Baltimore Gas and Electric will pay $170,530 to MISO members to end a dispute over cross-system congestion costs under a settlement approved by FERC last week.
FERC’s Nov. 17 order settles a dispute between BGE and almost 30 MISO utilities relating to the cross-system congestion costs known as Seams Elimination Charge/Cost Adjustments/Assignments (SECA). FERC said the uncontested agreement represents “a final settlement of all SECA obligations.”
| Baltimore Gas & Electric
The settlement directs BGE to pay members of the RTO $344,665 and for the RTO to collect $174,135 from its members for BGE, for a net payment by BGE of $170,530. The approval closes out dockets ER05-6-124, EL04-135-126, EL02-111-145 and EL03-212-140.
The SECA cases originated from a 2002 FERC decision allowing American Electric Power, Commonwealth Edison and Dayton Power and Light to move from MISO to PJM. The move created areas in the RTO that were cut off from the rest of the footprint and led to rate pancaking and the eventual elimination of regional through-and-out rates.
FERC approved the 16-month SECA transitional payment mechanism for 2004-2006 and upheld SECA use in 2010, but it said SECA rates recovered from MISO and PJM transmission customers were subject to refund by MISO and PJM transmission owners. The 2010 decision imposed additional SECA liabilities on BGE. MISO laid out SECA amounts in 2013, charging BGE and about 15 other PJM load-serving entities a combined $4 million in SECA charges.
LITTLE ROCK, Ark. — SPP gathered a half-dozen vendors to show off some of the latest transmission technologies before an audience of stakeholders and staff last week. A first for SPP, the Technology Expo was following a trend set by other RTOs.
“Doing these things is necessary because technology is evolving,” said Todd Ryan, director of regulatory affairs for Smart Wires. “It’s good for us because it helps us understand where our product fits in.”
Ryan was on hand to push his company’s PowerLine Guardian, a modular transmission power-flow control that the company says “will change how power grids are designed and operated.” Combined with the company’s Power Router, the Guardian addresses congestion through local control or central dispatch through devices hung on conductors and towers or deployed in substations.
“You ever hear of the Whac-a-Mole problem?” Ryan asked. “When you solve a problem in one place, it just to moves to another. Every grid has this problem, but [with Smart Wires], you have a tool to more finely tune your investment to your needs and whack more moles.”
Other speakers shared the latest on advanced conductors, topology optimization, dynamic line rating, energy storage and HVDC transmission lines. Almost three dozen members of SPP’s staff and stakeholders attended the expo, with others listening on the phone.
“All technologies are about two things: bringing new capacity to the market and integrating renewables,” said Joe Coffey of General Cable. He motioned to the screen behind him, where a slide showed higher-capacity conductors. “Hey look, a new technology!”
Jay Caspary, SPP’s director of research, development and Tariff studies, said the expo was designed to educate staff and stakeholders “of opportunities that exist today to improve grid operations and planning.”
“We look forward to continued dialogue with interested stakeholders, and we will work with members on efforts which could lead to pilot programs in the near future,” Caspary said.
FERC said last week it is considering changing the way it establishes license terms at nonfederal hydropower projects.
| FERC
The Federal Power Act allows the commission to issue original licenses for up to 50 years and renewals for between 30 and 50 years.
The commission’s current policy on renewals is to set a 30-year term when there is little or no new construction, or environmental mitigation required; a 40-year term for projects with a “moderate” amount of such activities; and a 50-year term for projects requiring “an extensive” amount of such activity.
“The purpose of this policy is to ease the economic impact of new costs and promote balanced and comprehensive development,” FERC staffer Carolyn Clarkin said in a presentation at Thursday’s open meeting. “Determining whether the measures required under a license are minimal, moderate or extensive is highly case-sensitive and largely based on a qualitative analysis of the record before the commission.”
The commission’s policy is a forward-looking approach, “such that measures adopted under a previous license term are not considered,” Clarkin added.
In a draft Notice of Inquiry (RM17-4), FERC sought comment on five potential options:
Retaining the existing license-term policy
Considering measures implemented during a prior license term
Establishing a 50-year default license term
Including a “more quantitative cost-based analysis”; and
Establishing the license term based on negotiated settlement agreements when appropriate.
The open meeting also featured a staff presentation on the commission’s dam safety program and a description of the recently opened Meldahl Project, four sets of hydropower turbines at locks and dams on the Ohio River. A joint venture between American Municipal Power and the City of Hamilton, Ohio, the 300 MW project was the first major hydropower project constructed in several decades in the U.S.
