Page 1498 – RTO Insider

December 8, 2015

NYISO Seeks OK for New Scarcity Pricing Rules

NYISO last week asked for FERC approval to change its scarcity pricing logic, saying the proposed rules will more closely reflect the real-time value of demand response (ER16-425).

Scarcity pricing determines the value of energy and certain ancillary services when DR resources are called upon to maintain system reliability. The purpose is to ensure that real-time prices reflect the costs associated with deploying DR, the filing says.

NYISO said the filing was prompted by New York transmission owners’ concerns that its current methodology could result in uplift because of inconsistencies between prices and resource schedules.

NYISO is also proposing to increase the value of 30-minute reserves in the Southeast New York region from $25/MW to $500/MW, effective at all times. “This increase appropriately recognizes that [emergency demand response program] resources and [special case resources] have historically been called upon to protect reserves in SENY,” the ISO wrote.

NYISO is asking FERC to accept the revisions by Jan. 29, 2016, to give it enough time to develop and deploy software changes. The proposed revisions would become effective on or before June 30.

NYISO implemented its current, ex-post scarcity pricing logic in 2013. The logic allows it to adjust real-time energy prices after resource schedules have already been established in the load zones in which DR resources are used.

─ William Opalka

December 8, 2015

Generators Dispute ISO-NE on Solar Capacity

By William Opalka

Generators are protesting the way in which ISO-NE calculated its installed capacity requirement for the 10th Forward Capacity Auction, saying the RTO hasn’t sufficiently vetted the way it reflects behind-the-meter solar.

In anticipation of its 2019/20 auction scheduled for February, ISO-NE filed its ICR with FERC on Nov. 12 (ER16-307).

The RTO said the only change in its assumptions from prior auctions was the inclusion of behind-the-meter solar resources that are not yet reflected in historical loads, which resulted in a 390-MW reduction in the load forecast.

In a protest filed last week, the New England Power Generators Association said the calculation should be determined by a Section 205 proceeding before FERC, after a more complete examination by the New England Power Pool.

NEPGA and Dominion Resources, which owns nuclear and gas-fired generation in the region, said that the RTO had discussed with NEPOOL stakeholders how the new methodology would be implemented but had not adequately examined related market and operational issues.

The ICR value failed to win endorsement by the NEPOOL Participants Committee, garnering a bare majority of 53%.

“A number of members expressed their opposition to those ICR values because of their view that the values were overstated because behind-the-meter PV was not properly and fully accounted for in the load forecast,” the committee said in its comments.

In a January order accepting the RTO’s filing in advance of FCA 9, the commission directed it to conduct a stakeholder process “to fully explore the incorporation of distributed generation” into its ICR calculations. (See FERC Rejects Bid to Increase DR, Distributed Generation in ISO-NE Capacity Calculations.)

ISO-NE said it developed the 390-MW solar forecast with stakeholders, including state regulators, over a 10-month period.

“In order to determine the load reduction impact of [behind-the-meter] PV resources, the ISO used solar PV production data of currently installed behind-the-meter PV resources provided by the states and distribution utilities. The ISO calculated the PV already embedded in load and then adjusted the load forecast by the forecasted” resources, the RTO wrote.

The New England States Committee on Electricity, which last year challenged the exclusion of distributed solar resources from the ICR calculations, supports ISO-NE’s current ICR filing.

“The ICR … must consider in a timely manner the rapid development of solar PV resources that are affecting system demand,” it said in its comments. “New England consumers are increasingly investing in clean, distributed energy resources in furtherance of state energy programs and policies. The ICR cannot be divorced from these significant investments in solar PV resources.”

ISO-NE is asking for FERC approval by Jan. 9.

December 8, 2015

New NYISO Head: New York a ‘Fantastic Opportunity’

By William Opalka

With transmission bottlenecks and aging and unprofitable legacy generation, New York presents a host of challenges for any experienced energy executive, let alone a newcomer. But a path-breaking initiative to transform the state’s power business that has the whole nation watching and an established wholesale market proved an irresistible combination for Bradley Jones.

