ISO-NE on Tuesday proposed a plan to refine the procedural and technical requirements for determining whether new or modified distribution-connected generation should be interconnected by the RTO or a local utility.
Cheryl Ruell, manager of transmission services for ISO-NE, delivered a presentation on guidance for distribution-connected generation to the NEPOOL Reliability/Transmission Committee, which met July 18-19 in Meredith, N.H.
The grid operator’s proposal would consider the location and status of the distribution circuit to which the resource connects — as well as the size of the proposed generator — to determine the nature of any application approval required under Section I.3.9 of the Tariff. The interconnecting transmission owner would submit an application on behalf of generators that don’t participate in the wholesale market. Distribution-connected generators less than 5 MW may file a special category notification form, while those under 1 MW are exempt under the Tariff.
Existing state interconnection processes would continue to apply to any Public Utility Regulatory Policies Act qualified facilities in cases when the generator is interconnecting to a FERC-jurisdictional facility, but only if those projects produce energy to be consumed only on the retail customer’s site or sell 100% of their output to the interconnecting utility, rather than selling to RTO markets. If the host utility wishes to register the qualifying facility in the wholesale market, the host utility must meet all ISO-NE registration, modeling and operating requirements.
Forward Capacity Market and Interconnection Standards
ISO-NE also presented the committee with the current procedures for integrating a new generator with the Forward Capacity Market and interconnecting an elective transmission upgrade (ETU), which is a merchant-funded transmission interconnection.
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Director of Resource Adequacy Carissa Sedlacek and Director of Transmission Strategy and Services Al McBride covered timelines for interconnection, resource deliverability and application of the overlapping impact test.
The grid operator analyzes generators and ETU projects in the order they entered the queue and allocates transmission upgrades accordingly. Overlapping interconnection impacts restrict qualification when the upgrades identified for a new generator cannot be completed by the start of the requested capacity commitment period.
Under FERC rules, it may not be just and reasonable “for a generator in one location to sell its capacity as a capacity resource to, and receive capacity payments from, a load in another location if the generator’s output is not deliverable to the load that buys the capacity.”
Queue reforms in 2008 improved the FCM and generator interconnection process by replacing the “first-come, first-served” approach with a combination of a “first-come, first-served” and “first-cleared, first-served” approach. The changes established two types of interconnection service: capacity network resource interconnection service (CNRIS) and network resource interconnection service (NRIS).
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Generators are not required to participate in the FCM in order to interconnect to the New England transmission system.
The grid operator uses overlapping impact analysis to identify qualifying transmission upgrades. The study resource — whether transmission or generation — is responsible for impacts where the addition of the capacity results in an overload on a transmission element that is greater than or equal to 2% of the applicable thermal rating or greater than 10 MVA of the applicable thermal rating.
Generation redispatch depends on the distribution factor (DFAX) of the generators on a transmission element in the subsystem, which is a measure of the change in electrical loading on an element such as transmission line or transformer because of a change in output from a given generator. Generation with a DFAX greater than or equal to 3% on a monitored element for a given contingency — “harmer” generation — is not to be redispatched to relieve the constraint for a given study dispatch.
The Organization of MISO States (OMS) on Monday voted to lodge a protest in an ongoing dispute over whether states can prohibit energy efficiency resources from entering RTO markets.
OMS Executive Director Tanya Paslawski said the protest asks FERC to apply the same treatment to EE resources as it did to demand response in Order 719. It also affirms the authority of states to have final say in the matter.
The protest filing was approved by the OMS Board of Directors at a July 17 meeting held during the National Association of Regulatory Utility Commissioners Summer Policy Summit in San Diego.
FERC Order 719 required RTOs to accept bids from DR resources for certain ancillary services “on a basis comparable to other resources” and allowed aggregators to bid DR on behalf of retail customers directly into the market under certain circumstances.
OMS’s request stems from a recent disagreement between PJM and the Kentucky Public Service Commission. Citing the need to prevent expensive and unnecessary capacity purchases, the commission issued an order restricting EE resources from participating in PJM wholesale markets except in special cases. PJM staff responded by producing a problem statement contesting state regulators’ authority to restrict EE participation its capacity market. (See “EE Problem Statement Narrowly Approved,” PJM Market Implementation Committee Briefs.) National trade group Advanced Energy Economy petitioned FERC in June for a declaratory order, asking the commission to assert jurisdiction over the terms of EE participation in RTO/ISO markets (EL17-75).
Paslawski said that while FERC expressly left EE resources out of the order, OMS supports their market participation.
OMS members at the San Diego meeting agreed with the filing’s tone to uphold state jurisdiction. Commissioner Ken Anderson said the filing’s “thrust” on the jurisdiction of states was fitting.
MISO Asks OMS for DER Ideas
MISO Executive Director of Market Design Jeff Bladen appeared at the OMS meeting to inform state regulators that the RTO is beginning to work on developing market rules for distributed energy resources — and that he’d like input from the organization.
“Like all emerging issues, this is very much a work in progress,” Bladen said.
MISO seeks to create a common definition for DERs, rather than defining resources by technology type, the first step to developing future policy and planning processes, Bladen said. The RTO is currently running simulations with increased concentrations of DERs in hypothetical conditions to determine how it can create a more coordinated grid in which DERs do not stress transmission operations and real-time reliability conditions.
“We’re trying to test scenarios to see if we’re on the right track,” Bladen said.
Michigan Public Service Commission Chair Sally Talberg asked if MISO could carry out such simulations without communicating with generation owners.
“We’re essentially ignoring the method of dispatch” at this point in our studies, Bladen said.
Stakeholders will again take up DERs as their “hot topic” discussion item at MISO’s next full board meeting in September. Bladen said MISO will ask for stakeholder ideas on how to best integrate the resources.