Meldahl Projet | AMP Public Power Partners
FERC regulates more than 2,500 dams with 55,800 MW of capacity, more than half of all hydroelectric capacity in the U.S. Almost 1,000 of the dams are classified as posing high or significant hazards and subject to annual inspections. The remaining, low-hazard, dams are inspected every three years.
LA QUINTA, Calif. — State commissions have a significant part to play in shaping RTO rules, but they must actively seek a place at the table when key decisions are being made, regulators and RTO representatives said during a panel discussion at the National Association of Regulatory Utility Commissioners annual conference last week.
Another takeaway: States will exercise more influence in the process when they cooperate with each other and strive to speak with a common voice.
Vermont Public Service Board Member Sarah Hoffman, the panel moderator, kicked off the discussion with a close-to-home example of the often-complicated relationship between states and RTOs.
Hoffman cited the challenges facing New England’s Integrating Markets and Public Policy (IMAPP) stakeholder process, which seeks to identify changes needed to align the region’s wholesale market with individual state energy policies, particularly those related to renewable energy. The goal of the process is to translate state policies into market rules that ISO-NE can adopt.
“It is a process that is ongoing and that has really put the states into the center of the discussion about how we are going to integrate these public policies” into the market, Hoffman said.
But it hasn’t been seamless.
“Generators and suppliers want to tear their hair out because the six states don’t all want the same thing,” Hoffman said. “Where Massachusetts wants 1,600 MW of offshore wind, Vermont has different requirements. Market participants would prefer that all the states share the same requirements.
“Based on the fact that we all have legislators, that’s never going to happen,” she added.
State Discord in PJM
“If all of the PJM states can be on the same page, that is very effective advocacy,” said Asim Haque, chairman of the Public Utilities Commission of Ohio.
That kind of unity is desirable whether the states are dealing with a “ground-up” state-initiated policy or a “top-down” PJM initiative, he said.
“The intrigue lies in when states do not agree,” Haque said.
Haque noted that the Organization of PJM States Inc. requires a 51% vote to take a policy position.
“If you’re not able to get that 51% and the states start going it alone on an issue, I think it creates a little friction between the states,” Haque said.
Indiana Utility Regulatory Commissioner Angela Weber emphasized the need for regulators to be engaged with their RTOs.
“There are a lot of commissioners who just aren’t engaged, and I think the idea is that [state commissions] don’t have jurisdiction over the RTO, so it doesn’t matter,” she said.
Weber said her work on the Organization for MISO States can seem like a distraction from state-related work, but she considers her involvement to be vital for her state’s residents.
She pointed out that MISO has approved more than $25 billion in transmission spending since 2003.
“All these costs flow through to our ratepayers,” Weber said. “If regulators in MISO want to have influence on these costs, they are better off doing so at the MISO level before the costs get passed on.”
Weber also pointed to an essential connection between state commissions and RTOs.
“There’s an intersection between the RTO’s responsibility to maintain reliability and the state regulator’s responsibility for ensuring resource adequacy,” Weber said. Through their resource planning processes, “the states effectively determine the tools that MISO has at its disposal to maintain reliability,” she said.
SPP General Counsel Paul Suskie said states wield significant influence within his RTO through the Regional State Committee. The committee has governing authority over transmission access charges, financial transmission rights, planning for remote resources and resource adequacy, while also providing input into market developments, strategy and transmission planning.
“Our CEO will tell you that when he said we were going to give state regulators this authority, some of his counterparts thought he was crazy, that it’s not going to work,” Suskie said.
The SPP model works because of the time and effort state commissions dedicate to working through market issues, Suskie said.
“Other states ask me about our governance model and I tell them, ‘From the state commissioner perspective, the good thing is you have the authority. The bad thing is you have the authority,’” Suskie said.
Stacey Crowley, vice president of regional and federal affairs at CAISO, said that a change in governance is key for enabling the ISO to expand into other parts of the West. The ISO was created in 1998 as a single-state body under California statute, with board members appointed by the governor.
That structure “will not satisfy a regional ISO,” Crowley said.
Crowley noted that regional discussions about a Western RTO have focused on the fact that each state has different policy structures, goals and procurement strategies.
“Those are all important and need to be respected in a regional ISO,” Crowley said.
