FERC said last week it will require the North American Electric Reliability Corp. to provide the commission access to NERC databases in what Chairman Norman Bay said is an effort to apply “Moneyball” techniques to reliability.
The commission issued a Notice of Proposed Rulemaking that would give FERC access to NERC’s transmission availability data system (TADS), generating availability data system (GADS) and protection system misoperations databases (RM15-25).
“It takes the concept of ‘Moneyball’ to our analytics on reliability,” said Bay, referring to the best-selling book on Oakland Athletics General Manager Billy Beane’s use of statistical analysis in evaluating baseball players.
The commission said access to the data “would inform the commission more quickly, directly and comprehensively about reliability trends or reliability gaps that might require the commission to direct [NERC] to develop new or modified reliability standards.”
TADS and GADS contain data on transmission and generation outages, respectively, including cause codes.
The protection system database collected information on about 2,000 misoperations in 2014, including causes. “Protection system misoperations have exacerbated the severity of most cascading power outages, having played a significant role in the Aug. 14, 2003, Northeast blackout,” FERC said.
“While the aggregated TADS, GADS and protection system misoperations data provided in NERC’s periodic reports afford the commission some insight into the reliability and adequacy trends identified by NERC, we believe that having direct access to the underlying data will assist the commission in its understanding of the periodic reports, thereby helping the commission to monitor causes of outages and detect emerging reliability issues,” FERC said.
FERC Micromanaging NERC?
Commissioner Cheryl LaFleur issued a concurring statement expressing concern that the proposal could be seen as micromanaging NERC. Although FERC has ordered NERC to initiate standards on geomagnetic disturbances and physical security, LaFleur said that authority should be used sparingly.
“It is important that we recognize the distinction between [FERC’s] oversight role and NERC’s primary responsibility to monitor reliability issues and propose standards to address them. Ultimately, I believe our efforts to sustain and improve the reliability of the bulk electric system are furthered by mutual trust and shared priorities between the commission and NERC,” she said.
“I understand that today’s proposal might be controversial within the NERC community. I therefore welcome comment on the proposal, including any potential issues or concerns not identified in the NOPR.”
Comments on the proposal are due 60 days after publication in the Federal Register.
The commission also gave final approval to two sets of reliability standards and preliminary approval to a third.
FERC approved reliability standards PRC-002-2, which specifies requirements for time-synchronized data for post-disturbance analysis (RM15-4), and PRC-005-4, adding sudden pressure relaying systems to the protection system maintenance rules (RM15-9).
It also approved a NOPR proposing to approve standard PRC-026-1, which would require that protective relay systems differentiate between faults and stable power swings (RM15-8).
The six New England states aren’t an island, but the region sometimes feels that way when it comes to its winter power supply. Although transmission ratings and maximum generation output is higher during the cold weather and peak load is lower, the ability to import power is a major concern.
“Transmission interfaces into New England are going to be loaded up pretty much around the clock every day,” Peter Brandien, ISO-NE’s vice president of system operations, told FERC on Thursday. “Which means that any sort of contingencies … I’ll have to handle with the resources internal to New England.
“People are talking about ramping up their efforts for the winter, but for us, [preparation occurs] throughout the year,” he continued. “I look forward to the time when I can come down here and say that we’re all set and we don’t have any concerns going into the winter. I feel like a broken record every time I’m down here talking about the same concerns.”
In addition to the familiar concerns over constraints on gas pipelines from the west, he also cited worries about diminished supplies from Nova Scotia. Natural gas supplied 44% of the region’s power in 2014, nearly tripling its share since 2000.
The lack of infrastructure also causes New England prices to be “higher than just about anywhere else,” Brandien said.
ISO-NE will again rely on the winter reliability program it has used for the last two winters, which gives oil generators incentives to secure fuel at the beginning of the winter. Last year, it added incentives for liquefied natural gas. “Hopefully, there will be LNG injections like last year,” Brandien said.