“We see ourselves as just another collaborator on this rather than giving the answers.”
Avangrid earned $120 million in the second quarter, up 17% because of new rate plans in New York and Connecticut, improved cost management and a 4% increase in renewable energy production, the company reported Wednesday.
Avangrid CEO James P. Torgerson | Avangrid
The company attributed last quarter’s spike in renewable output to the recently completed 208-MW Amazon Wind Farm in North Carolina but said production at its other wind facilities came in below average. Avangrid plans to sign power purchase agreements equating to 1,800 MW of new wind and solar through 2020.
“We’ve already secured 1,000 MW of that — or 55%,” CEO James P. Torgerson told investors and analysts during an earnings call.
Avangrid controlled more than 6,000 MW of renewable resources by the end of June, 349 MW of which was added this year. Another 600 MW is slated to come online during the second half of 2017, with wind representing 534 MW and solar making up the remainder.
Renewables Rising
The company manages two primary lines of business: Avangrid Networks comprises eight electric and natural gas utilities serving around 3.2 million customers in New York and New England, while Avangrid Renewables operates more than 6 GW of mostly wind power in 23 U.S. states.
Avangrid Renewables Pipeline | Avangrid
Avangrid is this year focusing on reducing its exposure to wholesale markets by decreasing its merchant capacity from 35% to 27%.
“Year-to-date, we’ve executed 589 MW of fixed-price contracts to reduce our merchant capacity, and we’re really committed to keeping on track and adding even more as we see opportunities,” Torgerson said. “The company targets to be at 75 to 85% PPA plus hedges that we have on merchant capacity, so by adding the long-term hedges, we will actually be over 80%.”
The Networks business continues to dominate the company, contributing 73% of overall adjusted net income year-to-date, up 9% over the same period last year. But the Renewables division is playing catch-up, seeing its adjusted net income rise 26% for the same period.
Offshore wind platform | Avangrid
The company sees clean energy and offshore wind initiatives in Massachusetts as “key opportunities” to increase income beyond its long-term plan, Torgerson said.
Avangrid plans to bid “multiple transmission and/or renewable solutions” into a collaborative effort by the Massachusetts Department of Energy Resources, Eversource Energy, National Grid and Unitil to solicit clean energy proposals for 9.45 TWh annually of renewable generation.
“They’re looking for incremental hydro on a firm basis, but also new Class I renewable portfolio standard [resources], which would be wind and solar,” Torgerson said. “A combination of both could include transmission projects under a FERC tariff.”
Massachusetts is also soliciting up to 1,600 MW of offshore wind proposals due in December, and Avangrid intends to bid into that in partnership with Copenhagen Infrastructure Partners, Torgerson said. The projects will be selected in April 2018.
NYPSC Quorum Commended
Torgerson lauded the recent appointment of a new chair and two additional commissioners to the New York Public Service Commission, which operated for several months with only two of five seats filled, causing a backlog.
As part of New York State’s Reforming the Energy Vision initiative, Avangrid subsidiaries New York State Electric and Gas and Rochester Gas & Electric have filed a combined proposal with the commission to launch an Energy Smart Community project. The two utilities have already installed 20,000 smart meters under the program.
Quorum Pending at FERC
Avangrid could stand to benefit — or not — from the restoration of FERC’s quorum. The D.C. Circuit Court of Appeals (15-1118) in April overturned FERC’s 2014 order setting the base return on equity for a group of New England transmission owners — including Avangrid’s Central Maine Power — at 10.57%. The court ruled that the commission failed to meet its burden of proof in finding the existing 11.14% rate to be unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.) The TOs are seeking to begin billing at the prior ROE.
“That is the most recent rate that’s legally in effect at this point, and we requested to begin billing that again 60 days after FERC has a quorum, with retroactive billing to June 8 of this year,” Torgerson said. “If no FERC decision is reached, we’ll start doing that.”
FERC has lacked the necessary three-person quorum since the February departure of former Chair Norman Bay, and has been down to one commissioner — acting Chair Cheryl LaFleur — since Colette Honorable left last month.
LaFleur may be joined by four new members if Democrat Richard Glick and Republicans Kevin McIntyre, Robert Powelson and Neil Chatterjee win Senate confirmation. (See Trump Names Energy Lawyer McIntyre as FERC Chair.) Glick is a former vice president of government affairs for Avangrid.
Stakeholders got a first look at the preliminary projects resulting from MISO’s yearly market congestion planning study during the July 19 PAC meeting. The RTO has so far floated three potential projects in the West of the Atchafalaya Basin (WOTAB) area straddling Texas and Louisiana:
A new $137.6 million 500-kV line and substation expansion from Hartburg to Sabine in southeastern Texas that would qualify as a market efficiency project and is expected to be in service by 2023.
A $2.8 million replacement of 26 transmission structures along the Sam Rayburn-Fork Creek-Doucette 138-kV line in southeastern Texas, expected to be complete by 2020.
Equipment upgrades valued at $500,000 for the existing Carlyss substation in southwestern Louisiana by 2020.
Arash Ghodsian, MISO manager of economic studies, said the RTO’s market congestion planning footprint diversity studies will produce final project recommendations in August. Project candidates will be submitted for approval by the Board of Directors at the end of the year. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs.)
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MTEP Siting Up for Review
MISO is also planning on updating siting guidelines for projects included in its Transmission Expansion Plan.
This year’s siting model will be slightly altered to add likely wind and solar zones. MISO will also consider zonal resource adequacy requirements when determining siting and exclude thermal unit development from non-attainment areas subject the National Ambient Air Quality Standards.
The RTO plans to further improve its siting modeling process for the 2019 cycle through a series of stakeholder workshops that will begin in September. Matt Ellis, a MISO policy studies engineer, said the overhaul will focus on the placement of new technology, including 100 MW of queued energy storage resources, future utility-scale renewables, rooftop solar — predicted to reach 10 GW by 2027 — and the addition of more electric vehicles and their demands on load.
