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.
SPP stakeholders last week endorsed a 10-year assessment of reliability and economic transmission projects that will likely continue to struggle to stay abreast of wind energy development.
“Actual wind in the ground outstrips our projections almost every time,” ITC Holdings’ Alan Myers, who chairs the Economic Studies Working Group responsible for the study, said during the Markets and Operations Policy Committee meeting, held Oct. 13 to 14.
The 2020 Integrated Transmission Planning (ITP) study comprises 54 projects at an estimated cost of $532 million, with a projected 4.0- to 5.2-to-1 benefit-to-cost ratio. The portfolio includes 92 miles of 345-kV transmission lines and 141 miles of rebuilt high-voltage infrastructure.
The two-year assessment’s business-as-usual reference case future projects 26 GW of wind energy by 2025 and 28 GW by 2030. The more aggressive “emerging technologies” future foresees 30 GW of wind by 2025 and 33 GW by 2030.
Meanwhile, SPP had 26.7 GW of registered wind capacity as of Sept. 1 and expects to have 29.7 GW in service by 2022.
“We are getting better. The projections for this study are a little further out,” Myers said. “You can draw the conclusion that we could have added more wind than we did.”
“If you look at ITPs in the past, most of the [reference case] Year 10 assumptions came to reality in two years,” SPP Director of System Planning Casey Cathey said. “Our wind assumptions … are becoming a reality a lot faster than Year 10.”
Casey called the ITP portfolio “fairly strong,” citing its B/C ratio. The study also took into account fossil fuel retirements and a 4- to 9-GW increase in solar generation.
The ITP assessment drew the usual criticism from transmission owners wary of building more 40-year facilities on top of the $10 billion or so in recently constructed SPP infrastructure.
“One of the questions we’ve asked for a long time is at what point do you quit building? At what point do you quit asking customers to be paying for these facilities?” Oklahoma Gas & Electric’s Greg McAuley asked. “We question the long-term viability of those benefits. We have no idea what the industry will look like in 40 years, much less in 10 years. The right transmission needs to be built. It’s these economic projects that we have the most concern about because those costs don’t go away.”
“These 40-year investments we’re making are actually fixed costs to the customers,” Golden Spread Electric Cooperative’s Mike Wise said. “SPP is showing variable costs with the B/C ratios. We’re trying to say the fixed costs are substantially risky because 40 years of fixed costs reduce some variable costs. Enough is enough. You can go broke to save money.”
The TOs approved the ITP study by a 12-2 margin, with three abstentions, as the measure passed with 88% overall approval.
Wind energy’s growth in the SPP footprint continues to outpace projections. | SPP
Center Stage for Electric Storage Proposals
Members began to address the footprint’s growing wave of energy storage resources (ESRs) by endorsing six recommendations from a white paper calling for SPP to capitalize on ESRs’ flexibility, reliability and economic benefits by developing cost-recovery mechanisms and determining whether they are used as generation and/or transmission assets. (See SPP Planning Approach to Battery Storage.)
“And many more to come,” said Evergy’s Allen Klassen, chair of the Operating Reliability Working Group (ORWG), referencing the document’s 37 proposals.
The ORWG worked with the Supply Adequacy Working Group (SAWG) in agreeing with the white paper’s recommendation to support use of the available effective load-carrying capability (ELCC) for ESR accreditation. The groups also urged adopting a four-hour minimum duration for capacity accreditation and no additional real-time ESR availability criteria.
Both recommendations passed unanimously. However, the two groups were unable to agree on the number of ESRs that can be aggregated in a resource adequacy portfolio. The ORWG recommended a maximum ESR participation limitation for each load-responsible entity, based on load and resource capacity calculations, while the SAWG argued against a participation limit “at this time.”
“We don’t feel the need to take action right now until we see the penetration and how batteries are used,” said Golden Spread’s Natasha Henderson, the SAWG’s chair. “We just don’t think we have the data to know what that limit is right now.”
SPP COO Lanny Nickell said staff will work on a scope document for a task force that further studies the issue related to FERCOrder 2222. Staff have already suggested a name for the task force: The 2×4.