While California represents a large population in the West, “its policies need to be seen as equal amongst all the states” in an RTO, she added.
CAISO has developed a model for state involvement with its Energy Imbalance Market, which features a regionally representative governing body and an advisory body of regulators that provides states with a forum to discuss market issues.
“It’s been a good way to develop a relationship and a way to communicate amongst the states,” Crowley said.
“FERC recommended MISO should explore and work with stakeholders to see if we need to change the confidentially provisions,” explained Neil Shah, MISO adviser of seams administration, during the Nov. 16 meeting of the Planning Advisory Committee.
FERC made the suggestion in an August order (ER16-1758) that largely accepted changes to MISO’s system support resource procedure. (See “MISO Planning Confidentiality, Notification Changes to Attachment Y Procedure,” MISO Planning Advisory Committee Briefs.) The commission recommended that MISO might follow PJM’s lead in notifying the public of future suspensions and deactivations as the notices are received.
“We recognize that PJM provides for even greater transparency by subjecting all official future generator deactivation requests to public notice,” FERC said. “We also encourage MISO independently to explore the possibility of allowing for greater transparency due to changing market conditions, further experience with the SSR and transmission planning processes, or other factors.”
If confidentiality is lifted, MISO would be able to publicly identify all generators that submit Attachment Y notices. Currently, the RTO keeps Attachment Y information confidential until the effective date of retirement unless its reliability study uncovers a reason to keep the unit online as an SSR or the resource owner has already disclosed the upcoming retirement.
“We definitely see merit in removing confidentiality,” Shah said. “It does help other resource owners understand the changing resource mix in MISO on a proactive basis rather than reactively.”
Shah said some generation owners submit Attachment Y notices as much as two years in advance. MISO requires six months’ notice.
MISO also said making the information public would help owners make new investments and site new projects more quickly and would facilitate more transparent discussions about reliability needs and the most useful transmission projects. Shah said having retirement notices from the start would be useful to the RTO’s Subregional Planning Meetings and its Economic Planning User Group.
Hwikwon Ham of the Minnesota Public Utilities Commission said state regulators should be involved at the beginning of retirement and suspension notices. “I think it’s now more relevant to release this data ahead of time so everyone can make a fair evaluation” for state resource planning processes, Ham said.
Shah asked for written feedback by Dec 2.
Storage Projects to be Included in Queue Rules — For Now
MISO is amending its generation interconnection Business Practices Manual to include interconnecting energy storage devices.
Shah said storage projects wishing to enter the interconnection queue will be treated like other resources and language will be added to Business Practices Manual 015 to expressly include such devices.
Energy storage projects seeking a new interconnection can follow the documented standard process to interconnect a new facility. Customers that already have an interconnection and wish to connect storage projects must request either a material modification study if their project will not exceed the megawatt estimate on their generation interconnection agreement or request an increase in generation capacity study if the megawatt amount will exceed what was estimated in the agreement.
Finally, customers wanting to connect a storage project to a pre-existing point of interconnection that they do not own must either make sure their connection will not exceed the megawatt value from the original agreement or be an affiliated company with a separate generation interconnection agreement.
Shah said the point of the BPM change is to cut a clear path for energy storage wishing to provide generation or capacity. He asked for stakeholder input by Dec. 2 and said MISO would return with updated language at the December or January PAC meeting.
Sam Gomberg, an energy analyst in the Midwest office of the Union of Concerned Scientists, asked if the rules would be open to future changes that accommodate the unique abilities of storage. He said he was seeking reassurance that MISO isn’t “foreclosing” on a more flexible process in the future.
MISO PAC liaison Jeff Webb said a larger discussion on storage integration will continue. “We do need to be prepared with basic procedures to handle immediate requests, and I think that’s what this language sets out to do,” Webb said.
Shah said the clarifying language does not require a Tariff change.
Quarterly Operating Limit Studies Charge Moved to Separate Filing
Because FERC has rejected MISO’s queue reform filing, the RTO plans make a separate filing to begin charging interconnection customers for Quarterly Operating Limit (QOL) studies, MISO’s Paul Muncy said.
Muncy said MISO has decided to pull the QOL cost responsibility language out of the larger queue reform filing in the hopes of quicker FERC approval. QOL studies determine a generating facility’s maximum permissible output.
The revised QOL language would require customers to make a $10,000 study deposit 60 days before a binding quarter begins. Differences between the actual study cost and deposit will be refunded or billed to the interconnection customer.
