Page 1184 – RTO Insider

April 23, 2018

FERC Orders RTOs to Shine Light on Uplift Data

By Michael Brooks

WASHINGTON — RTOs and ISOs will be required to submit monthly reports detailing their uplift payments and operator-initiated commitments under a rule that FERC said would increase transparency in the wholesale markets (Order 844, RM17-2).

But the commission’s order Thursday withdrew a requirement that grid operators categorize real-time uplift costs based on their causes and allocate them only to market participants “whose transactions are reasonably expected to have caused” the uplift.

FERC made both proposals in a 2017 Notice of Proposed Rulemaking the commission issued in January 2017 as part of a larger price formation initiative it began in 2014. (See FERC Seeks More Transparency, Cost Causation on Uplift.) Thursday’s order marked the last “generic” action it took as part of that initiative, FERC said.

Under the new rule, RTOs and ISOs will be required to report:

total uplift payments for each transmission zone, separated by day and uplift category;
total uplift payments for each resource monthly; and
megawatts of operator-initiated commitments in or near real time and after the close of the day-ahead market, broken out by transmission zone and the reason for the commitment.

Generators receive uplift payments when their production costs exceed their energy and ancillary services revenues. Operator-initiated commitments refer to when a generator operates at the direction of the grid operator at a loss for reliability reasons.

Penalty Factors

Grid operators will also be required to revise their tariffs to include the transmission constraint penalty factors used in their market software, the circumstances under which those factors can set LMPs and any processes by which they can be changed. Penalty factors are the maximum prices RTOs pay to redispatch resources before allowing power flow to exceed their maximum operating levels.

FERC found that although all RTOs/ISOs report some information about uplift payments and their causes, their disclosures usually lack detail and are inconsistent across markets. No RTO or ISO reports uplift on a resource-specific basis.

“A lack of transparency regarding uplift payments and operator-initiated commitments can mask system conditions, particularly in times of system stress,” Adam Cornelius, of FERC’s Office of Energy Policy and Innovation, said at Thursday’s open meeting. “The result is that market participants may not fully understand the needs of the system or recognize the resource attributes that are required to meet those needs. … Therefore, current reporting practices may not provide sufficient transparency for market participants to plan for and respond to system needs in a cost-effective manner, resulting in rates that are unjust and unreasonable.”

The increased transparency will help market participants invest in new infrastructure more efficiently and facilitate more informed stakeholder discussions, he said.

Compliance filings for the rule are due 135 days after its publication in the Federal Register, and the grid operators have another 120 days to implement it.

“Uplift isn’t the sexiest topic … even compared to FERC topics,” Commissioner Cheryl LaFleur joked. “And sometimes it’s get a bad name, as if it’s a bad thing. But commitment actions that lead to uplift are important” for reliability. The reports will “provide additional information to the marketplace so the marketplace can solve the problems that they reveal,” she said.

Commissioner Neil Chatterjee agreed. “It is no secret that transparency in RTO and ISO price formation is not the most riveting subject,” he said. “I haven’t seen a lot of headlines calling for better reports on uplift, and I wouldn’t expect these topics to be trending on Twitter any time soon. …

“But that doesn’t mean today’s action isn’t significant. The final rule is a win for all stakeholders participating in these markets, as they will benefit from the added transparency it will bring to each RTO’s commitment, dispatch and settlement processes.”

Cost Allocation Proposal Dropped

FERC had proposed that grid operators categorize deviations between the day-ahead and real-time markets, one of the main causes of uplift, as either “helping” (reducing the need for uplift) or “harming” (increasing the need) and that they allocate uplift costs to generators based on the net of their harming deviations.

However, many commenters, while agreeing with the rule’s general principle, questioned its feasibility.

Exelon pointed to PJM and the 2014 polar vortex as an example. During the period of extremely cold weather, high natural gas prices led to high energy prices in PJM, and the RTO dispatched high-cost generators to maintain reliability. At the same time, generators in neighboring regions self-scheduled imports into PJM, “chasing” the high prices, which led prices to drop. Thus, the PJM generators’ operating costs exceeded their revenues, leading to high uplift payments.

“While the large volume of self-scheduled imports may have ‘helped’ PJM meet system needs, and would ostensibly qualify as ‘helping’ deviations as contemplated in the NOPR, these self-scheduled imports nevertheless directly caused the system uplift payments,” Exelon said.

“Given the complexity of this issue and the varying practices among RTOs, the NOPR’s preliminary finding that someexisting RTO practices may be unjust and unreasonable does not justify standardizing this aspect of the various RTOs’ market design,” the Transmission Access Policy Study Group (TAPS) said in its comments.

“If the commission proceeds to a final rule, TAPS generally supports netting of helpful and harmful deviations as consistent with cost-causation principles,” the group said. “However, the commission should allow each RTO to propose specific criteria for determining whether a deviation is helpful or harmful and should recognize that in certain circumstances, a deviation’s ‘helpfulness’ or ‘harmfulness’ may be difficult to establish.”

Most commenters, however, expressed “broad” support for the transparency proposal. The lone dissenter was CAISO, who argued that its existing reporting provides enough transparency and that the new requirements — specifically the deadlines for filing the new reports — would be overly burdensome.