Separately, the SAWG produced a white paper proposing a methodology for prioritizing and allocating the available ELCC from capacity-qualifying ESRs in SPP. The group contracted an outside consultant to analyze an ESR’s capacity credit on the SPP system using ELCC and capacity value and two dispatch strategies: preserving reliability and economic arbitrage. The study also evaluated the capacity credit of batteries using two-, four-, six- and eight-hour equipment.
The MOPC also approved a Market Working Group (MWG) proposal for modeling and controlling ESRs’ hybrid configurations, passing the measure against a single opposing vote.
The MWG and other stakeholders and staff chose a market storage resource (MSR) model among three other alternatives. The MSR market-registration model was created for FERC Order 841, which directed RTOs and ISOs to eliminate barriers to ESR participation in their markets. The model allows generating and storage resources to be represented as a single resource in the market model with one set of offers.
“To the market, it looks like one resource,” SPP’s Gary Cate said. “The less resources the market-clearing engine has in its matrix, the less time it takes to solve. This model could apply more broadly to anything that has storage.”
The ESRs will still be modeled separately for reliability purposes, with offer parameters consisting of all those associated with MSRs. A single offer curve would be submitted, but SPP said this could prove challenging for mitigated offer-curve development because the generating costs represent a blended opportunity cost of injecting and/or self-charging. Staff said the MSR option will allow market participants to manage the co-located resources’ interactions as long as their total injection or withdrawal meet the combined dispatch.
Cate said SPP has looked at how other RTOs are addressing battery storage “because everyone is going through this at the same time.” (See RTOs/ISOs File FERC Order 841 Compliance Plans.)
The committee also endorsed:
the Regional Tariff Working Group (RTWG) and MWG’s recommendation that transmission-only ESRs should not pay transmission service and/or ancillary charges related to their charging activity. Stakeholders said this would put ESRs on the same level with other transmission assets providing similar services for which they do not pay service charges.
An ORWG white paper that urges development of a policy requiring fast-responding ESR owners and operators to clearly define the resource’s ramping capability during the registration process; the definition of acceptable response-rate ranges for each ancillary service and ensure coordination of energy deployment across all participating resources; and governing policies that require resources to perform within their registered capability as dispatched by SPP. The MWG will take the lead on the work.
Interconnection Improvements
A cross-functional MOPC stakeholder group directed to develop policies creating a balance between energy resource interconnection service (ERIS), network resource interconnection service (NRIS), generator-interconnection products and long-term firm transmission service secured approval for a 72-page white paper and a recommendation to replace NRIS with a new capacity resource interconnection service (CRIS).
The NRIS/ERIS Deliverability Task Force (NEDTF) said CRIS would add deliverability to the existing NRIS product and provide a clearer distinction between the two services.
CRIS provides capacity deliverability from a single resource to any load within a control area, balancing authority or other designated region that contains more than a single load. NRIS provides the interconnection customer with a sufficient interconnection that allows the generator to qualify as a designated network resource on the transmission provider’s system without additional network upgrades.
NEDTF Chair Rob Janssen, with Dogwood Energy, said the task force, which evolved from a Holistic Integrated Tariff Team (HITT) recommendation, engaged with several other working groups, gaining generally favorable feedback. He said there was general agreement that larger deliverability areas are preferable.
The NEDTF received a little bit more pushback on its proposal to tighten thresholds for mitigating ERIS system impacts, picking up on work by a previous task force. The proposed revision request would address stakeholder conclusions that too many unmitigated constraints lead to undesirable effects in the SPP market.
Committee members expressed concern over the $400,000 cost, but staff noted most congestion studies require building a generation and portfolio modeling system. In the end, the MOPC gave the threshold-tightening recommendation against just four opposing votes.
Members also endorsed the NEDTF’s white paper, which Janssen said would “lay the foundation” for whatever work will follow.