Because MISO plans to charge for the studies, interconnection customers will be able to opt out of the study, Muncy said.
“The QOL study may give you additional capacity for each quarter, but we do have some customers who may decide that ‘eh, it’s only one or two additional megawatts,’” Muncy said.
Muncy asked for stakeholder feedback on the proposed filing by Dec. 7.
LA QUINTA, Calif. — While the election of Donald Trump as president of the United States has clouded the future of federal energy policy, one thing is clear: President Obama’s Clean Power Plan won’t figure into it.
Such was the consensus view of a panel convened last week at the National Association of Regulatory Utility Commissioners annual conference to discuss the election’s potential impact on energy sector regulation.
“The Clean Power Plan is done — for the time being,” said Ray Gifford, past chairman of the Colorado Public Utilities Commission and formerly president of the Progress and Freedom Foundation, a now-defunct conservative think tank that advocated for reduced federal oversight of the telecommunications industry.
Gifford said the unwinding of the CPP could be part of a broader effort by Congress “to undertake broad-based regulatory reform,” which would also include eliminating the doctrine of “net neutrality” in telecommunications regulation.
Former Colorado Gov. Bill Ritter, now director of the liberal Center for a New Energy Economy, agreed with Gifford’s assessment, though he didn’t share his enthusiasm that the change would be positive.
“Ray’s right, [the CPP] is likely to be undone,” Ritter said, adding that “it’s connected back to Congress reasserting itself.”
Not So Bleak
Still, the prospects for reducing greenhouse gas emissions aren’t so bleak, speakers said.
“The interesting thing about state work is you realize that, apart from the Clean Power Plan — markets are already driving us to a variety of different methods of decarbonization,” Ritter said, acknowledging that state public policies are driving markets “to some extent.”
But markets have their limitations and cannot “dictate the timing” of dealing with issues such as climate change in a serious way, Ritter contended.
“So, what you’re going to see is a variety of states that are going to say, ‘We’re not going to let the markets control this because we think climate change is this important thing and we need to act,’” Ritter said, referring to the ambitious renewable energy standards enacted by states such as California, Hawaii, New York, Oregon and Vermont.
“It feels to me like there’s some momentum there that’s not going to be necessarily impacted by a course direction at the federal level,” Ritter said.
Moderating the panel was Montana Public Service Commissioner and outgoing NARUC President Travis Kavulla, who asked Gifford whether newly empowered Republicans would allow states to continue to pursue policies favoring renewable resources or intervene on behalf of traditional resource industries.
“I think that’s the big question, Travis,” Gifford replied. “I think Republican orthodoxy is to let the states be laboratories of democracy. You send power back to the states; you let those decisions be made closer to point of contact with the voters and the citizens.”
States’ Impacts on RTOs
But Gifford asserted that RTOs and ISOs are “being roiled by state action underneath them,” citing New Jersey and Maryland legislators’ attempt to fund new generators for their states and efforts by New York, Ohio and Illinois to subsidize existing in-state fossil and nuclear plants. (See related story, Bill to Save Coal, Nuclear Plants Introduced in Illinois.)
“That’s a big issue for the next FERC, and how they deal with it is anybody’s guess because you’ve got a lot of strains going on in markets and you’ve got a lot of states very unhappy with what markets are yielding,” Gifford said. “By watching New York, Ohio and Illinois the next six months to a year, and watching how FERC reacts and how the administration reacts, I think says a lot about the future of these wholesale energy markets.”
Devin Hartman, electricity policy manager at R Street Institute, a think tank that promotes competitive electricity markets and “limited, effective government,” said his organization “doesn’t see a clear need to reform any of the core aspects” of the Federal Power Act, although clarity is needed on what forms of state intervention in the energy sector would be viewed as acceptable under the act.
A specific area of concern: the need for a clearer line between federal and state authority over policies concerning distributed energy resources.
“It’s important to keep the core principles of the Federal Power Act intact, which has been correctly interpreted by FERC to uphold competitive markets,” Hartman said.
Conservative lawmakers might turn their attention to “tackling” the Public Utility Regulatory Policies Act, according to Gifford, who referred to the act as “strange, outdated law” with “a very bad track record.”
False Price Signals
“You can maybe give it credit for juicing the independent power production world,” Gifford said, but PURPA also created “false price signals.”
