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.
VALLEY FORGE, Pa. — Stakeholders quickly approved administrative revisions to Manual 14B at last week’s Planning Committee meeting, but gaining endorsement for the newly developed Manual 14F is likely to be a more complex task.
The new manual will cover the competitive planning process. PJM, which has been updating the proposed language based on stakeholder feedback, asked members to submit any additional comments now so the manual will be up to date when it’s approved. The RTO called attention to its “decisional process diagram” (section 8, attachment 4). (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)
“We really would like to get the comments now so we can integrate them,” said Steve Herling, vice president of planning.
Sharon Segner of LS Power questioned why provisions for cost containment aren’t thoroughly outlined and asked for a full vetting of the proposed text because there have been so many revisions.
PJM will bring the manual to the Markets and Reliability Committee on April 27 for a first read and hopes to receive endorsement in May.
Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues
When PJM changed its interconnection queue processes several years ago, the purpose was to ensure everyone paid their fair share of infrastructure upgrades. Previously, whichever project triggered an upgrade would be on the hook for it, no matter how much it contributed to the problem. By having all projects wait in a six-month queue under the new rules, every request that contributed to an upgrade could contribute to paying for it.
“It seemed like a great idea that everybody would take a small piece of a $5 million impact,” said PJM’s Aaron Berner, who is leading the review of the interconnection process. “We haven’t come up with a way to fix it without switching back” to the earlier cost allocation process.
At issue is how to fairly allocate upgrade costs without unreasonably delaying project completions. Back when most projects were large-scale plants with long construction lead times, PJM instituted a rule that all projects would be held in a six-month queue to determine if any upgrades would be necessary for the requests in the queue. Upgrade costs that totaled less than $5 million were allocated to all projects upon the queue’s closure.
Because projects can be much smaller and completed much faster now, the six-month wait time can delay developers’ schedules. PJM is proposing a rule change that would allocate costs of upgrades to the first request that necessitates the spending. Any subsequent requests in the queue would contribute proportionally. (See PJM Considering Injection Rights for Demand Response.)
Returning to this “first to cause” strategy for upgrades less than $5 million has largely gone unchallenged by stakeholders in a series of discussions on the topic, which caused Carl Johnson, who represents the PJM Public Power Coalition, to question who among the stakeholders would be disadvantaged by the change back. He pointed out that there will be an unlucky project that receives the cost allocation.
“I’m curious how that will play out,” he said.
“That’s another incentive to coming in [to the request queue] early,” Berner said.
The Tariff and manual changes are on track to be implemented for the project queue that opens on Oct. 1, he said.
NYISO Changes Spur PJM Review of Emergency Import Abilities
With the termination of the decades-old wheeling service through North Jersey and the near-term retirement of the Indian Point Nuclear Station, PJM is reviewing its ability to import power during an emergency.
PJM’s Mark Sims said the study of its capacity emergency transfer objective (CETO) and capacity emergency transfer limit (CETL) tests assumes a locational deliverability area (LDA) is at a 90/10 load level and in a generation-capacity emergency — in other words when the “load is high and they’re having issues with generation,” Sims said.
To ensure the system has adequate deliverability, the CETL must be equal to or greater than the CETO. Those numbers are calculated through thermal and voltage analyses. Facilities whose outage transfer distribution factors (OTDF) are more than 5% are considered in violation, as are factors more than zero on transmission lines that are 345 kV or larger. The OTDF measures how power transfers using the infrastructure being studied impact the system during an outage.
“We need to take our objective and turn it into a simulation,” Sims said. “During [an] actual emergency, operators are going to do what they can do to keep the lights on. That’s what we’re trying to reflect.”
Solar Forecast Is Coming
Mulhern | RTO Insider
PJM is developing a solar forecast and will need to make several Tariff and manual changes to accommodate it, said Joe Mulhern, senior engineer and project manager. The move — mandated by FERC Order 764 — comes as PJM has seen solar installations take off, from virtually nothing in 2007 to approximately 1,000 MW today.
“It’s really just so we’re ahead of the curve on solar installation,” Mulhern said.
