Electricity customers in Los Angeles County will soon have the option to purchase their power from a new publicly run supplier that will obtain more of its energy from renewable resources.
The county’s Board of Supervisors voted 5-0 on Tuesday to establish a community choice aggregator (CCA) that will directly compete with Southern California Edison for the region’s retail, commercial and industrial customers.
The supervisors authorized initial spending of $10 million to launch the Los Angeles Community Choice Energy (LACCE) Authority, with 80% of those funds slated for procuring power, and the balance used for covering administrative costs.
The new CCA will serve electricity users in the county’s unincorporated areas, as well as incorporated cities without a municipal utility, such as Long Beach, South Pasadena and Torrance. Customers in participating areas will be automatically enrolled in the program but can opt out and maintain service with SoCalEd.
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Customers of the municipally owned Los Angeles Department of Water and Power, Pasadena Water and Power and Burbank Water and Power will not be eligible to make the switch.
The motion voted upon by the board said the initiative will “bring significant environmental and financial benefits to the region, and reflects the growing state- and nationwide trend toward providing customer choice in the provision of electricity.”
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A report presented to the board last year showed that a countywide CCA would be financially viable and could provide customers power that is cheaper and “significantly greener” than that delivered by SoCalEd, an investor-owned utility serving much of the region. The county would aim to purchase 50% its energy from renewable resources, nearly double that of SoCalEd. That would reduce countywide greenhouse gas emissions by 850,000 metric tons — or 9%, the county estimates.
“There are few, if any, single actions that the county could take that would have such a large and immediate impact” on the environment, the county’s Chief Executive Office said in a report issued earlier this month.
SoCalEd said it maintains a “neutral” position on CCAs.
The county expects to roll out the CCA’s operations in three phases starting in January 2018, when the LACCE Authority will begin delivering electricity to county-run facilities in unincorporated areas.
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Phase two will kick off in July 2018 with the CCA offering service for commercial, industrial and municipal customers in unincorporated areas and cities that elect to become initial participants in the authority, a move that is expected to bring on about 200,000 new accounts.
A third phase launched in 2019 would begin providing service to approximately 1.5 million residential customers.
County officials began exploring the creation of an electricity provider last year. California currently has eight CCAs, with seven more scheduled to begin operations this year. A 2002 state law enabled the creation of CCAs, which rely on the existing distribution system to deliver electricity to customers.
Growth of CCAs is one factor prompting California energy officials to reconsider the idea of instituting retail choice in the state’s electricity market, an effort that was abandoned in the aftermath of the 2000/01 Western Energy Crisis. (See California to Reconsider Retail Choice.)
TULSA, Okla. — SPP’s Markets and Operations Policy Committee approved a revision request to comply with FERC guidance on the RTO’s disparate treatment of point-to-point (PTP) and network integration transmission service (NITS) during periods of redispatch.
MRR202 would allow NITS to be eligible for auction revenue rights for limited times of the year and only for the service not subject to redispatch. NITS would not be eligible for long-term congestion rights (LTCRs), because it does not have continuous service for the entire transmission congestion rights year.
The change is in response to FERC’s September order that raised concerns that allowing network service subject to redispatch prior to necessary upgrades being constructed could result in a decrease in allocated ARRs for other transmission customers, along with their ability to nominate LTCRs. The commission ordered a Section 206 proceeding and directed SPP to limit the eligibility for network customers’ ARRs and LTCRs with service subject to redispatch. (See FERC: SPP Treating P2P Customers Unfairly on Congestion Rights.)
“Our preliminary review indicates that SPP should not provide network service customers subject to redispatch with any LTCRs until the transmission upgrades are placed into service and the service is no longer subject to redispatch,” FERC said in the order (ER16-1286, EL16-110). “The commission notes that this approach would be consistent with SPP’s rationale for not providing point-to-point customers subject to redispatch with LTCRs.”
The 206 proceeding sought to determine whether NITS subject to redispatch while necessary transmission upgrades are being constructed should warrant the same treatment as PTP. SPP responded in December, asking that it be allowed to run the issue through the stakeholder process before FERC takes action.
Stakeholders rejected SPP’s recommended approach to allow ARRs until the end of the allocation year following the revisions’ effective date. With the change, eligibility limitations only apply to new NITS service after effective date, and current NITS service is “grandfathered” to receive current treatment for the service’s term.
SPP staff said it was concerned with the network service exemption because it interprets the order to mean that FERC is exempting awarded ARRs, and future nomination processes should treat NITS and PTP similarly.
“The way we interpret it, FERC is saying any firm transmission service with redispatch should be able to nominate for ARRs or LTCRs, period,” said Richard Dillon, SPP’s director of markets. “You can’t pull them back, but you don’t issue any more.”
Enel was the lone member to oppose the motion, saying the Tariff changes should apply prospectively to FERC’s refund date of Sept. 29, 2016. It proposed its own approach to a LTCR allocation methodology, which it said would ensure firm customers not subject to redispatch are given priority eligibility.
“We believe FERC was very clear that SPP’s method of allocating ARRs and LTCRS is unjust and unreasonable,” said Enel’s Lisa Szot.
Oklahoma Gas and Electric’s David Kays, chair of the Regional Tariff Working Group, said about 75% of the stakeholders’ recommended language aligns with FERC’s directive. “Where it’s different is the next allocation period,” he said. “That’s where it deviates from FERC’s suggested language.” The working group backed the changes.
Asked why SPP did not just use FERC’s suggested language, Dillon said the commission’s language is “80% of the way there.”
