Page 1159 – RTO Insider

June 17, 2018

Duke, ODEC Rebuffed on Polar Vortex Gas Refunds

By Rory D. Sweeney

Duke Energy and Old Dominion Electric Cooperative have likely struck out on trying to recoup millions of dollars in “stranded” gas costs they say PJM forced them to incur during the 2014 polar vortex.

The D.C. Circuit Court of Appeals on Friday ruled that FERC was justified when it denied the companies’ reimbursement requests in 2015, rejecting separate petitions for review (16-1133, 16-1111). (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)

Duke and ODEC had argued to FERC that they were owed compensation when PJM ordered them to be ready to run even as the cold snap sent gas prices soaring. Duke purchased $12.5 million worth of natural gas for its Lee plant in Illinois, only to have it not called on in real time. The company was able to resell some of its gas and sought $9.8 million in restitution.

ODEC complained that it was due nearly $15 million because PJM canceled multiple dispatches that left gas it had purchased for its plants unused. It also said its plants’ operating costs on Jan. 23, 2014, exceeded what it could recover in the day-ahead market because of the $1,000/MWh offer cap at the time. The co-op asked the commission to extend to Jan. 23 the waiver FERC granted PJM on Jan. 24, which allowed capacity resources to receive make-whole payments if their costs exceeded the offer cap.

FERC denied the request, saying PJM’s Tariff didn’t allow it and that ODEC’s ratepayers lacked sufficient notice that the approved rate was subject to change. The court upheld FERC’s decision, dismissing ODEC’s arguments that it could charge a market-variable formula rate and that customers received sufficient notice from an announcement PJM posted that it would seek commission approval for certain generators to exceed the rate cap.

“Close, but no cigar,” the court said of the formula rate argument. ODEC failed to identify Tariff provisions specifying such a rate or an instance in which utilities refunded overbillings back to customers, a bidirectional condition that would exist under formula rates. Additionally, “to toss that [$1,000/MWh rate] cap aside after the fact just because it did exactly what a cap is supposed to do — serve as a firm ceiling on market prices — would retroactively rewrite the terms of the filed rate,” the court said.

ODEC’s argument that PJM’s announcement qualified as sufficient notice “fails at every step,” the court said, noting that it wasn’t filed at FERC as required for rate changes.

The court also sided with FERC on Duke’s request, in which the commission concluded that PJM’s conversations with the company did not constitute an order to purchase expensive gas.

ODEC Duke Energy Polar Vortex PJM — | *Monitoring Analytics*

FERC determined that PJM operators told the generators “to do whatever needed to be done to fulfill its Tariff obligation” but “said nothing about when to purchase natural gas, at what price to purchase the gas, how to bid into the market or to take any action beyond that which Duke is otherwise obligated to take under the Tariff: to purchase natural gas to be prepared to run its units.”

The court conceded that “the record may well be subject to other interpretations,” including those preferred by Duke.

“But our task is not to assess whether Duke’s interpretation of the record is fair,” the court said. “Just the opposite: We must accept FERC’s interpretation unless unsupported by substantial evidence. And Duke has given us no basis for believing that a ‘reasonable mind’ would not find the evidence here ‘adequate to support [FERC’s] conclusion.’”

June 17, 2018

Plan Would Reduce PJM Capacity Curve Through Peak Shaving

By Rory D. Sweeney

PJM hopes to reduce its capacity market demand curve by including peak shaving among the variables used to develop its load forecast.

Andrew Gledhill, senior analyst of resource adequacy planning, explained the proposal at a meeting last week of the Summer Only Demand Response Senior Task Force (SODRSTF). It has the potential to reduce reliability requirements — and subsequently the variable resource requirement demand curve — by hundreds of megawatts.

PJM would start by adjusting historical loads back to 1998 through a formula that assumes perfect previous curtailment compliance. The program would be assumed to have been enacted every time a predetermined temperature-humidity index (THI) threshold was reached. THI has a strong correlation with loss-of-load expectation, the RTO said.

