Page 1357 – RTO Insider

December 29, 2016

UPDATE: Dynegy Files Mitigation Plan for Purchase of ENGIE Plants

By William Opalka

Dynegy says it will sell generation in PJM and ISO-NE if necessary to address FERC’s market power concerns over the company’s acquisition of ENGIE’s power generation unit.

The commission conditionally approved the sale Dec. 22 but said the company had to mitigate its market power in the two regions’ capacity markets (EC16-93).

The commission’s order found the $3.3 billion acquisition for 9 GW of generation assets will not have an adverse effect on competition in NYISO, MISO or CAISO, nor in the PJM or ISO-NE energy or ancillary services markets.

Dynegy would acquire a 50% interest in the Bellingham Energy Center | *NextEra Energy Resources*

But FERC said it was concerned the transactions could harm capacity market competition in PJM’s Commonwealth Edison locational deliverability area and ISO-NE’s Southeast New England (SENE) capacity zone. FERC said that existing market power concerns in ISO-NE would be exacerbated by the acquisition absent mitigation.

The sale also includes the sale of the France-based ENGIE’s plants in ERCOT, which are not subject to FERC jurisdiction.

Dynegy and partner Energy Capital Partners proposed to buy 17 fossil fuel plants of ENGIE subsidiary GDF Suez North America (GSENA) and named the joint venture Atlas Power Finance. In June, Dynegy said it would pay $750 million to buy out ECP’s 35% stake. (See Dynegy Buying out Energy Capital’s Stake in ENGIE Deal.)

FERC found that the acquisition would increase the Herfindahl-Hirschman Index for the “highly concentrated” ComEd LDA — currently 2,021 points — by 49 points.

Although Atlas Power would not currently be a pivotal supplier in ComEd, the planned retirements of the Will County Generating Station (May 2020) and Exelon’s Quad Cities nuclear plant (June 2018) would reduce capacity available to bid in the 2020/21 Base Residual Auction by 2,223 MW in the LDA.

“Factoring in the 2,223 MW of planned retirements leaves an insufficient supply of unforced capacity available to meet the ComEd LDA minimum annual resource requirement, which means that Atlas Power’s capacity is needed,” FERC said. “With all other factors held constant, we calculate that Atlas Power will be pivotal in the ComEd LDA for the 2020/2021 Base Residual Auction.”

Illinois Lawmakers Clear Nuke Subsidy.)

FERC in its merger order invited Dynegy to describe how the Elwood transaction would impact the mitigation analysis. The commission only said the Illinois legislation “may affect” Quad Cities’ status.

If the commission still requires mitigation, Dynegy proposed divesting generation units equal to or above the 327 MW it is acquiring in ComEd and using cost-based capacity market offer caps until generation is divested.

New England

In SENE, FERC said GSENA was pivotal before the transaction with approximately 1,273 MW of qualified capacity. After the acquisition, Dynegy’s assets in the SENE capacity zone will grow to 1,497 MW.

“Applicants argue that because GSENA is pivotal prior to the proposed transactions and Atlas Power will remain pivotal after the proposed transactions, the proposed transactions will have no adverse effect on competition. We disagree,” the commission wrote. “Being pivotal implies that a seller has the ability to unilaterally increase the market price, and the seller’s incentive to do so increases as it becomes more pivotal.”

FERC said mitigation was necessary through either a plant sale or a commitment to keep certain plants operating.

“Specifically, we are concerned with a seller’s ability to exercise market power in the ISO-NE Forward Capacity Auction when its resources enter or exit the market, and thus, applicants should tailor mitigation to address that concern. For example, applicants may consider, among other steps, divestiture of generation units or a commitment to keep resources in the ISO-NE capacity market for a specified period of time.”

Dynegy responded that it will divest generation equal to or above the 224 MW it is acquiring in SENE and would limit capacity bids in interim capacity auctions to no greater than the FCA clearing price until any divestiture. It also promised not to retire any units until the sales are completed.

The company asked for expedited approval by Jan. 30.

Public Citizen had protested the transaction because of two FERC investigations into allegations of Dynegy misconduct in a PJM 2015 capacity auction and a separate audit. (See Dynegy: No Evidence of Misconduct in Auction.) FERC said those issues were beyond the scope of its review of the acquisition’s effect on the public interest.