The RTO’s Pay-for-Performance program, which rewards successful generators and penalizes those who fail to meet their commitments, goes into effect in 2018.
Gas-electric communication, “a 12-month project,” has improved in response to FERC orders, he said.
The RTO hired a former gas industry veteran to help evaluate gas availability and developed a gas usage tool that scrapes the electronic bulletin boards of the five interstate pipelines serving the region.
This winter, the RTO also will begin allowing generators to change offers on an hourly basis in the day-ahead and real-time markets, improving incentives for following dispatch orders. “We think that’s going to pay dividends to us,” he said.
The RTO’s assumptions for the Winter 2015/16 Forward Reserve Auction included a reserve requirement of 2,363 MW.
“I’m somewhat comfortable that we have insight into all of [the challenges, that] we have the right communication, that we have the right emergency procedures and that we’ll be able to implement any operational actions in time,” Brandien said.
Still, ISO-NE said in its presentation: “[The] loss of any major non-gas unit or significant disruptions in gas supply or pipeline capability will create major challenges for ISO operations.”
FERC issued a preliminary order Thursday that would require RTOs and ISOs to align their settlement and dispatch intervals, saying it was the first of a number of proposals the commission plans to act on based on what it learned from the price formation proceeding it began last year.
The Notice of Proposed Rulemaking (RM15-24) would require organized markets to settle real-time energy and operating reserve transactions financially at the same five-minute time interval that it dispatches those resources. It would also require the markets to eliminate any lag between declaring a shortage and beginning shortage pricing.
Inaccurate Price Signals
The commission said current practices in some markets are not resulting in appropriate price signals.
Although all organized markets dispatch resources in five-minute intervals, ISO-NE, MISO and PJM settle those transactions based on the average price for all dispatch intervals during the hour (“hourly integrated prices”).
“This misalignment between dispatch and settlement intervals may distort the price signals sent to resources and fail to reflect the actual value of resources responding to operating needs because compensation will be based on average output and average prices across an hour rather than output and prices during the periods of greatest need within a particular hour,” the commission said.
In addition, some markets do not trigger shortage pricing unless the shortage lasts a minimum time — resulting in a delay before prices begin reflecting the shortage. The rule would require a shortage of any duration to be reflected in prices.
FERC said the changes “will help provide correct incentives for market participants to follow commitment and dispatch instructions, to make efficient investments in facilities and equipment, and to maintain reliability. The proposed reforms will also help provide transparency and certainty so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system.”
“Requiring settlement intervals to match dispatch intervals would make resource compensation more transparent by, among other things, increasing the proportion of resource payment provided through payments of energy and operating reserves rather than uplift,” the commission continued. “This increased transparency, in turn, better informs decisions to build or maintain resources and enhances consumers’ ability to hedge.”
Comments on the proposed rule will be due 60 days after its publication in the Federal Register.
Offer Cap Issue Coming to FERC
FERC’s price formation proceeding included workshops and staff reports touching on a variety of obscure — but often controversial — issues, including offer caps and uplift allocation. (See FERC Sets Feb. 19 Deadline on Price Formation Comments.
In its Thursday order, FERC said it “expects to undertake further action addressing various price formation topics, including offer price caps, mitigation, uplift transparency and uplift drivers,” though it gave no schedule for future action.
But the commission will be facing the offer cap issue shortly, with PJM planning to seek a rule change — with or without stakeholder consensus — by the end of October. The Markets and Reliability Committee will discuss the issue in a special meeting Thursday. (See PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight.)
But Commissioner Philip Moeller was impatient. “I wish we had done a little bit more and a little bit sooner,” he said Thursday. Moeller’s term expired June 30, but he has remained on the panel awaiting a new nominee from President Obama.
Industry, RTO Reactions
The Edison Electric Institute praised the commission’s action.
“We thought [the NOPR] was a good start to a really comprehensive look at these issues,” said Richard McMahon, EEI’s vice president of energy supply and finance. “The fact that they teed up these other important issues [for future action] is very encouraging.”