Ellis said projects in the interconnection queue generally exhaust themselves within a three- to five-year cycle, but MISO plans for its transmission system 15 years into the future.
He also asked for stakeholders to submit ideas by Aug. 11 on how MISO’s siting process can account for new technology.
MISO will also conduct a multi-value project triennial review this year, sizing up its existing portfolio and quantifying benefits. FERC requires a full review of the approved portfolio benefit every three years.
Project manager David Lucian said the review will have no effect on cost allocation for existing projects, but findings could be used to adjust project criteria in future projects. The review includes analyses of economic benefits, generator flexibility, renewable target standards, natural gas risks and job creation.
MISO last conducted an MVP triennial review in 2014, concluding that the portfolio held a benefit-to-cost ratio ranging from 2.6 to 3.9 and should create anywhere from $13.1 billion to $49.6 billion in net benefits over the next 20 to 40 years.
The triennial review report will be filed with FERC by the end of the year, PAC Chair Cynthia Crane said. Results will also be published in the MTEP 17 report due in December.
SAN DIEGO — New electricity business and regulatory models will be needed in the U.S. to transition to a future with more distributed and renewable resources, changing customer needs and new technologies, market participants and regulators said this week.
Industry representatives and state regulators gave an overview of the changing landscape at the National Association of Regulatory Utility Commissioners Summer Policy Summit. Common themes were the growth of distributed resources, managing large amounts of new renewables and developing fresh approaches as more electricity consumers also become producers.
Pacific Gas and Electric CEO Geisha Williams said that the key is to implement renewables, distributed generation and other new technologies “and not leave anybody behind.” About 40% of the utility’s customers are low-income, and they should not have to choose between paying for electricity and other critical expenses such as health care, she said.
The model of billing energy consumers purely based on the amount of electricity they use is becoming obsolete, Williams said. “That model is fundamentally at risk at this point.”
Many electric consumers are also producers, as behind-the-meter and distributed resources grow. Retail energy sales in the future “may very well likely not be a one-size-fits-all,” she said, similar to how mobile phone users have different data plans because they have widely different needs. This could entail using a tiered approach, service and access charges and new incentives for capital investment.
It is important that regulators and lawmakers put the right policies in place to implement new technologies and practices in an affordable way, Williams said, adding that “affordability is a strategic imperative to us.”
The country’s generation and distribution systems “are really undergoing a period of very dramatic change,” Nuclear Energy Institute CEO Maria Korsnick said. She contended that nuclear, particularly small modular reactors, should play a role in maintaining clean and affordable energy.
“Small modular reactors could be game-changers in many respects,” Korsnick said, providing smaller increments of power compared with a large central station plant and giving utilities more discretion in meeting demand. Modular reactors can also bring off-grid power to remote places and cycle up and down like a natural gas plant — but with no emissions.
In Pennsylvania, distributed resources are “popping up as a result of new opportunities,” Public Utility Commissioner John Coleman said. The agricultural sector is learning that biodigesters can help manage waste products while producing electricity. The question is to how to compensate these new resources.
As for the traditional ratemaking model: “Maybe it is at risk,” Coleman said. “Maybe it is time to start thinking of some of these things in a different way.”
The Pennsylvania PUC is surveying industry on new compensation approaches and ways to incentivize investment. He noted that the majority of the state’s consumers are served by competitive suppliers and electricity rates have dropped by about 30%. Natural gas plants are also rapidly replacing coal-fired units in the state.
Other than distributed resources, utility-scale generation is also changing, according to Ohio Public Utilities Commissioner Beth Trombold. The state has a potential 8,000 MW of new gas-fired generation coming online, with four gas plants under construction, one certified and four more under review. There is about 1,200 MW of new wind and 400 MW of new solar waiting in the wings, which will greatly increase the amount of renewables in the state.
Ohio is also in the middle of a grid modernization program and asking, “What kind of regulations and technological innovation are out there to enhance the customer-utility relationship?” Trombold said.
California Public Utilities Commission Chairman Michael Picker said that integrating renewables in the state has not been as challenging as was feared, and it is now more important to consider where they are placed.
Legislation is in the works in California to achieve a zero-carbon electricity grid by 2045 and the state recently extended its cap-and-trade program to 2030. (See California Lawmakers Extend Cap-and-Trade.)
“At this point, it’s not about getting more, it’s what you get, where you get it … and when it’s available,” Picker said of renewable generation. The state is experiencing lower electricity demand overall but higher peaks. The PUC is moving away from “silos” in terms of what kind of resources are put on the grid, but back to an integrated resource plan model, he said.
In terms of reducing greenhouse gases, more of the transportation sector must be electrified, he said. The transportation sector emits 40% of GHG in the state; gas for heating and other uses emit about 30%, while just 20% is emitted from the electricity generation.
CAISO will lean heavily on increased output from conventional generators — and a backstop of regulation reserves — to fill the void left by reduced energy production from California solar resources during next month’s solar eclipse.
The grid operator estimates that about 4,194 MW of utility-scale solar will fall off the system from the time the moon begins to pass in front of the sun (9 a.m.) to the moment of peak obscuration (10:22 a.m.) during the Aug. 21 event.
Graph shows a comparison between CAISO’s Aug. 21 eclipse load forecast compared with that for full-sun conditions. | CAISO
At the peak, grid-connected solar generation will come up about 5,600 MW short of what would be expected under full-sun conditions. Net load will surge to about 6,000 MW above normal because of diminished output from rooftop installations.
