Page 1367 – RTO Insider

December 27, 2016

CAISO Seeks Primary Frequency Response Market

By Robert Mullin

CAISO has kicked off an initiative to explore how it can procure resources equipped to automatically respond to disturbances in grid frequency.

The effort will examine implementation of a new market mechanism to compensate resources for providing primary frequency response — sending power into the grid within moments of a potentially destabilizing frequency event.

The new initiative is in response to NERC reliability standard BAL-003-1, which requires each balancing authority area (BAA) to carry sufficient capability to respond to a frequency event.

System operators seek to maintain the grid at a frequency of 60 Hz to maintain network stability. An uncontrolled drop in frequency creates the danger of cascading blackouts.

Under NERC’s standard, primary frequency response is the ability to respond to a deviation within about 20 to 52 seconds of occurrence. Such a rapid reaction requires that the resource automatically detect under-frequency and autonomously ramp its output without receiving a market signal or manual instructions from the ISO.

CAISO is seeking stakeholder input on developing a market mechanism to compensate resources for responding to frequency dips during the “primary” control horizon — just moments after the onset of the event.

While the initiative is primarily intended to help CAISO meet NERC’s requirement, the ISO hopes the effort will head off an issue expected to become more problematic as California moves to fulfill its ambitious renewable energy mandate.

“The ISO expects frequency response will worsen as nonconventional technologies increase,” Cathleen Colbert, senior market design and regulatory policy developer at CAISO, said during a Dec. 22 stakeholder call to discuss the initiative.

Nonconventional technologies typically have little or no inertial response to momentary changes on the grid; conventional generators have the ability to automatically vary their turbines’ rotational speed and output based on the pull of load. That built-in capability functions as a kind of damper for frequency excursions.

“The goal of introducing a primary frequency service would be, in the short term, to continue to support compliance with NERC’s frequency response requirement, which, without changes, will be more difficult in the long term as the generation mix changes to accommodate a renewable portfolio standard of 50% renewables by 2030,” the ISO said in an issue paper describing the initiative.

Last month, FERC proposed revising the pro forma generator interconnection agreements to require all newly interconnecting facilities, including renewable generators, to have primary frequency response capability (RM16-6). (See FERC: Renewables Must Provide Frequency Response.)

CAISO’s initiative will focus on whether the ISO should compensate resources for capital expenses associated with the equipment necessary to provide the service. It will also examine making payments for opportunity costs related to holding frequency response capacity in reserve and for operating expenses associated with providing response during an event.

Approved by FERC in 2014, BAL-003-1 requires each BAA to achieve specific performance measures to meet its “frequency response obligation” (FRO), which is calculated as the BAA’s portion of the overall obligation for the interconnection — referred to as the “IFRO.” (See FERC OKs Rules on Geomagnetic Disturbances, Frequency Response.)

The IFRO represents the minimum response needed to halt a decline in frequency resulting from the loss of two of the interconnection’s largest generators — the response necessary to head off reaching the “under-frequency load shedding” threshold of 59.5 Hz.

Based on an assessment of its generation and load relative to the rest of the Western Interconnection, CAISO says that its share of the region’s IFRO stands at about 23% — translating into 196 MW/0.1 Hz next year.

In 2015, CAISO determined that it would likely come up short of its obligation under NERC’s requirements, which took effect Dec. 1. To address the shortfall, the ISO filed Tariff revisions enabling it to enter annual contracts to acquire “transferred frequency response” — the transfer of frequency response performance across BAAs within an interconnection.

At the same time, the ISO committed to FERC that it would evaluate whether it could develop a market mechanism to cultivate a diverse set of resources to help the ISO meet the frequency response criteria.

The ISO is proposing a set of guiding principles for developing a primary frequency response market, which include:

Creating an environment in which the ISO fleet is positioned to provide sufficient frequency response;
Eliminating barriers to entry in order to allow all technologies to participate;
Producing price signals that incentivize adequate response; and
Ensuring compensation for frequency response-related capital investments if the capability becomes an interconnection requirement.

Stakeholders are being asked to consider whether the ISO’s existing ancillary services market generates sufficient compensation to enable the ISO to meet the NERC’s new reliability requirements.