More White Papers Approved
The MOPC overwhelmingly signed off on several white papers related to the HITT’s recommendations:
the Transmission Work Group’s paper documenting modifications to Tariff Attachment AQ limiting its application to new load, revisions to loads and load retirements that need to be addressed outside of the ITP because of timing or some other “significant” reason. The paper, approved unanimously, was produced to increase transparency and shorten the turnaround time to facilitate load growth.
a joint report from the ORWG and MWG demonstrating the economic benefits of topology optimization by using existing transmission assets to increase grid flexibility and efficiency. According to the report, while transmission elements are traditionally viewed as static elements, their topology reconfigurations may provide a means to reliably reroute power around congested facilities without causing additional burden on the system.
The ORWG and MWG also produced a second white paper on economic outage coordination that was part of the consent agenda. The paper explored other RTOs’ outage coordination processes and criteria thresholds before concluding SPP will need to invest time and money fully integrating and streamlining the process to take full advantage of the economic benefits.
Staff will use the white papers to develop policy and Tariff language to implement the changes.
$91M Increase for NPPD’s R-Project
Members approved a nearly $91 million increase for Nebraska Public Power District’s R-Project, raising the controversial 345-kV initiative’s price tag to $463.4 million. The measure passed with 83.5% approval.
NPPD warned the Project Cost Working Group in September that it expected the project to be out of bandwidth in the near term. The publicly owned utility has already sunk $100 million into the project and said its original estimate “significantly underestimated” the environmental cost, which was based on typical environmental tasks in previous efforts.
The project comprises 225 miles of 345-kV transmission line running through the environmentally sensitive Nebraska Sandhills and two new substations. It was approved as part of the ITP 10-year assessment in 2012 and received a notification to construct with conditions the following year.
In June, a federal district judge revoked a federal permit that would have allowed NPPD to kill or severely disturb the endangered American burying beetle during construction. The utility has said the ruling will delay but not stop the project, which has a 2024 in-service date.
Several TOs called for the project to be suspended and re-evaluated over cost concerns. That motion failed with only 30% approval.
“Is this still the right project?” asked Bill Grant, of Xcel Energy’s Southwestern Public Service. “This has been re-baselined several times, and I have huge concerns we’re not doing our due diligence. I have to ask whether this project is prudent or not.”
“This is a significant overrun here, and it’s been going on for a long time. At some point, we have to take another look at it,” McAuley said. “That’s why those of us who build transmission are very cautious. There’s always uncertainty. You can wind up in this situation four or five years down the road, but it’s too late. Customers are already paying for it.”
SPP staff said several generator interconnection agreements are dependent on the project, which has been framed as enabling renewable power, reducing congestion and strengthening system reliability.
“We have to continue to honor the [transmission] service in those agreements,” said Antoine Lucas, SPP’s vice president of engineering.
“The assumptions on this line going in are not the same as they were years ago,” said Advanced Power Alliance’s Steve Gaw, noting the project was originally approved as a reliability solution. “To evaluate and further delay this project has the potential to significantly increase costs.”
Carias Governs Last Meeting as Chair
MOPC members honored their chair, NextEra Energy Resources’ Holly Carias, with a virtual happy hour following the end of her two-year term and treated her to a parade of compliments.
“I couldn’t have done it without the entire membership. We had some challenges with COVID, but I think we responded pretty well,” she said. The full committee met virtually three times during the year, aided by staff’s development of an efficient e-voting system.
SPP COO Lanny Nickell, the committee’s staff secretary, noted that it will soon complete a structural reorganization of its stakeholder groups, an effort that began shortly after Carias took the gavel in January 2019.
“Holly led the group with poise and tact,” SPP Board of Directors Chairman Larry Altenbaumer said.
Evergy’s Denise Buffington, who served as Carias’ vice chair, shared an Albert Einstein quote translated from the original German: “Life is like riding a bicycle. To keep your balance, you must keep moving.”
Carias will continue as MOPC chair until November. She is leaving NextEra for Avangrid Renewables, where she will be vice president of origination. Buffington will serve as acting chair for the remainder of the term, which ends Dec. 31.