But the grid operator has been preparing its response since last year. (See With Solar Eclipse Looming, CAISO Weighs its Options.) After a winter of ample precipitation, “large and fast-moving” hydroelectric resources are being positioned for rapid response during both the loss and return of solar, according to Deane Lyon, a CAISO real-time operations shift manager.
Planners are also banking on gas-fired generators to help cover the gap.
“We’re actually working with Pacific Gas and Electric and [Southern California Gas] and coordinating with their gas control centers because, besides the hydro, the gas-fired thermal is going to have to make up for a lot of the loss of solar generation,” Lyon said Tuesday during a bimonthly Market Performance and Planning Forum.
The ISO will also procure about 900 to 1,200 MW of regulation up reserves for the three-hour period affected by the eclipse — compared with a typical procurement of 300 to 400 MW.
“That’ll help us manage as the solar goes away,” Lyon said.
Lyon noted that CAISO has been consulting with Western Energy Imbalance Market (EIM) participants to develop a “consistent policy” regarding transfer service requests (ETSRs) — or dynamic transfers across balancing areas — during the eclipse so that the ISO can take advantage of imports to the greatest extent possible.
“We got commitments from the operations folks at the EIM entities that they’re willing to keep the ETSRs wide open and fully operational for the balance of the eclipse,” Lyon said, acknowledging that the ISO does not expect a “huge” uptick in transfers given that Arizona Public Service and NV Energy will also be losing solar off their systems at about the same time.
On the flip side, the eclipse is not expected to actually undercut imports.
“APS has solar, but not PacifiCorp,” Lyon said. “We don’t expect it will have that big of an effect.”
Paula Lipka, of PG&E’s short-term electricity supply team, asked if the ISO intends to increase its procurement of flexible ramping and spinning reserves — as well as regulation.
“An increase in flex ramp procurement is being considered. As far as spinning and non-spinning reserves, we will have adequate amounts of that,” Lyon responded.
Regulation reserves are the ISO’s key concern.
“We’re trying to maintain our system balance for the duration of the sun going away and returning, which is going to be a pretty big challenge,” Lyon said.
SPP is accepting applications from industry experts to serve on an independent panel reviewing the RTO’s 2018 competitive transmission construction proposals.
The panel will review, rank and score proposals for competitive projects under FERC Order 1000. The previous two panels recommended one such project — a 22.6-mile, 115-kV line from Walkemeyer to North Liberal in southwest Kansas. However, the project was withdrawn because of decreased load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)
| Westar
Interested candidates must have expertise in at least one of the following transmission-related areas:
Engineering design;
Project management and construction;
Operations;
Rate design and analysis; or
Finance.
SPP will accept applications through Sept. 1 and choose panelists later this year based on recommendations by the RTO’s Oversight Committee, which must be approved by the Board of Directors. Selected panelists will be considered contractors and will be compensated through a monthly retainer and hourly rate.
Panelist applications, instructions and more information can be found on SPP’s website or by contacting Ben Bright, the RTO’s regulatory processes manager.
DENVER — SPP’s Z2 Task Force will likely soon be a relic of the past, but the issues with financial credits and obligations for sponsored transmission upgrades that spurred the creation of the group aren’t going away.
The Markets and Operations Policy Committee last week endorsed the task force’s request to conclude its work. Minutes later, SPP staff told the committee the RTO would have to resettle nine years of historical Z2 credits and obligations because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances.
SPP last fall identified about $200 million in revenue credits to be collected for transmission upgrades under its Tariff’s Attachment Z2, which details how to reimburse sponsors of network upgrades. The bills covered eight years of credits and obligations for 2008-2016, when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)
SPP’s Charles Locke said the resettlement results will be similar to last year’s processing and stressed they will not produce duplicate or additional charges.
“What you pay or owe is only the difference between the original settlement and the resettlement,” he said.
However, Locke could provide few details beyond that. “Generally, the amounts will be small. I’m reluctant to say how small,” he said.
That drew pushback from members, some of whom could recall early staff estimates of $50 million for creditable transmission upgrade projects, which eventually ballooned to nearly $850 million in assigned costs. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)
“Is there a number by what you mean by small?” asked ITC Holdings’ Marguerite Wagner. “It’s hard for me to understand what that actually means.”
“SPP assured us for years the amounts for Z2 were small, until they actually did the billing,” said Southwest Public Service’s Bill Grant. “I don’t get a lot of comfort when you say the amounts will be small. I do understand the reason, but it still tends to create regulatory issues for your members when they go back [to their commissions] and say, ‘Whoops! The calculations weren’t correct, so we’ll have to adjust it either up or down.’ It’s starting to get really painful.”
SPP COO Carl Monroe suggested that members focus on the difference between last year’s invoices and this year’s.
“What’s more important is the deltas,” he said. “We won’t know the deltas until we know the details of the resettlement. We won’t know the details until we go through the actual resettlement.”
Locke said staff intends to provide preliminary resettlement results in September, so members “at least have some indication of the numbers.” Staff will in September begin reprocessing data from March 2008, adding the months through July 2017. It hopes to post updated invoices in October to keep up with a timeline approved last year.
While chairing the Strategic Planning Committee on July 13, Golden Spread Electric Cooperative’s Mike Wise asked Locke whether the resettlement would be SPP’s last.
“We’re certainly hoping so,” Locke responded. “The last resettlement of historic data.”
In accepting the Z2 Task Force’s recommendation to let its charter expire, the MOPC also approved two recommendations from the group, with nine “no” votes (out of a potential 95 votes) and two abstentions. The first eliminated credits for non-capacity upgrades, such as substation facilities, while the second disposed of credits for short-term transmission service of less than a year.
The task force also reviewed the use of incremental long-term congestion rights (ILTCRs) as a substitute for Z2 credits — a practice by other RTOs — but was unable to reach consensus. The group said “significant concern” was expressed over SPP’s existing congestion rights processes and the “perceived lack of hedging.”