Each event would have been six hours from 1 to 7 p.m. on a non-holiday weekday. The events would have occurred any time between May and October, but “we don’t have a lot of high-THI events that occur in May, September and October, so … these are most likely to occur in June, July and August,” which account for the six highest load hours in the RTO, Gledhill said.

Adjusting the Model

The current method identifies the gross load for a delivery year and regresses for the forecast based on variables, including economic, weather and end-use changes.

“But there’s no variable in there for peak shaving,” Gledhill explained, so it would have been included only by reducing the gross load.

pjm load forecast peak shaving — | *An example from PJM of the potential impact to the VRR curve in ATSI’s transmission zone.*

Some stakeholders voiced concerns that requiring commitments to last six hours was a high bar that would reduce offerings into capacity auctions, but others urged them to take a holistic view.

“We have to look at what PJM’s need is, not simply what the easiest program or the most customer-friendly program would be,” GT Power Group’s Dave Pratzon said.

Staff said the six-hour time frame is intentional because it mitigates peak shifting. They noted that the curtailments have already been factored into forecasts. PJM would only be looking for compliance, but these would not be RTO programs.

“The load forecast has already reflected the benefit of reduction of load when THI trigger is hit,” PJM’s Tom Falin said. “The intent of this is to improve the load forecast. … We’ve already assumed a certain amount of behavior, so it has to continue in the future, so the forecast can remain consistent.”

Impact

PJM’s analysis showed that only a percentage of the cumulative peak shaving would impact the load forecast because of the peak simply shifting to another hour. For most transmission zones, the impact shrinks as the amount of shaving increases, staff found. For example, 100% of the megawatts in a 2% shave would impact the forecast in the Penelec zone, but less than 40% of the megawatts in a 10% shave would impact the forecast in East Kentucky Power Cooperative’s zone.

It would have even less of an impact on the reliability requirement, though it would still be significant. PJM found that, given a 6% peak shave, the reliability requirement would be reduced by anywhere from 30 to 85% of the shaved megawatts.

June 17, 2018

MISO to Lower SPP Interregional Project Thresholds

By Amanda Durish Cook

MISO last week said it will revise its regional cost-sharing practices for interregional projects with SPP to match its process for PJM seams projects, lowering the voltage threshold to 100 kV and eliminating a minimum cost requirement.

The move is part of MISO’s broader plan to revise cost allocation for market efficiency projects (MEPs) as Entergy’s five-year transition period — which limits cost sharing in MISO South — expires at the end of the year. The plan still includes Tariff changes to eliminate a footprint-wide postage stamp rate for MEPs in favor of more detailed benefit metrics, and to lower the voltage threshold for cost allocation eligibility of internal MEPs from 345 kV to 230 kV.

Unlike interregional MEPs, internal MEPs will still have to meet a $5 million minimum cost threshold, although both project types will still be subject to a 1.25:1 benefit-to-cost requirement. None of the changes extends to MISO’s multi-value project category. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)

MISO’s current regional cost-sharing rules for SPP interregional projects require at least a 345-kV voltage rating and a $5 million price tag. The new rules will mirror regional rules that FERC ordered for MISO-PJM interregional projects in 2016.

Narrowing the Cost Allocation Gap

MISO Director of Strategy Jesse Moser said that ensuring consistency along the RTO seams was the deciding factor in standardizing the treatment of SPP and PJM projects.

miso spp seams cost allocation — Moser | © *RTO Insider*

The current proposal will “best align who pays with who benefits,” Moser told RTO Insider.

“Our goal is to get as close to that as we can,” he said. “We’ve long had a concern about what we call the cost allocation gap on our seams.”

Having differing rules for separate RTO neighbors “leaves the door open for uncertainty,” Moser said. “We prefer a clear rule set for any beneficial project that comes out of the” interregional process.

MISO will spend the next two months preparing its overall cost allocation proposal for a FERC filing by the end of September. The RTO is open to holding a summer conference call that would invite stakeholders to offer minor suggestions for clarity, but it does not intend to open the proposal to any substantive change, Moser said.

MISO staff have spoken to SPP officials about the changes, which will not require a revision to the RTOs’ joint operating agreement because they only involve MISO’s regional cost sharing, Moser said. Meanwhile, the RTOs will work this summer on a proposal to similarly relax interregional project criteria in the JOA, which still mandates 345-kV and $5 million minimums. (See MISO, SPP Look to Ease Interregional Project Criteria.)

