital structure and depreciation rates.
The judge found PG&E’s forecasted cost of long-term debt to be unreasonable, ordering it be reduced, and lowered its ROE from a proposed 10.4% to 9.13%, which the company said was too low and objecting parties said was too high.
A panel at last week’s Energy Bar Association annual Fall Conference examining FERC’s response to the D.C. Circuit of Appeals’ Allegheny Defense Project v. FERC ruling evolved into an in-depth Q&A with panelist David Morenoff, FERC’s acting general counsel.
Allegheny upended longstanding FERC practice by barring the commission from using tolling orders to delay judicial review under the Natural Gas Act and Federal Power Act. The July order by the D.C. Circuit Court of Appeals concluded that the commission’s use of tolling orders to stop the 30-day clock for acting on rehearing requests improperly prevents litigants from appealing its rulings indefinitely even as it allows gas pipeline companies to seize property under eminent domain and begin construction. (See D.C. Circuit Rejects FERC on Tolling Orders.)
Adrienne Claire, Thompson Coburn | Energy Bar Association
Moderator Adrienne Claire, a partner with Thompson Coburn, noted that FERC Chairman Neil Chatterjee and Commission Richard Glick asked Congress to provide the commission with a “reasonable amount of time to act on rehearing requests.” (In light of Allegheny, FERC must now respond to all rehearing requests within 30 days or they are deemed denied “by operation of law.”)
“What would be a reasonable amount of time in your opinion? What’s feasible?” Claire asked.
Morenoff said Chatterjee developed “great respect” for members of Congress and their staff from both parties through his extensive experience working on Capitol Hill, “so he leaves to Congress the question about what will be the reasonable amount of additional time if Congress were to respond to that call and take action.”
Morenoff pointed to two bills introduced into Congress last spring, H.R. 6982 and H.R. 6963, to address rights to timely rehearing of FERC decisions under the NGA and FPA, respectively. The two bills would set rehearing time frames to 90 days under the NGA and 120 days under the FPA, “perhaps reflecting the relative greater complexity that we often see in rehearing requests under the FPA with respect to particularly the organized markets,” he said.
“I think that those provide a really good starting point for discussions that are proceeding on the Hill,” Morenoff said.
In response to Claire’s question about what changes FERC has already made in response to Allegheny, Morenoff said that, even before Allegheny, Chatterjee had directed commission staff to expedite actions on rehearing requests, especially regarding landowner requests in gas pipeline certificate proceedings.
David Morenoff, FERC | Energy Bar Association
“We have been doing coordination among not only the sections across [FERC’s Office of the General Counsel], including the rehearings section that we set up in February, but among the various program offices at FERC that work closely on a rehearing request … and I think that’s just more important now as we try to move even more quickly to cover that same ground in a post-Allegheny world,” Morenoff said.
Allegheny also prompted FERC to begin issuing two types of new notices in response to rehearing requests, Morenoff said. The first states that “rehearing may be deemed denied, period,” while the second says that “rehearing may be deemed denied and the commission intends to issue a further order on the merits addressing arguments on rehearing,” he said. (See FERC will not Seek SCOTUS Review of Tolling Decision.)
“We’ve been trying to move quickly on those second orders, but I think both of those notices indicate that the commission is going to put more emphasis on our underlying orders more often because, as we’re trying to move more quickly, the old kind of standing rehearing order that would have a lengthy background section, then summarize the order in detail, then summarize all the arguments raised in rehearing, that probably isn’t possible anymore given these time frames,” Morenoff said.
‘Uphill Battle’
“One of the issues that was percolating a few years ago was whether in the absence of a quorum, FERC could even issue a merits order on rehearing, much less a tolling order,” an audience member said. “Do you think the Allegheny decision gives us any insight into how the courts might resolve that issue?”
“I don’t think that Allegheny sheds a great deal of light on that subject, but I think it’s a very important question because regrettably we’ve had less time recently with five commissioners that all of us inside and outside would like,” Morenoff responded. He noted that when the commission realized it would be dropping below quorum in 2017, it issued an order that covered the delegation of additional responsibilities to staff.
“At the time, based on the research we had done, we felt quite confident that as long as there is a proper delegation from the quorum of the commission, there’s quite a good deal that can be done by staff,” he said.
Claire turned to the broader panel to pose a hypothetical question about how the Supreme Court would have responded had FERC appealed Allegheny, a step the commission said last month it would not take.
“I think there’s a decent chance the court would’ve granted review because it has a pretty high rate of granting petitions when the government is asking it to do so,” said Erin Murphy, an Environmental Defense Fund attorney.
But Murphy thought FERC would have faced a “pretty uphill battle” on appeal because the court, while potentially sympathetic to FERC’s arguments about the tolling orders as a longstanding policy matter, would still doubt that the rehearing delays complied with what Congress was “trying to accomplish” when it set rehearing request deadlines under the NGA.
“There’s certainly arguments about congressional acquiescence, and there’s a lot of water under the bridge at this point, but I think that there’s just that dynamic of [the rehearing delays] feeling like circumvention that would’ve been hard to overcome at the court,” Murphy said.