“We’re not [an SPP] member, but hopefully we will be soon,” Carias said.
Avangrid Renewables is a subsidiary of Spain’s Iberdrola Group, a renewable energy pioneer with more than 32 GW of projects spread across a dozen countries. Portland, Ore.-based Avangrid has more than 7.3 GW of wind and solar generation in more than 20 states.
Some Byway Costs to be Allocated Regionally
The MOPC endorsed the RTWG’s recommendation to implement previously approved language that creates a narrow process through which costs for transmission projects between 100 and 300 kV primarily used to move power out of the local transmission pricing zones can be fully allocated prospectively on a regionwide basis.
TOs opposed the measure (RTWG RR422) over what they said was a shift of byway cost responsibility from wind-rich areas to others. The change cleared TOs by 10-5 but enjoyed a 31-7 approval from transmission users in gaining an overall approval of 72.12%.
The MOPC’s consent agenda, which passed unanimously, included nine additional revision requests:
ESWG RR403: updates the ITP manual language to support current capabilities, as software revisions prevent building models on historic time periods.
MWG RR420: adds clarifying language to ensure SPP’s fast-start pricing practices are in FERC compliance. (See “Directs Further Compliance Filing on Fast-start Resources,” FERC OKs 2 Changes from SPP’s HITT Work.)
MWG RR421: removes registration provisions requiring energy storage resources to provide certification that its participation in the market is not precluded by the relevant electric retail regulatory authority, as required to FERC to be in compliance. (See RTOs Move Closer to Full Order 841 Implementation.)
MWG RR425: adjusts the day-ahead make-whole payment charge type’s calculations and changes the real-time out-of-merit charge type and the reliability unit commitment make-whole payment calculations.
PCWG RR415: clarifies and updates existing language in Business Practice 7060 (Notification to Construct and Project Cost-Estimating Processes).
RTWG RR423: removes expired or terminated grandfathered agreements from a Tariff attachment’s index and updates any termination dates that have changed or any changes in buying or selling party terminology.
SAWG RR412: allows both new and upgraded capacity from existing generators to be treated equally in qualifying as accredited capacity during the first peak season that each is available, thereby preserving the members’ expected generation investment value.
TWG/ESWG RR427: removes some of the detailed project proposal form’s requirements to reduce its size and scope.
Staff RR416: brings more accurate reporting and communication of RRs. Clarifies when an RR exploder is required to be used; requires summaries and notices of FERC rulings on RRs; and adds a section that documents the purpose of what is to be included in the RR master list.
The consent agenda also included approval of a $14.67 million increase above the $32.46 million original estimate for Empire District and Evergy Kansas Central’s 161-kV rebuild in eastern Kansas; an additional 161/69-kV transformer for Apex Clean Energy’s Jayhawk Wind project in eastern Kansas; scope revisions for the MOPC’s reorganized stakeholder groups; and the 2019-2020 annual violation relaxation limits report.
Transmission owners, regulators and stakeholders face a massive task in planning for new transmission as they attempt to modernize the grid and prepare for an influx of renewable resources.
That was the key takeaway of a panel at last week’s Energy Bar Association annual Fall Conference entitled “Looking into the Transmission Crystal Ball: What are the biggest issues facing the transmission industry in the next five years?”
A diverse cross-section of stakeholders from around the country working in various aspects of the energy industry quizzed a panel of transmission experts on their outlook for the grid.
Jason Stanek, Maryland PSC | Energy Bar Association
Jason Stanek, chairman of the Maryland Public Service Commission, said transmission assets built to meet delivery needs almost 100 years ago are reaching the end of their useful life and are being slated for replacement. At the same time, states like Maryland are advancing clean energy policies like offshore wind that will require transmission upgrades.
Stanek said the delivery systems were originally planned under an “umbrella approach” that considered the “interplay of regulatory policies and customer needs in a just and reasonable manner.” Planning for grid upgrades has become more complicated now that transmission planning today is primarily the responsibility of RTOs and ISOs, along with the growing state-federal conflict over energy and environmental policies, Stanek said.