Moser said there was a “possibility” that FERC could have ordered MISO to lower the SPP thresholds as it did with PJM projects, if the commission had received a complaint.

“Looking at the direction we’ve seen so far, on the PJM seam, that seems like something FERC would support,” Moser said. “We have a pretty firm belief that if this issue was not addressed, it would get put in front of FERC.”

But Moser reiterated that consistency, not the threat of a FERC complaint, drove MISO’s decision.

Transmission Owners: Equal Treatment Unnecessary

But some stakeholders continue to question what would be a discrepancy between the voltage thresholds for MISO MEP projects and interregional projects with SPP. (See MISO Cost Allocation Plan Hits Interregional Differences.)

More than 20 MISO transmission owners joined in written opposition to the 100-kV threshold on interregional projects with SPP. They contend that there are differences between the PJM and SPP seams and that the two “should not receive equal treatment.”

MISO’s seam with SPP is longer and has lower load density than that with PJM, meaning generation can be situated far from load, the TOs have pointed out. Higher-voltage interregional projects are a better fit for those conditions, unlike the MISO-PJM seam where population density makes smaller transmission projects more worthwhile, they argue.

The TOs also note that MISO and PJM have been coordinating along their seam for about 18 years while the relationship with SPP is “less mature,” evolving as SPP integrated the Western Area Power Administration and Basin Electric Power Cooperative transmission systems in late 2015 and MISO integrated its MISO South region in 2013. “Congestion patterns along that seam are not well understood and are subject to change,” the TOs said.

But while acknowledging that the proposal wasn’t “universally liked,” Moser contends that MISO collected sufficient stakeholder feedback on regional cost allocation to move ahead with the plan.

“This has been a fairly long process. We’ve been working on this since 2015. We’re looking at what the new needs might be given our new footprint. … We think we’re putting together a package of reforms that best meets the needs of our footprint,” Moser said.

MISO also plans to conduct a general review of its overall cost allocation design three years after implementation, Moser said. The RTO will examine whether projects built under the new rules have benefits commensurate with cost allocation and examine any past proposed projects that appeared highly beneficial but still couldn’t qualify for cost allocation.

“There’s an understanding that needs will continue to change,” Moser said.

New Local Economic Project Type

MISO last week announced another new wrinkle for its cost allocation plan: a new project type that will be ineligible for regional cost sharing for the sake of clarity.

Moser said the new category, “Local Economic Projects,” is meant for projects that demonstrate at least a 1.25:1 economic benefit but are below 230 kV. Such projects would have their costs allocated 100% to their local transmission pricing zone. Currently, these projects fall under an “other” category.

Moser said the category is needed to distinguish small economic transmission projects from small reliability-driven transmission projects. Today, most of MISO’s “other” category of projects are reliability-driven, with few small projects being built for economic reasons, he said.

June 17, 2018

CPV: Subsidies, not Gas Fears, Challenge for New Plants

By Michael Brooks

Competitive Power Ventures, which last week celebrated the opening of its new 805-MW combined cycle gas-fired power plant in Oxford, Conn., would like to build more gas plants. But it said it is wary of subsidized competitors.

The company announced Thursday that is has begun selling power in ISO-NE from its Towantic Energy Center, which uses two GE Power 7HA.01 combined cycle, dual-fuel turbines, one of the most efficient designs in the world, with up to 64% efficiency.

ferc competitive power ventures cpv towantic energy center — CPV Towantic Energy Center in early May, with construction nearly complete. | *CPV*

The plant represents the 26th HA unit to go online, GE said. The HA series is air-cooled, which CPV says “saves as much as 90% of the water used by similar” steam-cooled designs. Poor sales of its previous steam-cooled H-class turbines prompted GE to switch to condensed air, which allows for a simpler configuration that is not only more efficient but more economic to construct as well, the company says.