The current disconnect means resources will be under-compensated for energy produced during price spikes, or overpaid for energy produced during low prices in an hour where most intervals have high prices.
MISO
MISO’s Market Monitor David Patton has been recommending five-minute settlements since his 2012 State of the Markets Report.
“Even though a very small share (1 to 2%) of the energy produced and consumed in MISO is settled through the real-time market, the spot prices produced by the real-time market affect the outcomes and prices in all other markets,” Patton said in his 2014 report in June. “For example, prices in the day-ahead market, where most of the energy is settled, should reflect the expected prices in the real-time market. Similarly, longer-term forward prices will be determined by expectations of the level and volatility of prices in the real-time market. Therefore, one of the highest priorities from an economic efficiency standpoint must be to produce real-time prices that accurately reflect supply, demand, and network conditions.”
Patton said MISO has the metering and data necessary to make the change, which he said will require “only modest changes to MISO’s existing settlement calculations.”
At its Market Subcommittee meeting in August, MISO categorized the switch to five-minute settlements for generation schedules as “planned” and said that it was evaluating the “market efficiency benefits” and “process and system impacts.”
MISO implemented five-minute settlements for interchange schedules, as required by FERC Order 764, on June 30.
“We’re in the process of reviewing the NOPR now and will begin discussions with stakeholders soon about the implementation and timing,” MISO spokesman Andy Schonert said. The RTO addressed the implications of sub-hourly settlements in its comments to FERC on the price formation initiative in March. (See pp. 17-18 of the comments.)
PJM
In an April order on pricing of reserves, FERC rejected as out of scope a call from Public Service Enterprise Group that PJM implement five-minute settlements (ER15-643).
PJM Executive Vice President and COO Mike Kormos said in an interview after the FERC meeting that the change “was on the radar for sure.”
He noted that the order may require generators to make software changes and update old meters.
“It’s not just going to be ‘What’s the impact on PJM?’” he said. “It’s ‘What’s the impact on everybody?’”
ISO-NE
ISO-NE is already discussing with market participants a switch to five-minute settlements. At the Sept. 2 New England Power Pool Markets Committee meeting, RTO officials said they plan to settle generation, pump hydro and imports and exports on a five-minute basis but will continue to settle load assets and bilaterals hourly in real-time.
ISO-NE spokeswoman Marcia Blomberg said the idea of settling bilaterals subhourly also is under discussion.
Real-time reserve payments and inadvertent energy also would be settled every five minutes but the charge allocations would remain hourly.
On Sept. 2, the RTO told the NEPOOL Markets Committee that it plans to present Tariff language changes in November with a vote in December and implementation in 2017.
“We’re still reviewing the NOPR and evaluating what’s needed for compliance, but in terms of the proposal we’re discussing with participants, significant changes to the ISO’s settlement systems would be required to accommodate new calculations and significantly increased data volume, and market participants’ information systems would also require changes,” Blomberg said Monday.
NYISO announced Wednesday that its Board of Directors has selected Bradley C. Jones, senior vice president and COO of ERCOT, to replace Stephen G. Whitley as president and CEO, effective Oct. 12.
Jones is a distinguished energy industry executive with 29 years of wide-ranging experience, including grid operations, power plant operations, generation development, project finance, wholesale and retail market design, and regulatory and legislative affairs.
At ERCOT, Jones had responsibility for operations, grid planning and commercial operations.
Jones (left), Whitley (right) (Source: NYISO)
Jones joined ERCOT from Luminant, the competitive generation subsidiary of Energy Future Holdings, where he was vice president for government affairs. He previously worked at TXU Corp., rising from a plant engineer to become vice president for generation development.
A licensed professional engineer, Jones has a bachelor’s in mechanical engineering from Texas Tech University at Lubbock and an MBA from the University of Texas at Arlington.
“Brad has a strong commitment to reliability and a firm belief in the power of markets to benefit consumers,” NYISO Chairman Michael Bemis said in a statement. “His talent, experience and demonstrated commitment to excellence make him a great choice.”