The aggregate forecast data will be available to members for operational planning, transmission outage coordination and generation offering and scheduling. The project is targeting implementation by the end of the year. It would only apply to front-of-the-meter solar generators.
The rule changes would also require real and reactive power telemetry for solar generators of 3 MW or greater. At the Operating Committee earlier in the week, American Electric Power’s Brock Ondayko asked why such plants would also be required to report temperatures from the backside of solar panels.
“If you want it, we’ll give it to you,” Ondayko said. “I don’t know if the information is going to be accurate or not. … It seems to me just because things could be available, I think PJM should have to think of why it’s necessary.”
Staff: Developers Have no Right to Retain Previously Proposed Projects
Transmission developers whose proposals don’t get approved will need to continue proposing them until the constraint disappears or risk another developer landing the project if it ever is approved, PJM staff told participants at the Transmission Expansion Advisory Committee meeting.
One stakeholder, who declined to be quoted by name, asked about a “right of first refusal” policy, noting that he noticed several new proposals that had appeared to be the same as previous proposals.
“It seems kind of unfair” that a company could have proposed a project that was rejected, only to see a “copycat” receive approval for it later, he said.
PJM’s Herling said the idea was discussed at FERC when the competitive transmission rules were being developed, and the commission specifically ruled out such a provision.
“The bottom line is we start over every time,” Herling said. “You have to propose in every window if there’s congestion to be addressed.”
RENSSELAER, N.Y. — NYISO updated stakeholders last week on its response to concerns over capacity exports, providing a status report on modeling revisions and recommending stakeholders consider broad policy changes as part of the ISO’s 2018 Project Prioritization Process.
The ISO is attempting to insulate consumers from anticipated capacity price spikes in the Lower Hudson Valley and New York City zones expected as a result of FERC’s October order allowing the 1,242-MW dual-fuel Roseton 1 generator to export some of its capacity to ISO-NE. The plant, 43 miles north of New York City, is in the import-constrained G-J locality.
In January, FERC approved NYISO’s plan to change its capacity market rules to recognize the impact of counterflows. The new rules use a “locality exchange factor” to reflect how much capacity from “rest of state” can replace capacity exported from an import-constrained locality. The prior rules assumed that 100% of a generator’s exports from an import-constrained area must be replaced with generation in that locality.
ISO officials now are working with General Electric to develop a probabilistic approach to determining the locality exchange factor. The new methodology could replace the deterministic method designed last year and approved by FERC.
Emilie Nelson, vice president of market operations, told the April 12 Business Issues Committee meeting that “the subject is proving more complicated than expected.”
GE presented its proposed methodology and export topologies at the March 22 meeting of the Installed Capacity Working Group. It is expected to present preliminary results of its analysis at the working group’s April 19 meeting.
NYISO Zones F&G to ISO-NE | General Electric presentation to NYISO Installed Capacity Working Group, March 22, 2017
By June 1, the ISO plans to file an informational report with FERC outlining work that will remain to be done after that date.
NYISO recommended stakeholders consider the topics of capacity imports, payments to capacity-exporting generators and capacity resource interconnection service in the 2018 Project Prioritization Process, which allows stakeholders and the ISO to rank proposed initiatives against one another based on expected benefits and costs. The initial list of project candidates and descriptions will be on the agenda at the Budget & Priorities Working Group meeting April 26.
Every four years, the American Society of Civil [not Electrical] Engineers releases its Chicken Little report on American infrastructure.[1] The report says our energy infrastructure — the second largest category after roads and bridges — should get a D+.
Huntoon
I don’t know if the rest of the infrastructure sky is falling,[2] but when it comes to electric infrastructure, most everything in the report is wrong.[3] [To see ASCE’s response, click here.]
For starters, there is this claim: “With more than 640,000 miles of high-voltage transmission lines across the three interconnected electric transmission grids … the lower 48 states’ power grid is at full capacity, with many lines operating well beyond their design.”
The fact is that 0 (zero) transmission lines are being operated beyond their design capacity. The grid has been and continues to be designed and constructed to cover projected peak demand years in advance. And every line is operated within its design limits. The ASCE claim is alarmist and wrong.