The turbines’ efficiency will give Towantic an advantage in ISO-NE’s energy market, said Tom Rumsey, CPV senior vice president of external and regulatory affairs. With no load growth in New England, new plants must be more efficient to be profitable, he said.

The plant officially began generating power May 21, just in time for the June 1 start of the 2018/19 capacity commitment period. CPV sold 750 MW of capacity into ISO-NE’s ninth Forward Capacity Auction in 2015.

It gets its fuel primarily from the Algonquin Gas Transmission pipeline and interconnects to the grid through Eversource Energy’s 115-kV Baldwin Junction-Beacon Falls circuit.

Rumsey said the company expects the plant to be a baseload resource, and it isn’t worried about there being gas shortages for the plant because it can also burn ultra-low-sulfur diesel fuel. In the 2014 polar vortex and this year’s bomb cyclone events, “it wasn’t that you couldn’t get gas. It was that gas was so expensive,” he said.

CPV is concerned, however, about state-subsidized resources disrupting the markets, Rumsey said. The company is looking to build more gas plants in New York, Illinois and New Jersey, all of which have enacted zero-emission credit programs for at-risk nuclear plants. They “represent the biggest challenge to the competitive markets since they began,” Rumsey said.

He cited the brief FERC and the Justice Department filed with the 7th U.S. Circuit Court of Appeals in the challenge over Illinois’ program, which argued that it was not pre-empted by the Federal Power Act under the Constitution’s Supremacy Clause. (See Analyst: FERC Asserts Role in Handling Nuke Subsidies.)

CPV also opposed PJM’s capacity market repricing proposals to address subsidies, instead joining Calpine and Eastern Generation to propose a “clean” minimum offer price rule applicable to all subsidized resources. (See Gas Gens Ask FERC for ‘Clean MOPR’ in PJM.)

“Accommodating these resources is the wrong way to go,” Rumsey said.

Combined with the Department of Energy’s latest plan to bail out uneconomic coal and nuclear plants, “it’s all coming to a head at FERC this year.”

June 17, 2018

MISO Seeking SPP Tx Penalty Compromise

By Amanda Durish Cook

CARMEL, Ind. — MISO says it will seek to alter SPP’s practice of levying unreserved transmission use penalties on MISO load-serving entities when the charges pose a deterrent to building interregional projects.

spp transmission penalty load serving entities — Thoms | © *RTO Insider*

Eric Thoms, MISO manager of interregional planning and coordination, last week said the RTO’s other contract path sharing agreements with PJM and Ontario’s Independent Electricity System Operator allow for use of transmission service when a normal feed is open and joint contract path capacity is used to serve load.

It likewise does not charge for transmission service when non-MISO LSEs use its transmission under contract path sharing.

But SPP does not acknowledge contract path sharing, instead issuing MISO LSEs bills for transmission service and unreserved usage penalties. Thoms said MISO is concerned those charges could extend to future interregional projects cost-shared between the two RTOs.

Thoms likened SPP’s charges to the early days of cellphone contracts before shared plans, when bandwidth could be exceeded only with bill increases.

“Should MISO and SPP approve an interregional project, under certain qualifying conditions, MISO members could be expected to acquire transmission service or be subject to unreserved usage penalties in addition to MISO’s cost of an interregional project,” Thoms said during a June 13 Planning Advisory Committee meeting. He recommended that the RTOs seek a compromise in the JOA that exempts MISO members from SPP’s additional transmission service or unreserved usage penalties for any future interregional projects.

“We got a shadow of evidence that this could be an issue in the last [coordinated system plan] study,” Thoms said, saying that considerable MISO load on one proposed interregional project could have seen SPP charging transmission fees on MISO LSEs.

MISO and SPP have never approved an interregional project, despite conducting two coordinated system plan studies. Thoms said stakeholders attending the PAC have suggested that SPP’s current practices “may be an impediment to interregional projects with SPP.” Some MISO stakeholders in public meetings have said a first-ever interregional project will continue to be elusive until RTOs have comparable transmission usage charges.

Thoms said some stakeholders have suggested MISO “reciprocate” and use SPP’s interpretation of transmission charges, but he discouraged the idea.

