MISO and PJM will submit new filings with FERC in response to a second deficiency letter regarding their pseudo-tie coordination efforts.
The commission’s deficiency letter seeks clarification on a proposed joint operating agreement revision that would allow the RTOs to terminate or suspend pseudo-ties that don’t acquire transmission service or follow modeling rules (ER17-2220). The language gives a native balancing authority the ability to redirect pseudo-tie output to avoid exceeding NERC operating limits. (See MISO, PJM Float Pseudo-Tie Coordination Plan.) PJM’s matching proposal triggered an identical deficiency letter (ER17-2218).
| MISO, PJM
FERC’s lingering questions include how and under what circumstances a native reliability coordinator would commit, de-commit or redispatch pseudo-tied generation to avoid exceeding system operating limits or interconnection reliability operating limits, features both RTOs say would be beneficial for maintaining reliability. The commission also asked the RTOs to clarify what constitutes a pseudo-tie suspension and delineate the grounds for such suspensions. It also seeks clarity on the rationale behind the 42-month notice to terminate a PJM pseudo-tie, all the possible grounds for termination and what process will be in place to handle contested terminations. The RTOs have until Oct. 28 to respond.
MISO will be working internally and with PJM to draft a response to the deficiency letter, MISO Director of Market Engineering Kim Sperry said at an Oct. 5 Reliability Subcommittee meeting. She provided no other details. MISO and PJM introduced the coordination efforts in early July.
The most recent letter comes five months after the RTOs received a deficiency notice on their pseudo-tie pro forma agreement. The pro forma has since been approved by FERC staff, but the commission ― which has since gained a quorum ― could overturn that approval. (See FERC Conditionally OKs MISO’s Pseudo-tie Pro Forma.)
MISO’s Independent Market Monitor has protested the new JOA language, saying “nothing in the filing ameliorates the myriad significant problems caused by the pseudo ties.” For more than a year, Monitor David Patton has called for the complete elimination of pseudo-ties, arguing that the process produces dispatch and reliability risks along with expensive congestion that is difficult to manage.
FERC on Thursday rejected a request by PJM to allow Linden VFT to convert the 330 MW of firm transmission on its lines between PJM and NYISO to non-firm, but the commission acknowledged it is moving forward with an investigation of the rules that required it to deny the request (ER17-2267).
The ruling mirrors one the commission made Sept. 8 in response to a similar request by Hudson Transmission Partners, which owns lines that carry 673 MW across the PJM-NYISO border (ER17-2073).
Those lines were part of a decades-old service agreement between Public Service Electric and Gas and Consolidated Edison that the latter company terminated in April. The service “wheeled” 1,000 MW from Upstate New York through PSE&G’s facilities in northern New Jersey and into New York City on the lines owned by Linden and Hudson.
A joint engineering analysis by PJM and NYISO found that continuing to wheel a 400-MW operational base flow (OBF) was the best option for maintaining system reliability. The OBF was implemented despite strong opposition from PJM stakeholders but is expected to be reduced to zero by 2021. (See NYISO Members OK End to Con Ed-PSEG Wheel.)
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In a separate order Friday, the commission approved changes to the PJM-NYISO joint operating agreement reflecting the new operational plan for the ABC and JK interfaces between New York and New Jersey, effective May 1, 2017 (ER17-905).
Linden and Hudson attempted to convert their firm transmission withdrawal rights to non-firm rights, but FERC denied both companies after PSE&G refused to accept the changes. Under the current rules, PSE&G has the right, as a party to the original interconnection service agreements (ISAs), to refuse them.
‘Preferential’ Rate
The New Jersey Board of Public Utilities, which supported PSE&G’s refusal, argued the requests are “an attempt to obtain a preferential rate for New York customers to the detriment of New Jersey ratepayers … because New York customers will continue to receive the same benefits … without any cost responsibility.” It also said the filings constitute “a collateral attack on PJM’s pending [Regional Transmission Expansion Plan] cost allocation methodology and its results in pending cost allocation proceedings” because the firm withdrawal rights are used in determining cost allocations. The changes would establish an alternative cost-allocation methodology “that would yield arbitrary results” compared to PJM’s current solution-based distribution factor (DFAX) method, the BPU said.
Following termination of the “wheel,” PJM asked FERC to reassign $533 million in costs related to the Bergen-Linden Corridor (BLC) project to Hudson, which the commission approved on April 25. The project upgrades facilities needed for the wheel. The New York Power Authority, which is contracted to use Hudson’s lines until 2033 and has taken control of the lines’ firm withdrawal rights, said the reassignment increased its allocation for the project to $645.42 million. It is seeking rehearing on the reassignment order (ER17-950).
FERC sided with PSE&G in both cases but acknowledged that the merchant transmission companies’ ISAs “may be unjust and unreasonable and unduly discriminatory” in not allowing the companies to unilaterally convert their firm transmission rights. The fact that the changes may impact PJM’s RTEP cost allocation “is a challenge to the justness and reasonableness of PJM’s RTEP cost allocation, not whether [the companies] should be able to relinquish [their firm transmission rights].”