Jones was chosen following a nationwide search conducted by Heidrick & Struggles. He could not be immediately reached for comment.
Whitley, appointed CEO in 2008, will remain with the ISO during the transition and then act as an advisor to the board.
The developers of the abandoned PATH transmission project would be denied recovery of more than $10 million of their $121.5 million claim under an initial decision by a FERC administrative law judge Monday.
Judge Philip C. Baten recommended that the commission deny the developers, American Electric Power and the former Allegheny Energy (now FirstEnergy), recovery of lobbying and advertising costs as well as part of their legal costs and losses on the sale of the property they acquired (ER09-1256-002, ER12-2708-003). The commission can accept the recommendations in whole or in part.
The proposed 765-kV “coal by wire” Potomac-Appalachian Transmission Highline project was approved by PJM in 2007 to run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md.
By 2011, however, PJM said the need for the line had moved several years beyond 2015 due to reduced load growth following the recession. The PJM Board of Managers ordered transmission owners to suspend work on the line pending a more complete analysis in 2011 of all upgrades in its regional transmission plan and terminated it in 2012.
Victory for Pro Se Interveners
Although the developers would recover most of their request, the judge’s ruling was a victory for two PATH opponents from West Virginia, Keryn Newman and Allison Haverty, who filed a pro se intervention challenging the companies’ request for recovery of $6 million in spending on lobbying and advertising campaigns intended to win political support for the project. The judge denied recovery of any of the expenses.
Baten also said $3.6 million in losses that the companies incurred on past land sales are not recoverable and that recoveries from any future land transactions “must be accomplished by commercially reasonable procedures.”
The judge also denied recovery for part of $3.9 million in legal expenses, for which the companies’ failed to provide documentation, and cut the companies’ proposed 10.4 % return on equity for the abandonment costs to 6.27%.
But Baten approved recovery for the purchase of property for a planned substation in Maryland and rejected a request by state consumer advocates to reject $29 million in spending incurred in 2010-2012 as imprudent.
The advocates said that the PATH companies should have recommended to PJM that the project be terminated by the beginning of 2010 and that expenses between that point and the actual termination should be denied.
The judge ruled that the expenses were recoverable because the PATH companies had a contractual obligation to construct the transmission projects as assigned by PJM. “The PATH companies did behave as a prudent utility by proceeding with their assigned obligations until otherwise instructed by PJM,” he wrote.
First Impression
Baten said that the case “presents significant issues of first impression” on FERC Order 679, a 2006 initiative that sought to accelerate transmission investment through incentives.
“This case addresses some new issues and gives the commission a unique one-stop opportunity to review and set policies for the comprehensive litigation scheme arising from Order No. 679,” Baten wrote.
The PATH project was initiated with PJM’s 2007 Regional Transmission Expansion Plan, and in 2008 FERC accepted a formula rate that entitled the developers to recover all prudently incurred costs if the project were cancelled.
In 2012, the companies filed for recovery of $121.5 million in abandonment costs. After settlement attempts with opponents failed, hearings in the case were held in March and April.
Lobbying Campaign
The pro se interveners contested spending on public relations agencies, advertising and public coalitions intended to influence public officials during the zoning and certificate of public convenience and necessity (CPCN) proceedings in Maryland, Virginia and West Virginia.
“When utilities are seeking selection or CPCN approvals from governmental entities, the utilities should rely on the established governmental approval processes to persuade the officials and not indulge in collateral efforts such as public education, outreach and advertising activities,” the judge ruled. “… If the selection or CPCN application has merit, the governmental selection process provides a sufficient vehicle for the utilities to present their engineering, marketing and economic studies and thereby hope to merit the vote of approval from these officials. In this regard the PATH companies spent over $8 million on attorney fees to prosecute the CPCNs before the respective governmental bodies, which begs the need for these collateral expenses.”