December 29, 2016

FERC Orders Hearing in Maine Dispute over Capacity Rules

By William Opalka

FERC ordered hearing and settlement procedures in a dispute over capacity obligations in an area of Northern Maine separate from ISO-NE (ER17-192).

The dispute concerns the Northern Maine Independent System Administrator, whose transmission system is not directly connected with the rest of New England and whose market participants are not subject to ISO-NE’s jurisdiction and do not participate in the New England Power Pool.

At issue is the ISA’s request to eliminate a requirement that market participants prove the deliverability for resources located outside Northern Maine but within the New Brunswick balancing authority area, of which the ISA is a part.

NMISA said the deliverability assurance requirement in its market rules is no longer needed because its rebuild of Line 691 and planned spring 2017 upgrade of the Tinker transformer at the New Brunswick-Northern Maine interface will eliminate the transmission constraint into the area.

The request was protested by ReEnergy Biomass Operations, which owns the 37-MW Fort Fairfield and 39-MW Ashland generating plants in Aroostook County, within the NMISA control area.

Ashland Generating Station | *ReEnergy Holdings*

ReEnergy contends that even after completion of the upgrade, as much as 140 MW of load in Northern Maine could be reliant on 98 MW of available transmission capacity from New Brunswick. It said the upgrade was required to support 74 MW of existing firm reservations, meaning the upgrade would only add 24 MW of additional firm transmission capacity. Eliminating the deliverability requirement would impact reliability and distort price signals, it added.

NMISA disputes ReEnergy’s calculations, saying its 140-MW load estimate includes Eastern Maine Electric Cooperative, which should not be counted because it is not connected to New Brunswick via the Emera Maine-New Brunswick interface.

It said that the total Emera Maine capacity requirement for summer 2016, including reserve margin, was 124 MW, below the 129-MW total summer transfer capability from New Brunswick to Northern Maine once the upgrade is complete.

The authority said ReEnergy opposes the changes because it wants to maintain a competitive advantage in the area. If the requirement were maintained, market participants would be incented to hoard firm transmission capacity, preventing other resources from competing in the market, it said. The authority’s position was backed by the Maine Public Utilities Commission, which also said it feared reduced competition and higher prices if the rule remained.

FERC’s Dec. 22 order accepted NMISA’s proposed change subject to refund but suspended it, saying it needed more information to resolve the factual dispute over how much capacity will be provided by the upgrade.

“NMISA has not demonstrated that the Tinker upgrade located at the New Brunswick-Northern Maine interface will relieve the constraint at this interface, or that capacity located inside and outside of the Northern Maine transmission system is capable of meeting Northern Maine’s peak load capacity requirements before and after the Tinker upgrade,” the commission said.

December 28, 2016

FERC Wants More Detail on PJM’s Seasonal Capacity Plan

By Rory D. Sweeney

FERC has issued a deficiency notice requesting more information from PJM on its proposal to incorporate more seasonal resources under Capacity Performance (ER17-367).

PJM has until Jan. 22 to respond to the Dec. 23 notice, which asks for more detail and specific examples about its plan to integrate seasonal resources into capacity auctions and incorporate them into operational protocols. The proposal would relax the current prohibition on seasonal resources aggregating across locational deliverability areas. In October, the RTO angered some stakeholders when staff announced at the annual meeting of the Organization of PJM States Inc. that it was filing its proposal despite a lack of stakeholder consensus. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.)

pjm ferc seasonal capacity performance resource — Unadilla Solar Project | *Allco Renewable Energy*

“The proposed [Open Access Transmission Tariff] revisions appear unclear as to how PJM will determine which Seasonal Capacity Performance Resource offers clear an auction and which do not, and how PJM will ensure least-cost capacity procurement,” the commission wrote.

It asked if offers will be put in auctions individually or paired with a resource from the opposite season with an aggregated offer price. FERC also asked how PJM’s optimization algorithm will compare seasonal and annual resources, at what price the algorithm would stop clearing seasonal resources and how it will break ties if multiple seasonal resources submit identical offer prices.

The RTO’s proposal would allow resources to aggregate beyond LDA borders, with unmatched resources moving up to the next LDA level until a match is found.

FERC wanted more detail on how PJM’s cross-LDA aggregation concept would affect operational procedures, noting that the current proposal allows a seasonal resource to clear an auction, be counted toward the reliability requirement of an LDA other than the lowest level one in which it’s located and receive a clearing price less than that of the lowest-level LDA.