The most significant argument in favor of developing a new market structure is that the ISO does not currently procure primary frequency response but must still meet NERC’s standard. The existing ancillary services market covers only the requisition of frequency regulation that qualifies as NERC’s “secondary” and “tertiary” control mechanisms following a frequency event — both of which respond to an explicit ISO market signal.

In addition to contracting for transferred response, the ISO relies on unloaded frequency response capability acquired through the current ancillary services procurement, Colbert said. However, resources procured during that process may not have the capability for a sufficiently fast response.

Additionally, the ISO has observed a “deteriorating trend” in its frequency response performance over the past two years when comparing its average capability with its obligation.

“We believe we have received guidance [from FERC] to explore other options,” Colbert said.

Stakeholders must submit comments on the issue paper by Jan. 12, 2017.

December 27, 2016

FERC Rejects Rehearing on Capacity Performance Penalty Exemption

FERC rejected a request to rehear its order blocking Tariff changes that would have exempted PJM capacity resources from nonperformance charges under certain circumstances.

The commission’s Dec. 22 order said the challenge by the PJM Utilities Coalition — American Electric Power; Buckeye Power; Dayton Power and Light; Duke Energy Kentucky; East Kentucky Power Cooperative; and Virginia Electric and Power — “does not offer any information or arguments that are new to this proceeding and primarily reiterates arguments advanced in PJM’s prior pleading” (ER16-1336-001).

The changes, approved by stakeholders following months of debate, would have exempted a capacity resource from penalties if it was following PJM’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. The changes were designed to discourage generators from self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges — behavior that PJM said would pose operational challenges and reliability risks.

The commission rejected the change in May, saying PJM had not shown that its operational concerns justified the proposal, which it said undercut Capacity Performance rules designed to ensure resources are available during a crisis. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)

The commission reiterated its conclusion in rejecting rehearing, saying “the existing incentives in the threat of a nonperformance charge and risk of losses due to self-scheduling were robust enough for resource owners to both properly maintain their units and follow PJM dispatch.”

– Rich Heidorn Jr.

December 27, 2016

FERC Approves PJM Rate Increase

By Rory D. Sweeney

Rejecting criticism over employee salaries and a lack of detail on other spending, FERC approved PJM’s requested rate increase, saying it was “adequately supported” (ER17-249).

The Dec. 22 order allows PJM to increase its composite rate from $0.3349/MWh to $0.36/MWh for 2017 and 2018, with a 2.5% annual increase in subsequent years through 2024, when the charge will reach $0.41/MWh. The first increase is effective Jan. 1.

Consumer advocacy group Public Citizen protested PJM’s filing, arguing that the increase was requested without first considering ways to reduce costs, such as limiting salary increases. (See Public Advocacy Group Files FERC Complaint over PJM Rate Increase.)

The commission said that the financial statements questioned by Public Citizen are “subject to adequate independent review” by stakeholders on the Finance Committee and noted the committee may reject unjustified expenditures and direct refunds to ratepayers.

Public Citizen also complained that the RTO provided no support for its spending on outside services, which the group said may include expenses related to political advocacy. FERC did not address the advocacy question but noted PJM testimony that outside labor services “includes building and ground maintenance, utilities, outside legal fees and cybersecurity monitoring” and said it provided sufficient detail justifying the expenses.

“PJM has implemented cost-control measures, including reducing the number of full-time equivalent contractors, renegotiating telecommunications and utility contracts, expanding PJM’s vendor pool to increase supplier competition, increasing PJM employees’ share of medical insurance costs and modifying PJM’s retirement benefits,” FERC wrote. “PJM further supported the increased compensation levels, documenting that compensation levels were in line with industry averages, and identifying increased staffing requirements.”

The commission acknowledged PJM’s concerns that it needed to restore its depleting financial reserves.

“Nearly two-thirds of the estimated 7.5% increase in the 2017 stated rate proposed by PJM is to restore the reserve to its prescribed level of 6% of annual revenues, with a 2.5% annual increase in 2019 through 2023 and a 0.7% increase in 2024, while 2018 will see no increase,” the order read.

December 27, 2016

PJM Markets and Reliability Committee Briefs

WILMINGTON, Del. — Just a month after approving changes that PJM and its Independent Market Monitor felt stripped away important market protections, the Markets and Reliability Committee approved new revisions to reinstate them.