Among the spending rejected was $332,000 on a public opinion poll, $2.7 million in advertising and $94,000 paid to the then head of the West Virginia Democratic Party, Larry Puccio.
The judge said that the “nature and origins of the PATH companies’ business relationship with Puccio are somewhat amorphous” and that the companies paid him $31,000 “before his assignments were even formulated.”
“The invoices of record provide little description of his services. When the PATH companies were asked in discovery to provide additional details, their response was that such records are not available. While the PATH companies make protestations that Puccio’s services were not to lobby and instead were to educate the public and public officials, without proper documentation the only factual inference that can be drawn is that his services were to influence public officials, and the PATH companies have failed in their burden of proof to show otherwise.”
Load representatives said Thursday they will oppose PJM’s proposal to increase the installed reserve margin (IRM) to 16.6%, from 15.7%.
“There’s going to be a lot of push back on this,” said James Wilson, a consultant to state consumer advocates, who criticized what he called PJM’s “arbitrary” choice of a load model. “There’s quite a lot of load models that would fit equally well” but result in lower reserve margins, Wilson said.
Ed Tatum said the proposal prompted a “fairly violent” reaction among his colleagues at Old Dominion Electric Cooperative and threatens to renew the “IRM wars” of previous years.
Tatum said the increase in the IRM was “counterintuitive” given the higher performance expectations of PJM’s new Capacity Performance product. As a result, he said, load representatives will challenge the “overly conservative” assumptions PJM used in calculating the figure.
PJM’s Patricio Rocha-Garrido said the increase resulted from changes in 2015 capacity and load models as well as a decline in the capacity benefit of ties (CBOT) — expected capacity imports.
Rocha-Garrido noted that seemingly large increases in IRM may not have that much impact on the forecast pool requirement (FPR), which determines the amount of capacity procured in the annual Base Residual Auction.
The reliability requirement is calculated based on the 50/50 peak load forecast for the delivery year multiplied by the FPR. The FPR is increasing from 1.0847 to 1.0881 (from 8.47% to 8.81% above the peak load forecast.)
The increase is a result of a new load model (2003-2012) that better represents the coincident peak distribution in the 2015 load forecast, Rocha-Garrido said.
The CBOT was reduced because the “rest of world” peak demand is becoming more coincident with the PJM peak, he said.
PJM will seek members’ endorsement of IRM and associated parameters for delivery years 2016 through 2019 beginning in October, with final approval by the PJM board expected in December or January.
New Methodology Could Lower Summer 2018 Forecast by 2.6%; Winter down 1.8%
PJM could lower its 2018 summer peak load forecast by 2.6% as a result of new forecasting methodology that incorporates more recent economic data, a shorter weather simulation and the energy efficiency of air conditioners and electric appliances.
The new methodology also would reduce the winter 2018 forecast by 1.8% over the current official projection.
The forecast outlined to the PC last week will be finalized after an additional update to economic data, equipment index trends and any additional equipment “saturation” data by zones.
Manual language documenting the new methodology still needs to be developed and presented to the PC and MRC.
PJM said the new methodology will reduce the error rate for forecasts three years into the future to 1.5%, compared with the current method’s 6.6%.
One significant change is the RTO’s effort to improve its weather forecasts to reflect a trend of higher peak temperatures.
The RTO has based its forecasts on temperature and humidity data from 26 weather stations dating back to 1973. But a new analysis revealed that peak readings for 1993-2013 were higher than those for 1973-1993.
As a result, PJM’s Andrew Gledhill said, the RTO plans to exclude the earlier data and rely on that from 1994/95. It will reevaluate the historical base about every five years. (See “Climate Change Impact? Higher Highs has PJM Adjusting Weather Forecasts,” in PJM Planning Committee Briefs.)
ODEC’s Tatum said PJM’s plan to reevaluate the time sample for the weather forecasts could inject subjectivity into the modeling, creating a temptation to make changes “to get the answer you want.”
But PJM’s Tom Falin said the weather analysis will be done independently and not evaluated based on its impact on the forecast load.