“Existing customers may prefer the risk of waiting on cash recovery versus getting ILTCR’s, which may have limited value in the future,” according to the task force’s recommendation to the MOPC.
“We feel like at this point in time, the task force has done what it can about whether or not there is something else we can do to reduce the burden of Z2 and replace it with something else,” the task force’s chair, Kansas City Power & Light’s Denise Buffington, told the MOPC. “After many, many, many meetings, we could not get to a decision on the underlying policy or whether to socialize those costs. Unfortunately, we are where we are.”
American Electric Power’s Richard Ross, who likes to hand out gold stars to his fellow stakeholders, said he was awarding Buffington a “Richard Ross Gold Star for Cat Herder of the Year.”
MOPC Suggests 1-MW Threshold for Network Load
It came down to a single vote, but the MOPC offered direction to the Regional Tariff Working Group on how to address “inconsistency and uncertainty” over which behind-the-meter generation qualifies as network load.
The committee directed the RTWG to use a 1-MW threshold for reporting network load and to develop a list of inclusions and exclusions. In a roll-call vote, the last member to record its vote pushed approval of the motion from 65% to 66.2% — just above the 66% necessary for passage.
For customers taking network service, SPP currently follows FERC policy that sets all load at discrete delivery points as network load, which effectively sets the threshold at 0 MW for load served by BTM resources.
“At least this gives some guidance to MOPC,” Monroe said, alluding to the difficulties the RTWG has had in tackling the issue.
“If so, then make every member of the MOPC charter members of the [RTWG’s] Billing Determinants Task Force, because that is what we spent two and a half years discussing,” said Oklahoma Gas & Electric’s David Kays, who chairs the RTWG. “If 10 members were in the room, we had 10 different exceptions. If 15 members were in the room, then we had 15 different exceptions.”
The RTWG, through the BDTF, has been working on the problem since 2014 and has haggled over two revision requests (RR158 and RR 232). The task force developed the first and defined network load to include load served by certain BTM generators at discrete delivery points, while excluding load served by other BTM generators where load is shed automatically. The second revision request was developed with input from the SPC and excluded load served by a BTM generator or group of generators totaling 1 MW or less.
Members were never able to reach consensus on the proposed Tariff language. The RTWG in June rejected RR158 and RR232.
“We spent significant time on RR232 trying to cover as many issues related to behind-the-meter generation as possible,” said BDTF Chair Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission. “Different people interpret the Tariff provisions related to network load … differently. Maybe it’s not so straightforward to some folks.”
The RTWG will bring back its list of exclusions and inclusions to the October governance meetings. Assuming clarity and approval of the network load list, Starnes said, the RTWG will then develop Tariff language once again subject to the stakeholder process.
“This is a need, an immediate need,” Wise said. “I think there may be some cross-subsidization going on because of the way the network load is actually reported. I want to make sure we have consistency across the entire footprint and where the whole load gets reported accurately, because we do have substantial costs paid by the network load. All these loads need to pay their fair share of those costs.”
Staff to Review AECI Joint Project After Cost Increase
David Kelley, SPP’s director of interregional relations, told members he would spend this week reviewing an alternative to a previously approved transmission project that recently saw a 50% cost increase.
The joint project with Associated Electric Cooperative Inc., originally estimated at $9.2 million, was endorsed by the MOPC and SPP Board of Directors in January and included in the RTO’s 2017 Integrated Transmission Planning 10-year assessment. It involves installing a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield, Mo.
“As luck would have it,” Kelley said, AECI notified him July 7 that it raised the project’s cost estimate to “just shy of $14 million.” Because the costs increased more than 20%, the parties can revisit the initial cost-sharing agreement.
“We had another alternative that wasn’t a seams project. It provided comparable benefits but, at the time, significantly more expenses,” Kelley said. “I’d like to spend the next few days making sure we’re still making the right decision.”
Kelley said if his revised analysis is not ready for the July 25 board meeting, he will present it during the October governance meetings.
The Morgan project would be regionally funded, as it solves congestion issues on SPP’s side of the seam, and is contingent on reaching an agreement for compensating AECI. SPP was to assume responsibility of $8.7 million of the original cost estimate. AECI will own the project and be responsible for its construction, operations and maintenance.
MWG to take Another Shot at MWP Manipulation
Members remanded back to the Market Working Group a previously rejected revision request (RR221) that addressed potential manipulation of make-whole payments (MWPs) related to mitigated energy offers and no-load offers for resources with a three-day minimum run time or greater.
RR221 would have added language that establishes a permissible percentage threshold above the mitigated offer at the time of the original commitment. Ross, the MWG’s chair, said that as structured, RR221 would force SPP to report to FERC’s Office of Enforcement deviations as little as a penny.
“Monitoring is not always clear and concise,” Ross said. “We have concerns with moving forward with that request. There’s no room for error when updating offers for fuel-price changes, and the burden of implementation is on the market participants to run the calculations. You could be one penny over the line because of a rounding error. You could violate the Tariff without any impact to the market.”
“There has to be a bright line. Yes, it’s a violation, but let’s exercise some judgment first,” he said. “It’s been my experience with manuals and protocols that … they’re nice guidance, but if you get to a circumstance where [they have] to be enforced, they don’t carry the same weight.”
Staff and members, in agreeing to send RR221 back to the MWG, said the issue was more of a market design problem.
“Let the market design experts take another shot at this,” said Midwest Energy’s Bill Dowling. “I’d prefer to see them deal with this issue one more time. Maybe there’s a way to navigate this.”
Wind Integration Study’s Recommendations Move On
The MOPC unanimously approved staff study recommendations for how much wind energy the SPP system can reliably absorb. The RTO has routinely broken the 50% penetration level for wind and has said it can go even higher. (See SPP Eyes 75% Wind Penetration Levels.)