In his question to the panelists, Stanek asked how regulators and stakeholders can “reopen the umbrella” to have coordinated and cost-effective transmission planning to achieve a clean energy future.
Beth Emery, GridLiance | Energy Bar Association
Beth Emery, senior vice president and general counsel for GridLiance, said she is seeing major pushback from RTO/ISO stakeholders over what some claim to be “the spiraling cost of transmission.” Emery said most of the current costs for transmission are tied up in reliability projects, in which cost-benefit analyses are not typically done, adding to the skepticism about costs.
Unless stakeholders, including state regulators, have open and transparent access to what projects are being proposed, planning estimates and the actual costs, Emery said, it will be difficult to convince ratepayers that the transmission projects have value.
Emery said FERC’s push toward forward-looking transmission formula rates seems to have made the transparency problem even worse, encouraging new transmission builds but making it even less clear on the costs.
GridLiance has a published white paper proposing FERC require RTOs to collect and publish consistent data on transmission investment, Emery said, which some RTOs already do, but the information can be difficult to find.
“It’s almost impossible for customers to get useful project-by-project information in the formula rate protocol process,” Emery said. “I think TOs need to be able to plan and make prudent decisions for local reliability, and they absolutely need to maintain their existing assets. But plans should be transparent and costs discoverable.”
Valerie Teeter, senior manager of federal regulatory affairs at Exelon, said Stanek’s question addressed an important trend. In states that have restructured transmission planning, Teeter said, there has been a move away from integrated resource planning between utilities and the states to determine the needed resources to meet environmental goals and the role transmission will play.
Valerie Teeter, Exelon | Energy Bar Association
Teeter said broader regional planning creates some “disconnects” between the utilities and states, with utilities waiting to see what projects get into the generation interconnection queue. She encouraged state regulators to think about how they could play more of a role in planning because they have the clearest vision of state energy goals.
“States have clean energy goals; they have ideas of what they want their future to look like,” Teeter said. “They understand the resource mix they’re hoping to see to lead them to their clean energy future.”
Lisa McAlister, senior vice president and general counsel for American Municipal Power, said customers are experiencing “sticker shock” as TOs continue to replace aging infrastructure across the country. McAlister agreed that greater transparency in the planning process and rate structures would help customers better understand the projects and help TOs better justify the projects that are most cost-effective.
McAlister said efforts currently underway in PJM, ISO-NE and CAISO by TOs to remove projects from the regional transmission planning processes and make themselves solely responsible for planning will “balkanize the transmission grid,” increasing costs and customer complaints.
“That’s going to make achieving a clean energy future more challenging,” McAlister said.
5-year Discussion
John Moura, NERC director of reliability assessment, said he views the changing resource mix as one of the most important reliability issues to tackle over the next decade. Moura said industry-supported studies have determined that an extra-high-voltage network from Wyoming to Ohio will be needed to achieve carbon-reduction goals.
Moura asked how to start difficult conversations about transmission among stakeholders in the next five years.
Lisa McAlister, AMP | Energy Bar Association
Customer demand is driving the development of renewable resources and carbon pricing, McAlister said, and having discussions with a focus on meeting mandated or voluntary objectives, whether carbon-reduction goals or planning for the grid of the future, will require a coordinated approach between consumers, load-serving entities, distribution and transmission utilities, the RTOs, FERC and Congress.
“Now, more than ever, we need to develop a collaborative and a consensus-based approach to building transmission that spans multiple states to connect these renewable resources to the load pockets,” McAlister said. “The most effective pathway forward will be through the RTOs because they have the most comprehensive information regarding new generation and the interconnection queue, congestion and other market data.”
Emery said stakeholders involved in the planning process understand the steps needed to be taken to build a consensus, but reaching that consensus is difficult. Consensus is built by making people comfortable and helping them understand the costs of projects and what the benefits will be once they are completed, she said.
She said she believes federal legislative action is needed to make interregional planning successful and that states will not be able to do the necessary planning without a prompt from Congress. There must also be a mechanism for everyone involved in the planning process to benefit in some way, she said.