“It doesn’t fit with Devin’s competitive wholesale market model at all, and it has brought many states to their knees,” Gifford said. “So I’d start with, ‘Let’s erase it and start the bidding from there.’”
Ritter said the potential for grid modernization represented the “biggest difference” between a Hillary Clinton and a Trump administration on issues related to electricity.
“It’s something that you as commissioners should care a great deal about,” Ritter told the audience, referring to the deployment of microgrids, “smart grid” technologies and transmission network improvements.
Ritter said he hopes grid modernization will end up as part of a broader infrastructure package under the new administration.
“But there are a lot of people that hear infrastructure and they don’t think the grid,” Ritter said.
Panelists were asked to conclude the session with a bit of advice for the incoming president and Congressional leadership.
“Pay attention to science,” Ritter said. “I really respect the attention that we need to pay to markets, but markets can’t always dictate timing.” He added that the U.S. needs to understand its “role and obligation in trying to address the very serious global problem” of climate change.
Hartman said it’s important that the country take a “long-term view” on the efficacy of environmental policies that he thinks could cause economic harm without making much of a dent in overall global emissions.
“When we see international environmental progress work well, it’s when the emissions abatement technology was cheap,” Hartman said. “That’s where a long-term innovation agenda is so important.”
Gifford wrapped up with a humorous solution.
“Appoint state commissioners to federal agencies and regulatory commissions,” he said to laughter. “Pandering to the audience, you can never go wrong.”
Clark: Trump Election to Have Limited Impact on FERC
In a separate question-and-answer session with Kavulla, former FERC Commissioner Tony Clark said it was too early to tell exactly what impact Trump’s election would have on the CPP.
“We know that the new administration has indicated that they’re going to look to pull it back in some way,” he said, adding that states will likely have “more time and flexibility” to deal with the changes that would come with the plan.
Clark doesn’t see significant post-election implications for FERC as an agency.
“You tend to not see huge swings out of FERC” after elections, he said. “You’ll have a little more of a bully pulpit, maybe, on some of the reliability issues where reliability and environmental regulations come up.
“But any new group of commissioners brings a [bit of a] different perspective,” Clark said.
Clark said he thinks there’s been “an unraveling of the regulatory consensus” during the 16 years he’s worked as a utility regulator. He said regulators at one time focused on answering the question of what are the most safe, reliable and affordable forms of energy to serve ratepayers.
Now the questions are myriad.
“In some cases it’s things like, ‘How do I preserve these generation jobs in my state?’” said Clark, who agreed to join law firm Wilkinson Barker Knauer after four years on FERC and 12 years on the North Dakota Public Service Commission.
“How do I preserve my tax base? How do my utilities plan for a carbon-constrained future? How do they reduce their carbon footprint?”
Clark hedged on a question about whether electricity regulation has become more partisan.
“Maybe in some way,” Clark said. “I think so much of environmental politics has come into the job that utility commissioners do.”
Still, Clark said that utility commissions are relatively insulated from politics compared with other federal and state agencies.
Speaking of his time at FERC, Clark noted, “We often said there is no Democrat or Republican way to keep the lights on, and I think that consciously trying to keep politics at bay and out of the regulatory commission was something that was very important for the long-term integrity of the agency.”
The NYISO Board of Directors on Tuesday upheld the Management Committee’s vote to cap capacity payments in the constrained Lower Hudson Valley and New York City zones.
Zone Map | NYISO
The board’s Nov. 15 order rejected an appeal by the Independent Power Producers of New York. The association sought to overturn the Management Committee’s Oct. 25 vote, which the ISO said was needed to protect consumers from higher prices. (See Generators Appeal Lower NY Capacity Cap.)
The rule change was in response to FERC’s Oct. 17 order allowing Castleton Commodities International’s 1,242-MW Roseton 1 generator to supply 511 MW of its capacity to ISO-NE beginning next June for the 2017/18 delivery year.
The board’s written decision rejecting IPPNY’s appeal has not yet been posted on NYISO’s website.
California Public Utilities Commissioner Carla Peterman sees zero difference between the two numbers.
“Now, granted, [there are] three zeros of difference,” she said, eliciting laughter during a panel discussion on EV rate design at the National Association of Regulatory Utility Commissioners’ annual conference last week. “But I really see zero difference.”
Despite the current disparity between the two states, Peterman explained, every state commission in the country will eventually face the same challenges related to greater adoption of EVs.