SPP set a record for North American RTOs in April when wind energy served 54.47% of its load — 58.67% with the addition of solar and hydro. The RTO had 15.7 GW of installed wind capacity when the study began last year and currently projects 17.2 GW by the end of 2017.
Casey Cathey, SPP’s manager of operations analysis and support, said wind has exceeded 50% penetration several times and exceeded that mark for hours at a time.
“We’re meeting all NERC standards, but there are things out there we can continually improve on,” he said.
Last year’s Variable Generation Integration Study (VIS) stressed the transmission system to a point of instability, identifying reliability impacts during high-wind and low-load scenarios. Staff analyzed 45% and 60% wind penetration levels and examined transient stability, frequency response, voltage stability and a targeted five-minute ramping.
The VIS recommends seven solutions and improvements to increase reliability, including the installation of online transient-stability and voltage-stability analysis tools. Staff has estimated the software will cost a combined $3.2 million.
Members OK Re-baselining Out-of-Bandwidth Projects
Members unanimously approved re-baselining four out-of-bandwidth projects, three of which were a combined $95.5 million less than original estimates once project owners lowered material, engineering and construction costs through more accurate data.
One estimate, an OG&E 500/161-kV transformer project, went from $15.1 million to $25.6 million because of an increase in internal costs, unforeseen site work and the need to keep the 161-kV lines energized throughout the project.
All four projects were regionally funded, with operating voltages of greater than 100 kV and cost estimates of more than $20 million. (The OG&E project was a legacy project.) They became eligible for re-baselining when their updated cost estimates exceeded the +/-20% variance bandwidth after receiving notifications to construct.
MOPC Approves 9 Revision Requests
The MOPC approved a modified two-year-old revision request (RR82) that ensures combined cycle units do not lose eligibility for start-up cost MWPs because of a physical or environmental limitation, avoiding outage deviation penalties in the process.
RR82 adds a previously discussed increase in the MWPs’ grace period for commitments from one hour to two. The revision’s implementation date was scheduled for this August to allow SPP to complete development of software that allows market participants to register and submit separate offers for combined cycle units’ multiple configurations.
Final approval of the revision request is contingent upon the Regional Tariff Working Group’s endorsement of Tariff language changes. RR82 was approved by the MOPC and board in October 2015, but staff identified the additional changes while developing the FERC filing letter.
The committee approved eight other revision requests as part of its consent agenda, which passed unanimously:
MWG-RR185: Clarifies which SPP criteria document (Planning Criteria or Operating Criteria) is referenced when used in the market protocols and the Tariff’s Attachment AE, and correctly directs users to the specific document.
MWG–RR210: Changes the process for testing a contingency reserve deployment (CRD) by adding a deployment test instruction issued in conjunction with the out-of-merit energy dispatch, allowing sufficient time to review test results and provide accurate data. Also changes SPP’s communication of the CRD’s test results from 60 minutes to within one business day. Should a resource retest be requested, SPP agrees to complete the test within two business days, subject to its assessment of system stability.
MWG-RR222: Includes a multiconfiguration combined cycle resource’s (MCR) committed and actual configuration for each interval in a bill determinant report, allowing MCRs to shadow the configuration SPP is using to settle these resources.
MWG-RR225: Cleans up confusing and misleading Tariff language on incremental long-term congestion rights (ILTCRs) that could construe ILTCRs as load-serving entities or non-LSEs.
MWG–RR226: Changes settlement location pairs that have potential for unconstrained flow to electrically equivalent settlement locations during the auction revenue rights process, to comply with a FERC order (ER17-310). SPP will post the settlement locations before the annual ARR allocation process, along with the system topology and other data.
MWG-RR229: Satisfies FERC Order 831’s requirements on energy offer caps by using actual costs for make-whole payments on offers above $1,000/MWh. According to the order, costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used to calculate LMPs.
ORWG-RR228: Clarifies existing planning criteria language for system operating limits to reduce the potential of misinterpretation by entities complying with NERC reliability standards.
RTWG-RR233: Ensures that eligible network customers will not be billed twice for the same delivery. Customers will also not be assessed charges against a specific use of a single owner’s facilities that do not receive the benefit those charges provide to other transmission owners under the Tariff. The Southwestern Power Administration (SPA) and SPP have entered into a contract (Attachment AD) that provides for SPP to offer transmission service on SPA’s facilities, including network integration transmission service (NITS), and allows SPA to participate in the RTO’s transmission planning. SPA also voluntarily contributes to Schedule 11 representative of the grandfathered transmission service agreements (GFAs) it has in place for non-federal uses of its transmission facilities. SPA and SPP are transitioning customers with GFAs to NITS under the Tariff, creating implications for new customers who also receive federal hydropower deliveries.
The consent agenda also included:
Modifications to the revamped revision process, adding the Integrated Transmission Planning Manual and certain technical documents to the approval process. (See “Changes Proposed for Revision Process,” SPP Markets and Operations Policy Committee Briefs.)
A waiver request to FERC restating settlement prices for transmission congestion rights (TCRs) at Omaha Public Power District’s Fort Calhoun nuclear plant site. The plant was retired Dec. 1, 2016, but incorrect modeling of shift factors from Dec. 1 to Dec. 14, 2016, resulted in the marginal congestion component being overstated and the TCR settlements sourcing at the location being understated.
MISO last week presented stakeholders with a proposal to tighten rules on capacity imports amid uncertainty over whether a recent appellate court ruling will impact FERC’s ability to approve the changes.