“We added … a single sentence that grandfathered the historical network dispatch,” he said. “FERC found that ARRs granted to customers should not continue past the current year. We’re saying that the effective date should be as of Sept. 29, 2016, or the date FERC issued its order in this proceeding.”
Staff said the commission intends to issue a final order by May, assuming it has a quorum by then.
VALLEY FORGE, Pa. — Power demand proved difficult for PJM operators to forecast in March as a snowstorm was followed by exceptionally warm weather, RTO staff told participants at last week’s Operating Committee meeting.
“That was the story of March: a lot of up and down,” PJM’s Chris Pilong said.
The balancing authority area control error limit (BAAL) performance score dipped to 99.4%, the lowest it’s been since last March, PJM’s Ken Seiler said, with 257 excursion minutes. The BAAL was high in some cases, suggesting that plants were over-generating, he said. The longest excursion lasted nine minutes.
“This is eerily similar to what we had last year,” he said.
A 24-minute spinning event on March 23 occurred when market-to-market constraints in MISO prevented PJM from loading combustion turbines from the west, as the RTO had planned, Pilong said. PJM is looking at the event to determine which units responded and which did not, Seiler said.
PJM’s perfect dispatch performance is 76%, which is about six percentage points lower than it was at this time last year.
PJM Wants to Study Frequency Response
PJM is proposing a problem statement and issue charge to understand why many generating units either aren’t providing frequency response or are responding incorrectly to signals from the RTO.
While frequency response is essential for grid reliability, a 2012 NERC report found that only 30% of units were providing primary frequency response, PJM’s David Schweizer said. FERC published a Notice of Proposed Rulemaking on the topic in November that would require all new units, excluding nuclear, to provide the service. The commission is considering the comments it received. (See FERC Seeking Comments on Primary Frequency Response.)
In a survey of its generators last year, PJM found that, among its critical load resources — generators with a four-hour or less hot start time — just 95% have a functional governor, 75% are using NERC-recommended settings and 25% are using controls that override frequency response.
Other grid operators, including CAISO, MISO and ISO-NE, have requirements consistent with NERC reliability standards, PJM said.
The new rules, which PJM would be looking to implement for all units, would comply with NERC standards and might also include compensation, even though the NOPR didn’t propose that.
PJM had suggested separating the components across the Operating and Market Implementation committees, but stakeholders were adamant that they should be kept together to ensure any market signals are designed to incent the desired behavior.
A PAR Too Far?
PJM and NYISO are still interested in replacing a broken phase angle regulator at Consolidated Edison’s Ramapo substation, despite stakeholder skepticism about its necessity. The grid operators are holding a meeting Tuesday at NYISO’s offices to discuss the situation and consider modifying their joint operating agreement. The joint stakeholder interactions are intended to create criteria for a benefits analysis that would factor in the cost allocation of any remedies. (See PAR Wars: A Struggle for Power.)
PJM’s Stan Williams walked through a presentation NYISO created on the issue, in which the ISO urges replacing the PAR.
“They see enough benefit there that they want to move ahead with replacing the second PAR by the fall,” he said.
Williams said the joint stakeholder engagement will be beneficial as it might create a roadmap for future cross-border projects. PJM uses a similar benefits analysis with MISO in determining transmission, he said. Gabel Associates’ Mike Borgatti asked PJM to develop a presentation on how that process works.
Carl Johnson of the PJM Public Power Coalition and Calpine’s David “Scarp” Scarpignato complained about the PAR meeting being scheduled on one of PJM’s only two no-meeting days of the month. Both said they will be unable to attend.
“You’re going to have a one-sided meeting. It only happens once a month,” Scarp said.
Dave Pratzon of the GT Power Group supported PJM’s engagement with NYISO on the issue, pointing out that the RTO objected when MISO attempted to make PJM pay for PARs installed on the Michigan-Ontario border.
Although the paper found a capacity mix of more than 20% solar would threaten reliability, Bryson noted that currently renewables only make up about 2% of the mix.
The paper was very narrowly focused, he noted, and purposefully didn’t address other topics, such as environmental issues or whether natural gas infrastructure could keep pace with the high percentage of gas-fired generators PJM’s analysis said the fleet could handle. The paper did not identify a percentage of gas-fired units that would threaten reliability.
Additionally, it didn’t consider dual-fuel units or units with access to multiple fuel pipelines. It also assumed that all units had confirmed supply contracts.
FirstEnergy’s Jon Schneider pointed out that the study highlighted only a third of the portfolios that PJM considered “desirable” would be resilient enough to withstand polar vortex-type conditions, which the study attributed to “the increased risk of natural gas delivery under extremely cold and high load conditions.” He asked for clarity on assumptions made regarding gas supply since it can be either firm or interruptible.
Bryson acknowledged that the study assumed firm service for all units and said that the results would factor into PJM’s planning going forward.
Scarp said many gas units have access to multiple pipeline sources and that, despite coal units maintaining a 30-day onsite fuel supply, many such piles were frozen and unusable during the 2014 polar vortex and recalled a similar period in 1994 that resulted in rolling blackouts.
“Just because you have a 30-day inventory doesn’t mean you have supply for 30 days,” he said.
VALLEY FORGE, Pa. — With several changes under consideration for its financial transmission rights processes, could PJM be forming another FTR task force?
PJM convened task forces in 2011 and again in 2015 to address FTR underfunding.