The new revisions are similar to an amendment the Monitor and PJM had proposed for the original changes developed by Citigroup Energy. The amendment never received a stakeholder vote, however, because Citigroup’s proposal passed the MRC in November with enough support to avoid considering alternatives. (See “PJM, IMM Partner on Capacity-Replacement Revision,” PJM Market Implementation Committee Briefs.)

At issue is how quickly after a bid clears an Incremental Auction that the bidder can take credit for the purchase and flatten its position. Citigroup’s Barry Trayers said the change was necessary to allow his company to reconcile its books sooner and avoid excessive credit requirements.

PJM said the change to Manual 18 widened a loophole that allows participants to arbitrage price differences between the BRA and IAs by reselling the replaced capacity. The IMM had filed a complaint with FERC on the change, which several stakeholders credited for convincing them to reconsider their initial support.

The revisions were approved by a sector-weighted vote of 4.39 out of 5, winning near unanimous support from all sectors except for Other Suppliers. The IMM has since filed to withdraw its complaint with FERC.

The approved revisions included a friendly amendment from Mike Cocco of Old Dominion Electric Cooperative that requires PJM to respond to requests for early replacement capacity within 15 days.

Trayers attempted to defend his original changes, reading from a statement that carefully outlined his intentions and explained that the new revisions would reinstate the obstacles he had attempted to address in the first place. Trayers said an anomaly that can result in double counting of PJM participants’ capacity balances would require them to maintain collateral after they no longer have a position to collateralize. “The proposal here today would reinstate double counting,” he said.

Although Citigroup does not participate in the BRA or IAs, it provides receivables financing by purchasing the offsetting capacity positions and the future payment obligations of PJM, Trayers said. The change approved in November “does not alter the responsibility of all capacity market participants to meet their obligations with true physical capacity,” he said.

Task Force on Uplift Directed to Vote Again

Members directed the Energy Market Uplift Senior Task Force to seek consensus on ways to reduce uplift and address cost allocation concerns by revoting on five proposals that had previously received the most support.

While two proposals on uplift and volatility have received majority support, none of the more than 20 proposals on allocation has received such an endorsement.

Although the task force couldn’t agree on a path forward, PJM’s Dave Anders said the voting process indicated “overwhelming support for making a change.” He said several proposals successfully address the cost allocation issue but met resistance from stakeholders pushing for “backtesting” to determine how each package of changes would affect billings.

Anders said backtesting has been done on a few packages, but it would be “extremely complicated” for others. He urged members to focus on overall market design rather than how much each package is going to cost participants. But some stakeholders said they would oppose any reconsideration of the packages without some sort of backtesting.

Monitor Joe Bowring called for action. “There are some participants who have benefited from a delay, continue to benefit from a delay. It’s time to decide,” he said.

Others, including FirstEnergy’s Jim Benchek and Carl Johnson of the PJM Public Power Coalition, also urged the process forward.

“If we come out of this with nothing else, I would like to go to FERC with something that causes them to take action,” Johnson said. “I’m not sure it matters what we suggest to FERC. What matters is getting a [Section] 205 [of the Federal Power Act] action in front of them.”

After PJM committed to providing as much backtesting as possible, members approved directing the task force to revote on the top five packages. Its next meeting is Jan. 25.

Stakeholders Remain Skeptical of Campaign to Revisit CP

American Municipal Power’s Ed Tatum took to the MRC floor for what he noted was his “fourth first read” on a problem statement calling for a holistic review of PJM’s capacity construct.

For several months, Tatum has represented a coalition of stakeholders requesting a review. His arguments have often been met with ambivalence and a reluctance to tinker with the complex market, which is still incorporating the introduction of Capacity Performance requirements. (See No End in Sight for PJM Capacity Market Changes.)

The coalition took a month off after receiving substantial feedback in October, but Tatum said it decided to return to the MRC after being contact by RTO officials. “We got a call from PJM, and we answered the phone,” he said. The feedback resulted in several changes to the proposed problem statement and issue charge, including transferring the focus from addressing potential state public-policy action to generalized governmental action.

Stakeholders suggested a variety of potential revisions that might help gain their support, including word choice.