In early July, the D.C. Circuit Court of Appeals eliminated portions of PJM’s minimum offer price rule that have been in place since 2013, ruling that FERC overstepped its authority when it suggested changes to a PJM proposal that resulted from a compromise among stakeholders. The court said although FERC can make minor changes to Tariff filings, it cannot substitute its own plan and must approve or reject an RTO proposal as is. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
MISO’s proposal — which would integrate external resources zones into the Planning Resource Auction using a single clearing price for each external balancing authority — has been met with a mixed stakeholder response. As a result, some stakeholders think the RTO should hit pause on a proposed September FERC filing and continue working for a proposal that has broad support.
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FERC’s Power Diminished?
MISO Assistant General Counsel Michael Kessler said that the appellate ruling means FERC’s power may be diminished when it regains its quorum. (See related story, Trump Names Energy Lawyer McIntyre as FERC Chair.)
“It’s sort of a new package of standards. As it stands now, it’s a definite limitation on the commission’s authority to accept changes on a Section 205 filing,” Kessler said during a July 12 Resource Adequacy Subcommittee meeting.
Kessler said there is some ambiguity in the ruling on the distinction between significant changes that FERC is prohibited from suggesting and minor changes the commission can order.
“This isn’t just a PJM, MISO issue; it’s an industry issue. Any filing party will have to consider what FERC can and can’t do now since the back-and-forth that we’ve gotten used to [since the 1990s]. That route is not going to be available anymore. The whole industry will be carefully reviewing this to see the implications on filings going forward,” Kessler said. He added that all pending appeals of FERC-ordered changes could be up for reinterpretation.
Stakeholders said that with FERC expressly prohibited from ordering changes to RTO proposals, chances of the commission approving the contentious locational proposal may be smaller.
Customized Energy Solutions’ David Sapper, representing MISO’s Load-Serving Entity Coalition, said the ruling may signal to MISO that it’s time to only pursue filings with majority stakeholder support.
Last month, Sapper and the coalition made a motion to delay the locational proposal in favor of a capacity transfer rights proposal that would treat long-term supply arrangements involving external resources the same as internal planning resources. (See Changing Course, MISO Adopts IMM External Resource Zone Plan.) Stakeholders later passed the motion in an email vote 34-11 with three abstentions.
MISO Executive Director of Strategy Shawn McFarlane reminded stakeholders that the motion is only treated as advice and is not binding. He said the motion signals to the RTO that more discussion with stakeholders is needed.
“So, we think we need some follow-up conversations,” he said. “We’ll be reaching out to stakeholders over the next few weeks. … We think some one-on-ones is going to be appropriate.”
McFarlane added that MISO will be making sure that the stakeholders that voted in favor of the motion understand the locational proposal; he said it would look for some possible modifications as well.
Asked if FERC would reject the filing without consensus among MISO and its stakeholders, McFarlane said it was too early for speculation and that the RTO still has time to alter its proposal.
Combined Filing Likely
Indianapolis Power and Light’s Ted Leffler asked if MISO has considered filing the locational proposal separately from hedging rules so the external location zone filing is not rejected based on its proposed approach on allocating excess auction revenues.
MISO has proposed that auction revenues be first handed to resources with historical commitments, with pre-RTO formation capacity arrangements and pre-locational capacity arrangements given first consideration for funding. External resources with contracts to MISO load affected by the proposal are next in line before the RTO doles out revenues as usual using an existing zonal deliverability benefit assessment.
McFarlane said MISO has considered separate filings but is still leaning toward a combined filing.
Leffler asked how many external capacity resources will become unmarketable because of a low clearing price and the lack of a historic capacity agreement.
“I think it’s important that we understand how much is at risk here,” Leffler said. “The auction clearing prices are very sensitive to changes in supply and demand.”
“We don’t feel like we have a choice but to address the potential reliability issue from our current approach here,” McFarlane said. He added that MISO is eyeing a “reasonable” approach that can win FERC approval.
Some stakeholders are still asking MISO for more details on how external resources are treated based on geographic distance from the RTO’s footprint. They asked that prices be based on a resource’s proximity to loads inside MISO instead of a uniform external balancing authority price.
Laura Rauch, MISO manager of resource adequacy coordination, said that except for resources near a border, the RTO sees no difference in deliverability in resources situated “150 miles away from MISO or 300 miles from MISO.” Its concern is whether a resource in Chicago or New Jersey can deliver against Lower Michigan’s clearing requirement “as well as a Detroit resource,” she said.
VALLEY FORGE, Pa. — The Planning Committee last week approved PJM’s recommendation to use 10-year historical data from 2003 to 2012 and to change the “world” peak week in its 2017 reserve requirement study.
PJM’s Patricio Rocha-Garrido told stakeholders the RTO decided to separate its peak load from that of the “rest of world” because of software limitations. Coincident peak distributions from the PJM load forecast cannot be used directly in its PRISM (probabilistic reliability index study model) software, which handles model uncertainty by week rather than day-by-day.
“The world” comprises of neighbors MISO, New York, the Tennessee Valley Authority and SERC Reliability’s VACAR region in Virginia and the Carolinas — areas from which the RTO would seek to import generation if it runs short.
“When we have PJM and ‘the world’ peaking on the same week, effectively we’re having PJM and ‘the world’ peaking on the same day,” Rocha-Garrido said.
However, over the past 18 years, PJM and “the world” have peaked simultaneously eight times, while they have not peaked together 10 times.
In response, PJM moved the world peak to Week 11 in the summer and retained its peak on Week 10 to match the “historical diversity” in peaks.
Rocha-Garrido said the 2003-2012 load model, which was also used in last year’s study, was “a close second place” to the top-ranked 2004-2012 time period but had the advantage of an extra year of data.
“We do not see evidence to change that this year,” he said.
The recommendation was endorsed by acclamation, with no objections or abstentions.
RTEP Cycle Revisions Approved
The committee approved revisions to the rules for the Regional Transmission Expansion Plan, agreeing to extend the cycle from one year to 18 months.