Emery pointed to the creation of the interstate highway system as a federal model to strive toward.
“We need to figure out how we take that model and apply it in the context of transmission where there’s a cooperation between the federal government and the state governments and all the consumers because people see both local and national benefits from what we’re doing,” Emery said.
Federal Policies
Rob Gramlich, president of Grid Strategies, said modeling shows the need for larger regional and interregional transmission, but the regulatory structure is not in place to effectively facilitate for planning. Gramlich said FERC Orders 890, 2000 and 1000 all attempted to address some of the regional transmission planning, but a gap exists between what needs to be done and where the process currently stands.
Gramlich asked how policies can be put in place through FERC or Congress to make regional and interregional planning happen more often and more smoothly.
Jennifer Curran, MISO’s vice president of system planning, said when the conversation of interregional planning comes up in the RTO, there are three conditions that take precedent in transmission building: “policy consensus, robust business case and fair cost allocation.”
Curran said policy consensus does not mean all stakeholders are pursuing the same goals, but it does mean that stakeholders have decided transmission is a way to help meet renewable goals and bridge the diversity among state goals. She said her expectation is that a federal policy to provide for regional and interregional transmission planning would have to be “pretty extreme” because many states will want to go faster in the planning process, while others would continue to be resistant to change.
“If we can get to a place where everybody understands transmission is part of the answer, then I think that’s helpful,” Curran said.
FERC has allowed MISO to avoid eight years of resettlement work on certain manual dispatches dating back to early 2009.
The commission last week did not act on MISO’s longstanding Tariff violation. The grid operator may have miscalculated on some make-whole payments to resources that were manually dispatched from January 2009 to May 2018 (ER18-1611).
Commissioner James Danly concurred with the decision while castigating FERC’s multiple other waiver approvals.
MISO said that during a 2018 quality check, it discovered that its settlement system was not technically handling manual redispatch as outlined in its Tariff. It said its software was setting dispatch instructions to a specific level, rather than a range of acceptable dispatch levels as described in the Tariff. The RTO also said its software was checking for economic dispatch statuses in both the day-ahead and real-time markets, when its Tariff does not require such a check for economic status in the day-ahead market.
The financial fallout from the eight-year inconsistency totaled just $1.6 million, or $200,000 annually, MISO said. The grid operator said manual redispatch was necessary in a little more than 1% of all make-whole payment hours since 2009.
MISO also said its Independent Market Monitor did not find any generators “intentionally making inflexible offers … to gain excess margins from the system during intervals that a resource was manually redispatched.”
MISO control room | MISO
FERC said that while the discrepancy amounted to a nearly decadelong Tariff violation, the amounts were too small to be reopened, calling resettlement counter to public interest.
“We agree with MISO that, based on the circumstances here, market resettlement and refunds are not an appropriate remedy,” FERC said. “We are persuaded that, to the extent resettlement of the market transactions at issue would be feasible, requiring such resettlement and associated refunds could create inequitable results by unfairly punishing market participants that followed MISO manual redispatch instructions and could undermine confidence in market outcomes.”
The commission cited its “broad authority” to determine remedies for Tariff violations. It also said that because it was not directing resettlement or refunds, it was not required to address MISO’s waiver of its Tariff during the discrepancy.
Danly said he agreed with the decision, unlike the nine waiver approvals issued during FERC’s open meeting Thursday. He said that in this instance, FERC did not exceed its legal authority by granting a backdated waiver that could violate the filed-rate doctrine and rules prohibiting retroactive ratemaking. Instead, he said, the commission confirmed the violation between settlement software and Tariff language and disregarded the request for waiver.
“I agree with this holding. In my view, this is the approach we should take in all situations where a utility has violated its own tariff,” Danly said, noting MISO’s “relatively small error and the extreme difficulty in resettling bills back to 2009 support this decision.”
Danly also said FERC should have first denied MISO’s waiver request, then made the finding that the RTO violated its Tariff to keep the commission’s decision-making process uniform and orderly.
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.