“I don’t mean to sound like a broken record … but [consider] approaching this from less of a defensive posture and thinking that the states are out to get us, because I don’t think that’s actually what’s going on,” EnerNOC’s Katie Guerry said. “I don’t think that’s a fair representation.”

James Wilson of Wilson Energy Economics suggested reviewing the ISO-NE and NEPOOL documents founding the Integrating Markets and Public Policy (IMAPP) process, which he said are more focused on trying to accommodate state policies.

PJM’s markets don’t reflect the costs of carbon emissions and some states might want to address it, he said. “To the extent that you accept that [carbon is harmful], then PJM’s markets aren’t efficient because they don’t reflect this externality, and what the states are doing is pushing things toward a more efficient result,” he said.

Others asked the coalition to better define its intended scope. “You’re saying, ‘Take everything we do here every day and change it,’” Gabel Associates’ Mike Borgatti said. “If we’re talking all of it, I’m not sure where I’d want to start.”

The Industrial Customers’ Susan Bruce questioned the problem statement’s timeline. “This is a lot of stuff, and to look at having deliverables [by] the third quarter of 2017, that’s ambitious.” she said.

Tatum acknowledged the additional feedback but expressed concern that the focus seems to be moving away from the proponents’ original intent. He solicited stakeholder help in making supportable revisions, but Exelon’s Jason Barker said the proponents needed to better clarify their goals. “We’re stepping on a slippery slope is all Exelon is saying,” he said.

Stakeholders Balk at Applying Tougher External Capacity Rules to Past Auctions

Stakeholders expressed concern that a PJM proposal tightening eligibility requirements for external capacity resources might violate FERC prohibitions on retroactive ratemaking.

The proposal, which won 68% support in a vote of the Underperformance Risk Management Senior Task, would require external resources to have firm transmission service with rollover rights from their native region and to meet “specific operational and market modeling requirements” to ensure that the resources can deliver energy without imposing congestion costs on PJM members.

Stakeholders expressed concern over PJM’s intention to apply the tightened requirements to capacity resources that have cleared in prior auctions. The proposal would allow existing resources that fall short to either build the transmission upgrades required to qualify under the new rules or to be relieved of their requirements without penalty.

“I think everybody should pay an awful a lot of attention to how this is being handled as far as grandfathering or not grandfathering” resource contracts, said consultant Roy Shanker. Calling it “horrible policy,” he said the proposal creates the potential to disqualify a cleared resource and reduce the amount of capacity cleared without adjusting the clearing price.

Other stakeholders, including Johnson and Barker, joined Shanker in voicing concern that it could result in retroactive ratemaking. They suggested that the rules be implemented going forward from the next BRA.

Bowring opposed “PJM’s continued inadequate approach to ensuring that capacity imports be substitutes for internal capacity resources,” including grandfathering existing long-term contracts with external resources and extending the current exceptions for two additional BRAs.

PJM had indicated it would seek votes of the MRC and Members Committee in January.

ARR Enhancements, Manual Revisions Unanimously Endorsed

Changes to the residual auction revenue rights process received little discussion and were endorsed with one objection and two abstentions. (See “Stakeholders Debate ARR Changes,” PJM Market Implementation Committee Briefs.)

Members also endorsed by acclamation revisions to manuals 10, 13 and 14D that were largely administrative in nature. The Manual 13 changes were the result of a periodic review and included updating the Mid Atlantic Dominion primary reserve requirement from a static 1,700 MW to 150% of the area’s largest single contingency. It includes a note permitting the use of deliverable resources outside of the area to satisfy the requirement.

“It really just aligns it with the [rules for the] RTO,” PJM’s Chris Pilong said.

The Manual 14D changes align it with the planned changes to Manual 13 and include revisions to the fuel-limitation reporting section to update seasonal reporting procedures, add a periodic reporting process and remove details on real-time reporting. The reporting focuses on fuel-inventory and environmental-limitations issues. “The reason for the change to both manuals is to better clarify the reporting process,” PJM’s Augustine Caven said.

— Rory D. Sweeney

December 27, 2016

PJM Considering Expansion of Spot-in Tx Solution to All Borders

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM proposed modifying an initiative on spot-in transmission by expanding it to all borders.

The proposal came despite reservations from Vitol’s Joe Wadsworth, who had won approval for a problem statement and issue charge specific to transactions between NYISO and PJM. (See PJM, NYISO Still Seeking Spot-in Tx Solution.)