“This is a fantastic opportunity,” Jones, who took over as president of NYISO in October, told RTO Insider last week. “It’s a great state, it’s a great market and I’ve enjoyed Albany quite a bit. It’s a wonderful opportunity and it’s the right place for me.”

‘The One I Wanted’

Jones, 53, came to New York from ERCOT, where he was senior vice president and chief operating officer — presumably in line to contend for the top spot next year, when current CEO H.B. “Trip” Doggett retires.

In August, however, ERCOT named General Counsel Bill Magness as Doggett’s successor. Thus, after spending his entire, near-three-decade professional life in the Southwest, Jones moved cross country to replace the retiring Stephen C. Whitley, who headed New York’s power grid for seven years. (See New NYISO Head Brings Broad Experience.)

“I did have many opportunities, but this is the one I wanted,” he said. “One of the things is the market changes I was trying to make happen at ERCOT I have found that New York had already done.”

One of those is NYISO’s look-ahead capability, which allows its operators to identify upcoming changes in conditions, such as equipment outages or changes in renewable energy output, and prepare the system to most efficiently respond.

“I was amazed to find that NYISO already had that in place and had already been applying those tools,” Jones said.

Adding Transmission

Jones has extensive experience in what New York policymakers want — namely building infrastructure and integrating wind. “I hope my experience at ERCOT will show how to manage these things,” he said. “My three initiatives, without joking, have always been transmission, transmission, transmission.”

He said he was amazed that the ISO has had to curtail low-cost hydroelectricity because of the lack of transmission to move it west to east. But he’s encouraged by the New York Public Service Commission’s recent initiative to eliminate bottlenecks for downstate load centers.

The PSC is expected to vote this month on two transmission projects totaling an estimated $1.2 billion. The proposed routes would satisfy Gov. Andrew Cuomo’s Energy Highway goal to bring 1,000 MW of power generated upstate to areas of high demand in southeastern New York and New York City. (See NYPSC Staff Recommends $1.2B in Transmission Projects.)

There are also transmission proposals to access wind resources in northern New York to help the state meet Cuomo’s goal of 50% renewable electricity by 2030. “We can increase wind or renewables capacity by 50%, somewhere around 17.5 million MWh a year, from west and north to the rest of the state,” Jones said.

Jones said the state’s Reforming the Energy Vision will mostly affect change at the distribution network. “We expect we will be able to develop very quickly a platform for how that will work. We will be able to interconnect very quickly,” he said.

Strategic Plan

On Monday, NYISO released its 2016-2020 Strategic Plan.

The plan addresses several trends:

Gas-electric coordination: “The reliability of the bulk power system is increasingly linked to the performance of the natural gas pipeline infrastructure, raising reliability concerns related to fuel delivery during periods of peak demand.” The plan vows to improve coordination with the gas industry and develop market designs that promote fuel assurance among generators.
Integration of distributed energy resources: The plan anticipates that DER will grow due to improving economics and public policies, influencing the design of the grid. “The NYISO will work to integrate such resources into its markets in a manner that enhances system efficiencies through increased demand elasticity while deploying new planning and operational tools to ensure visibility into system conditions and future needs as distributed energy resources proliferate.”
Federal and state policies: The ISO’s markets and planning functions will have to respond with more complex market designs to accommodate the growing role of renewables and DER under the EPA Clean Power Plan and the New York State Energy Plan.

Shaking Hands with 500

Jones said he will implement the plan by engaging every employee. He started on his first day, standing at the entrance of a welcome barbeque to shake everyone’s hand. NYISO employs more than 500.

[Editor’s Note: An earlier version of this article mistakenly suggested that ERCOT had not yet chosen a successor for retiring CEO H.B. “Trip” Doggett.]

December 8, 2015

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — PJM will use the default economic capacity base load (CBL) to measure the non-summer response of Capacity Performance demand response under manual and Tariff revisions endorsed by the Market Implementation Committee last week.

The method will allow PJM to bypass the more labor-intensive relative root mean square error (RRMSE) test. Extensive analysis has determined that the process would deliver accurate CBLs for most customers, PJM’s Pete Langbein said.

