California officials Thursday cleared the Aliso Canyon natural gas storage facility to resume injections, even as momentum builds among lawmakers, regulators and the public to permanently close the site of the massive methane escape near Los Angeles.
The methane leak caused by a broken pipe casing at the 86-Bcf storage facility owned by Southern California Gas was discovered in October 2015 and plugged in February 2016.
State engineering and safety officials said that after months of “rigorous inspection,” they “have concluded the facility is safe to operate and can reopen at a greatly reduced capacity in order to protect public safety and prevent an energy shortage in Southern California,” according to the California Public Utilities Commission. State legislation required the PUC and Division of Oil, Gas and Geothermal Resources to clear the facility for operation before gas injections could resume there.
PUC Executive Director Timothy Sullivan said: “After careful review of testing results, our safety teams have confirmed the integrity of the wells at this facility. Out of an abundance of caution and consideration for public safety, storage capacity will be restricted to approximately 28% of the facility’s maximum capacity — just enough to avoid energy disruptions in the Los Angeles area.”
Aliso Canyon Well Head | Earthworks
State Oil and Gas Supervisor Ken Harris issued an order laying out testing requirements at the facility after injections resume. About 60% of the wells at Aliso Canyon have now been taken out of operation and isolated from the facility, and remaining wells were cleared during testing, officials said. Active wells now have real-time pressure monitors and will be subject to aerial monitoring. The wells also have new steel tubing and seals.
The finding came the same day the head of the California Energy Commission wrote PUC Chairman Michael Picker, calling for the facility to be permanently closed. He said Gov. Jerry Brown asked him to make plans for the facility to be permanently shut down.
“My staff is prepared to work with the CPUC and other agencies on a plan to phase out the use of the Aliso Canyon natural gas storage facility within 10 years,” CEC Chairman Robert Weisenmiller said in the letter.
Weisenmiller said that closing the facility “is no small task and the recommendation to close the facility is not one that I take lightly or without thoughtful consideration.” But he said reliability worries could be addressed through investing in renewable energy, energy efficiency, electric storage and other tools.
SoCalGas welcomed the decision in a statement Thursday. The company had warned of reliability concerns stemming from the loss of the facility and in November 2016 requested permission to resume injections.
State Senator Henry Stern: “There is no rush to re-open Aliso Canyon”
“Aliso Canyon is an important part of Southern California’s energy system, supporting the reliability of natural gas and electricity services for millions of people. SoCalGas has met — and in many cases, exceeded — the rigorous requirements of the state’s comprehensive safety review,” the company said.
On Wednesday night, State Sen. Henry Stern (D) tweeted that the “proposal to re-open #AlisoCanyon before we know what caused the leak and before earthquake and fire risks studied is premature & unnecessary.”
DENVER — As it comes to grips with the migration of 430 MW of West Texas load to ERCOT, SPP is confronting the possibility that as much as 1,300 MW of additional load could leave its system.
SPP members are encouraging the RTO to explore the reasons for the departures — and how to prevent them.
East Texas member Rayburn Country Electric Cooperative last month opened a project with the Public Utility Commission of Texas to “identify issues pertaining” to transferring its load and portions of its facilities into ERCOT (Docket 47342).
Despite its membership in SPP, only 15 to 20% of Rayburn Country’s load (about 150 MW) sits in the Eastern Interconnection. ERCOT estimates it will cost $38 million — primarily for a new 345-kV substation, a 138-kV switching station and the expansion of several 138-kV lines — to connect the co-op’s SPP load with the Texas Interconnection.
Rayburn Country owns and operates 160 miles of transmission in SPP, of which it proposes to move 130 miles into the ERCOT footprint, adding to the 207 miles of lines it already owns there.
The co-op determined that consolidating its load into ERCOT will give it access to “a more liquid and competitive wholesale power market, improved reliability, and elimination of cross-grid issues such as multiple NERC reliability standard audits and differing regional practices.”