In the Hudson case, FERC opened a separate docket (EL17-84). Linden, however, has already filed a complaint where FERC said it will address the issue (EL17-90).
Commissioner Cheryl LaFleur noted as part of the order rejecting Hudson’s request to convert its firm rights that she dissented in the order that applied the solution-based DFAX to the BLC. In certain situations, such as the short-circuit violations addressed in the BLC upgrades or the stability violations addressed by the Artificial Island project, “entities that use the lines may grossly overpay, while entities that benefit from resolution of the underlying violation underpay,” she said. (See Board Restarts Artificial Island Tx Project; Seeks Cost Allocation Fix.)
JOA Changes
In its order Friday, the commission approved revisions to interchange scheduling and market-to-market (M2M) coordination for the PJM-NYISO interfaces, finalizing a delegated order by FERC staff on March 31, when the commission lacked a quorum. The commission also rejected requests by PSE&G, the BPU and Linden to rehear the March 31 order.
The revised JOA combines the ABC and JK Interfaces with the 5018 line and the RTO’s Western ties into an aggregate PJM-NY AC proxy bus. The grid operators said the changes would make use of existing interchange scheduling constructs and support the phase angle regulators (PARs) on the interfaces. Pricing will reflect the impacts of imports and exports on the NYISO and PJM transmission systems, weighted by power flow distribution percentages.
In approving the changes, the commission:
Rejected complaints by PSE&G that there is no reliability need for the OBF and that the changes infringe on transmission owners’ rights;
Said Con Ed should not be charged for PJM RTEP projects, including the BLC project; and
Rejected NRG Energy’s protest over establishing a single price for the PJM-NY AC proxy bus and its complaint that the OBF is a barrier to open access under FERC Order 888.
Dynegy attorneys undoubtedly thought they were helping their case with FERC by volunteering rate information to expedite the sale of its gas-fired Lee Energy Facility, but the filing instead raised questions that last week prompted the commission to initiate an inquiry into the plant’s reactive service rate schedule.
The company had asked FERC to waive a requirement to provide 90 days’ notice of a change in ownership of the 692-MW, eight-turbine facility in Dixon, Ill. (ER17-2321). According to records, Dynegy struck a deal on July 10 to sell the facility to Bruce Power “as soon as possible” (EC17-162). The plant required commission approval to transfer ownership, which it received last Tuesday, but Dynegy had only filed for the approval on Aug. 16. The 90-day period would have lasted until Nov. 14.
Dynegy filed the waiver request the same day it filed for approval of the sale. In support of the request, the company made an informational filing that outlined its commission-approved reactive power revenue requirements, which PJM must pay the facility for providing reactive service.
FERC approved the waiver, but it noticed the revenue requirements were incomplete, including the absence of any leading reactive power test data and only some lagging test data, which the commission said “appear to show that there is degradation of the MVAR output of all eight generator units.” Dynegy’s filing noted that each of the eight units has a nameplate rating of 53.63 MVAR, but that test data supported site-rated gross capabilities ranging from 28.42 to 32.68 MVAR. As a result, the commission established a proceeding to examine the justness and reasonableness of Lee’s reactive power rates (EL17-91).
A settlement judge will be assigned to the proceeding by Oct. 29 and have 30 days to agree on a settlement. Failing that, FERC will assign a presiding judge who must make an initial decision within 180 days of last week’s order being published in the Federal Register. The commission expects it would then take up to eight months to issue a final decision but would set the refund date to the date of publication.
Houston-based Dynegy operates about 31,400 MW of generation in the Northeast, Mid-Atlantic and Midwest (including almost 1,800 MW from plants in which it shares ownership). The company has been fighting to save its coal-fired generation and was approached in May about a potential takeover. (See Report: Vistra Energy Suggests Takeover of Dynegy.)
Bruce Power is owned by Rockland Capital, based in The Woodlands, Texas. Rockland also owns about 10,000 MW of generation in the U.S. and England, along with the New Jersey-based Vineland Energy power marketer.
FERC has declined to involve itself in a dispute over whether Consumers Energy must transfer ownership of transmission assets to its former subsidiary.
The commission said last week it does not have “exclusive jurisdiction” over whether Consumers Energy must transfer reclassified transmission assets to Michigan Electric Transmission Co. (EL17-48). METC argued that under a 15-year-old Distribution-Transmission Interconnection Agreement with Consumers, it had the ownership rights on several of Consumers’ distribution facilities reclassified as transmission facilities by NERC in 2012.