PJM held a special session of the Market Implementation Committee on Wednesday, where stakeholders also debated implementing unlimited service along the NYISO-PJM seam. The seam is unique among PJM’s physical interfaces because all transactions are economically evaluated via NYISO’s clearing engine. Imports over other seams are price-takers that are paid PJM’s real-time LMP.

John Dadourian of Monitoring Analytics, PJM’s Independent Market Monitor, reiterated the IMM’s previous criticism of the unlimited service proposal, saying any market changes should apply uniformly across all borders to avoid any unintended market consequences. The Monitor is “not interested in creating a different methodology for handling [such transactions] at different borders,” he said.

Unlimited service, however, is opposed by other grid operators worried that extensive cross-border transfers could create constraints on the transmission lines of uninvolved operators. They cite language from joint operating agreements and discussions before the North American Energy Standards Board that call for limiting such transfers.

The proposal also potentially introduces new costs (and perhaps revenue) that NYISO has insisted also be shared by PJM.

As an alternative, PJM and Wadsworth have considered moving PJM’s earliest request time for spot-in service to 10 a.m. from the current 9 a.m. The delay would allow potential market participants to know if their NYISO bid has been approved before requesting service into PJM.

While Wadsworth called the alternative proposal “not great,” PJM pointed out that such service has been available in excess of 959 MW every hour since July 2015.

The Monitor asked that this proposal also be expanded to apply across all borders, which Wadsworth eventually agreed to “in the spirit of considering different solutions.”

“I don’t want to end up in a situation where we were five years ago, where we’re precluded from implementing a good solution for one seam just because it doesn’t work for all seams,” he said.

The modified problem statement and issue charge will be presented for approval at the Jan. 11 MIC meeting.

December 23, 2016

FERC Upholds PJM Advocates’ Funding

By Rich Heidorn Jr.

FERC upheld its order approving funding for PJM’s state consumer advocates, rejecting contentions by Talen Energy and Essential Power that the commission exceeded its authority (ER16-561-001).

consumer advocates ferc pjm — Griffiths | © *RTO Insider*

The commission in February approved PJM members’ vote granting the Consumer Advocates of the PJM States (CAPS) an initial annual budget of $450,000 to fund the advocates’ stakeholder activities through a charge to electric customers. Former Commissioner Tony Clark dissented from the vote, saying CAPS should be funded through the appropriations of state legislatures. (See FERC Approves PJM Funding of Consumer Advocates.)

Talen and Essential sought rehearing, saying the order exceeded the commission’s authority under Section 205 of the Federal Power Act because CAPS’s participation in the stakeholder process was not a jurisdictional service nor a practice that has a “direct effect” on jurisdictional rates.

In its Dec. 21 order, the commission said its authority came under Section 205’s direction to ensure just and reasonable rates. “The Supreme Court has held that this jurisdiction extends to rules and practices that directly affect wholesale rates. … The PJM stakeholder process is a practice that directly affects wholesale rates, and thus approval of a proposal that would enhance that process falls within the commission’s jurisdiction. … For example, stakeholder input is an essential element of a just and reasonable regional transmission planning process, a process that the courts have agreed is one that directly affects jurisdictional rates.”

The commission cited the Independent Market Monitor’s comment that “PJM consumers have been systematically underrepresented” in the stakeholder process, and that the funding was “a meaningful first step to obtain needed balance.”

In response to the complainants’ contention that the funding violated cost causation rules, the commission repeated its conclusion that funding CAPS benefits PJM’s ratepayers by increasing its responsiveness to customers and other stakeholders. “We disagree with Talen/Essential Power that making the stakeholder process more inclusive, transparent and robust through CAPS’s participation is not a legitimate reason to accept a tariff funding mechanism for CAPS,” FERC said.

FERC also rejected Talen and Essential’s complaint that the funding constituted “compelled speech” in violation of the First Amendment. “By contributing to funding CAPS’s participation in the stakeholder process, neither Talen/Essential Power nor any other stakeholder becomes identified with CAPS’s views in a way that causes them to become an instrument for fostering public adherence to them,” FERC said. “On the contrary, all stakeholders remain free to express their views within the stakeholder process and to support or oppose any position that CAPS advances.”