At the Oct. 1 Markets and Reliability Committee meeting, PJM officials will discuss how they plan to incorporate the new methodology into its capacity auctions. Stu Bresler, senior vice president of markets, said adjustments will have to be made to ensure the RTO is not double counting energy efficiency, which can offer into the auction as a capacity resource.
Action Delayed on Voltage Threshold for Competitive Projects
PJM delayed a vote on a plan to exclude transmission reliability projects below 200 kV from competition, saying it wants to refine the proposal in response to stakeholder comments.
PJM said reliability projects below 200 kV are almost always allocated to one zone and thus automatically assigned to the incumbent transmission owner. The “voltage floor” would allow the RTO to eliminate the cost of evaluating competitive proposals in cases where the likely solution is a transmission owner upgrade. It would not apply to market efficiency projects.
Competitive developers expressed reservations about the proposal at the August PC meeting. (See “Developers Wary of ‘Voltage Floor’ on Competitive Projects” in PJM Planning Committee Briefs.)
At last week’s PC, PJM distributed an expanded chart for how the RTO would handle projects between 100 kV and 200 kV and those above 200 kV or below 100 kV. PJM’s Sue Glatz said the chart “narrows the scope of discretion” for PJM in determining whether or not to open a project to competition.
ITC Holdings’ John Kopinski said the chart made his company more comfortable with the proposal, which he said was consistent with the FERC-approved process for deciding which projects are competitive and which are reserved for incumbents. “You’re not really changing what’s competitive and what’s not,” he said.
Paul McGlynn, general manager of system planning, said PJM will modify the chart and proposed Operating Agreement language to reflect stakeholder comments from the meeting. PJM would like to implement the change in time for the 2016 Regional Transmission Expansion Plan.
Winter Peak Reliability Study
PJM planners last week outlined new rules for separately modeling winter reliability as part of the RTEP.
The changes to Manual 14B: PJM Region Transmission Planning Process would require planners to conduct a reliability analysis to ensure that the grid can deliver enough generation to meet the 50/50 winter peak. It will model generators by fuel class based on historical operation during winter peak loads.
In the past, PJM has planned for reliability based only on its summer peak load.
The changes will be brought to an endorsement vote at the PC next month, with plans to incorporate the study in the 2016 RTEP.
At the Transmission Expansion Advisory Committee meeting later Thursday, planners presented the results of their first study under the new rules, which defines winter as December through February. (See pp.11-24 of the presentation.)
The analysis looked at thermal and voltage violations both with and without consideration of gas contingencies. The North American Electric Reliability Corp.’s transmission planning standard (TPL-001-4), which takes effect Jan. 1, requires PJM to consider extreme system events such as the loss of a large gas pipeline serving significant generation.
PJM analyzed 30 gas pipeline and compressor failure contingencies that could result in the loss of 1,000 MW or more of generation.
Two contingencies, for pipeline outages in EMAAC, suggested the potential loss of 10,000 MW of generation, although officials said the generation would not go offline immediately because of the ability to burn “line pack” gas.
McGlynn said the results of the winter study did not suggest “the sky is falling” but reinforced the need for criteria to capture problems not seen in the light load or summer analyses.
Manual Language on Multi-Driver Projects OK’d
Members approved manual changes documenting how PJM will oversee transmission projects that have multiple benefits. The new rules on multi-driver projects are documented in manuals 14B and 14A: Generation and Transmission Interconnection Process.
Multi-driver projects have benefits in at least two categories, including baseline reliability upgrades, market efficiency and public policy.
States seeking to meet public policy objectives could sign on to projects after they have been approved. But once rights of way or equipment such as transmission towers have been acquired, states would be liable for costs “even if they didn’t go forward with the solar farm or wind farm,” said PJM’s Fran Barrett.
Long-Term Firm Transmission Service Study
The PC approved the charter for a group considering changes to the way PJM conducts studies for long-term firm transmission service.