Then there is this: “Often a single line cannot be taken out of service to perform maintenance as it will overload other interconnected lines in operation.”
Hello, this is why most maintenance is performed in off-peak months — as has been done for decades.
And this: “As a result of aging infrastructure, severe weather events, and attacks and vandalism, in 2015 Americans experienced a reported 3,571 total outages, with an average duration of 49 minutes.”
Whoa! “Total outages” is outages, large and small, across the entire country. The total number of people claimed to be affected? 13.2 million out of America’s 325 million population.[4] The average number of people affected per outage? 3,714. Yes, less than 4,000 people per outage. For an average duration of 49 minutes.
And what portion of these 3,571 outages is even attributable to allegedly overloaded infrastructure, the gravamen of the ASCE report? According to ASCE’s own data, a mere nine (yes, nine) outages are attributed to “overdemand.”[5] Major outage causes are weather and trees at 1,069, faulty equipment and human error at 942, vehicle accidents at 419, squirrels at 89, etc.
So much for the present.
As for the future, the report relies on an obsolete projection of future electric demand. Increased efficiency and distributed energy resources, among other factors, have caused the U.S. Energy Information Administration to halve projected growth between 2016 to 2025, from ASCE’s assumed 8% to the current 4%.[6] Using ASCE’s methodology, it means “needing” $467 billion instead of $934 billion over the next 10 years.
ASCE projects spending of $757 billion, so under ASCE’s own methodology, using the current EIA growth projection, we will be spending hundreds of billions more than we need to.
There’s more. Buried in the study is an implicit assumption that the efficiency of electric generation is static; in other words, the capital cost of generating electricity remains constant, so we have to keep deploying the same dollars of investment per unit of increased electric demand.
The fact is that competitive market forces inexorably force down costs and thereby prices. Recent years have seen significant increases in the efficiency of natural gas generation and reductions in the cost of new electric generation capacity.[7] In other words, we are generating more electricity per dollar of capital investment.
Finally, the report doesn’t recognize differences in how infrastructure decisions are made in this county. Other infrastructure, such as roads and bridges, do compete with other governmental spending priorities in political decisions by federal, state and local elected officials.
Electric infrastructure investment is not a political decision. It is determined by long-term planning criteria overseen in large part by independent regional (RTOs) and national (NERC) organizations, that in turn are overseen by an independent, highly regarded federal agency (FERC).[8]
Our electric infrastructure deserves an A.
Let’s save the D+ for the ASCE report.
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel.
[6]EIA’s 2017 Annual Energy Outlook projects electricity sales in 2025 of 3,892 billion kWh, which is about a 4% increase over 2016 sales of 3,727 billion kWh.
[8]There are some states where reliability is more state-overseen than federal. Yes, state commissions face some political pressure to keep rates down … but even more to not have outages.
America’s Energy Infrastructure: Room for Improvement
By Chuck Hookham, Otto J. Lynch and Adrienne Nikolic
The American Society of Civil Engineers’ 150,000 members design, build, operate and maintain infrastructure in the U.S. and globally. While roads and bridges are often the first thing to come to mind when hearing the word “infrastructure,” civil engineers also ensure Americans have access to reliable, low-cost energy from its roots (oil/gas wells, electric generation, etc.) to its delivery at the pump or outlet. As an example, each transmission line is essentially a suspension bridge of steel, concrete, wood, cable and other materials, requiring surveying, site work, foundations, structures and construction — all areas of expertise for civil engineers, working in conjunction with other engineering disciplines.
Who better to assess the health of the nation’s energy infrastructure than civil engineers?
That’s why, since 2001, ASCE’s Infrastructure Report Card has included energy infrastructure, with particular emphasis on electricity transmission and distribution infrastructure. Released every four years, the Report Card follows the familiar A-to-F format of a school report card, grading 16 categories of infrastructure. Prepared by a team of civil engineers with expertise across all categories, the Report Card serves as an unbiased, go-to source for information on the state of the nation’s infrastructure, and has been cited by U.S. presidents, countless elected officials at all levels of government, academics and media outlets.