Although California leads the nation in EVs, their penetration still represents less than 1% of the state’s passenger fleet. But that is expected to change. Bloomberg New Energy Finance forecasts that the total unsubsidized cost of owning an EV will likely fall below that of a gas-powered car by the mid-2020s.
“You need to be thinking about how these vehicles interconnect” with the grid, Peterman said.
Key Questions
Peterman said there are several key questions commissions must ask themselves: How do EVs impact my system? What type of load do they add? Are the vehicles charging at times that make sense?
California’s thinking about EVs has evolved over time, from focusing on how to reduce the negative impact of EVs on the grid to exploring ways in which the vehicles can actually support the state’s objectives, Peterman said.
The state’s investor-owned utilities (IOUs) were once prohibited from becoming too deeply involved in EV charging based on concerns about anti-competitiveness, Peterman explained. But with this summer’s passage of Senate Bill 32, which requires the state to reduce its emissions to 40% below 1990 levels by 2030, vehicle electrification is now a “principal goal” for utilities.
To facilitate this new role for the IOUs, the CPUC has been accepting applications to create pilot programs for developing an EV charging infrastructure. The proposals have resulted in a variety of models.
One proposal would have San Diego Gas & Electric owning the charging infrastructure and rolling it into the company’s rate base as a capital expenditure. Another would have Southern California Edison investing in the “make-ready” — the infrastructure from the meter to the charger, which would be treated as an operating expense and also rolled into rates.
In approving an EV infrastructure model, state commissions need to consider the benefits for all ratepayers, not just EV drivers, Peterman said. California set out the benefits in statute, including some not easy to quantify, such as a more reliable grid, improved air quality, greenhouse gas reductions and the creation of better-paying jobs.
She added that commissions should also guard against anti-competitive behavior, allowing EV flexibility to choose charging equipment.
EV-Specific Tariffs
Peterman also suggested adopting specific tariffs for EV drivers.
“You want to encourage charging at times when power is plentiful,” she said, adding that California sees EVs as a way to absorb excess electricity produced by solar installations during the day.
“That electricity is so low cost, especially compared with oil, why not have an opportunity for your vehicles to run on that?” Peterman said.
With a contested proceeding on EV infrastructure currently before his agency, Michigan Public Service Commissioner Norm Saari had to remain tightlipped on his views about how to allocate those costs. But he also laid out a not-too-distant future in which all commissioners would confront the EV issue.
EVs “are now driving in the fast lane,” he said, citing the performance figures for the latest Tesla Motors models.
He added that in some states, EVs are also eligible to travel in the high-occupancy vehicle lane.
“EVs are not just the noble [experiment] they were a decade ago,” Saari said.
Saari pointed to the multitude of federal programs promoting the adoption of EVs, which includes the Corporate Average Fuel Economy (CAFE) mileage standards for auto manufacturers, tax incentives and the Obama administration’s recently announced effort to create 48 EV charging corridors throughout the country. (See White House Announces Nationwide EV Charging Network.)
“Regulators, the private sector and utilities have some critical decisions to make on where the EV world is going to be taking us,” Saari said.
He lauded the work that regulators in states such as California and Oregon have already done to anticipate the adoption of EVs and said EV forums among state regulators are a critical way to share best practices.
“I would encourage other state regulators, if you haven’t put together the subject matter experts to plan out the programs, now’s the time to really look at doing that,” Saari said.
Bob Jenks, executive director of the Citizens’ Utility Board of Oregon, expressed surprise that policymakers are looking at his state’s cost recovery provisions for EV infrastructure as a model for the rest of the country.
Those provisions require the state commission to condition a utility’s recovery on whether an EV-related project is within the utility’s service territory; is prudent as determined by the commission; is reasonably expected to be used; is expected to stimulate innovation, competition and customer choice; and is expected to support the utility’s system.
“As somebody who was in the room when we negotiated that piece of legislation, I can tell you that the last thing we thought we were doing was setting some sort of national standard for ratemaking associated with EVs,” Jenks said. “All we were trying to do, quite frankly, was get a deal — with the legislative clock ticking during a short legislative session — that we had to have [done] that afternoon.”
Jenks said the EV section of the deal was almost eliminated at the last minute.
The cost recovery provisions, Jenks explained, are not specific to EV infrastructure but apply to any investment made by the state’s utilities.
That last consideration — supporting the utility’s system — could be key for Oregon utilities seeking to gain approval for EV infrastructure projects. Jenks cited a Pacific Northwest National Laboratory study that concluded widespread adoption of EVs could help the region integrate all of its wind.