Market Monitor Joe Bowring reiterated his objection to the method.

“We think that the proposed measurement verification for DR for the winter … would permit double-counting, and that’s not appropriate,” he said. “The simple fact that it may be administratively difficult to do [the mean square test] is not a reason not to do it.”

Problem Statement to Define Operating Parameters Approved

Members endorsed a problem statement to develop standardized definitions of operating parameters under Capacity Performance.

PJM proposed the initiative after discovering that market sellers and PJM had different interpretations of various parameters for CP and base capacity resources.

PJM wants to expedite the work of defining the terms before June 1, when the CP rules take effect for delivery year 2016/17.

The definitions are expected to impact Manuals 11, 15 and 28 and include such terms as soak time, start-up time, start-up cost and no-load cost.

Several stakeholders expressed concern over rushing through defining such important terms, and many agreed that the MIC is not the appropriate committee to handle the task.

Market Monitor Joe Bowring took issue with the idea that the work is time-sensitive.

“There is no urgency. The issues, to the extent that any exist, have been around for a long time,” he said.

PJM Provides Update on Line-Loss Refunds

PJM CFO Suzanne Daugherty provided an update on marginal loss surplus allocation billing adjustments, responding to a recent FERC order regarding the seven-year-old issue.

Daugherty said PJM has completed the billing adjustments that were affirmed in FERC’s November order. (See FERC: PJM Entitled to Recoup Line-Loss Credits.)

“Everyone who was owed a recoupment credit got it in full the summer of 2012,” she said. If there is any money left to be refunded, it will only be going to members who paid default allocation assessments that summer, she said.

“There is no more charging related to this topic that I expect to occur,” she said.

— Suzanne Herel

December 8, 2015

ITC Accused of Overcharges in Depreciation Dispute

By Amanda Durish Cook

ITC Midwest is overcharging its customers for network upgrades because it isn’t applying for tax breaks to which it is entitled, customers and Iowa officials told FERC last week.

Among the projects affected is Wisconsin Power and Light’s 201-MW Bent Tree Wind Farm in southern Minnesota.

In an unexecuted facilities services agreement filed with FERC, ITC said it needs $38.8 million in network upgrades to support Bent Tree’s generation. It sought to bill WPL $418,020 monthly over 25 years.

WPL asked FERC last week to reject the rates, claiming the charges are excessive because they fail to reflect the “bonus” depreciation that ITC could claim on its federal taxes (ER16-206).

WPL’s sister company, Interstate Power and Light in Iowa, filed a motion to intervene on Nov. 24, saying it could face an identical situation over its Marshalltown Generating Station, which is interconnecting into ITC’s transmission system in Iowa.

“IPL has estimated that ITC Midwest’s annual revenue requirement is roughly $18 million higher in 2015 than it would have been had ITC Midwest taken available bonus depreciation in prior years in which it was eligible to do so. This results in an ITC Midwest transmission rate which is approximately 5% higher, unnecessarily increasing charges to ITC Midwest’s customers — including IPL and its customers,” IPL stated in its motion.

The Iowa Office of Consumer Advocate, Iowa Consumers Coalition, Iowa Utilities Board and Resale Power Group of Iowa have all filed to intervene in the matter.

“The IUB also understands that when bonus depreciation is utilized, it is done so on all capital investments within a given class of assets in a given year, not just selected projects. Thus, ITC Midwest’s choice to not utilize bonus depreciation will affect not only the Bent Tree or Marshall Generating Station network upgrades, but could affect all capital investments in the asset class, including investments elsewhere in the ITC Midwest transmission system, which could directly affect Interstate Power and Light’s customer costs of transmission service,” the Iowa Utilities Board said.

Likewise, the Iowa Consumers Coalition said ITC should “articulate a sound rationale for not electing to take bonus depreciation.”

ITC did not respond to a request for comment.

December 8, 2015

Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement

By Ted Caddell

In recent policy disputes over capacity markets and energy price caps, FirstEnergy and the independent power producers of the Electric Power Supply Association have usually been on the same side.