The commission also asked how a resource could be subject to a performance assessment hour in the LDA where it’s located, but receive the clearing price and help with the reliability requirement for the LDA in which it cleared the auction. It wanted to know how PJM plans to apply performance-related charges and credits and what rates will apply.

FERC also asked if the RTO intends for fixed resource requirement capacity plans that include seasonal resources to have equal quantity of summer and winter resources.

The commission wondered why PJM created a way for summer demand response to offer into auctions, but not for winter resources. “Why does PJM propose to exclude a winter-period demand resource from participating as a seasonal Capacity Performance resource?” it asked.

FERC also showed interest the differences between seasonal resources, asking PJM to opine on whether resources from one season or the other make a bigger difference on system reliability. It asked about any documentation PJM has on the topic.

December 27, 2016

PJM Credit Adder Fails upon Heightened Review

By Rory D. Sweeney

WILMINGTON, Del. — A proposed revision to credit requirements for financial transmissions rights participants received significant stakeholder debate before the Markets and Reliability Committee and withered under the scrutiny.

MRC Meeting at Chase Center, Wilmington, Del. | © *RTO Insider*

The proposal was supported by FTR holders who complained that the “undiversified credit adder” applied to net counterflow portfolios caused over-collateralization of some FTR portfolios. The proposal, approved by the Credit Subcommittee, eliminates the adder in exchange for increasing the historical adjustment factor in underlying credit calculations for historically counterflow paths from 10% to 25%.

The adder was created following the $52 million credit default by Tower Research Capital’s Power Edge hedge fund in 2007. Members agreed to review it following a 2013 survey of issues of concern to the Credit Subcommittee.

Exelon’s Sharon Midgley had complained at the Dec. 14 Market Implementation Committee meeting that the change would increase her company’s credit costs, but the committee approved the change 88-34. (See “Credit Limit Changes Pass Despite Exelon Objections,” PJM Market Implementation Committee Briefs.)

That changed in the sector-weighted vote at the MRC on Dec. 22, where it won a majority of only one sector (69% of Other Suppliers), scoring only a 1.25 out of 5.

Exelon’s Jason Barker criticized how the credit increases would be implemented, saying it would be taking large “chunks” of credit from overcollateralized portfolios and “peanut-buttering” it over other undercollateralized ones. “We think that the balance is certainly off,” he said.

“From a customer perspective, I think it’s difficult to take the chance as we know the facts today,” said Susan Bruce of the PJM Industrial Customer Coalition. “I’m not in a position to take a chance, but I’m willing to talk more about this.”

PJM’s Stu Bresler said the RTO “doesn’t have a dog in the fight” over whether members are willing to accept potential defaults. But he said it does have a long-term concern.

“Even if the members are willing to accept additional risk … we have to consider the effect and potential ramifications,” he said. “I think it goes beyond reputation. It goes to the confidence to participate in the markets if [a default] were to occur again.”

Under current rules, collateral held by PJM would have covered all of the $52 million in FTR net counterflow portfolio losses in 2007-8. Under a proposed rule change, only $8 million of the losses would have been covered, leaving PJM members to reimburse $44 million, according to stress tests by the RTO.

Opponents of the changes, including the Independent Market Monitor, preferred to maintain the current protections against events like the Tower default. “I’d prefer that something like that never occur again,” American Municipal Power’s Ed Tatum said. “I haven’t seen an upside for the stakeholders but for those who are performing these transactions.”

Bruce Bleiweis of DC Energy called the proposed changes “good policy” that “right-sizes” credit portfolios. He also questioned whether the incident that precipitated the changes could occur again given rule changes that have been implemented in the interim.

“We don’t think that’s an accurate stress test because we don’t think that the Tower portfolio would have occurred,” he said. Tower wouldn’t have taken the position because its bid collateral would be more than $35 million today, he theorized.

December 27, 2016

FERC Upholds Berkshire Market-Based Rate Ruling

By Robert Mullin

FERC denied Berkshire Hathaway Energy’s request to rehear a ruling prohibiting the company’s subsidiaries from selling electricity at market-based rates in four neighboring balancing authority areas in the West.

The commission’s June 9 decision restricted Berkshire-owned utilities PacifiCorp and NV Energy and 19 other affiliates from offering power at market rates in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas based on concerns about horizontal market power. (See Berkshire Market-Based Rate Sales Restricted in 4 BAAs.)