An SPP task force has identified several other potential Texas entities with a medium-to-high risk of transferring an additional 1,100 MW of load into ERCOT, not including Lubbock Power & Light and the aforementioned 430 MW.
At its recent annual retreat, SPP’s Strategic Planning Committee considered whether it should “develop incentives or other mechanisms” to prevent future member migrations, Vice President of Process Integrity Michael Desselle said last week during an SPC meeting.
Who Pays?
“The strategic issue of who pays for what is actually fairly important,” said Oklahoma Gas & Electric’s Jack Langthorn, who chaired a task force studying the implications of LP&L’s departure. “When you lose load, should the costs go with it? When entities come in or leave, who pays for what?”
“These strategic questions remain and won’t go away,” said SPC Chair Mike Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy. “The lack of [retention] incentives we have in SPP needs to be resolved.”
The costs would be significant for Golden Spread and Southwestern Public Service, which currently serves Lubbock’s load.
A recent joint study between SPP and ERCOT indicates that the transfer of LP&L would increase annual transmission revenue requirement (ATRR) payments for 17 of SPP’s 18 transmission zones by an average of 1.3%. Zonal rates in the SPS zone would decline about 9.3% because of an approximate 10% drop in load, but the zone’s remaining load would see a regional-allocation increase similar to other SPP zones on a cost-per-megawatt basis, or $217/MW.
“What we’re really talking about is $14 million being reallocated within the SPS zone,” said Bill Grant, SPS’s regional vice president of regulatory and strategic planning. “It’s not insignificant by any means.”
“I am a big load inside the SPS zone. If this load leaves the zone, it increases my [transmission] costs,” Wise said.
Dueling Studies
SPP and ERCOT performed production-cost analyses for the years 2020 and 2025 to evaluate the effects of moving part of the LP&L system. SPP would see fuel costs drop $64 million to $86 million in its footprint and $61 million to $89 million in Texas in 2020. Those ranges increase to $71 million to $105 million and $68 million to $113 million, respectively, in 2025.
ERCOT’s portion of the study found its production costs would increase as much as $77 million in 2020 and $74 million in 2025. The ISO says that increase will be offset by using the LP&L interconnection to unlock wind energy currently trapped in the Texas Panhandle. (See “LP&L Study: Production Costs Increase,” ERCOT Board Briefs.)
| ERCOT
The Texas grid operator last year conducted a separate study showing it will cost $364 million to integrate LP&L, mostly through construction of 141 miles of new 345-kV lines. SPP’s study found it would need to spend $5.1 million on additional transmission projects to compensate for the loss of LP&L’s load, but another $1 million of upgrades could be deferred or avoided.
ERCOT’s study found the new facilities would increase grid stability in the Panhandle, while SPP determined any reliability concerns could be mitigated. The joint study predicted “minimal impacts” on ancillary service procurement quantity and markets, and on congestion rights and their markets.
LP&L announced in 2015 that it planned to disconnect its load from SPP and join ERCOT in June 2019 (Docket 45633). The PUC last summer asked the grid operators to conduct coordinated studies focused on a cost-benefit analysis for ratepayers. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
Grant encouraged the SPC to compare the two studies and “really start digging into the issues of why an entity might want to leave. There’s no better way to put it than Tariff arbitrage. That’s what it is.
“I don’t know what you can do to stop that,” Grant said. “If there are any savings to an individual entity, it’s the way they’re treated under their individual tariffs. If [zonal placements don’t happen fairly], you don’t get the added value of having transmission requirements in your zone.”
LP&L said it will next month file a contested case with the PUC slated to begin in May 2018 and has asked the commission to discuss the matter during its July 28 open meeting. The municipality said this timeline would allow it to successfully integrate with ERCOT before a “bridge agreement” extending its SPS power contract expires in May 2021.
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.
| ISO-NE
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).
| ISO-NE
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.)
| MISO
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.
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.)
| PJM
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.)