FERC disagreed that CAISO was sufficiently transparent. The ISO aggregates uplift data to its 10 local capacity requirement areas and reports daily total uplift costs for each month by market and type of cost. (See graph.) It also reports the daily aggregated megawatt-hours of “exceptional dispatches.” But it does not specify which of those resulted from operator-initiated commitments.

ferc uplift — CAISO’s exceptional dispatch uplift costs for January and February 2018. The ISO includes these graphs in its monthly Market Performance Reports, but some stakeholders noted that it does not include the underlying data. FERC said this level of transparency was insufficient. | *CAISO*

To address CAISO’s concerns, the commission said it would consider extending the filing deadline for the monthly zonal report (20 days after the end of the month) if the ISO can show in its compliance filing that 20 days is not enough time. FERC also extended the deadline for the monthly resource-specific report from 20 days after month-end to 90.

Several commenters argued that resource-specific uplift data should only be obtainable through a password-protected page on the grid operators’ websites, an idea FERC rejected. “Providing data only to certain market participants does not achieve the goals of this final rule,” the commission said. “Transparency into resource-specific uplift payments can highlight potential instances of gaming and collusion for other market participants, and allow them to advocate for solutions and call attention to such issues more quickly and efficiently.”

April 23, 2018

NYPSC OKs Con Ed EV Charging Program, REV Initiatives

By Michael Kuser

The New York Public Service Commission on Thursday approved a seven-year tariff for Consolidated Edison’s electric vehicle quick-charging station program (17-E-0814).

new york REV EV Con Ed — The New York Department of Public Service held a commission session on April 19

Under the tariff, the utility will expand the scope of its economic development Business Incentive Rate (BIR) to be available to owners of EV quick-charging stations with a minimum aggregate charging capacity of 100 kW and a maximum aggregate demand of 2,000 kW in New York City and Westchester County. The program could support more than 85,000 EVs by the end of the seven-year program, the company said.

“The city already indicated the program will complement its efforts in increasing access to quick-charging infrastructure,” said Department of Public Service staffer Mary Ann Sorrentino.

The New York State Energy Research and Development Authority indicated that Con Ed’s program, coupled with NYSERDA’s incentives, will likely achieve the near-term economics necessary for greater uptake and installation of quick-charging stations, she said.

The New York City area was one of 17 metro areas selected for the first cycle of $250 million in spending on zero-emission vehicle infrastructure under the $2 billion Volkswagen settlement for violating the Clean Air Act.

The state expects to receive $127.7 million for air pollution mitigation projects, according to a Department of Environmental Conservation report.

Delaying implementation of the Con Ed EV program would result in decreased uptake and a missed opportunity to leverage the BIR to maximize new investment in the utility’s territory, Sorrentino said.

PSC Commissioner Diane Burman voted against the tariff filing, without prejudice.

“I think we’re oversimplifying the issues here,” Burman said. “I don’t understand how this is not in conflict with moving forward at this time. Are we saying that failure to act now is going to cause us to not be able to get the VW settlement monies in the New York City area? Because there’s nothing in the record to say that we need this for the VW settlement monies.”

Warren Myers, DPS director of regulatory economics, said, “This is a very specific program that, to me, is very consistent with all of our economic development flex-rate programs that have been around for years and years. This is a way, as Commissioner [Gregg] Sayre said, to try to attract load that otherwise would not come to the electric utility.”

The PSC on April 19 also instituted a proceeding (18-E-0138) to encourage greater penetration of EVs and related supply equipment, possibly through the solicitation of scalable pilot programs.

The new proceeding supports other state initiatives such as ChargeNY— Gov. Andrew Cuomo’s goal of installing 10,000 EV charging stations by 2021, up from 2,000 today.

As in the Con Ed charging station program, utilities will help design rates to incentivize off-peak charging and invest in EV infrastructure and related supply equipment. The commission will soon announce the stakeholder feedback schedule for the new initiative.

“This proceeding is important because we need a framework that will get this right in respect [to] the costs, the benefits and the issues for the distribution grid that arise out of the penetration of electric vehicles,” said PSC Chair John B. Rhodes.

More REV

The PSC also acted on other initiatives under the Reforming the Energy Vision strategy to lead on climate change: expanding the integration of energy storage systems onto the grid; approving an upstate community smart energy project; creating an online platform for data sharing among energy companies; and streamlining permitting for farmers using anaerobic digesters to produce electricity.

In the matter of the Value of Distributed Energy Resources initiative (15-E-0751), the commission ordered that distributed generation suppliers be allowed to connect energy storage projects up to 5 MW to distribution systems. In addition, the commission issued two orders (18-E-0018; 15-E-0557) to improve the standardized interconnection requirements application and contract process to allow developers to connect projects to the grid without undue delay.

“Our standardized interconnection requirement simply can’t stand still,” Sayre said. “Some of the changes in this item are necessary because of our orders on the Value of Distributed Energy Resources, some of them come out of the stakeholder process to improve the interconnection process, and still others are necessary to accommodate technological and market changes in areas like energy storage.”

The commission approved New York State Electric and Gas’ request to implement a pilot program of time-differentiated electric rate options, the Energy Smart Community project, which includes deploying advanced metering infrastructure to approximately 12,000 customers in Ithaca and the surrounding area.

The Utility Energy Registry approved by the PSC will make load data for the major utilities available for local planning, market research and community choice aggregation development, without providing individuals’ consumption profiles.

The commission also ordered that community distributed generation (CDG) projects serving only farm customers no longer be required to comply with several CDG program requirements, including the 10-member minimum.

Rhodes closed the session by reading a resolution of appreciation for DPS Chief of Electric Rates and Tariffs Michael Twergo, who is retiring after 32 years of service.