FERC denied the Berkshire Hathaway Energy request to rehear a decision that revoked the ability of the company’s subsidiaries from selling power at market-based rates in the IPCO, NWMT, PACE and PACW balancing authority areas.

In its Dec. 21 order, the commission rejected Berkshire’s contention that the June ruling had denied the company due process because of FERC’s failure to convey “newly announced standards for determining market power” ahead of the company’s initial “change in status” filing, which was triggered by the 2013 acquisition of NV Energy (ER10-2475, et al.).

“We clarify that the June 9 order did not create new criteria for obtaining or retaining market-based rate authority,” the commission said. “Rather, in the June 9 order, the commission identified areas where the [Berkshire companies’] analysis fell short of existing requirements and, where appropriate, provided suggestions for meeting the requirements.”

The commission did approve the Berkshire subsidiaries’ revised market-based rate tariffs filed in compliance with the June order and clarified that the companies are entitled to propose new cost-based rates for making sales into the four areas, rather than being limited to relying on default cost-based rates.

The commission also terminated the Section 206 proceeding on the matter.

In its June 9 order revoking market-based rate authority, the commission found that the Berkshire companies failed to provide reliable delivered price test (DPT) analyses rebutting the presumption of market power in the four balancing authorities.

FERC policy allows companies to submit a DPT after failing the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power within a balancing area.

The DPT offers a company the chance to provide more granular market power assessment that factors in native load commitments to determine a supplier’s “available economic capacity” — energy available for offer in the open market.

The commission’s decision to revoke Berkshire’s market-based rate authority ultimately rested on what the commission called a “flawed” DPT analysis from the company. The commission pointed to Berkshire’s failure to calculate unique season and load levels for each of the four areas, instead relying on assumptions based on data for only the PACE area.

In its July 11 request for rehearing, Berkshire countered the commission’s findings by arguing that each of its 57 “unique” DPT analyses “was prepared in accordance with the commission’s previously announced requirements and each was similar in form and substance to” analyses the commission had previously approved. (See Berkshire Contests Market-Based Sales Restriction in West.)

“The [Berkshire companies] failed to provide any historical transmission data, eTag or otherwise, to corroborate the results of their DPTs as required by section 33.3(c)(6) of the commission’s regulations,” the commission responded in its Dec. 21 order. Furthermore, based on its own review of transmission data, the commission said it was unable to corroborate the DPTs.

The commission also noted its longstanding policy of requiring companies to compare actual trade patterns with DPT results.

“This is not a new standard or a higher threshold test; it is the obligation the commission has required for DPTs since 1997,” the commission said.

The commission also rejected Berkshire’s contention that it had failed to follow past practice by not allowing the company opportunity to correct mistakes in its original submittal.

“The [Berkshire companies] were given many opportunities to correct errors in their DPT,” the commission said, citing a Dec. 9, 2014, order describing “multiple deficiencies” in the supporting data for the tests. The commission pointed out that FERC staff met the Berkshire representatives to discuss that order.

The commission additionally dismissed Berkshire’s claim that the commission failed to make a “definitive finding” that the company possesses market power in all four regions before revoking market-based rate authority, as required under FERC Order 697. After failing the initial market power screens, Berkshire, not FERC, had the burden of proof, the commission said.

“If the commission cannot revoke market-based rate authority in areas where sellers fail to rebut the presumption of market power created by a failure of the indicative screens, then sellers could deliberately submit inadequate evidence for the commission to analyze and thus be allowed to keep their market-based rate authority in perpetuity,” the commission said.

December 27, 2016

NYPSC Rejects Challenge to Clean Energy Standard, Nuke Subsidy

By William Opalka

The New York Public Service Commission turned aside numerous challenges to its adoption of a Clean Energy Standard and its subsidy for upstate nuclear power generators, rejecting 17 petitions for rehearing and/or reconsideration.

Most of the petitions were dismissed by the commission. Several others, regarding “eligibility issues” for some resources, warrant further investigation by the PSC but do not warrant rehearing, the Dec. 15 order said (15-E-0302).

The commission granted a petition by Exelon seeking the elimination of a condition related to its acquisition of the James A. FitzPatrick nuclear plant, noting that the sale has already been approved. (See FERC Approves FitzPatrick Sale to Exelon.)

The CES mandates New York to acquire 50% of its energy from clean resources by 2030 and seeks to further that goal by providing zero-emission credits to support nuclear plants, which were in danger of closing.