At Wednesday’s Market Implementation Committee meeting, Direct Energy’s Jeff Whitehead presented a proposed problem statement and issue charge to address the allocation of day-ahead surplus congestion funds and FTR auction revenue surplus funds.
Other stakeholders immediately questioned the proposed language, concerned that it seemed to “presuppose” a solution. Whitehead and other sponsors of the problem statement, including Steve Lieberman of American Municipal Power and John Rohrbach of ACES, representing the Southern Maryland Electric Cooperative, agreed to revise it.
PJM’s Asanga Perera supported the proposal, saying the RTO attempted to implement it but was told by FERC it should go through the stakeholder process. Independent Market Monitor Joe Bowring favored it as well.
Barry Trayers of Citigroup Energy felt it remained too narrowly focused. “There’s a lot of moving parts and this misses a ton of them,” he said.
Whitehead defended the initiative, saying FERC narrowed the scope with its September order directing PJM to allocate balancing congestion costs to real-time load. By removing a major source of FTR underfunding, he said, the existing funding sources can be reviewed and removed if unnecessary. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)
“But I guess we’re going to talk about that in the FTR task force,” Whitehead said.
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His issue charge does not call for creating a task force — instead suggesting the issue be addressed by the MIC.
But there are other FTR issues pending as well. Later in the meeting, Perera discussed several other FTR updates, including additional information on the delayed results for the March 2017 FTR auction. He said he asked other RTOs about their processes.
“They all said PJM’s process is extremely complicated,” he said. “None of them have any overlapping periods like we do.”
Perera proposed removing the single quarterly auction that overlaps monthly auctions or developing software upgrades to speed up the solution time. (See “FTR Lateness Blamed on High-Volume Period,” PJM Market Implementation Committee Briefs.)
“Hardware, software, market structure — there are things that can be done better than the one-off solution of killing one quarter,” DC Energy’s Bruce Bleiweis said.
“The IMM supports PJM’s proposal to remove the overlapping-period quarterly auction as a solution to the issue, at least as a stop-gap measure. The monthly component product periods of the quarter will still be available and market-sensitive auction results will be made available on a more timely basis,” said Howard Haas, the Monitor’s chief economist.
TULSA, Okla. — SPP COO Carl Monroe told the Markets and Operations Policy Committee last week that allocating costs for existing transmission facilities would not be an issue should the Mountain West Transmission Group be successful in its quest for RTO membership.
Mountain West doesn’t expect to pay for SPP’s facilities “past or present,” Monroe said, and SPP is “thinking similarly.”
“We have a current situation within SPP where we’re not sharing costs of the upgrades across the Eastern and Western Interconnections,” he said. “There’s already a situation in the SPP Tariff that, through contract, load in the West doesn’t pay for Eastern upgrades. That makes sense, because they don’t get any electric benefits out of that.”
SPP and Mountain West are also trying to determine whether to operate as a single market or two separate markets. There are currently four DC ties between SPP and Mountain West facilities, with a total capacity of 710 MW. Mountain West’s membership would place all seven U.S. ties between the Eastern and Western Interconnections under SPP’s Tariff.
“We’re talking with vendors, technical staff and outside experts to see whether it’s possible to operate a market over DC ties,” Monroe said.
Monroe was unable to answer several questions from members, citing confidentiality issues. However, he welcomed stakeholders to participate in the Strategic Planning Committee’s executive sessions, where discussions on Mountain West’s potential membership will take place. (Members will have to sign non-disclosure agreements to participate.)
Monroe and Tri-State Generation and Transmission Association’s Mary Ann Zehr said Mountain West hopes to determine whether to continue pursuing membership before July. The two entities would begin drafting revisions to governing documents shortly thereafter, with the intention of getting SPP board signoff in January 2018.
The MOPC overwhelmingly agreed with staff’s recommendation to remove a Southwestern Public Service 345-kV line from the 2017 Integrated Transmission Planning’s 10-year assessment. The vote was opposed only by independent transmission companies ITC Holdings and Hunt Transmission, with Golden Spread Electric Cooperative and South Central MCN abstaining.
The MOPC and SPP’s board directed staff in January to further evaluate the Texas Panhandle project following pushback from SPS, which said it was “the wrong time” for the line. (See “Board Sends $144M Tx Project Back for Re-evaluation,” SPP Board of Directors/Members Committee Briefs.)
Staff’s further evaluation and modeling changes revealed a 6.5% decrease in the SPP region’s adjusted production costs savings, and a third-party review using more detailed routing assumptions lengthened the project from 90 miles to 109 and increased the $144 million cost estimate to $173 million.
In March, SPS parent Xcel Energy announced it would add 1,230 MW of new wind energy north of the proposed project in Texas and New Mexico. Load forecasts south of the constraint also indicated an 800-MW reduction in load, further reducing its need. The transmission line would run southwest of Amarillo to an SPS power plant being evaluated for continued operation.
“It’s a balancing act. We have to get it right,” said Engineering Vice President Lanny Nickell, responding to comments about the additional modeling and studies. “We’ve probably done more analysis on this single ITP10 than we’ve done on any number of studies cumulatively. … We need to get better at interpreting these results.”
“I look at planning as a core fundamental of the RTO,” said MOPC Vice Chair Todd Fridley of Transource Energy. “If we can’t do that well and have these fits and starts, we’re not getting the job done.
“Major input changes at the end of the planning process makes this determination more difficult. Everyone wants to build the right projects, but we must also maintain the integrity of the planning process so that everyone has confidence that we are delivering customer value,” Fridley said.