April 23, 2018

MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk

By Amanda Durish Cook

Increased renewable integration, especially solar generation, will shift MISO’s peak load to evening hours, with a spikier but shorter daily loss-of-load risk, according to the initial results of the RTO’s new long-term renewable study.

Senior Policy Studies Engineer Jordan Bakke said the study, which has thus far focused only on resource adequacy, found distinct trends as renewable penetration was dialed up by increments of 10% of the resource mix:

The average daily loss-of-load expectation (LOLE) becomes heightened, though it compresses to a smaller window later in the day;
Wind and solar resources are less likely to be able to meet the late-day risk owing to their operational characteristics; but
Geographically dispersed and diverse technologies like demand response and storage can assist renewables in their ability to meet load.

“We found strong evidence that the sun-down part of the day becomes high-risk hours,” Bakke told stakeholders at an April 18 Planning Advisory Committee meeting.

MISO’s multiyear Renewable Integration Impact Assessment, announced last year, seeks to identify “inflection points” where the growth of renewables and the retirement of baseload units will require changes in the structure or operation of the system.

The study aims to predict how and when reliability will be impacted under heavy renewable output; if there are limits to the amount of wind and solar generation MISO can support; how long before energy storage becomes a requirement; what parts of the grid will be stressed first; and how much renewable energy can be deployed before significant system changes are needed. (See MISO to Conduct Long-Term Renewable Integration Study.)

MISO renewable power LOLE — Loss of Load Risk with Renewable Penetration | *MISO*

MISO studied an ever-increasing renewable penetration in the footprint, topping off at 100% using a mix of 75% wind, 17.5% utility-scale solar and 7.5% distributed solar.

Bakke said even with a small solar penetration increase, net peak load will shift from 3 p.m. to 6 p.m. MISO currently has 270 MW of installed solar.

“We’re seeing some dramatic shifts with relatively low levels of penetration,” Bakke explained. “What we’re seeing here is even when solar is at 5% penetration, this time shift already occurs … as solar drops off early in the evening.”

Bakke also said while MISO’s average year-round risk of losing load peaks from “noon to late in the day,” the risk period narrows to 5 to about 8 p.m. as more renewables are employed.

Some stakeholders set into an M.C. Escher-esque discussion on the change in loss-of-load risk, saying that while rising solar generation could cause a shift in the traditional peak load pattern, the traditional 3 to 6 p.m. peak demand hours do still exist — albeit muted by increasing solar supply. Some pointed out that a late-day loss-of-load risk falls to hours that historically have had less electricity demand and could be manageable.

Wind on the Wires’ Natalie McIntire asked if MISO’s study included a scenario in which increasing use of energy storage offsets the sharper loss-of-load risk.

Although MISO’s study indicates that storage can help offset the risk, Bakke said MISO used existing levels of non-renewable resources for the study and did not run scenarios with escalating use of energy storage. Customized Energy Solutions’ David Sapper said storage scenarios would have been “fundamental” to the early stage of the study.

MISO’s early results also show that a 100% renewables scenario can force negative loads during the day, meaning some generation must be curtailed or exported, Bakke said.

But some stakeholders said the need to plan for daytime negative loads is decades away, if it ever happens.

“We have a long way to go to get to 100% renewables, if we ever do. We need to focus on 10, 20, 30 years out,” McIntire said.

Bakke agreed, but said, “It’s important to look at these things early and often” because just a small increase in solar shows MISO may have to reallocate generation and load.

MISO found that wind and solar combinations do work symbiotically over an average day, especially in summer, with mid-day solar able to offset small dips in mid-day wind generation.

“They are not the perfect complement to each other, but they do complement one another,” Bakke said.

MISO plans to continue the renewable study on an open-ended basis; the RTO said it will continue to study resource adequacy under increasing renewables through the end of the year.

MTEP Resource Siting

In a related matter, Bakke said MISO’s 2019 Transmission Expansion Plan resource siting forecasts have been retooled this year to account for renewable adoption. Resource siting will rely on predictions of future energy storage sited at MISO’s busiest load buses; MISO predictions on electric vehicle adoption; National Renewable Energy Laboratory predictions on distributed resources; and the usual study from Vibrant Clean Energy that identifies areas ripe for utility-scale wind and solar development. MISO will reveal a first draft of MTEP 19 resource siting in September. (See Renewables, Storage Get More Play in MISO 2019 Planning.)

Meanwhile, the Planning Advisory Committee in June will begin to flesh out how to analyze and recommend energy storage as baseline reliability solutions in the MTEP process, a responsibility passed to it by the Energy Storage Task Force last month. PAC Chair Jeff Webb said MISO may have to submit Tariff changes with FERC to allow storage projects to be considered for reliability purposes.

Webb said staff and stakeholders have until Sept. 15 to propose reliability projects for MTEP 19. Some stakeholders have requested MISO allow storage projects to be submitted as baseline reliability projects in MTEP 19.

April 23, 2018

Calif. Energy Bills Move Forward, but Big Ones Stall

By Jason Fordney

California lawmakers moved forward with several pieces of energy legislation last week, but hotly watched items such as a 100% renewable energy standard and CAISO regionalization seem to be set on simmer.

california energy legislation — Several bills moved through a California Assembly Committee last week | © *RTO Insider*

There has been no movement this year on SB100, former State Senate President Pro Tempore Kevin de Leon’s 100% renewable energy bill that was front and center as the 2017 legislative session drew to a close. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.) SB100 has seen no votes since the Assembly Appropriations Committee last September.