“That would also have broader implications on how contract paths are interpreted,” Thoms said. “This is in the spirit of trying to remove impediments to mutually beneficial interregional projects.”

Thoms said MISO staff will next approach the MISO-SPP Joint Planning Committee to seek a negotiation of the unreserved use charge practice with respect to interregional projects.

David Kelley, SPP director of seams and market design, said his RTO’s Seams Steering Committee is aware of MISO’s position on the “potential unreserved use charges under SPP’s Tariff and their perceived impact to future SPP-MISO interregional projects.”

“SPP looks forward to further discussions with SPP and MISO stakeholders during future [Interregional Planning Stakeholder Advisory Committee] meetings as we continue to look for ways to remove barriers to developing mutually beneficial transmission projects,” Kelley told RTO Insider.

MISO-SPP Interregional Changes

Meanwhile, MISO is still committed to making its interregional project process with SPP more scalable by removing the $5 million cost threshold and the RTOs’ joint model requirement, while adding an avoided cost benefit metric in addition to the adjusted production cost savings for interregional projects. (See MISO, SPP Look to Ease Interregional Project Criteria.)

“It’s a herculean effort to build a joint model. It takes several months, and it’s essentially another screen,” Thoms said, adding that MISO hopes to file a JOA change with FERC by the end of the year.

MISO and SPP said the 15 stakeholders that provided feedback to a spring survey were divided over whether to eliminate the joint model.

“Several stakeholders believed removing the joint model would eliminate barriers and streamline the process. Others expressed concern about equitable cost allocation, lack of joint collaboration and study timelines,” MISO said.

MISO also noted a majority of the stakeholders responding to the survey support removing the $5 million cost threshold.

MISO and SPP stakeholders will have a chance to discuss the proposed JOA changes at a July IPSAC meeting, for which no date has been set.

June 15, 2018

Gas Costs Drive Sharp Gain in CAISO 2017 Prices

By Jason Fordney

CAISO wholesale prices jumped 25% last year on higher natural gas costs stemming from tight supplies in Southern California, where the region’s main pipeline operator has no timetable for returning a critical line back into service.

The ISO’s total cost to serve load in 2017 was $9.3 billion, or $42/MWh, compared with $34/MWh in 2016, its Department of Market Monitoring estimated.

Regional spot gas prices increased 27% last year, helping to drive up electricity prices, the department said Thursday. It calculated the prices based on the average of the SoCal Citygate and Pacific Gas and Electric Citygate delivery hubs. Without factoring the gas price increases and greenhouse gas compliance costs, ISO prices rose by a much lower 4%.

natural gas caiso wholesale market — CAISO quarterly prices, system energy, all hours | © *CAISO Department of Market Monitoring*

Power prices received an additional boost from reduced energy supplies in the day-ahead market, a rising need for ancillary services and increased transmission congestion, the Monitor said in its 2017 Annual Report on Market Issues & Performance.

2017 wholesale prices “reflect the efficient and competitive conditions that exist during most hours of the year. However, DMM notes that the tightening of supply and demand conditions observed in 2017 has created the increased potential for uncompetitive market outcomes in 2018 and beyond.”

About 3,000 MW of gas-fired generation retired in 2017, the largest one-year volume in the ISO’s history. Another 600 MW has announced retirement in 2018, while about 770 MW of summer peak generating capacity was added, mostly solar.

The day-ahead market comprises most of the total wholesale market and remained structurally competitive, except for 36 hours, or 0.4% of intervals, when there was a single pivotal supplier needed to meet demand. The two largest suppliers were pivotal in 128 hours (1.6% of intervals), while the three largest suppliers were pivotal during 336 hours (3.8%).

Day-ahead prices spiked past $770/MWh on Sept. 1 and were greater than $200/MWh for a four-hour period.

“These high day-ahead prices reflect a tightening of supply conditions during peak ramping hours that DMM expects will continue in 2018 and the coming years,” the Monitor said. Conditions were also competitive in the Western Energy Imbalance Market and its expansion and performance improved efficiency for the CAISO real-time market and other balancing areas.