ITC Holdings’ Alan Myers, who chairs the Economic Studies Working Group that brought forward the staff recommendation, reminded members that SPP’s new transmission planning process will include accountability mechanisms designed to promote timely data exchanges, reviews and approvals. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
“One of the core tenets in the new process is more stakeholder discipline,” he said. “There will be some bright lines about when we need to have your data in. What we have here is a little more unprecedented.”
“What SPP did was go back and do a fair assessment with the stakeholders that were involved,” said Bill Grant, director of strategic planning for SPS. “This evaluation is showing that, yes, if we had 8 [GW] of wind, transmission has to be built.”
MWG Closing out MMU’s Recommendations
The Market Working Group took another step toward closing the 2014 State of the Market Report’s nine proposed market changes by securing approval of a revision request that removes the day-ahead must-offer requirement.
The change request, MRR125, came out of the Market Monitoring Unit’s recommendations to improve the Integrated Marketplace and was designed to run in parallel with revisions to physical withholding rules. The MOPC declined to take up the revision request in July to allow for further discussion on the rules. (See “MOPC Defers Action on Must-Offer Rule,” SPP Markets and Operations Policy Committee Briefs.)
Working group Chair Richard Ross of American Electric Power said the group spent considerable time since then discussing the issue. In February, it rejected a revision request that would revise the physical withholding rules to include a penalty for noncompliance. The MMU has appealed that decision and plans to bring it up at the July MOPC meeting.
“The conclusion was a preference to stay with current monitoring activities,” Ross said. “It’s important you realize whether these provisions are in or out, you’re still subject to physical withholding” prohibitions.”
MMU Director Alan McQueen was asked if the unit agreed with the MWG’s conclusion.
“We think the market has the right incentives,” McQueen said. “[MRR125] doesn’t eliminate concerns around potential cases of physical or economic withholding in the market. We think the rules can be improved, but we don’t think the day-ahead must-offer significantly contributes to that.”
MOPC Chair Paul Malone, with the Nebraska Public Power District, asked McQueen whether he had any concerns over “after-the-fact” market power.
“[Market participants] may not know when they have local market power,” McQueen said, “but generally, from experience, MPs should be able to discern when they’re likely to have market power.”
“The [MWG’s] concern was there may be particular conditions on the grid, like transmission outages, planned and unplanned, where a unit may find itself in a situation where it has market power,” Ross said. “The concern on MPs’ part was we may not be as smart as the MMU staff thinks we are.”
Ross said eight of the nine 2014 recommendations are closed, though McQueen disagreed.
“Richard represents the MWG, I represent the MMU,” he said.
McQueen took the opposing side when the MOPC then considered MRR214, which would allow market participants to add a 10% buffer to mitigated offers.
The MWG said the 10% buffer added to the mitigation offer will give MPs more margin for error when submitting their mitigated offer curve. The group also said the change would improve price formation in SPP’s markets by removing a penalizing feature that may be suppressing offered prices today.
“Mitigation and economic withholding are trying to keep the market at competitive levels when there is the presence of market power,” McQueen said. “Are we accomplishing that? Are we improving that? Are we making it better? Is this making sure the market stays competitive during those periods when mitigation actually goes into effect?
“What’s being proposed is inconsistent with what we’ve seen in other markets and what’s been approved by FERC,” he said.
“This came across because of a discussion at the Board of Directors,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on the Members Committee and chairs the Strategic Planning Committee. “Many MPs have encouraged us to do this. They’re not recovering their short-term marginal costs.”
“This needs more work,” said Lincoln Electric System’s Dennis Florom. “I don’t see staff supporting it, I don’t see the MMU supporting it. We’re going to have our own members and the MMU fighting at FERC, which is embarrassing to me.”
The committee sent the revision request on to the board for its approval next week, with seven members opposing and five abstaining.
Separately, Ross recommended the committee reject RR201, which would have provided market participants a mechanism to settle day-ahead market errors without repricing and re-clearing the entire market.
“The challenge folks encountered was if we do that without resettling the whole market, you’re just throwing it in a bucket and spreading it across the whole market,” he said.
The MOPC agreed, though two members opposed and another dozen or so abstained.
Another change (MRR209) that would have expanded resources’ “status options” to include start-up/shut-down and testing was rejected on a roll-call vote, with 61% of the members opposed.
SPP staff said the change would “result in a clearer understanding” of why a resource may not be following dispatch instructions. However, it drew opposition from members who couldn’t balance the revision’s minimal benefits with its estimated $22,000 cost when operators will continue follow-up phone calls for reliability reasons.
The committee also approved MRR203, which adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-to-sink path can be nominated.
MOPC Endorses Re-evaluation of Basin Electric Project
The MOPC endorsed Basin Electric Power Cooperative’s request for an expedited re-evaluation of a 345-kV project in northwestern North Dakota. The project — replacing a 33-mile, 115-kV line at an estimated cost of $52.3 million — was approved last July for a notification to construct with conditions (NTC-C) out of the 2016 Near-Term assessment. (See “First Competitive Tx Project Pulled; ND 345-kV Line Approved,” SPP Board of Directors and Members Committee Briefs.)
Basin Electric had projected 2.5% load growth in the nearby Bakken shale play in making its earlier request, but updated load forecasts from its member companies have revised that number downward. It asked for the expedited assessment to confirm the timing of construction and associated financial expenditures.