December 21, 2016

LS Power Unit Wins MISO’s First Competitive Project

By Amanda Durish Cook

MISO has selected LS Power’s Republic Transmission to build the RTO’s first competitive transmission project.

St. Louis-based Republic and partner Big Rivers Electric, a generation and transmission cooperative in Henderson, Ky., beat out 10 other qualified developers for the Duff-Coleman 345-kV transmission project in Southern Indiana and Western Kentucky. Hoosier Energy will acquire a share of Republic in exchange for providing maintenance and operations for a segment of the project located in Indiana.

Priti Patel, regional executive for MISO North and executive director of MISO’s Competitive Transmission Administration, said Republic’s $49.8 million proposal was “the clear and decisive winner” among the 11 proposals, which ranged from $34 million to $55.7 million. MISO had estimated the project at $58.9 million. (See 11 Developers Vie for MISO Duff-Coleman Project.)

“Republic Transmission’s project proposal exhibited the best balance of high-quality design and competitive cost, best-in-class project implementation and top-tier plans for operations and maintenance,” Patel said. She said the proposal carried the highest sense of certainty, the most details, the lowest risk and a low cost. “It comes down to providing the greatest value,” Patel added. “That encompasses more than just cost.”

Republic will be required to deliver quarterly status reports to MISO. The company also must execute a binding developer agreement using commitments from its bid proposal and competitive requirements from the MISO Tariff.

“With the evaluation and selection phases of the competitive developer selection process now over, we look forward to working closely with Republic Transmission, stakeholders and the Organization of MISO States to ensure the success of this project,” said Patel.

The project, approved as part of the 2015 MISO Transmission Expansion Plan, is expected in service no later than Jan. 1, 2021. Construction includes a pair of substations and a 28.5-mile 345-kV connecting line in Southern Indiana and Western Kentucky.

‘Decisive’ Winner

MISO used four FERC-approved criteria to weigh the proposals: cost and design, project implementation, operations and maintenance and participation in the planning process.

Alongside Tuesday’s announcement, MISO published a 135-page selection report that said all competitive bidders “demonstrated the necessary breadth and scope of capabilities, and the financial wherewithal, to design, finance, construct, operate and maintain the project.” However, MISO said Republic’s proposal scored a 95 out of 100 possible points, while other proposals scored between 41 and 80 points.

Proposed route lengths varied from 28 to 36 miles. All proposals scored an ‘acceptable’ or better rating from MISO. Republic’s proposal scored a ‘best’ due to a “well-thought-out” route; “ample” right-of-way width; a specific operations-and-maintenance plan; and a “strong cost cap” with a 9.8% return on equity for the life of the project.

Brian Pederson, a senior manager in MISO’s competitive transmission unit, said the report seeks to explain the analysis behind the RTO’s selection, be transparent “within the bounds of the Tariff confidentiality provisions” and encourage future participation in the Order 1000 competitive process.

Review Begins

Pederson said MISO will convene a new Competitive Transmission Task Team reporting to the Planning Advisory Committee to suggest potential improvements and lessons learned from the first solicitation.

“In January, we want to focus on attaining stakeholder feedback,” Pederson said during MISO’s Dec. 14 Planning Advisory Committee. By mid-2017, he envisions stakeholders and MISO finalizing Tariff revisions to the competitive developer selection process.

MISO will also use 2017 to continue to refine the minimum design requirements required of competitive projects in Business Practices Manual 029. The RTO is expected to sunset its Minimum Design Requirements Task Team and funnel final design requirement changes through the Planning Subcommittee in January. Changes to BPM 029 should become effective in the spring. The new rules establish a more detailed set of ratings that projects must meet. (See “MISO Releases Minimum Requirements for Competitive Tx Projects,” MISO Planning Subcommittee Briefs.)

The RTO has also committed to reaching out to the bidders of the 10 rejected proposals to explain its decision in one-on-one meetings during January and February.

December 20, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM is expecting “typical” temperatures and almost 50,000 MW of capacity beyond its projected peak load for the first winter using Capacity Performance, PJM’s Chris Pilong told the Operating Committee last week.