When EPSA won a federal appeals court ruling voiding FERC’s authority over demand response last year, FirstEnergy asked the commission the same day to prevent DR from being included in PJM’s capacity auction.

But when the Akron-based utility announced last week that it had reached a settlement with the staff of the Public Utilities Commission of Ohio to secure guaranteed rates for several of its merchant plants, the company found itself under attack by many of its former allies.

By Thursday, EPSA had corralled Dynegy, Talen Energy, the PJM Power Providers Group (P3), the Sierra Club of Ohio, AARP and others in a coalition blasting the deal. Dynegy and Talen threatened to sue.

“The fault of FirstEnergy’s inability to compete in Ohio lies with FirstEnergy and it should not be dependent on the citizens and businesses of Ohio to provide a bailout,” said Robert C. Flexon, CEO of Dynegy, which increased its stake in PJM with its purchase of 12,500 MW of generation from Duke Energy and Energy Capital Partners earlier this year. (See Dynegy Wins FERC OK for $6.25B Duke, Energy Capital Partners Generation Deals.)

“Dynegy will pursue all available avenues, including litigation, to prohibit the power purchase agreement from being enacted so as not to compromise the competitive market design, and we strongly encourage the PUCO commissioners to oppose and vote down this adverse anti-market public policy.”

Dynegy said that FirstEnergy is already enjoying the benefits of the wholesale market and shouldn’t need any further assistance.

“Recent market awards indicate that FirstEnergy is already set to receive significant revenue for capacity at all of their Ohio plants for the next three years,” Dynegy said. “According to FirstEnergy’s own data from their recent investor presentation at the Edison Electric Institute’s Financial Conference, FirstEnergy’s fleet has been awarded more than $2.3 billion in revenues over the next three planning years from the PJM capacity auction with all of their generating plants clearing the most recent capacity auctions, which is significantly more than the amount expected at the time of FirstEnergy’s original subsidy request. As part of the award, FirstEnergy’s plants are now obligated to run through May 31, 2019, without the PPAs.”

Reliability Threat

FirstEnergy has said that it needs the income guarantees, in the form of PPAs for its Davis-Besse Nuclear Power Station, the W.H. Sammis coal-fired plant and its share of Ohio Valley Electric Corp.’s generation output, to keep them profitable.

American Electric Power has a similar proposal pending before the Ohio commission. Without the guarantees, the companies say, they might have to retire their plants, threatening system reliability.

Sixteen parties, including PUCO staff and civic groups, signed on to the proposed settlement filed with the commission last Tuesday (14-1297-EL-SSO). Several other organizations, including the Office of the Ohio Consumers’ Counsel, rejected the deal and joined in a motion to reopen the record.

FirstEnergy’s first proposal, which PUCO staff rejected earlier this fall, called for income guarantees for 15 years. The settlement seeks income guarantees for eight years. Ratepayers would make FirstEnergy whole if its generators were not profitable based on their capacity and energy sales in the competitive market.

Although PUCO staff approved the settlement, it still needs approval of the commission. FirstEnergy said it expects the commission to hold hearings on the proposal early next year.

Picking Winners and Losers

Talen joined Dynegy in promising to contest the deal in court if it is approved by the commission.

“As you are aware [PPL, one of Talen’s predecessors] led successful legal challenges in the federal courts against generation subsidy initiatives in New Jersey and Maryland,” Talen spokesman Todd Martin said Thursday. Before PPL’s generation assets were spun off to form Talen, the company won court rulings voiding PPAs obtained by Competitive Power Ventures for two merchant plants. (See CPV Md. Plant Goes Forward Despite FERC Ruling.)

“We believe states with competitive electricity markets must let those markets operate without interference or subsidies, and should not in effect be picking winners and losers,” Martin said.

P3 President Glen Thomas said PUCO staff’s “about face” represents “corporate welfare at its worst.”

“Forcing customers to buy overpriced electricity from uncompetitive plants to deliver windfall profits to FirstEnergy is a holiday offering that only the Grinch could support,” said Trey Addison of AARP Ohio.