“We’re still seeing load increases in that area, just not at the rate we anticipated,” said Jason Doerr of Basin Electric member Northwest Iowa Power Cooperative. “It’s still Basin Electric’s belief that this load will continue to grow at a rate that’s significantly less. Next year, wherever the economy goes, we’ll have another load forecast to provide SPP.”
SPP’s Jason Davis said the project could eventually fall under FERC Order 1000, but until then, “We want to take a step back, see what needs and issues still exist going forward.”
Another project did proceed as a potential seams project, with the MOPC’s approval of a 50-MVAR reactor at a 345-kV substation near Springfield, Mo. The Seams Steering Committee and Transmission Working Group both recommended the project’s approval out of the regional-review process. The project was identified last year in a joint study with Associated Electric Cooperative Inc.
The MOPC also approved the TWG’s 2017 ITPNT, which includes 16 reliability projects at a combined cost of approximately $60 million, and its scope for the 2018 ITPNT. Both motions passed unanimously.
Cost Allocation Review Cycle Could Extend to 6 Years
The MOPC approved a task force’s unanimous recommendation and an accompanying revision request that future regional cost allocation reviews (RCARs) be conducted at least once every six years, doubling the previous three-year timeline.
The Regional Allocation Review Task Force said extending the timeline would save SPP manpower and consulting costs, noting the most recent RCAR showed an increase in benefit-to-cost ratios and only one entity below the threshold. Ross, the RARTF’s vice chair, pointed out the Tariff still allows members to seek relief for an out-of-cycle RCAR at any time from the board, MOPC or Regional State Committee.
“It’s not a trivial task. We’re spending well over $400,000 to produce the reports,” Ross said. “It is quite literally a single-word change.”
The motion was opposed by the City of Springfield, whose transmission zone in southwestern Missouri was found to be deficient by RCAR II, and several other smaller entities. The Morgan project — a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a connecting 161-kV line at an estimated $9.2 million — was approved out of the 2017 ITP10 in January as a remedy to Springfield’s deficiency, and was recommended for regional funding by the MOPC last week. However, the project is contingent on reaching an agreement with AECI, which would not see reliability benefits from a potential seams project that sits within its service area.
Jeff Knottek, director of transmission planning and compliance for Springfield utilities, said if the Morgan project doesn’t provide the city with a remedy, it didn’t want to wait another six years.
“We’re still technically a harmed entity through two RCARs,” said Knottek, who abstained from the vote. “We haven’t climbed out of the hole yet, and [Morgan] could fall on its face. Under a worst-case scenario, in six more years we could be sitting [at a negative number].”
Changes Proposed for Revision Process
SPP staff introduced potential changes to the revision-request process for technical documents that don’t require MOPC approval.
Staff said NERC reliability standard IRO-010-2, which requires the reliability coordinator (RC) to maintain documentation of data specific to its responsibilities, and a recent revision request that would create RC and balancing authority data as an appendix to the operating criteria, created a need to manage other documents not a part of the current process.
While the revision process for technical documents would not require MOPC approval before being enforced, the committee would still hear appeals from members. Written reports on the changes would be provided in the MOPC’s background materials, and members could request discussion on the changes if they’re not part of the working groups responsible for the documents.
Staff said the revised process would better meet NERC requirements and proposed starting with reliability data specifications and the communication protocols. Other documents that could fall into the process include the Integrated Transmission Planning manual, the balancing authority’s emergency operations plan, the SPP Reliability Coordinator Area’s restoration plan and other technical handbooks and guides.
Several stakeholders, primarily from smaller members, expressed concerns over losing visibility into changes.
“Letting [the documents pass] out of the primary working group … how would we know they have passed?” asked ITC Holdings’ Marguerite Wagner. “How would we keep track of that?”
“As the organization gets bigger and bigger in geography and more members, I’m not comfortable with this,” said Chairman Malone, referring to extending the process to other SPP documents. “In our organization, we try to have someone plugged in to every working group, but not everyone can do that. I’m just not comfortable with it yet.”
Monroe said the primary working groups and staff would be responsible for notifying all parties of pending changes, and that some of the more technical revisions would be included on the MOPC consent agenda. He also said he had heard support for giving the working groups the ability to approve technical documents, rather than send them to the MOPC.
Staff said it will return with a formal proposal for the committee’s July meeting.
Paul Suskie, SPP’s legal counsel and corporate secretary, shared the Corporate Governance Committee’s proposed bylaw change for organizational group chair and vice chair selections.
Under the changes, group chairs would be nominated by the committee and appointed by the board to a term that coincides with the board chair’s two-year term. Vice chairs are elected by the groups’ members, with their terms now coinciding with the group chairs’. The MOPC vice chair would be elected by the board.
Should there be a vacancy at the chair level, the vice chair would become the interim chair until a replacement is appointed by the board to fill out the remainder of the term.
The working group leadership’s terms would be staggered to expire in even or odd years. Committees reporting to the board would have their leadership’s terms match that of the board chair. This doesn’t apply to those committees advising the board, such as the Regional State Committee and the Cost Allocation Working Group.
Upon board approval, the bylaw changes would be filed with FERC for its approval.
MOPC Approves Doubling Credit Allowance to $50M
SPP will join its RTO/ISO brethren in adopting a $50 million unsecured credit allowance should the board next week approve a revision request raising its current cap from $25 million.
SPP is the last of the RTOs without a $50 million allowance cap. CPWG-RR218 calls for raising the allowance to reduce the costs of capital for utilities, while exposing SPP’s customers to “minimal additional credit default risk.”
FERC Order 741 allowed RTOs and ISOs to grant up to $50 million in unsecured credit, a limit most grid operators have adopted.