Time-of-Use Rates
For that reason, Jenks cautioned against imposing time-of-use rates for EV drivers.
“I don’t know that time-of-use rates are the best way to deal with wind variability,” he said.
Jenks also said states should avoid using rate design to lead their EV policies.
“I think where we need to go is direct load control by the utility,” Jenks said. “There has to be a program to compensate customers for it, but I don’t know what that is.”
“We will design these [programs] down the road and these will evolve,” he said.
CARMEL, Ind. — Tim Horger, manager of interregional coordination at PJM, said last week that MISO and PJM have agreed not to publicly talk about the issue of pseudo-tie congestion double-counting until a FERC complaint on the issue is resolved.
Some stakeholders were frustrated with the gag order curbing work on fixing the double-counting, reasoning that if the RTOs used ongoing litigation as a silencing factor, then it could be argued that even capacity could not be discussed.
Tilton Energy, the owner of a 180-MW natural gas generator in Eastern Illinois, filed the complaint in August, arguing that MISO is violating its Tariff by assessing congestion and scheduling fees on Tilton’s pseudo-tie transactions that have already been assessed by PJM (EL16-108).
“At least as early as February 2016, MISO and PJM have been aware of, and discussed at JCM [Joint and Common Market] meetings, the potential that generation pseudo-tied from MISO to PJM may be assessed duplicative congestion costs when market-to-market constraints bind simultaneously in both markets,” Tilton said. “While the JCM stakeholder process grinds on, generators pseudo-tied from MISO to PJM — such as Tilton — are suffering charges for congestion and scheduling fees by both RTOs.”
MISO asked FERC to dismiss the complaint on Sept. 26, insisting the charges are consistent with its Tariff and that Tilton has failed to show the Tariff is unjust and unreasonable. Horger said the “proceeding potentially could affect how the pseudo-ties are treated.”
Interface Pricing
While mum on the double-counting issue, the two RTOs said they plan to pursue what they call a collaborative approach for interface pricing in time for the beginning of the 2017 financial transmission rights planning year beginning June 1. The approach relies on PJM’s existing 10-bus definition for the common interface definition. It also allows the RTOs’ market entitlement-based limits — calculated using firm flow entitlement estimates in the day-ahead and FTR markets — to be modified as needed to reflect a transaction’s impact on a constraint. MISO had been backing a centroid-to-centroid approach. (See “No Consensus on Interface Pricing,” MISO/PJM Joint and Common Market Meeting Briefs.)
Beibei Li of MISO’s market evaluation and design team said MISO and PJM officials have been holding regular conferences to discuss how the RTOs should handle post-implementation standards, monitoring and metrics.
Horger said MISO and PJM’s efforts to revise pseudo-tie processes are being done in “parallel,” even though PJM recently failed to elevate any pseudo-tie rule changes for stakeholder consideration. PJM staff had developed one improvement package, while three PJM stakeholders each submitted their own; all were rejected. (See “Underperformance Changes Would Weaken CP, Says PJM, Monitor,” No End in Sight for PJM Capacity Market Changes.)
MISO, meanwhile, is readying a filing to amend its Tariff and Business Practices Manual and create a new agreement requirement between all parties involved in the creation of a new pseudo-tie. The updated requirements will tighten transmission service obligations and subject new pseudo-ties to system impact studies. (See MISO Readies Updated Pseudo-Tie Rules.) MISO and PJM currently have 31 pseudo-ties totaling 2,100 MW.
Freeze Date Future in Buckets?
PJM and MISO are contemplating a three-step “bucket” approach to replace the current 2004 freeze date reference point used to determine firm rights on flowgates in the allocation process based on flows before current markets were instituted.
Horger said MISO and PJM are looking at dividing flowgate allocations into separate tranches. The first would be for active designated network resources predating the current April 1, 2004, freeze date and historic transmission service requests. A second tranche would be for active designated network resources and transmission service requests after 2004. The third tranche would allow for entitlements to be granted for limited market-based transfers within the RTO balancing authority.
The first bucket would get first consideration for flowgate needs; excess allocations will be returned to the owner of the flowgate. Horger said the proposal showed consistency from the old approach to the new one, with new designated network resources joining the post-2004 bucket.
ITC Holdings’ Ray Kershaw observed that the three-step allocation method would result in “winners and losers.”