The group, which resulted from a problem statement approved in April, has met twice, with a third meeting set for Sept. 24.
It will determine if changes are needed to:
Modeling practices for long-term firm transmission service requests (TSRs) in RTEP power flow cases;
Study methods used in RTEP and new service queue studies; and
Cost allocation requirements associated with long term TSRs.
PAR Transmission and Withdrawal Rights
Planners gave stakeholders the first read on rules governing how phase angle regulators (PARs) that redirect energy flows can qualify as controllable AC merchant transmission facilities.
The proposal resulted from a problem statement proposed last November by PSEG Energy Resources & Trade.
PJM currently awards withdrawal and injection rights to controllable AC and DC merchant transmission facilities using only variable frequency transformer (VFT) technology, which excludes PARs. (See “PSEG Seeks Injection Rights for PARs” in PJM Planning Committee Briefs.)
The task force appointed to review the issue endorsed a PJM staff recommendation after staff determined through flow control analyses that PARs “did not show any significant deviation from other controllable AC or DC type installations.”
The task force said that PARs did not harm holders of existing injection and withdrawal rights “assuming reinforcements identified for PAR installations were made.”
PAR owners will be required to comply with rules governing allowable deviations for all resources that are self-scheduled. The operators must be able to control their flows automatically, with the ability to manually adjust.
PJM will allocate costs for PAR facilities consistent with the methodologies used for HVDC and VFTs.
The new rules will be added to Manual 14E: Merchant Transmission Specific Requirements; no Tariff change is required.
None of the 10,017 MW of additional capacity committed in the 2017/18 transition auction will be calculated in this week’s incremental auction for the delivery year, PJM said.
“Originally, we said yes, the new commitments — the incrementally additional committed megawatts — would be rolled into capacity,” Stu Bresler, PJM senior vice president for markets, told the Market Implementation Committee. However, he said, “The Tariff will not allow us to do that. It’s very specific in the calculation of how many megawatts we procure or release.”
But, he said, PJM believes that incorporating new capacity into the incremental auctions is “the right thing to do” and will be introducing a Tariff change at the Oct. 1 meeting of the Markets and Reliability Committee.
If a load forecast changes between a Base Residual Auction and the corresponding delivery year’s incremental auction, PJM adjusts its reliability requirements, Bresler said.
“Conceptually, if the reliability requirement goes up, PJM could buy more capacity. If it goes down, which has been the trend, the requirement drops, and PJM could sell off previously committed capacity in the incremental auction,” he said. “Participants could buy that as replacement.”
Bresler said that if the Tariff change is approved, PJM expects to include additionally committed capacity in the third incremental auction for the 2016/17 year, to be held in February. The transition auction for that year procured 4,246 MW of additional capacity.
The operator of the R.E. Ginna nuclear plant in western New York has reached an agreement to keep the financially stressed generator operating.
Administrative law judges for the New York Public Service Commission said Wednesday that a joint proposal for the PSC-ordered reliability support services agreement between Constellation Energy Nuclear Group and Rochester Gas & Electric is expected to be filed by Sept. 23.
The judges posted a revised schedule calling for comments on the agreement by Sept. 30, with an evidentiary hearing to be held on Oct. 14 (14-E-0270).
Parties to the agreement in principle include the PSC staff, the New York Division of Consumer Protection and a group of interveners representing commercial and industrial customers.
Entergy Nuclear, which has plants in western New York and the Hudson Valley, and NRG Energy have opposed the RSSA throughout the 14-month proceeding. The companies will neither support nor oppose the agreement, the filing said.
Environmental groups Alliance for a Green Economy and Citizens’ Environmental Coalition will oppose the agreement in part, but the objectionable sections were not identified.
The out-of-market contract is expected to raise rates for customers in the Rochester area. The PSC recently adopted a temporary rate surcharge to lessen rate shock when a final agreement is sent to the commission. (See NYPSC Approves 5.2% Ginna Rate Surcharge.)