The Credit Practices Working Group’s revision was pulled from the consent agenda over concerns that SPP was planning to raise its cap just to match other RTOs. However, staff said SPP’s transmission congestion rights market, with its collateral requirements, highlighted the need to revisit the cap.
Staff estimated the increase would affect about 15 credit customers. The revision was approved unanimously by the MOPC.
Twelve other revision requests also passed unanimously as part of the consent agenda:
BPWG-RR207: Aligns the business practices with the Integrated Marketplace’s tag-denial criteria.
MWG-RR200: Allows bilateral settlement statements (BSS) at a withdrawal point to be included in the overcollected losses calculation. Capping the BSS at the maximum amount of the real-time withdrawal minus any amount of grandfathered agreements or any federal service exemptions will diminish the dilution at a generation or hub settlement location.
MWG-RR205: Allows the implementation of the combined-resource option changes by including the minimum regulation-capacity operating limit, and adds resource offer parameters that can be changed daily for a jointly owned resource’s minimum physical capacity and physical-regulation capacity operating limits.
MWG-RR216: Reinstates Tariff language omitted from RR173 and filed at FERC last year related to eligibility of multi-configuration resources for regulation-up or regulation-down service.
MWG-RR217: Removes Tariff language related to violation relaxation limits to make the section consistent with a compliance filing to FERC’s Order 825 on shortage pricing.
MWG-RR219: Ensures language in SPP’s Tariff meets FERC requirements for enhanced combined cycle units.
ORWG-RR213: Creates a new appendix to the SPP Operating Criteria that defines how the SPP reliability coordinator will operate voltage stability limited system constraints, as recommended by the Wind Integration Study.
RTWG-RR208: Implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission-expansion plan, creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
RTWG-RR211: Establishes an additional criterion for competitive projects, requiring that the total competitive segments for a transmission project cost meet or exceed $3 million.
TWG-RR224: Aligns the existing criteria with NERC’s new definition of special protection schemes as remedial action schemes, and cleans up planning-criteria language coinciding with changes made to the operating-horizon system operating limits methodology.
VALLEY FORGE, Pa. — FERC did not act on PJM’s proposed changes to its shortage pricing, so revisions for how to handle transient shortages will go into effect May 11 as planned, Manager of Real-time Market Operations Lisa Morelli told the Market Implementation Committee on Thursday. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
The curve step changes are still on track to be implemented on July 1, but it’s unclear whether that will definitely happen.
“There’s unfortunately uncertainty [about] a lot of what’s happening at FERC right now,” PJM attorney Steve Shparber said. “We will keep going on until we hear otherwise.”
PJM’s plan would change the scarcity signal for the maximum $850 penalty factor from the economic maximum of the single largest contingency to the highest actual output of a single unit. Next, it would add two lower “steps” that would trip a $300 pricing level. One step would be calculated as the highest actual output plus 190 MW — a static number derived from the synchronous reserve mean of the Mid-Atlantic Dominion zone plus one standard deviation. The second step would be calculated as the previous step plus an extension.
PJM to Review Black Start Prior to New RFP
PJM released its first request for proposals on black start units in 2013 to have them in place by 2015. As part of that process, the RTO instituted a five-year review, meaning the next black start RFP will be in 2018 for projects to be available in 2020.
To begin that process, staff will be holding a special one-hour session after the May 2 Operating Committee meeting to review results and lessons from the first RFP. Stakeholders pointed out that that is the second day of the FERC technical conference on the impact of state policies on RTO operations in PJM, ISO-NE and NYISO (AD17-11). PJM staff promised the meeting will be quick.
Earlier in the meeting, stakeholders endorsed changes to the annual revenue requirements for black start units. PJM and its Independent Market Monitor came to an agreement on having the revenue go into a non-interest-bearing account for each unit until its costs have been approved, at which point the RTO will conduct a true-up.
MISO Independent Market Monitor David Patton on Thursday repeated his call for MISO, PJM and SPP to develop better procedures for transferring control of market-to-market constraints during high congestion.
“It would save all the RTOs a lot of money and improve efficiency,” Patton said at an April 13 Market Subcommittee meeting.
Patton pointed to the Feb. 7 transfer of a Midwest constraint to PJM that provided relief for $40 million worth of congestion. (See Tornadoes, Wind Generation Drive MISO Tx Congestion.) Market Monitor staffer Michael Wander said PJM still has monitoring control of the constraint in question, and it is not unusual for an RTO to keep control of a transferred constraint for longer periods. “They review it periodically and keep it unless there’s a change in the situation,” Wander said.
“The fact that PJM physically monitors this constraint doesn’t mean that MISO is disadvantaged in any way,” Patton told stakeholders.
Northern Indiana Public Service Co.’s Bill SeDoris asked if the Monitor is notified of the transfers.
“Not only are we appraised, we’re raising concerns when the transfer hasn’t taken place. We tend to be advocates of this,” Patton said.
The Monitor reserved his harshest criticism for existing pseudo-tie procedure.
“The only reasonable requirement in our opinion is to get rid of the pseudo-tie requirement into PJM. … The fact that anyone thinks pseudo-tying is a good idea is astounding to me,” said Patton, summarizing a Section 206 complaint the Monitor filed against PJM in early April (EL17-62). (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)
Patton blasted PJM’s practice of requiring dispatch control of external generators. “This is an unprecedented requirement,” he said. All 12 MISO resources pseudo-tied into PJM were dispatched inefficiently, resulting in 114 new market-to-market constraints in 2015 and 2016, he said.