And AB813, legislation that would regionalize CAISO, sits in committee during this session as other, higher-profile issues heat up. (See Calif. Lawmakers Relaunch CAISO Regionalization.) The regionalization language is currently in the Senate Rules Committee and the next step is a referral to the Energy Committee.

The U.S. Senate Democratic primary between de Leon and longtime Sen. Dianne Feinstein is taking up a great deal of political oxygen and an unrelated series of sexual assault controversies are another major distraction in the Capitol. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)

On Thursday, the Assembly Utilities and Energy Committee, chaired by Assemblyman Chris Holden (D) passed several pieces of legislation, including:

AB2068(Chu), to Appropriations: It would require IOUs to evaluate the feasibility of discounting rates for public schools by at least 15% and for the California Public Utilities Commission to determine whether to adopt the discount. It requires the CPUC to direct IOUs to evaluate and report on the feasibility and economic impact of establishing the discounts. The evaluation must include commercial rate increases for the past five years that affected schools and the economic impact to other ratepayers if all public schools receive the discount. The bill requires the CPUC to submit the report to the legislature by Jan. 1, 2020.
AB2208(Aguiar-Curry) to Natural Resources: The bill requires investor-owned utilities, community choice aggregators, retail energy sellers and publicly owned utilities to procure an unspecified percentage of their resources from geothermal, biogas or biomass facilities. An unspecified amount would have to be procured from the Salton Seageothermal resource area, 10 generating plants producing 327 MW in Southern California’s Imperial Valley. According to an author’s statement, “AB 2208 will make it easier to reliably integrate higher amounts of renewable energy generation into the grid by requiring the procurement of ‘grid-balancing’ renewables, such as geothermal and bioenergy.” It would allow bioenergy facilities open to continue accepting wood waste as a forest fire management measure.
AB2515(Reyes) to Appropriations: The bill requires the CPUC to report to the legislature pending and previously approved changes to IOU revenue requirements over at least the past five years that resulted from requests by IOUs and CPUC decisions and resolutions. It also requires IOUs seeking a rate change to disclose estimated rate and bill impacts on each customer class.
AB2831(Limon) to Appropriations: Requires the CPUC, in consultation with the Office of Small Business Advocate within the governor’s Office of Business and Economic Development, to ensure that adequate marketing, education and outreach are undertaken to enable small business customers to fully participate in demand-side energy management programs.

April 23, 2018

Western Regulators Get Schooled in RTO Legal 101

By Robert Mullin

VANCOUVER, Canada — With three RTOs advancing competing efforts to extend their services into the West, the region’s utility regulators last week took a timely crash course on the legal implications of allowing their utilities to join organized markets.

It was a bracing — and invaluable — session, according to some industry stakeholders attending the spring joint meeting of the Western Interconnection Regional Advisory Body and the Committee on Regional Electric Power Cooperation.

organized electric markets — Hempling | © *RTO Insider*

Scott Hempling, an attorney specializing in public utility law, provided a compressed but comprehensive 90-minute primer of the statutes, regulations and case law governing the functioning of RTOs, beginning with their origins in FERC Order 2000, which encouraged — but did not require — utilities to form or join an RTO.

“The primary purpose was to end discrimination by transmission owners,” Hempling said. “One of the methods of discrimination before Order 2000 was to keep secret the availability of transmission.”

Hempling explained the four “minimum characteristics” of RTOs required by FERC: independence; appropriate scope and regional configuration; operational authority; and exclusive authority over short-term reliability.

In addition, RTOs must fulfill eight “required functions,” including tariff design and congestion management. “Understanding those 12 things is crucial to understanding what’s getting turned over to the RTO,” he said.

Hempling clarified that a transmission-owning utility legally becomes a customer of an RTO once it joins the RTO and turns over its transmission assets. It also becomes FERC jurisdictional. “When your utility joins an RTO, it no longer provides transmission service,” he said.

“Let me put it bluntly: you lose jurisdiction over transmission costs” when a utility joins an RTO, Hempling told the audience of commissioners. As a result, any state commission that has approved RTO membership cannot “logically disallow” a utility from including in retail rates the costs of becoming a customer of the RTO.

“Once FERC determines that the rate charged by the RTO to the transmission owner is prudent, the state must pass that cost on” to customers, Hempling said.

And while a transmission-owning utility does receive a pro rata share of the revenues the RTO generates from all transmission customers, the resulting credits don’t always make retail ratepayers whole. “You’d think the retail charges and credits would be a wash, but that’s not necessarily the case,” Hempling said.

One commissioner asked if FERC made distinctions within RTOs between how it treats investor-owned utilities on the one hand and rural cooperatives and municipal power systems on the other.

Hempling noted that the Federal Power Act exempts publicly owned systems from FERC oversight — unless they are TOs and join an RTO. “Co-ops and munis join RTOs by contract. Now if they’re transmission owners, are they subject to FERC jurisdiction? The answer is ‘yes.’” Based on FERC’s reciprocity rule, “if you want to take transmission service and you own transmission, then you’re going to need to provide transmission service,” Hempling said.

FERC ‘Controversies’

Hempling turned to key areas “where FERC finds itself resolving controversies” related to the nation’s RTOs.

Chief among the agency’s concerns: return on equity for transmission investments.

“There is a great deal of controversy over what is the ‘fair return on equity,’ and it’s not just about profiteering,” he said. “We’re talking about hundreds of billions of dollars in necessary transmission investment, and that money is going to have to come from somewhere and get paid off over a certain period of time. So return on equity matters, both from the customer standpoint and the investor standpoint.”