SPP is preparing for the Environmental Protection Agency’s Clean Power Plan by beginning outreach to state officials and planning to form a task force under its Strategic Planning Committee.
The RTO scheduled a two-hour webinar to kick off the effort on Friday, Sept. 18. Lanny Nickell, SPP’s engineering vice president and point man for CPP compliance, told the SPC during its August meeting that all 14 states in the RTO’s footprint have been invited.
While there have been no requests for SPP to develop a plan or trading rules, the RTO says a regional approach would be easier to implement.
The SPC tabled a motion to form a CPP task force and instead asked staff to work with Golden Spread Electric Cooperative’s Mike Wise, the committee chair, to draft a scope document to better understand and pursue the regional-trading issue.
Nickell said SPP will include modeling futures based on the final EPA rule in its 2017 Integrated Transmission Plan’s 10-Year Assessment to determine how it impacts the RTO’s transmission needs.
SPP’s regulatory staff is currently meeting with key state legislators, according to an update given to another task force responsible for gas-electric timeline coordination.
SPP-MISO Settlement to be Filed Oct. 9
David Kelley, SPP’s director of interregional relations, told the RTO’s Seams Steering Committee last week that SPP and MISO plan to file a settlement agreement with FERC on Oct. 9 that could bring an end to their dispute over the latter’s use of a 1,000-MW contract path between its North and South regions.
“There’s not a lot I can share publicly,” Kelley said, “but I can discuss the schedule.”
The proposed settlement also was discussed by MISO members at meetings last month. (See “Settlement with SPP over 1,000-MW Limit Will Eliminate ‘Hurdle Rate’” in Markets Committee Briefs.)
SPP RE Reliability Assessment Webinar
SPP and the SPP Regional Entity have scheduled a 30-minute webinar on the 2015 winter reliability assessment for Sept. 23. SPP RE staff will present an overview of the draft assessment and solicit feedback before it is finalized with the North American Electric Reliability Corp.
Registrants will receive the draft assessment and presentation for review.
CAMBRIDGE, Mass. — Speakers at the Northeast Energy and Commerce Association’s dinner meeting last week discussed pending legislation in Maine, the future of the proposed Northern Pass Transmission project and net metering.
The state’s Site Evaluation Committee has a 10-step process for approving such projects. “The governor has been clear that she is waiting for the site evaluation process to play out,” Allegretti said.
Christopher Sherman, president of New Hampshire transmission for NextEra Energy, said one of the investor-owned utilities in Massachusetts earlier this year reached the 4% limit on the integration of net-metered generation onto the grid.
“The governor’s own bill [which would raise the cap to 6%, with future increases left to state regulators] will be considered at a hearing by the end of this month, with the possibility the legislature will pass a bill later in the fall,” Sherman said.
Sandi Hennequin, vice president of U.S. public affairs for Nova Scotia-based Emera Energy, mentioned a bill backed by Maine Gov. Paul LePage that would allow local distribution utilities, which were divested after restructuring in 2000, to own some generation assets.
The bill would require the Public Utilities Commission to determine “that ownership is beneficial to the utility’s ratepayers” and to “impose terms, conditions or requirements the commission determines are necessary to protect the interests of the utility’s ratepayers.” The bill was introduced last session and has been held over for consideration during the coming session.
Patrick C. Woodcock, director of the governor’s energy office, said LePage saw the need for the legislation because of ambiguity about whether affiliates of local utilities can own generation. Woodcock said neither the state’s restructuring law nor a recent court ruling provided clarity. The case involved a proposed $333 million joint venture by Emera and First Wind to finance wind farms in the state.
“The governor asked, ‘Does it really make sense to have this iron-clad prohibition?’” Woodcock said in an interview after the dinner. He said limited utility ownership of generation could help the state modernize older hydro facilities.
“I think there’s an opportunity there for some of the utilities to benefit from generating from solar,” said Maine Rep. Larry C. Dunphy, who introduced the bill on the governor’s behalf. “There’s a number of motivations.”