“There’s going to be winners and losers in any change, but we’re trying to minimize those impacts,” Horger replied. “I think we all agree that this needs to be updated. The system is planned a lot different than it was in 2004.”
The two RTOs will develop a straw proposal that will be unveiled at the next JCM meeting on Feb. 28 at PJM’s Conference and Training Center. MISO’s Ron Arness admitted that the RTOs have yet to develop many of the proposal’s particulars. “We don’t have the details … the purpose was to start thinking about these complicated topics,” Arness told stakeholders. Arness said freeze date concerns could be voiced through MISO’s Seams Management Working Group.
Horger also said it’s unlikely that an alternative will be implemented by the targeted June deadline.
FERC on Thursday gave final approval to a rule updating its processes for the handling of Critical Energy Infrastructure Information (CEII), a measure to protect the grid from terrorist attacks (RM16-15, RM15-25-001).
The rule (Order 833) is intended to comply with the Fixing America’s Surface Transportation (FAST) Act. Although the bill mainly dealt with highway funding, Congress added the CEII provisions (Section 215A of the Federal Power Act) following controversy over the agency’s security procedures.
The order establishes rules for designating information as CEII; prohibits unauthorized disclosure of CEII; and sets penalties for FERC employees who knowingly and willfully make unauthorized disclosures. FERC said the final rule “largely adopts” the proposals in its June Notice of Proposed Rulemaking. (See FERC Proposes Protections on CEII.)
In response to concerns raised by the Nuclear Regulatory Commission, FERC clarified that its rule “does not limit the discretion of other federal agencies to protect sensitive information in their custody” but provides a way for agencies to consult with the commission’s CEII coordinator.
“We believe this change strikes a reasonable balance by recognizing other federal agencies’ discretion to protect their information, while adhering to the statutory framework that limits CEII designation authority to the commission and” the Department of Energy, FERC said.
The commission also said it would make a change to clarify it has delegated to the General Counsel authority to decide appeals of CEII designations.
Penalties
The rules include sanctions for unauthorized disclosures of CEII by commission staff and a requirement to refer improper disclosures by commissioners to the Energy Department’s Inspector General. FERC commissioners and staff could face dismissal and criminal prosecution for improper disclosures.
The commission said it has already instituted requirements that former employees and commissioners certify that they are not unlawfully removing records from the agency and acknowledge potential criminal penalties for doing so.
The FAST Act’s CEII provisions were both a vindication and a rebuke of former FERC Chairman Jon Wellinghoff’s controversial campaign to raise awareness of the grid’s vulnerability to sabotage.
Wellinghoff | FERC
The sanctions for unauthorized release of CEII stemmed from Wellinghoff publicly discussing a confidential FERC analysis on the grid’s vulnerability to physical attacks. But the bill also included measures to protect the grid from terrorist attacks and natural disasters, giving the secretary of energy emergency powers and creating a Strategic Transformer Reserve. (See Transportation Bill Includes Grid Security Measures.)
Sharing, NERC Information
The rule requires recipients of CEII outside of FERC to sign nondisclosure agreements. FERC said it will continue to “balance the requestor’s need for the information against the sensitivity of the information.”
“The commission has utilized this balancing approach effectively in response to Critical Energy Infrastructure Information requests for almost 15 years.”
Order 833 also implements the commission’s June order giving FERC access to NERC’s transmission availability data system, generating availability data system and protection system misoperations databases. (See FERC to Look over NERC’s Shoulders on Reliability.)
The commission said it will treat information downloaded from NERC databases as nonpublic. It will evaluate whether it should be designated as CEII in response to a request for the information or if the commission determines such information should be disclosed.
FOIA Improvement Act
In a separate order, FERC also approved a final rule implementing the requirements of the FOIA Improvement Act of 2016 (RM17-5).
The law requires federal agencies to:
Allow a minimum 90-day period for Freedom of Information Act requesters to file an administrative appeal — up from 45 days.
Include in any FOIA denial letter a notice that the requester may seek dispute resolution services from the Office of Government Information Services in the National Archives and Records Administration.
Provide requested information unless “the agency reasonably foresees that disclosure would harm an interest protected by an exemption” or “disclosure is prohibited by law.”
Make reasonable efforts to segregate and release nonexempt material by redacting protected information in documents.
Release records 25 years or older that would otherwise be subject to the deliberative process exemption.
Make information that has been requested and disclosed three times publicly accessible in an electronic format.