Hempling pointed to the differences between administering general rate cases (FERC’s past approach) and formula rate cases (its current approach).

“A formula rate’s a spreadsheet, and I guess the word is that you ‘populate’ the spreadsheet with the numbers — as opposed to a general rate case, where everybody and their brother and father and mother and sister gets into the case and everybody fights over what the ultimate [regulated rate of return] should be,” Hempling said. “For years, FERC set transmission rates with a general rate case, but now it prefers to set them by formula. But just because it’s a spreadsheet that you populate across doesn’t mean that FERC goes to sleep and just asks that you include whatever you want to put in there.”

Hempling expressed his respect for FERC, calling the agency “very, very professional — even in the current political environment.” But he cautioned state commissioners about the agency’s limitations in judging the reasonableness of transmission project expenditures, another area of focus for the agency.

FERC “does not disallow costs very often. … There is a question whether an agency whose authority is transmission [has] competency in looking at alternatives,” he said, adding that FERC “does not do integrated resource planning.”

Hempling also pointed to FERC’s role in overseeing RTO transmission cost allocation.

“You’re a multistate region — which state’s customers are paying for what? And there are now a variety of court of appeals decisions and FERC decisions that allocate costs among the family members, who at conferences like this are all happy to see each other over pastries, but then they’re happy to hire very expensive lawyers to fight over who’s getting which dollars.”

Power to the States?

Hempling posed a series of hypothetical questions regarding a state’s influence over utilities before and after a decision to join an RTO. His answers, he made clear, were based on his own professional opinion, not settled law.

Can a state order its utility to join an RTO?

Yes, Hempling said. A state commission could find that a utility’s rates “will not be just and reasonable, reliability will be insufficient to satisfy state law unless the utility joins an RTO,” he said. “I also think therefore — and everything I’m saying now is subject to debate — that a state can reject a utility’s request to join, I think for the same reason.”

Can FERC order a utility to join?

“This question, along with all the others, is untested, because if FERC does have the authority to order a utility to join, then that would pre-empt a state that rejects a utility to join. That would be an inconsistency, right? You can’t put a utility between a rock and a hard place,” Hempling said.

“Do I think FERC has the authority to order a utility to join? I think they do. … And in any event, FERC has never said so,” he said. “And that’s why the joining of RTOs by utilities is opportunistic. That’s why they at least get to decide … based on their own self-interest, because FERC has not said it can order a utility to join.” But FERC has conditioned a utility’s request for merger approval on joining an RTO, he noted.

Hempling also posed the possibility of a state requiring a utility to get state permission before proposing to the RTO any new construction of transmission above a particular level. “In my legal opinion, a state can do that, but it has not been tested,” he said.

After the Fact

How can a state pursue its values after a utility joins an RTO?

Hempling noted that legal precedent precludes states from forcing a utility — including an RTO — to submit a tariff change with FERC. Still, a state can circumvent that restriction by persuading the utility or RTO to make a state-sought filing.

“The way the Federal Power Act works is this: If a utility makes a filing at FERC, and that filing satisfies the Federal Power Act standard of ‘just and reasonable’ … FERC is obligated to approve it, even if FERC has a better idea. … It’s a utility-deferential statute,” he said. “Which means if you are a state wanting to say, ‘I’ve got a better idea,’ and so you introduce at FERC a filing, FERC is going to say, ‘I like your idea a lot better, state, but the utility’s idea is just and reasonable.’”

SPP has worked around this situation through the authority granted to its Regional State Committee, which can order SPP to make a filing even if the RTO disagrees with it, Hempling said. “Now SPP can also make its own filing, and they can say, ‘We think the state’s idea is crap,’ but we file it because we agreed to file it. And what happens now is that FERC can actually choose either one. So it puts the states on equal legal footing in terms of the chances of being selected.”

Former California Public Utilities Commissioner Mike Florio, now principal of Florio Consulting, said that California legislators have asked him whether the state can direct an investor-owned utility to leave an RTO.

“My … answer is no, because … it’s a contract that FERC has approved,” Hempling replied. “And that contract is where you go to find out the authority of someone to leave. And because it’s a FERC-jurisdictional contract, a state cannot issue an order that causes a utility to act in violation of the contract. That would be pre-emptive.

“FERC wants the stability about decisions to be in FERC’s hands,” he added.

Utah Public Service Commissioner David Clark said one of his concerns about his state’s utilities joining an RTO is the cost-of-service differential between it and other states in the region — namely, California.

“I know FERC has been concerned that the RTO process maintain status quo benefits and focus on new benefits,” Hempling said. “I think FERC has not had the notion of creating enemies of the RTO process.”

Another commissioner asked: “How do we know we’re protecting our state’s interests?”

Hempling replied with a question: “What is the commonality that we’re trying to pursue through the RTO mechanism when there are so many differences? … Focus on what the commonalities are.

“I was once at a [National Association of Regulatory Utility Commissioners] meeting and there was a Midwestern commissioner who said, ‘Whoa, if we’re not preserving state regulation, what are we here for?’” Hempling said. “And I’m thinking, ‘What you’re here for is something bigger than that. You’re here for efficiencies; you’re here for the customer; you’re here for investors; you’re here for marginal values. You’re here for something. You’re not here for jurisdiction.’

“The mission is not jurisdictional preservation. It’s jurisdictional effectiveness.”

April 23, 2018

Stakeholders Concerned over Tx Conflicts in MISO Retirement Plan

By Amanda Durish Cook

MISO stakeholders are concerned over the RTO’s unit retirement proposal, saying it could result in conflicts over interconnection service rights between suspended units and those in the queue.