“This bailout would leave Ohio locked into outdated and costly coal and nuclear plants, when we should instead be working to transition to a cleaner and more competitive energy system,” said Shannon Fisk, managing attorney with Earthjustice. Fisk was involved in settlement negotiations on behalf of the Sierra Club but withdrew in protest just before Thanksgiving.

Also weighing in was anti-nuclear group Beyond Nuclear, which blasted any deal that would result in the continued operations of FirstEnergy’s Davis-Besse nuclear plant. “The ratepayers of Ohio would be gouged additional billions of dollars on their electricity bills to prop up the uncompetitive Davis-Besse atomic reactor, effectively being forced to fund 20 more years of radioactive Russian roulette at the problem-plagued atomic reactor,” Beyond Nuclear spokesman Kevin Kamps.

$20/MWh Premium

Despite the opposition, UBS analysts predicted last week that the commission will approve the PPAs, which the analysts valued at $68/MWh.

That would be $20 MWh above market prices, based on Ohio’s most recent auction for default service. PUCO in November accepted the results of AEP Ohio’s third wholesale auction to determine the default price through May 2018, at $48.29/MWh. That price will be blended in with result from other auctions to determine the price-to-compare for June 1, 2016, to May 31, 2018. The $48.29 price was the result of a 13-round auction with six competitive suppliers participating.

On Monday, UBS upgraded AEP to “buy” on the expectation that it will win PUCO approval of its deal.

FE: Looking out for Ratepayers

For its part, FirstEnergy said it wasn’t surprised to see the blowback from competitors.

It said it alone is looking out for Ohio’s ratepayers. Although residential ratepayers would pay an extra $3.25 to $3.50 a month during the first year of the deal, the company claims it will produce overall savings of about $560 million. FirstEnergy’s projections, which assume sharply higher natural gas prices in the latter years of the deal, have been widely disputed.

“FirstEnergy has stated from the outset that customers will likely see a monthly charge in the first three years under this arrangement, with the charges converting to credits for customers for the remainder of the eight-year term,” FirstEnergy spokesman Doug Colafella said Friday.

“Out-of-state power producers opposing our plan are betting on sharply higher power prices in Ohio down the road, so naturally they would oppose putting safeguards in place to protect our customers,” Colafella said. “Our proposal is that safeguard.”

December 8, 2015

New Generation Boosts ERCOT’s Reserve Margins Through 2025

By Tom Kleckner

ERCOT will add about 9,300 MW of additional capacity by 2019, relieving concerns that the grid’s reserve margins would drop as load continued to grow, according to a new analysis.

The updated 10-year Capacity, Demand and Reserves (CDR) report released last week shows a continuing rise in planning reserve margins — topping 20% in the “next several years.” The Texas grid operator’s reserve margin has stood at 13.75% since December 2010.

The latest CDR shows about 6,250 MW of planned resources have become eligible to be included since the May 2015 report (a net of 3,660 MW after discounting wind nameplate additions). Planning reserve margins increased for all years except 2016.

Gas turbines and wind and solar farms account for much of the expected new capacity. ERCOT said solar capacity should increase from its current 193 MW of installed capacity to 1,789 MW by 2017. Nameplate wind capacity is expected to grow 45% to more than 4,200 MW over the same period, while natural gas capacity is projected to grow 1% to more than 51,000 MW.

ERCOT’s director of system planning, Warren Lasher, said the new generation was responding to the state’s continued growth. “We continue to see the demand for electricity here increase as more people and businesses move into Texas,” he said during a Dec. 1 conference call.

“The generation mix is also growing and changing,” Lasher said. He said some of the capacity growth could be offset by fossil unit retirements as “changing environmental rules begin to take effect.”

ERCOT forecasts a peak of more than 70,500 MW next summer, growing to almost 78,000 MW by summer 2025.

Two years ago, ERCOT was predicting a 20% decrease in its reserve margin. The grid operator had come perilously close to rolling blackouts during a blistering summer of 2011 and plant construction was practically nil.

Recent summer temperatures have not reached predictions and new capacity has come online since then, but ERCOT also revised its planning standards last year. Staff has incorporated growth trends in customer accounts, or premises, to better project regional demand growth.