Generators and some environmental advocates said the ZEC program — which some critics say will cost more than $7 billion over its 12-year lifespan — goes beyond the authority granted to the PSC by state law. (See CES Under Attack on Multiple Fronts in Rehearing Requests.)

The commission disagreed, saying “the ZEC requirement the commission adopted in the CES order is the best way to preserve the affected zero-emissions attributes while staying within the state’s jurisdictional boundaries.”

Complaints that the ZEC program intrudes on wholesale markets under FERC jurisdiction were similarly dismissed. “As explained in the CES order, neither the ZEC requirement nor any other aspect of the CES program inappropriately intrudes on the wholesale market or interferes with interstate commerce,” the PSC said.

nypsc clean energy standard nuclear subsidy — Tannery Island Hydroelectric facility | *Ampersand Energy Partners*

Owners of existing resources, including hydropower developers, said the CES order failed to properly measure their environmental benefits under the state-operated market for renewable energy credits. New large-scale hydropower projects are ineligible for ZEC payments under the order. Some smaller hydropower, wind and biomass resources built before 2015 that are eligible for smaller REC payments under previous state programs said they were in danger of closing because of extraordinarily low natural gas prices.

Staff has been directed to further study eligibility requirements, the order states, instead of waiting for a triennial review as established in the CES order in August.

The commission also dismissed petitions that claimed that state procedures were violated during the compressed time frame under which the ZEC program was open for public comment.

The commission’s order won’t be the final word on the subject, however, as two court challenges remain pending. (See Environmental Group Files Second Challenge to NY Nuke Subsidy.)

December 27, 2016

NYISO Members OK End to Con Ed-PSEG Wheel

By William Opalka

RENSSELAER, N.Y. — The NYISO Management Committee on Wednesday approved an agreement with PJM to end the 1,000-MW Con Ed-PSEG wheel next year while maintaining an operational base flow (OBF) of 400 MW that will be reduced to zero by 2021.

Consolidated Edison said it would not renew its contract with PJM when the current agreement expires next spring because it is no longer needed to deliver upstate power into New York City. But the OBF is needed to maintain system reliability in northern New Jersey, says PJM. (See “Con Ed-PSEG ‘Wheel’ to Reach 0 MW Baseflow by 2021,” PJM PC/TEAC Briefs.)

The vote was unanimous with five abstentions, one from Public Service Enterprise Group.

“We don’t agree with PJM that the operational baseflow is needed,” PSEG’s Ken Carretta said.

NYISO COO Rick Gonzales declined to respond to that objection, which was raised repeatedly. “I’m not going to opine on what PJM has determined,” he said.

The wheeling service was implemented by modeling 1,000 MW flowing from NYISO to PJM over the JK (Ramapo-Waldwick) interface and from PJM to NYISO over the ABC (Hudson-Farragut and Linden-Goethals) interface.

Under draft language for the NYISO-PJM Joint Operating Agreement, the wheel will be temporarily replaced by an operational base flow — “an equal and opposite megawatt offset of power flows” over the Waldwick and ABC phase angle regulators to account for natural system flows over the JK and ABC interfaces.

Last week’s modifications more definitively set the size of the OBF and fixes the start and end date. “The initial 400-MW OBF, effective on May 1, 2017, is expected to be reduced to zero megawatts by June 1, 2021,” it says.

An annual review of the baseflow will be conducted starting next year, which then gives the grid operators two years’ notice to end it, unless they establish an earlier date.

PJM has said that the 2021 deactivation target materialized because it was the date that planning analyses determined the OBF was unnecessary. “With the projects that are expected to go into service, we aren’t seeing any operational need for an OBF,” PJM’s Paul McGlynn said at the Dec. 15 Transmission Expansion Advisory Committee meeting.

The revised JOA was reviewed Thursday at PJM’s Markets and Reliability Committee meeting. PSEG’s Alex Stern confirmed that PJM would clarify in the meeting minutes that the JOA can’t supersede the PJM transmission operators’ agreement.

A joint filing is expected at FERC next month with implementation starting May 1.

Con Ed decided in April to end the wheel following a dispute with PJM over the allocation of transmission upgrade costs. (See Con Ed-PSEG ‘Wheel’ Ending Next Spring.)

— PJM correspondent Rory D. Sweeney contributed to this article.

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.