“Folks were not comfortable with granting … conflicting interconnection rights,” MISO engineer Patrick Jehring said during an April 17 Planning Subcommittee meeting.

MISO is proposing to model suspended units as offline during the three years of their suspension, then considering them available to participate in local balancing authority dispatch in planning scenarios thereafter. Units that retire during the three-year process by waiving their interconnection rights with MISO will be modeled offline indefinitely in planning models.

Jehring said the modeling plan is like the three-year offline modeling used today but aligns with MISO’s new proposal to have generation owners considering a shutdown enter a catch-all suspension period for three planning years.

Owners would no longer have to decide between a permanent retirement and a temporary shutdown, which requires an estimated return-to-service date. Instead, they would have three full planning years to prepare a return to service or decide on retirement. Suspended generators would lose interconnection service after three planning years if they don’t resume operations. (See MISO Readies Retirement Change.)

Pat Hayes, LS Power transmission policy manager, asked what happens when the owner of a suspended unit returns after the three-year rescission period to find that new generation is poised to assume its interconnection service.

“It’s never happened before,” Jehring said. In such a case, he said, the projects’ local transmission pricing zone would bear the cost risks of the network upgrades necessary to accommodate both the new and existing unit.

“Basically, the stars need to align for this situation to occur. … The likelihood of this occurring is low based on what we’ve seen in the past and what we expect in the future,” Jehring stressed.

Some stakeholders said MISO’s modeling still leaves open the risk that local transmission pricing zones will bear the cost of interconnecting two conflicting units.

“I guess what I would say to that is the possibility for this rift already occurs today. It’s an if-upon-if-upon-if situation to get to that situation,” Jehring said.

Of the approximate 27 GW of Attachment Y suspension/retirement notices that MISO has received, Jehring said only 6 GW has returned to service. MISO unit owners typically submit Attachment Y when catastrophic equipment failure occurs or the units become uneconomic to operate. “When we think about the magnitude of it, we’re only talking 6,000 MW.”

Jehring said including suspended units in the dispatch in modeling after their three-year suspension period doesn’t mean the units would ever be dispatched again. The decision to dispatch is based on the “most economic firm resources being utilized to meet a local balancing area’s firm load and interchange obligations,” according to MISO.

“If a unit goes on suspension for economic reasons, it is unlikely it would be dispatched in the planning models anyway,” Jehring said. “The only real reason that a unit will stay on suspension is they’re on the economic bubble … and they’re truly seeing if they’ll become economic again.”

MISO will accept written stakeholder comments on the modeling proposal through May 4.

April 20, 2018

Gas Dominates, Again, in FERC State of the Markets Report

By Michael Brooks

WASHINGTON — By now, it sounds like a broken record.

As they have in the past four years, the trends in natural gas dominated the discussion of FERC’s annual State of the Markets report at the commission’s open meeting on Thursday.

The report found that average U.S. natural gas spot prices rose 21% in 2017 from 2016, while average day-ahead on-peak LMPs increased 3 to 13% at pricing nodes in RTO/ISO markets.

State of the Markets Report FERC Natural Gas — FERC had a packed agenda for its open meeting April 19, including a presentation on the 2017 State of the Markets report. | © *RTO Insider*

While the previous two years were marked by cheap prices driven by warm winters, last year saw cold weather at both its beginning and end, with an especially severe cold snap at the end of December and into January 2018 leading to a sharp spike in prices, especially in ISO-NE. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)

Last year also marked the first since 1958 that the U.S. was a net exporter in gas, propelled by increased LNG export capacity. “The largest increase in demand for natural gas came from LNG exports, which rose from 0.63 Bcfd to 2.19 Bcfd, a 248% increase,” according to the report. Total exports to Mexico, the U.S.’ biggest LNG customer, increased by 0.5 Bcfd to an average 4.2 Bcfd for the year, aided by several new cross-border pipelines.

Gas producers also found new markets within the U.S. About 12 billion Bcfd and 773 miles of new pipeline capacity went into service last year, most of it in the Marcellus and Utica shales. “New pipeline capacity out of the Marcellus and Utica shale plays allowed producers to meet demand in previously inaccessible markets,” the report says. “These shale plays demonstrated the largest U.S. natural gas production growth in 2017, with a 10.3% year-over-year increase for a total production of 22.1 Bcfd by the end of 2017.” Total U.S. gas production rose 1.0%, averaging 73.6 Bcfd.

One of the only metrics to fall significantly was storage inventory. 2017 saw the third lowest weekly storage injection rate since 2010, while the end-of-year cold snap led to the largest withdrawal in history, 359 Bcf. The large winter withdrawals also led to the lowest end-of-winter storage level since 2014: 1.35 Tcf on April 5, 2018.

Commissioners Neil Chatterjee and Robert Powelson both noted the prevalence of gas in the report, focusing their comments on the importance of fuel security and gas-electric coordination to grid reliability.

“Staff’s report indicates that at the beginning of last year, fuel security was already a particular concern within New England and Southern California because of limited natural gas transportation and storage infrastructure, and that by last winter, those concerns had grown into real anxiety,” Chatterjee said. Noting the cold snap in the East and pipeline outages in California, “I look back at 2017 as the year of close calls that underscore the importance of examining fuel-security issues,” he said.

“The analytics … in today’s report are really a testimony to the benefits of organized markets and what they do in terms of providing reliability,” Powelson said.