While recent winters were impacted by anomalies such as El Nino, weather this season is likely to be about “average,” he said. PJM’s installed capacity for the winter is 183,665 MW, with 177,525 MW committed through the Reliability Pricing Model. The forecasted peak load is 135,548 MW.

“Average temperatures aren’t going to be what’s driving us as far as peak-load days,” he said. “It’s going to be the outliers.”

Natural gas-fired capacity has increased by 17,225 MW since the polar vortex nearly three years ago to 61,513 MW, he said, about 35% of committed capacity. Of that, about half — 31,946 MW — is committed through CP.

An Operations Assessment Task Force assessment of pipeline-disruption sensitivity found no reliability issues for base and N-1 analyses, Pilong said. “The good news was even under the worst-case scenario, everything was solid,” he said.

By the end of the year, an additional 2,800 MW of generation will have been brought online since this summer, he said. The system also will have the benefit of transmission upgrades on the Baltimore Gas and Electric, Dominion, Commonwealth Edison and American Electric Power systems.

PJM Moves to Cut Operator-Training Grace Period in Half

The grace period for dispatchers at utilities’ market operations centers and small generation plants to complete initial training will be reduced from 12 months to six months in revisions PJM is proposing for Manual 40.

“Our long-range plan is to get that number [for the allowable grace period] to zero,” PJM’s Glenn Boyle said. “What we’re saying is that’s too much exposure risk.”

He said PJM is hoping to have the grace period removed entirely by next year.

Regulation Requirement Changing from ‘Peak’ to ‘Ramp’

PJM is proposing to change the way it sets regulation requirements, replacing the targets for on- and off-peak periods with those for on- and off-ramp intervals to better capture seasonal system conditions.

pjm operating committee capacity performance — | *PJM*

The revisions, which will be incorporated in Manuals 11 and 12, were recommended by the Regulation Market Issues Senior Task Force.

The lower regulation requirement of 525 effective MW, which currently applies during off-peak hours of midnight to 04:59, would apply during off-ramp hours. The requirement for the on-peak hours of 05:00 to 23:59 would be applied to the on-ramp and increase from 700 to 800 effective MW.

On- and off-ramp periods will vary by season. From Sept. 1 through Nov. 30, for example, the on-ramp period will be hours ending 6:00 through 8:00 and 18:00 through 24:00. For the winter, the morning ramp starts one hour earlier and ends one hour later while the evening ramp begins an hour earlier.

The seasonal periods will be posted on the RTO’s website. PJM’s Eric Hsia said he plans to also announce them at the Operating Committee meetings starting two months prior to the beginning of the affected season.

PJM Won’t Pay for Frequency Response Under FERC NOPR

FERC’s Nov. 17 rulemaking that would require most new generators to have primary frequency response capability left it to individual RTOs to decide if compensation is warranted for the service, and PJM currently believes it’s not, Hsia said.

The rule would apply to both synchronous and nonsynchronous facilities as a condition of interconnection. Nuclear units are exempt.

Hsia said he didn’t agree with the argument that generators should be compensated for lost-opportunity costs, noting that the Notice of Proposed Rulemaking would not require them to preserve “headroom” for the frequency response when offering their output for sale (RM16-6). (See FERC: Renewables Must Provide Frequency Response.)

He acknowledged “ongoing conversation” on the topic, however. Comments on the NOPR are due to FERC on Jan. 24.

Members Question Redundancy of Pseudo-Tie Efforts

Members asked PJM staff why the RTO is seeking to create a pro forma pseudo-tie agreement when the issue of pseudo-ties is already being discussed by the Underperformance Risk Management Senior Task Force.

“The lack of this agreement has resulted in a lack of uniformity,” PJM’s Jacqui Hugee said.

Staff wanted to develop such a document for the task force but couldn’t complete it fast enough to avoid delaying the task force’s progress, she said. The effort to develop a pro forma document is being done in coordination with the task force, she said, and PJM doesn’t plan to make multiple filings on the topic with FERC. (See related story, MISO Stakeholders Narrowly Support New Pseudo-Tie Rules.)

– Rory D. Sweeney

December 20, 2016

FERC Orders Hearing in Entergy Formula Rate Dispute

FERC on Thursday ordered hearing and settlement procedures in a dispute between Entergy and its customers over the company’s accounting for income taxes and post-retirement benefits in its formula rates tariff (ER16-1528).