Ancillary service costs increased to $172 million from $119 million in 2016 and $62 million in 2015 on tight supply conditions and higher operating reserve requirements during the summer. CAISO this week described how a problem with solar inverters led to a need to increase operating. (See Solar Inverter Problem Leads CAISO to Boost Reserves.)

The DMM is continuing its campaign against CAISO’s congestion revenue rights auction, saying payouts to CRR holders exceeded auction revenues by more $100 million in 2017 and $42 million in the first quarter of 2018. The ISO is working to overhaul to the CRR auction process. (See CAISO Developing New CRR Proposal.)

SoCalGas Says ‘No Timetable’ for Line 235

Southern California’s tight gas supplies were largely driven by the loss of Southern California Gas’ Line 235-2, which ruptured on Oct. 1, 2017, also taking nearby Line 4000 out of service. The company told RTO Insider there is “no timeline” for the return to service of the pipe, characterized as a “backbone” facility at certain points in the region.

Another factor: a restriction on withdrawals at the Aliso Canyon storage field, leading SoCalGas to warn of possible supply problems and curtailments for gas-fired plants this summer. The company has been seeking to regain full use of the facility, which has been on restricted status since a large methane release in October 2015. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.) Residents near the facility are pushing for its closure, saying they are still suffering negative health impacts, and Gov. Jerry Brown has also called for its eventual closure.

To study the capacity issue, CAISO, the California Public Utilities Commission, the California Energy Commission and others formed the Aliso Canyon Technical Assessment Group, which has determined about 500 MMcf of line capacity is missing per day compared with last year at this time, with about 2,655 MMcf available on May 1. The Line 235-2 outage will require SoCalGas to draw more from storage.

Those factors have led CAISO to warn of tight generation supplies this summer. SoCal Gas said that it has concerns the technical assessment done by the state agencies is “overly optimistic.”

“Service reductions or interruptions to electric generators may be necessary this summer and withdrawals from Aliso Canyon may be required to prevent more extensive customer outages,” the company said. No cause has been publicly identified for the Oct. 1 rupture and subsequent 5-acre fire, which occurred the day after the expiration of an CPUC-approved agreement between SoCalGas and CAISO that allowed the company to increase injections into Aliso Canyon.

June 15, 2018

PJM: Stakeholders Safe from Defaulting Member

By Rory D. Sweeney

PJM said Wednesday that it has terminated electricity supplier AMERIgreen Energy’s membership, assuring stakeholders they won’t be exposed to the company’s financial woes.

But the RTO’s actions might be the least of AMERIgreen’s concerns.

PJM announced Tuesday that the company was in default for failing to pay its May month-to-date weekly invoice, which severed its access to the RTO’s markets, rights to transmission service and ability to participate in committee meetings. But that won’t matter much as the company has crumbled seemingly overnight amid a cloud of fraud accusations and the mysterious disappearance of its CEO.

AMERIgreen Energy — PJM canceled the membership of AmeriGreen, which was owned by the Pennsylvania company Worley & Obetz, after it defaulted on paying its bill.

AMERIgreen provided electricity service to commercial and residential customers as an subsidiary of Worley & Obetz, a fuel supplier based in Lancaster County, Pa. The parent company’s issues became public on May 31 when it announced via Facebook two rounds of layoffs, the “disappearance” of CEO Jeff Lyons and a law enforcement investigation into “potentially fraudulent activity.”

On the same day, three regional banking companies alerted the Securities and Exchange Commission that they will likely lose more than $60 million combined on loans to an unnamed company, according to local media reports. One of the banks accidentally implied the defaulting company was Worley & Obetz, and another one confirmed it several days later as the saga wore on. In that time, a fourth bank disclosed additional likely losses to the SEC, saying they “resulted from fraudulent activities believed to be perpetrated by one or more executives employed by the borrower and its related entities.”

Two weeks earlier, the Pennsylvania State Police announced they were looking for Lyons because he was reported missing by his family. The CEO, a 22-year veteran at the company, had left home without his wallet or credit cards and turned off his cellphone. He missed a meeting with the company’s vice chairman and a large commercial customer, where he was expected to discuss financial records he had previously been reluctant to disclose. He was terminated for cause later that day.