Unfortunately, much like the overall grade across all 16 categories, the energy grade has been stalled in the D’s. In the 2017 Report Card, ASCE graded the nation’s infrastructure a D+ and energy also received a D+ — both the same as in 2013.
To determine the grades, we assess relevant data and reports, consult with technical and industry experts, and assign grades using the following key criteria: capacity, condition, funding, future need, operation and maintenance, public safety, resilience and innovation.
While U.S. energy systems are sufficient to meet the country’s projected energy needs, the 2017 Report Card highlights both issues of concern and potential solutions. Most existing power lines were constructed in the 1950s and 1960s with a 50-year life expectancy, meaning they were not designed to meet today’s significant demand or the evolving need to integrate distributed energy resources. While projections for energy consumption indicate only modest increases between 2015 and 2040,[1] the country still faces significant challenges in ensuring energy is available where it is needed, including transmitting energy from renewable sources to population centers. We cannot build a new wind farm in Kansas and expect the power to just magically appear in New York.
Aging lines and equipment in America’s multiple power grids are operating well beyond their designed maximum operating temperature and peak load, and congestion creates transmission constraints for delivering power from remote generation sites to areas of demand, also affecting reliability and cost of service.[2] NERC’s standards for tree clearance and vegetation only go so far when confronting increasing extreme weather events and exposure to human threats. And just as one closed road causes traffic jams, one power line outage can affect transmission and distribution to millions. Because of a lack of storage and near constant demand, the interruption of any energy system is immediately felt by the user.
While there are certainly more potholes in America’s roads than there are estimated power outages each year, loss of electric power or gas flow through a major pipeline causes a ripple effect on Americans’ daily lives and the economy. The U.S. energy system is the critical infrastructure that keeps America’s lights on, transportation moving and information flowing. Yet the current system in many parts of the country is not adequately resilient and efforts to change that through investment and improvement are highly politicized, often caught up in larger debates about climate change, fuels and national security.
As part of the Report Card, ASCE also commissioned an independent economic analysis of the investment needs and consequences across 10 sectors of infrastructure, including electricity, by a well-respected economic research group. The series, titled “Failure to Act,” was first released in 2011 but was updated in 2016.[3][4] The 2016 study examines the investment needs, projected funding and remaining gap for building new infrastructure as well as maintaining or rebuilding existing infrastructure. The analysis also presumes the mix of generation technologies and sources continues to evolve, resulting in new efficiencies and approaches for meeting demand. The study concluded that in electricity, while the investment gap totals $177 billion between 2016 and 2025, more than 80% of the total infrastructure investment needs are projected to be funded, thanks in no small part to the significant involvement of the private sector in the nation’s energy systems.
No American who has experienced an extended electrical outage, lost appliances because of a power surge or seen downed wires in their neighborhood would grade our electric infrastructure an A, nor do the engineers who design, build and desire to maintain that infrastructure day in and day out.
Chuck Hookham, P.E., M.ASCE, is director of NBD services at CMS Energy, a large regulated electric/gas utility and non-regulated developer of energy projects, headquartered in Jackson, Mich. He has more than 35 years of experience in power generation, transmission and distribution, natural gas and oil pipelines and refineries, and infrastructure systems, and is a member of the ASCE Committee on America’s Infrastructure, which prepared the 2017 Infrastructure Report Card.
Otto J. Lynch, P.E., F.ASCE, F.SEI, is vice president of Power Line Systems Inc. in Nixa, Mo. For more than 28 years, he has participated in the design and construction of numerous high-voltage transmission line projects around the world and was a pioneer in the use of LiDAR in the transmission line industry. He is a member of the ASCE Committee on America’s Infrastructure, which prepared the 2017 Infrastructure Report Card.
Adrienne Nikolic, P.E., M.ASCE, is an energy and utilities consultant based in Philadelphia, Pa. She is responsible for assisting energy and utility clients with the management of projects that modernize the grid, and is a member of the ASCE Committee on America’s Infrastructure, which prepared the 2017 Infrastructure Report Card.
[3] American Society of Civil Engineers. Failure to Act: The Economic Impact of Current Investment Trends in Electricity Infrastructure. 2011. http://www.asce.org/electricity_report/