“We have been able to provide a more accurate look at future demand and energy use,” said Calvin Opheim, ERCOT’s manager of load forecasting and analysis. “I’ve been very happy with how our new forecasting model has performed.”

The latest CDR forecasts peak loads averaging more than 500 MW higher through 2021 than the forecast used for the May CDR. ERCOT said the report is based on average weather over the past 13 years and includes additional electricity demand from a liquefied natural gas facility near Houston, which is scheduled to be fully operational by summer 2019.

The CDR’s data on generation comes from information provided by resource owners.

The report counts as capacity 4,700 MW of coal generation ERCOT expects to retire as a result of EPA’s Clean Power Plan and Regional Haze Program. The draft Regional Haze rule would require scrubber upgrades or retrofits at 12 coal-fired units by 2020. A final rule is expected in several months. The next CDR update is scheduled for release in May 2016.

ERCOT Sets Another New Wind Peak

ERCOT set a new record for wind generation Nov. 25 with 12,971 MW. That accounted for nearly 37% of the grid’s load at the time (9:10 p.m.).

The wind peak is ERCOT’s third since Oct. 21.

December 8, 2015

Entergy Rebuffs Cuomo Offer; FitzPatrick Closing Unchanged

By Ted Caddell

Entergy said last week it is sticking to its plan to close the FitzPatrick nuclear generating station, despite a rescue attempt by New York officials and an offer by Exelon to provide it fuel at cost.

Entergy announced last month that competition from low-cost natural gas generation will force it to retire the 838-MW plant in late 2016 or early 2017, when the plant would otherwise be shutting temporarily for refueling. (See Entergy Closing FitzPatrick Nuclear Plant in New York.)

Then came news that New York Gov. Andrew Cuomo wants the Public Service Commission to mandate that 50% of the state’s electricity come from renewable sources by 2030. Cuomo also called for incentives to keep the state’s nuclear plants operating until then. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

At the urging of Cuomo administration officials, Exelon agreed to acquire enough fuel for FitzPatrick and to give Entergy until next June to decide whether to use it based on the clean energy mandate. The PSC said that the proposed “fuel bridge” would allow Entergy to delay its decision without purchasing the $50 million worth of fuel now.

The offers weren’t enough to change Entergy’s mind.

“We have explored every legitimate commercial arrangement that might have changed the decision regarding Fitzpatrick’s retirement,” Entergy spokeswoman Tammy Holden told The Post-Standard. “There is no viable alternative left to consider. The plant will retire at the end of 2016 or early 2017, as we previously announced and have formally advised” the Nuclear Regulatory Commission.

December 8, 2015

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM is drafting manual changes to document the parameter adjustment process under Capacity Performance rules.

The process allows a generation operator to request an adjustment if it believes its resource’s physical constraints will prevent it from meeting the parameters assigned by PJM.

Related revisions to Manual 11: Energy and Ancillary Services Market Operations will be presented for endorsement by the Markets and Reliability Committee this month.

At last week’s Operating Committee meeting, the RTO gave a presentation comparing the unit-specific parameter adjustment process with parameter limited schedule (PLS) exceptions.

Unit-specific adjustments would be permitted only because of ongoing, long-term operational limitations, said PJM’s Alpa Jani. Staffing, for example, would not qualify as a physical operating constraint.

PLS exceptions will be used to address short-term, temporary issues such as equipment damage.

Adjustment requests must be submitted to PJM no later than Feb. 28 before the delivery year. If the situation arises after that date, a waiver must be obtained from FERC.

Members also reviewed PJM’s new soak time parameter. Soak time is defined as “the minimum number of hours a unit must run in real-time operations, from the time the unit is put online (breaker closure) to the time the unit is at economic minimum or dispatchable.”

Until the new parameter is added to PJM manuals, adjustment requests similar to the soak time definition will be documented in the minimum run time parameter, and soak time will be noted in PJM internal documentation so it can be updated when a long-term solution is implemented.

In a related matter, the Market Implementation Committee approved an issue charge presented by Bob O’Connell on behalf of PPGI Fund A/B Development to study the process of requesting exceptions to the default parameter limited schedule. (See “Parameter Limited Schedule Exemption Process to be Reviewed” in PJM Market Implementation Committee Briefs.)