He said he was concerned about the phaseout of the Aliso Canyon storage facility in California, noting the state’s aggressive renewable portfolio standard, the closure of several nuclear plants there and, in what he called “the “who-would-have-thunk-it moment,” commission-approved reliability-must-run contracts for gas units in CAISO. He called these, along with the high prices in New England, “alarming situations.”

The report was released right after FERC issued a Notice of Inquiry to review its 1999 policy statement on natural gas pipelines. (See related story, FERC Outlines Gas Pipeline Rule Review.)

April 20, 2018

FERC Order Seeks to Reduce Time, Uncertainty on Interconnections

By Rich Heidorn Jr.

FERC on Thursday ordered new rules to increase the transparency and timeliness of the generator interconnection process (RM17-8, Order 845).

The order adopts all but four of 14 potential rule changes in the commission’s December 2016 Notice of Proposed Rulemaking revising the pro forma large generator interconnection procedures and large generator interconnection agreement (LGIA). (See FERC Proposes Changes to Interconnection Rules.)

The rulemaking, which was prompted by a complaint by the American Wind Energy Association, applies to generators larger than 20 MW.

ferc generator interconnection — Blue Canyon wind farm | *EDP Renewables*

Commission staff said the revisions acknowledge the inefficiencies that have resulted from changes to the generation industry since the commission issued the pro forma interconnection procedures and agreement in 2003 (Order 2003).

“These inefficiencies include backlogs in interconnection queues, long timelines to process interconnection requests and late-stage withdrawals of interconnection requests that can lead to cascading interconnection restudies, which can lead to even more withdrawals,” staff said in a presentation at the commission’s open meeting.

It also seeks to address transmission providers’ concerns that the interconnection study process has become difficult to manage because they have been flooded with requests for new facilities that have little chance of reaching commercial operation.

The final rule removes a limitation on an interconnection customer’s ability to construct interconnection facilities and standalone network upgrades and requires transmission providers to improve their dispute resolution procedures.

To improve transparency and efficiency, the rule:

requires transmission providers to make public their methods for determining contingent facilities and to list the processes and assumptions used for network models employed in interconnection studies;
revises the definition of “generating facility” to explicitly include electric storage;
sets requirements for reporting on aggregate interconnection study performance;
allows an interconnection customer to request a level of service lower than its generating facility capacity;
requires transmission providers to allow provisional interconnection agreements that offer limited operation of a generator before completing the interconnection process;
requires transmission providers to offer the use of surplus interconnection service; and
requires transmission providers to consider changes in an interconnection customer’s proposed technology that occur during the interconnection process to determine if they constitute a material modification.

“The transparency reforms make information more timely and accessible to transmission customers, thereby potentially reducing the number of interconnection requests for projects that are unlikely to reach commercial operation,” staff said. “The efficiency and enhancement reforms facilitate the use of existing interconnection, mitigate the likelihood of unnecessary upgrades and related costs, provide paths to bring generation online more quickly, and allow for the incorporation of technological advancements into an interconnection request.”

Stakeholder comments persuaded FERC not to adopt four other rule changes requiring periodic restudies, self-funding of network upgrades, the posting of congestion and curtailment information and the modeling of electric storage.

The commission also took no action on two other issues on which the NOPR sought comment but for which no proposals were made: cost caps for network upgrades and affected-system coordination, the latter of which was the subject of a two-day technical conference in early April. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.)

The American Council on Renewable Energy (ACORE) issued a statement praising the order. “While the reforms cover interconnection for all types of energy generators, we believe the final rule is an important recognition of a fundamental shift in the U.S. electric sector as we continue to diversify our electricity supply. Going forward, we are optimistic the rule will improve and expedite critical interconnection procedures for solar, wind and other renewable technologies, while also expanding access to energy storage resources.”

The rule will be effective 75 days after publication in the Federal Register.

April 20, 2018

FERC Finalizes Cyber Controls on Portable Devices

By Rich Heidorn Jr.

FERC on Thursday approved rules to prevent malware from infecting “low impact” computer systems through transient electronic devices such as laptops and thumb drives (RM17-11, Order 843).

The order approves a requirement outlined in the commission’s October Notice of Proposed Rulemaking directing NERC to modify reliability standard CIP-003-7 to mitigate the risk of malicious code that could result from third-party devices that frequently connect to and disconnect from low-impact systems. (See FERC Seeks Cyber Controls on Portable Devices; Sets GMD Plans.)

The commission reiterated the concerns it raised in the NOPR that the NERC standard “lacks a clear requirement to mitigate the risk of malicious code” that could result from third-party transient devices. “Accordingly, we direct NERC to develop a modification to the reliability standard to provide the needed clarity. Such modification will better ensure that registered entities clearly understand their mitigation obligations and, thus, improve individual entity mitigation plans,” the commission said.

bulk electric system (BES), cybersecurity, North American Elecrtric Reliability Corp. (NERC), Federal Energy Regulatory Commission (FERC), transient devices, RM17-11, FERC Order 843 — | © *RTO Insider*

However, the commission declined to adopt a proposal requiring NERC to “provide clear, objective criteria for electronic access controls” for low-impact systems. NERC tiers its cybersecurity requirements based on classifications of high-, medium- and low-impact Bulk Electric System (BES) cyber systems.

The commission said comments from NERC and others convinced it that the reliability standard already “provides a clear security objective that establishes compliance expectations.”