Patton encouraged stakeholders to file comments in support of his complaint.
Dynegy’s Mark Volpe asked if the spike in MISO-PJM pseudo-ties is the result of problems with MISO’s capacity market design.
“That certainly can’t be ignored,” said Patton. “But at this point, MISO’s excess capacity is a little higher than PJM’s.”
MISO: No Resettlements for Tariff Error
MISO will make a Section 205 filing seeking FERC approval for a waiver to void an eight-year-old Tariff mistake that prohibits resources incurring an excessive or deficient energy deployment charges from receiving day-ahead margin assurance payment for multiple hours.
The RTO’s Business Practices Manual only bars inefficient resources from receiving day-ahead margin assurance payment for the hour that the charge was incurred. (See MISO to Fix Recently Discovered Tariff Mistake.)
The waiver asks FERC to exclude resettlement of previous day-ahead margin assurance payments. The filing will include an affidavit from the Monitor recommending no resettlement.
“Resettlements would be extremely damaging to the market and create inefficient financial risk prospectively by undermining market confidence,” MISO said.
Bladen said there would be no technology changes to fix the mistake. “Essentially the only cost of this is administrative and legal,” he said.
Bladen also said MISO experienced a second-tier maximum generation event on April 4 in MISO South. He said MISO will review the event at the May 11 Market Subcommittee meeting. The Reliability Subcommittee will also review the event.
Expanded ELMP Price-Setting Begins May 1
MISO has filed for FERC approval to expand extended locational marginal price setting to online resources with a one-hour start-up time starting next month (ER17-1081).
The RTO will put the new eligibility into effect on May 1, Bladen said, and MISO expects to receive an order from FERC staff even without commission quorum. No one has protested the filing.
The new pricing structure preserves the requirement that offline resources must have a start time of 10 minutes or less to set prices. The move will increase the share of peaking resources eligible to set prices from 8% to 58% on a capacity basis, MISO said. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)
VALLEY FORGE, Pa. — After years of dragging the issue forward, Vitol’s Joe Wadsworth was about to see PJM stakeholders vote on schedule changes to accommodate spot-in sales between the RTO and NYISO.
But the scheduled vote at Wednesday’s Market Implementation Committee meeting was delayed after John Rohrbach of ACES said PJM’s simple solution for solving the problem would harm power sales in the South.
PJM had proposed delaying the spot-in request time by an hour to 10 a.m. across all seams, which would allow market participants looking to bring in power from NYISO the time to confirm they were approved by the ISO to export power. However, the delay causes issues along PJM’s southern border, Rohrbach argued.
The Market Implementation Committee delayed a vote on a schedule change to accommodate spot-in sales between PJM and NYISO because of concerns it could harm power sales in the south. | Monitoring Analytics
Rohrbach said that the daily sales market in southern states begins early in the morning and is generally done by 10 a.m., so any power that doesn’t receive approval for PJM spot-in service wouldn’t have another market to be sold in. At 9 a.m., however, opportunities still exist to make bilateral trades, he said.
“Today, if you don’t get spot-in, you have other opportunities,” he said. “By 9, it’s already starting to tail off. … If you wanted to change the time to 8 a.m., we’d actually be happier with that.”
The South is a thinly traded market and the vertically integrated utilities there are comfortable with their schedule, Rohrbach said. They are “guaranteed” not to conform with PJM’s proposed changes, he added.
The news wasn’t bad for Wadsworth, who had originally proposed a more complicated, market-based solution and later suggested that the time change be limited just to the NYISO seam, which was opposed by the Independent Market Monitor. NYISO had also proposed a market-based solution that PJM stakeholders rejected. (See “Vitol Accepts Simplified Solution to Spot-In Issues,” PJM Market Implementation Committee Briefs.)
“We are happy to compete in a competitive marketplace. … I was very clear that I didn’t want to make a change that would impact others,” Wadsworth said. “This kind of creates the balloon effect — squeeze the balloon at one place and it’s going to pop out at another.”
PJM’s Chris Pacella said the issue with the market-based proposals are that they will require software upgrades, which would take time and resources. Stakeholders acknowledged the challenges but urged Pacella to see if the proposal could be accommodated using the current system.
“I know it’s not your preference, but you should at least look at adjusting [PJM’s software] to try the NYISO solution without hurting the other seams,” Direct Energy’s Jeff Whitehead said.
“I certainly feel for the folks who are trying to solve this,” said Carl Johnson of the PJM Public Power Coalition. “We took on the problems serially. We haven’t invested our best problem solving techniques. I don’t think we’ve given this our best effort.”
Throughout the spot-in discussion, the Market Monitor has insisted on maintaining consistent rules across all seams, which Monitor Joe Bowring highlighted ironically by quoting Ralph Waldo Emerson: “‘Consistency is the hobgoblin of small minds.’” He supported considering Rohrbach’s concerns and leaving the current rules in place in the interim.
Wadsworth agreed to remove his request for a vote on the proposal, but he asked stakeholders to help him revise the problem statement. Rohrbach immediately volunteered.
Alberta-based Maxim Power announced it has closed a deal to sell its U.S. subsidiary and its five generation plants, concluding a two-year effort to stave off threats to the company’s survival.
Hull Street Energy, through its newly formed affiliate Milepost Power Holdings, paid $106 million for Maxim’s 447 MW of power generation assets in the U.S., or about $238,000/MW of generating capacity. Three of the plants are dual-fuel combined cycle plants in New England, and the others are simple cycle natural gas turbines in New Jersey and Montana.