The work will be conducted as part of regular MIC meetings and will seek to identify improvements to existing practices for requesting and obtaining PLS exceptions. The group is expected to recommend manual and possible Tariff changes to the MIC by April.

Members Mull Performance Assessment Hour Notifications

PJM also gave the OC a presentation in response to stakeholder questions about performance assessment hours under Capacity Performance.

Generators are subject to steep penalties for failing to meet their capacity obligations during performance assessment hours — periods for which PJM has declared an emergency action. (Base capacity resources are exempt from such penalties except during the June-September summer peak season.)

Members discussed the best way for PJM to communicate the start and stop times of a performance hour. PJM is proposing to post the information in a banner on its Emergency Procedures web page. The notice would direct resource owners to a page where they will be able to find what is expected of them.

Several stakeholders said the information is so crucial that an alert should be placed on the PJM homepage.

PJM Assistant General Counsel Jen Tribulski cautioned that the placement of the notice on the site would not affect market sellers’ responsibility to perform.

“You’re excused from the penalties during the assessment hours if PJM didn’t call on you,” she said. “If we’ve called on you and we have not dispatched you down, you are expected to perform, regardless of whether there’s any notification on our website.”

Also under review is a new signal providing a “desired” basepoint that would be used during performance hours, but it’s not clear whether the signal would recognize a resource’s economic max or unforced capacity commitment.

Members also were told that all units must operate under their local reliability constraints, but having to do so will not excuse them from penalties for not meeting performance requirements.

Charter Approved for Metering Task Force

The committee approved a charter for a task force charged with reviewing metering policies and requirements and implementing best practices.

The group will consider classifications such as real-time telemetry versus revenue metering, generator versus transmission system metering and large generation versus distributed generation applications.

The task force will report recommended manual revisions to the OC. Its work is expected to take six months.

— Suzanne Herel

December 8, 2015

FERC Rejects SPP Proposal for Seams Transmission Projects

By Tom Kleckner

FERC last week rejected SPP’s proposal to create a new class of seams transmission projects, saying its plan was too broadly drawn (ER15-2705).

The commission’s Nov. 30 order said that SPP did not distinguish “the criteria to be deemed a seams transmission project from the criteria to qualify under SPP’s Order No. 1000 interregional processes.” It said the revisions “do not contain any prohibitions or limitations to support SPP’s assertions” that projects eligible for its Order 1000 interregional processes may not be classified and evaluated as seams transmission projects.

spp — FERC rejected SPP’s request to create a new class of seams transmission projects to supplement its approved highway-byway cost allocation.

SPP had proposed seams transmission projects as a new category to fill a gap in its transmission planning. It said the proposal would identify potential transmission projects that “may fall outside the Order 1000 interregional planning process or may not be eligible for cost allocation under SPP’s Order 1000 interregional processes,” such as projects involving external entities that are not neighboring planning regions.

SPP’s current rules designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a region-wide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.

SPP proposed to define a seams project as one operating at 100 kV or above and costing at least $5 million. It proposed a default regional cost allocation for such projects, with the RTO’s Board of Directors able to choose an alternate allocation at its discretion under certain conditions.

Xcel Energy protested the proposal, saying SPP had not provided “adequate analytical support” for the new category.

FERC agreed, saying the planning process for seams transmission projects “lacks clarity and does not adequately explain” how a seams project would progress from project identification to construction approval. It said SPP’s proposal for projects identified through joint special studies or coordination agreements “does not adequately define the methodology it will use to evaluate the project’s regional benefits.”

FERC said it wasn’t clear that regional review “will be transparent and include sufficient stakeholder involvement.”

The commission said, however, that SPP could make project-by-project filings for non-Order 1000 facilities that “may relate to seams concerns with an associated cost allocation and [justification for] the specific cost allocation.”

SPP legal staff expressed confusion over the ruling during a Dec. 3 meeting of the RTO’s Seams Steering Committee, saying it is “still digesting” the order.