Police announced two days later that he had been located but that, because he wasn’t in danger, they couldn’t provide more information. According to media reports, a family member announced on Facebook that he was found in Minnesota.

The company then attempted to secure credit for restructuring, but the banks refused the plan. The company announced it was shutting its doors last Monday and has since filed for bankruptcy as “a direct result of the fraudulent actions of Jeffrey B. Lyons.”

AMERIgreen’s nosedive was abrupt. On Wednesday, it was still offering electricity contracts serviced through Texas-based TriEagle Energy, but it has since ceased.

In announcing the membership cancellation, PJM assured market participants that they won’t be liable for the default.

“PJM projects it holds sufficient financial security from AMERIgreen to cover both its outstanding charges and any anticipated remaining charges related to their default,” PJM said. “Therefore, PJM does not anticipate there will be a default allocation assessment to PJM members resulting from AMERIgreen’s default.”

PJM spokesperson Jeff Shields said the RTO’s credit requirements are designed for this issue.

“All members are required to provide credit based on their recent historical invoice activity, so more members buying more energy would be required to provide more collateral. Some members also engage in market activities that are screened, such as [financial transmission rights] and virtual transactions, and those other market activities have additional requirements,” he said via email. “PJM allows a limited amount of unsecured credit for investment-grade members; all activity exceeding that level must be collateralized.”

The company’s load is being transitioned to applicable electric distribution companies. The terms of service for such customers is set by state regulators, Shields said.

June 15, 2018

MISO Intervenes in IPL Storage Appeal

MISO this week filed to intervene in Indianapolis Power & Light’s appeals challenging FERC decisions on energy storage compensation and dispatch within the RTO.

IPL Storage Energy Storage MISO FERC — IPL Harding Street Station battery interior | *IPL*

In a June 11 filing, MISO said it had “direct, substantial and legally protectable interest that would be subject to impairment” by IPL’s litigation. The RTO also said its independence from its members ensures “no other party can adequately represent” its interest in the case that could force changes to its Tariff (18-2104).

The case is pending before the 7th U.S. Circuit Court of Appeals after IPL filed a petition for review in mid-May, challenging FERC orders stemming from the company’s 2016 complaint that MISO’s Tariff unreasonably limited energy storage participation. (See FERC OKs MISO Plan to Expand Storage.)

In its petition for review, IPL pointed out that FERC’s original order on its complaint in early 2017 was issued two days before the commission lost its quorum and was reduced to just two commissioners.

— Amanda Durish Cook

June 15, 2018

MISO Planning Advisory Committee Briefs: June 13, 2018

CARMEL, Ind. — MISO is moving ahead with a plan to address delays in its interconnection queue by reducing the number of project studies and making generation owners more accountable for site control.

The RTO in May proposed to remove its transient-stability, short-circuit and affected-system studies from the first phase of the definitive planning phase (DPP) of the queue and require customers to demonstrate ownership, lease interest or land rights on a project’s site before entering the queue. (See MISO Proposal Aims to Speed Up Queue Process.)

June 13 MISO Planning Advisory Committee | © *RTO Insider*

MISO is now proposing to eliminate its proposed requirement that a developer have 100% site control upon entering the queue. A revised plan would instead increase the deposit due when entering the queue from $100,000 to anywhere between $500,000 and $2 million in cash, depending on the megawatt size of the project. The larger deposit would only become refundable if the proposed project makes it to the generator interconnection agreement step.

Under the plan, a project owner would have to demonstrate full site control by the second decision point of the interconnection queue, MISO Planning Manager Neil Shah said during a June 13 Planning Advisory Committee meeting. Any owner unable to provide proof of site control by then must forfeit the larger deposit and withdraw their interconnection application, he said, adding that MISO plans to hire consultants to validate site control demonstrations.

Stakeholders — particularly renewable developers — said the proposed site control requirements were still too high.

But Shah noted that in April alone, an additional 40 GW entered the interconnection queue, with around 75% of project owners electing to pay the current $100,000 refundable deposit instead of securing site control.

“The bar is too low for entering the queue,” Shah explained. “The intent is to raise the bar, so we have reasonably high requirements that do not harm ready projects because of the entry of the non-ready projects.”