The commission said the dispute raised unresolved factual issues and that Entergy’s proposed formula rate changes may be unjust and unreasonable. It made the changes effective June 2015 and June 2016 but suspended them pending the settlement proceedings. The order consolidated two dockets, ER15-1436 and ER15-1453, with ER16-1528.

The multiple dockets stem from February 2013, when Entergy first filed proposed transmission formula rate templates to recover its transmission revenue requirements as a MISO member. The proposed rates were modeled on MISO’s Tariff but incorporated practices established under Entergy’s previous tariff for its operating companies.

In July 2015, Entergy reached a partial settlement on the formula rate templates with several customers, including the South Mississippi Electric Power Association and Arkansas Electric Cooperative Corp. By then, however, Entergy had already proposed two changes to the rate templates related to income taxes and retirement costs that were not reflected in the settlement.

The customers protested, contending that the changes did not reflect established practices under the Entergy tariff and were unsupported by its “grossly deficient” filing. They said Entergy’s claim for recovery of $612.7 million in prepaid pension costs was unjustified and could increase its transmission revenue requirement by $8 million annually.

Entergy said the pension costs would increase rates by only $1.3 million per year.

— Tom Kleckner

December 20, 2016

CAISO Board Welcomes GridLiance Membership

By Robert Mullin

GridLiance moved one step closer to joining CAISO as a participating transmission owner after the ISO’s Board of Governors voted Dec. 15 to approve the company’s membership.

The company is seeking to join the ISO after agreeing to purchase Valley Electric Association’s 230-kV transmission network for more than $200 million. (See Valley Electric Approves Sale of 230-kV Network to GridLiance.)

valley electric caiso board gridliance — GridLiance says its purchase of Valley Electric’s 230-kV network represents a long-term commitment to the co-op and California’s energy development. | *Valley Electric Association*

Nevada-based Valley Electric is the ISO’s only transmission-owning member outside California. The cooperative provides power to about 45,000 customers in a 6,800-square-mile service territory along the California-Nevada border.

The transmission assets being transferred include 164 miles of 230-kV lines linking Valley Electric’s base in Pahrump, Nev., with both Las Vegas and the Mead substation — a major delivery point for power wheeled into California. Valley Electric completed the network in 2013 in order to improve reliability for its sprawling but sparsely populated service area.

As part of the deal, GridLiance has said it will reinforce the ISO’s interconnection with Nevada’s Eldorado substation, another major wheeling point into California.

Valley Electric saw the value of its network increase significantly after the co-op joined the ISO in 2013. It will recover about 2.4 times its investment.

Chicago-based GridLiance acknowledged that it is paying top dollar for the assets, saying they will provide the company with a foothold in an area that bridges the California market with the interior West.

“We did pay a premium to enter this relationship,” GridLiance CEO Ed Rahill told the CAISO board ahead of its vote. “And if you think about that, it’s only because our commitment is so many decades into the future that it becomes insignificant.”

Under the agreement, Valley Electric will still operate and maintain the system. The acquisition is not expected to affect the co-op’s distribution system.

“Our relationship with Valley is going to continue as a long-term partnership to help the region and the community through economic development and energy projects that benefit not just Valley but the California ISO and California,” Rahill said.

Valley Electric CEO Thomas Husted said the co-op joined the ISO because it is a “strong proponent” of regionalization.

“The sale of those assets does not change that position,” Husted said. “We will continue to be a load-serving entity and a [participating transmission owner] within the California ISO.”

Husted said the network was built to serve Valley Electric’s load, provide reliability and foster development of renewable assets that will continue to support regionalization.

“That [regionalization] now is growing beyond Valley Electric’s original mission and beyond our charter,” Husted said.

The board’s approval is conditioned on GridLiance executing a transmission control agreement with the ISO and FERC accepting the company’s transmission owner tariff and revenue requirement.

GridLiance would be the 17th transmission owner to join the ISO.

Launched in March 2015 with backing from the Blackstone Group, GridLiance bills itself as the nation’s first competitive transmission company focused on collaborating with public power entities. It made its first two acquisitions — 420 miles of 69-kV and 115-kV lines in Missouri and Oklahoma — a year ago. (See GridLiance Makes First Acquisitions.)