In May 2015, Maxim reported that it had breached several financial covenants with its Canadian bank and that “significant doubt may exist with respect to the ability of the corporation to continue as a going concern.” The company said it was pursuing asset sales to improve its cash position.
The company’s outlook was not helped later in May 2015 when FERC accused it of manipulating the New England power market in a fuel-switching scheme (IN15-4). Under a consent agreement approved with FERC’s Office of Enforcement last September, Maxim agreed to pay a $4 million fine and disgorge another $4 million in earnings to ISO-NE, but it did not admit guilt. (See Maxim Power to Pay $8M to Settle Fuel-Switching Case.)
The same month, Maxim sold 176 MW of generation assets in France, its COMAX subsidiary, to an affiliate of Basalt Infrastructure for 47 million euro ($52.8 million at the time), about $300,000/MW.
Maxim said it will use $8 million (CAD) of the proceeds from the sale of its U.S. assets as collateral for letters of credit and $5 million (USD) to fulfill the settlement agreement with FERC. The company, which trades on the Toronto Stock Exchange, reported $2.2 million in net income on $94.5 million in revenue for 2016.
The assets acquired by Milepost are the 181-MW Pittsfield plant that FERC identified in the fuel-switching scheme; the 87.2-MW Forked River plant in Ocean County, N.J.; a 63.5-MW plant in Pawtucket, R.I.; the 62.1-MW CDECCA plant in Hartford, Conn.; and the 54.9-MW Basin Creek plant in Butte, Mont.
New England states will not have enough renewable resources to meet the 2025 and 2030 targets in current renewable portfolio standards without adding transmission for new onshore wind, according to a scenario analysis conducted for the New England States Committee on Electricity.
NESCOE’s Renewable and Clean Energy Mechanisms 2.0 Study used a model from London Economics to evaluate the impact of five scenarios on prices, emissions and “missing money” — the potential gap between generators’ revenues and their operating costs.
ISO-NE officials provided a briefing on the Phase I findings — part of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative — at the NEPOOL Participants Committee meeting on April 7.
The results are expected to be discussed at FERC’s technical conference May 1-2 on tensions between state public policies and wholesale markets in ISO-NE, PJM and NYISO.
One scenario that considered the accelerated retirement of the region’s nuclear capacity included sensitivities based on natural gas prices. One that looked at more renewables and transmission considered several alternatives for expanded state renewable standards.
The study concluded that new renewable generation or additional clean energy imports to New England with very low marginal costs will cut energy and capacity revenues for all other resources. Nevertheless, the study noted that under every scenario considered, nuclear generators, existing oil combustion turbines, oil internal combustion turbines, oil steam and pumped storage will remain profitable in 2025 and 2030.
The study found that under base case load conditions, New England’s addition of more than 25 million MWh annually of renewable resources and/or clean energy imports by 2025 would cause existing renewable and clean energy resources to produce less power.
If the region doesn’t build new transmission to move power from new onshore wind to load centers, both new and existing onshore wind “will operate less often and earn less revenue in 2025 and 2030,” the study said.
Unsurprisingly, it also concludes that the retirement of the region’s nuclear generation would “significantly” increase carbon emissions, as would a failure to increase renewable capacity above current RPS levels.
| New England States Committee on Electricity Renewable and Clean Energy Mechanisms 2.0 Study
Phase II of the study will test the operability of each scenario and assess additional market outcomes:
Natural gas pipeline constraints, to be discussed with the Planning Advisory Committee in the second quarter;
Forward Capacity Auction prices, also to be discussed with the PAC in Q2; and
Frequency regulation, ramping and reserves, to be discussed with the PAC in the fourth quarter.
FERC last week released the agenda for the May 1-2 technical conference (AD17-11).
Before the conference, ISO-NE plans to issue a summary of its “concept for accommodating additional state-subsidized resources and their associated pricing impacts on the capacity market.” The New England Conference of Public Utilities Commissioners Symposium in Connecticut in May and the NEPOOL Participants Committee summer meetings may allow for additional dialogue on the concept, said Chief Operating Officer Vamsi Chadalavada.
ISO-NE likely will file any related proposals with FERC by the end of 2017 to allow for implementation ahead of FCA 13.
The grid operator also is evaluating fuel security issues and their effect on the bulk power grid and plans to discuss its findings with stakeholders during the second half of 2017.
Chadalavada also updated the Participants Committee on the Updated 2017 Work Plan, saying the RTO is considering accelerating its discussions of potential pricing approaches for resource ramping.
Previously, the grid operator had delayed the resource ramping assessment to follow both IMAPP and the day-ahead reserve market enhancement assessment. The RTO now plans to hold technical sessions on how ramping currently works and to survey how other regions are handling the issue by the fourth quarter of this year.
The COO also said ISO-NE’s 2017 long-term load, energy-efficiency and solar PV forecasts are nearly complete. “The overall trend is lower net energy and seasonal peak demand for New England,” Chadalavada said.
NEPOOL Seeks Flexibility on DA Market Schedule
The NEPOOL Participants Committee unanimously supported a Tariff revision recommended by the Transmission Committee providing more flexibility in the day-ahead market schedule.
The change eliminates the requirement that real-time external transactions at interfaces not subject to coordinated transaction scheduling be submitted into the real-time energy market before “noon the day before the Operating Day.” The new text says the deadline will be specified in Section III.1.10.1A of the Tariff.