Shah said MISO intends to file Tariff changes with FERC sometime in July.

5 Focus Areas in Market Congestion Planning Study

MISO has slimmed 116 new project ideas down to five areas of focus in this year’s footprint-wide market congestion planning study.

The Market Congestion Planning Study (MCPS) has so far identified four project candidates in four separate locations in MISO Midwest, and five projects to remedy one area of concern in MISO South.

In MISO South, five projects ranging from $8 million to $40 million with estimated benefit-cost ratios ranging from 1.10:1 to 3.27:1 are contenders to alleviate congestion on the 115-kV Natchez line at the Mississippi-Louisiana border.

In MISO Midwest, two projects focus on upgrading 138-kV facilities while two others are 161-kV solutions:

A rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota at an estimated $20.1 million, yielding a 3.62:1 benefit-cost ratio.
A project to add a series reactor on the Forest Junction-Elkhart Lake 138-kV line in eastern Wisconsin for $2 million, resulting in a 3.7:1 benefit;
A reconductor project on the Michigan City-Trail Creek-Bosserman and LNG-Maple 138-kV lines in northern Indiana for an estimated $8.5 million, with a 1.42:1 benefit.
A new 161-kV line with a reconductor of an existing 161-kV line near the towns of Paradise and Wilson in southern Indiana for $33 million with a 1.59:1 benefit.

MISO Manager of Economic Studies Zheng Zhou said all cost estimates are planning-level estimates and are subject to change.

MISO’s MCPS study seeks to identify both near-term congestion-relieving transmission projects and long-term economic projects. Last year’s MCPS focused exclusively on MISO South and did not produce a single project recommendation.

Zhou said MISO will present final project recommendations from the MCPS at the September Planning Advisory Committee meeting.

— Amanda Durish Cook

June 15, 2018

WAPA Formally Requests SPP’s RC Services

By Tom Kleckner

The Western Area Power Administration said Wednesday it has submitted a formal request to SPP for reliability coordinator (RC) services on behalf of its Upper Great Plains West and Western Area Colorado Missouri balancing authorities.

WAPA said the two BAs are considering taking SPP’s RC services in early 2020, contingent on the RTO gaining certification and meeting other conditions. The BAs encompass WAPA’s Pick-Sloan Missouri Basin Program in the Western Interconnection, Loveland Area Projects and part of its Colorado River Storage Project Management Center territory.

“We are excited about this opportunity and look forward to more detailed negotiations with SPP,” WAPA CEO Mark Gabriel said in an announcement.

SPP said the request was the first of what it hopes will be many since it announced June 5 that it intends to provide RC services in the Western Interconnection by late 2019. (See Westward Ho: SPP Plans to Become RC in West.)

The RTO said it has received 28 letters of intent from utilities expressing interest in the service but noted that WAPA’s letter was special.

SPP WAPA reliability coordinator — Monroe | © *RTO Insider*

“Our agreement with WAPA is distinct in that it’s the first — of many, we anticipate — to go a step further and commit to the preparation of an actual service agreement,” COO Carl Monroe said in an emailed statement to RTO Insider.

Monroe said the letters of intent “have established partnerships in which SPP will assist each of them in evaluations of the costs and benefits of our provision of reliability coordination service.”

Peak Reliability current provides WAPA’s RC services, but the agency said in February it had sent withdrawal notices to Peak, effective Sept. 2, 2019. WAPA is considering both SPP and CAISO, which also plans to become an RC. The Alberta Electric System Operator already provides reliability coordination in the West.

The Western Electricity Coordinating Council has asked its BAs and transmission operators to confirm which RC they will be using by Sept. 4.

“We continue to engage with neighboring utilities and Mountain West Transmission Group participants on the future of energy markets and RC services in the West,” Gabriel said.

A WAPA spokesperson said the agency has asked SPP to submit a proposal for terms and conditions under which its BAs would receive RC services.

WAPA is one of four power marketing administrations within the Department of Energy. It encompasses a 15-state region of the central and western U.S. and has a 17,000-mile system that carries electricity from 56 federal hydropower plants.