Instead, FERC ordered NERC to conduct a study within 18 months to assess the implementation of the standard to determine whether the electronic access controls adopted by responsible entities “provide adequate security.” The study was proposed in a joint filing by the American Public Power Association, Edison Electric Institute and National Rural Electric Cooperative Association, identified in the order as “trade associations.”

Reversal

NERC said that the standard requires responsible entities to “document the necessity of its inbound and outbound electronic access permissions and provide justification of the need for such access.”

The trade associations, Electric Consumers Resource Council (ELCON) and Transmission Access Policy Study Group said the proposal would be burdensome and ineffective. While it “appreciates the value establishing more tangible criteria for adequate low-impact BES cyber system controls … the additional requirements that the commission proposes would do nothing to harden a low-impact facility against the rapid evolution in cyber warfare,” ELCON said.

The trade associations urged a risk-based approach to allow responsible entities to focus their resources on assets that have a higher impact on reliability.

“Given NERC’s statements, we believe that there will be adequate measures to assess compliance with reliability standard CIP-003-7,” FERC concluded. “We expect responsible entities to be able to provide a technically sound explanation as to how their electronic access controls meet the security objective.”

Mitigation of Malicious Code

The trade associations and ELCON also opposed the NOPR’s proposal to require responsible entities to prevent malicious code from entering their systems via transient electronic devices used by contractors and other third parties. The trade groups said risk mitigation is implicitly required under Section 5 of the standard.

But FERC said the standard doesn’t go far enough. “While commenters agree that, at least implicitly, the mitigation of malicious code is an obligation, the lack of a clear requirement could lead to confusion in both the development of a compliance plan and in the implementation of a compliance plan,” the commission said. “In addition, although NERC contends that the proposed directive may not be necessary, NERC agrees that modifying reliability standard CIP-003-7 to address the mitigation of malicious code explicitly could clarify compliance obligations.”

FERC said the new standard also will improve reliability by requiring responsible entities to have a policy for declaring and responding to “exceptional circumstances” — defined by NERC as a natural disaster, civil unrest or a situation that threatens to impact BES reliability or presents a risk of injury or death.

April 20, 2018

FERC Outlines Gas Pipeline Rule Review

By Rich Heidorn Jr.

FERC will open a 60-day comment period on potential changes to its policy statement on the permitting of natural gas pipelines, acknowledging that it may have to reconsider how it balances project benefits against adverse consequences in light of the shale gas revolution, global warming concerns and other changes since it last considered the issue in 1999.

All five commissioners said Thursday they welcomed the Notice of Inquiry (PL18-1), which FERC Chairman Kevin McIntyre had promised at his first meeting in December. (See FERC to Review Gas Pipeline Approva l Process.)

But given the increasing contentiousness over pipeline expansions, it’s unlikely the commission will find consensus on all issues on which the NOI seeks comment. (See FERC Whipsawed on Pipeline Policy in House Hearing.)

Flashpoints

The biggest flashpoint may be the debate over how the commission evaluates the greenhouse gas impacts of new pipelines under the Natural Gas Act (NGA) and National Environmental Policy Act (NEPA). The NOI also noted “increased concerns” by landowners and communities affected by proposed projects as the total miles of interstate pipelines approved by the commission annually hit a peak of 2,739 miles last year.

Another point of contention could be calls for speedier pipeline approvals. The NOI says the commission “is committed to carrying out” President Trump’s executive order 13807, which calls for completion of all federal environmental reviews and permitting processes for infrastructure projects within two years.

FERC natural gas pipelines — | *National Fuel Gas Co.*

“The commission’s aim in this proceeding is the same as in the policy statement: ‘to appropriately consider the enhancement of competitive transportation alternatives, the possibility of over building, the avoidance of unnecessary disruption of the environment and the unneeded exercise of eminent domain,’” FERC said.

McIntyre said the commission’s issuance of the NOI does not mean FERC will ultimately change its current procedures. He said it will apply the current rules to pending applications on a case-by-case basis during the inquiry. “The commission will consider only generic issues and will not consider any comments that refer to open, contested commission proceedings,” the NOI warned.

1999 Policy Statement

The 1999 policy statement followed moves to reduce regulation and increase competition in the industry under the Natural Gas Policy Act of 1978 and FERC Order 436, which allowed local distribution companies and industrial customers to buy gas directly from producers or merchants and transport their gas on interstate pipelines.

The policy statement said the commission will consider whether a proposed project’s anticipated public benefits outweigh its adverse effects on economic interests. If so, the commission then analyzes the project’s environmental impacts in reaching a conclusion on whether a project is required by the public convenience and necessity.

Four Topics of Inquiry

The commission asked for comments on four topics:

The reliance on precedent agreements to demonstrate project need, and how contracts with pipeline affiliates should be treated (e.g., “Should the commission examine whether the proposed project meets market demand, enhances resilience or reliability, promotes competition among natural gas companies, or enhances the functioning of gas markets?”);
Landowner interests and the use of eminent domain (e.g., “Should applicants take additional measures to minimize the use of eminent domain?”);
The evaluation of alternatives and environmental effects under NEPA and the NGA (e.g., “Are there any environmental impacts that the commission does not currently consider in its cumulative impact analysis that could be captured with a broader regional evaluation?”); and
The efficiency and effectiveness of the commission’s certificate processes (e.g., “Should certain aspects of the commission’s application review process (i.e., pre-filing, post-filing and post-order-issuance) be shortened, performed concurrently with other activities or eliminated to make the overall process more efficient?”).

Comments will be due within 60 days of the publication of the NOI in the Federal Register.