PJM’s Amanda Long said the planning cycle will begin in September and run through February of the following calendar year. A new cycle will begin every September, overlapping the previous cycle. (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)
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The committee also approved Operating Agreement changes to extend the 30-day competitive proposal window for short-term projects to 60 days beginning about June annually. The long-term proposal window will remain at 120 days.
The proposal was endorsed by acclamation, with no objections or abstentions.
PJM’s Mark Sims explained how the RTO’s recent focus on resilience will impact its planning processes.
NERC’s standards require PJM to consider in its planning critical “stressed” conditions so it can manage the system regardless of actual conditions on any day. In addition, NERC requires the RTO to conduct a system assessment and explore potential solutions of low-probability “extreme” events.
As a result, Sims said, PJM will seek to identify “worst offenders,” such as circuits that frequently are involved in low-probability events. (See “PJM Reconsidering Planning Assumptions,” PJM Planning & Tx Expansion Advisory Committees Briefs.)
“It’s not involved in one low-probability event; it’s involved in many. So in my opinion, it’s no longer low-probability,” Sims said, adding that it “might” make sense to fix these issues.
John Farber of the Delaware Public Service Commission reiterated his concerns from a similar conversation during the Operating Committee meeting earlier in the week.
“There are major issues with implementing resilience as a standalone driver in the RTEP,” he said. “Achieving a sufficient level of objectivity to justify its inclusion as a standalone driver in the RTEP is just a difficult challenge to deal with.”
He said it will be difficult to develop objective cost and benefits criteria to justify millions in spending, especially when individual states may have different viewpoints on spending the money.
Greg Poulos of the Consumer Advocates of the PJM States agreed. Developing appropriate metrics will be important to determine how goals will be achieved, he said. The timeline is another issue, he said.
“There’s a lot of concern about things adding up,” he said. “I certainly agree it’s an evolution, but the consumer advocates are concerned it’s a slippery slope. Where does it begin and where does it end?”
Sims assured stakeholders it would be a “very deterministic” process. “I think this paradigm is going to be a little bit of a shift,” he said.
Winter Evaluation
PJM’s Tom Falin provided an update on the RTO’s analysis of winter resource adequacy and capacity requirements, the subject of an issue charge approved by stakeholders last year. The details highlighted the differences across the RTO. (See “Winter Resource Adequacy Analysis Raises Questions,” PJM Planning & Transmission Expansion Advisory Committee Briefs.)
An analysis of the ratio between the winter and summer peaks in each locational deliverability area (LDA) found that the East Kentucky Power Cooperative was the heaviest winter peaking LDA in the RTO, with a winter-summer ratio at about 1.3. The RTO itself is mostly summer peaking with a ratio of .87, and Rockland Electric is the heaviest summer-peaking LDA with a ratio of about .59.
“The heaviest summer-peaking LDAs are basically [in] New Jersey,” Falin said.
The loss-of-load expectation analysis results found that, even including the outliers from the winter of 2014-15 that included the polar vortex effects, and assuming historical forced outages and the maximum historical planned outages, the LOLE was .02 days/year. Falin noted that these numbers only included generator forced outages and that transmission outages would need to be considered as well.
Going forward, Falin said PJM will compute summer and winter reliability requirements for the RTO and selected LDAs while continuing to investigate a winter load forecast model.
Solar Capacity Factors Class Averages
PJM has updated its capacity factors for wind and solar based on actual summer data from 2014-2016.
PJM’s Jerry Bell said the analysis found that wind turbines have a capacity factor of 14.7% in mountainous terrain during peak summer hours between 3 and 6 p.m. and 17.6% in open, flat terrain during the same period. Solar capacity factors ranged from 60% for ground-mounted arrays that track the sun, to 42% for fixed ground-mounted panels, to 38% for all panel types other than ground-mounted.
The capacity factor affects generators’ capacity revenues and a project’s entitlement to capacity injection rights.
Renewable developers can request higher capacity factors for their projects if they can provide evidence to prove their generators operate at higher levels.
The study hasn’t yet considered how capacity factors are affected by degradation of the equipment over time, but Bell said it will be added in the future. Several stations were removed from the analysis because they displayed obvious degradation over time, he said. Degradation is, however, factored into CIRs for stations, he said.
Transmission Expansion Advisory Committee
Transmission Proposal Window Opens
PJM opened a 45-day window last week seeking proposed transmission projects to fix reliability criteria violations on 43 flowgates. The window will close on Aug. 25.
The flowgates were identified in the 2022 analysis: 34 in PJM’s Western Region, six in the Southern Region and three in the Mid-Atlantic Region. The remaining 161 flowgates from the analysis were excluded from the window as either immediate-need projects or under 200 kV, which is PJM’s threshold for opening projects to competitive bidding. The RTO has found that projects under 200 kV tend to be upgrades handled by the incumbent transmission owner.
Updates to AI Analysis
Staff have updated PJM’s beneficiary analysis for the Artificial Island project to address issues raised by stakeholders at the June 9 special Transmission Expansion Advisory Committee meeting. Among the additions was a list of transmission facilities that could compose a stability interface.
Most of the $280 million bill for the project would shift from Delaware to New Jersey and Pennsylvania under two alternative methodologies outlined in the analysis. But it will be up to PJM’s TOs to petition FERC to adopt a new methodology for the project. “PJM does not have the authority to devise or file allocation methodologies as federal law makes clear that the Section 205 filing rights over rates and cost allocation in this area rests with the PJM transmission owners,” the report says.
The project, PJM’s first foray into competitive bidding under FERC Order 1000, has been bogged down in stakeholder infighting for years. In April, PJM’s Board of Managers lifted a suspension on the project and re-awarded it to LS Power. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