Consumers transferred its then-existing transmission facilities to subsidiary METC in 2001, then sold METC to Michigan Transco Holdings in 2002. As part of the sale, Consumers and METC signed the Distribution-Transmission Interconnection Agreement, which stipulates that “should future system modifications result in the reclassification of assets, the parties agree to convey ownership of those assets to the appropriate party.” Consumers argued that it should keep possession of the disputed assets because the reclassification was not caused by a “physical system modification.” METC was acquired by ITC Holdings in 2006.
| ITC
FERC said the transmission ownership issue was a matter of contract interpretation that should be left to the courts. The commission also said there was no merit to Consumers’ argument that FERC is uniquely positioned to decide whether the assets should be transferred in because of its expertise in NERC reliability issues, the Federal Power Act and promoting competition in transmission development.
“The outcome of this matter appears to turn on interpretation of the parties’ intentions and construction of the [agreement] rather than any determination requiring the commission’s special expertise,” FERC said.
The commission also said the disagreement was a one-off situation that would be unlikely to create precedent because the company’s agreement was uncommon. “The [agreement] is a unique, bilateral, interconnection agreement covering a transaction in which a generation and distribution company sold its transmission assets to a third party. … [It] is not a standard or common provision in interconnection agreements. Thus, the outcome of this proceeding would not determine a general policy … and the resolution of the contractual dispute here likely will have little effect beyond the parties involved.”
FERC last week opened hearing procedures to determine the fairness of reactive power rates for an east central Illinois gas-fired generating plant.
The 195-MW Tilton Energy plant made an informational and rate schedule filing in April, spurred by a change in upstream ownership. The company did not propose a change to its current rate schedule, explaining that the plant “is being transferred completely intact” with no interruption of its reactive service. In the last decade, Tilton has changed hands from Dynegy to LS Power to current parent Rockland Capital.
Tilton Energy Center | Google Maps
While the commission accepted Tilton’s informational filing and unchanged rate schedule, it instigated settlement proceedings and set an Oct. 5 refund date, explaining that Tilton’s current reactive power capability may have degraded since FERC approved a $781,383 annual revenue requirement for the plant in 2010 (ER17-1428, EL17-79).
Those of us who dwell in the economic/regulatory/public policy realm wonder about the origins of atrocious public policy. Where did it come from? Whose awful idea was this?
In the case of the Department of Energy’s Cash for Clunkers proposal, we pretty much know.
Robert Murray, owner of the coal mining company Murray Energy,[1] was a large fundraiser for candidate Donald Trump during the campaign.[2] After the election, Murray had a couple of meetings with President Trump at which the president promised Murray to do whatever he (and FirstEnergy) wanted Trump to do. I’m not making this up.[3]
What Murray wanted was for Rick Perry, the secretary of energy, to declare an emergency on the electric grid so that FirstEnergy would keep buying a lot of coal from Murray’s coal mining company. Again, I’m not making this up.
Now it seems that pesky government lawyers figured out that the supposed basis for such an action, Section 202(c) of the Federal Power Act, couldn’t possibly justify that. “The White House and the Department of Energy are in agreement that the evidence does not warrant the use of this emergency action.”[4]
At this point, a lot of us naively assumed it was safe to go back about our business. We were wrong.
Somebody came up with Plan B (or more like Plan 9) of using an even more obscure federal statute to tell FERC to have a rulemaking to subsidize the coal and nuclear clunkers in the country. So here we are.
FERC on Friday accepted ISO-NE’s updated cost of new entry (CONE) and offer review trigger price (ORTP), effective March 15, 2017 (ER17-795).
The RTO, which is required to recalculate the values every three years, will apply the revisions in Forward Capacity Auction 12 in February 2018 for the June 2021–May 2022 capacity commitment period, as well as in FCAs 13 and 14.
In its Oct. 6 order, the commission agreed with ISO-NE on every point and refuted every protest filed by the New England Power Generators Association (NEPGA). The RTO changed the reference resource on which it bases the CONE and net CONE values from the combined cycle gas turbine chosen in 2014 to a simple cycle generator, citing it as the most economically efficient, with a net CONE value of $8.04/kW-month. The grid operator cited the combined cycle turbine as the next most efficient resource type, with a net CONE of $10/kW-month.
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NEPGA argued that zonal clearing prices in FCAs 7-9 were at or above $14.99/kW-month, which indicated that the actual CONE is higher than ISO-NE’s proposed value. The commission disagreed, saying “NEPGA has not persuaded us that the proposed net CONE value will result in a starting price that will limit investment and competition in the FCA.”
Regarding NEPGA’s comment that ISO-NE’s consultant on the Tariff revisions, Concentric Energy Advisors, listed a production tax credit value as 15 cents/kWh, rather than 1.5 cents/kWh, the commission noted that “this appears to be a typographical error that is not carried forward into Concentric’s calculation of the actual ORTP value.”
The commission also approved ORTP values of $7.856/kW-month for combined cycles, $6.503/kW-month for combustion turbines, $11.025/kW-month for onshore wind, $0/kW-month for energy efficiency, $1.008/kW-month for large demand response and $7.559/kW-month for mass-market DR. Offers below the technology-specific thresholds are subject to review by the RTO’s Market Monitor for buyer-side market mitigation.
FERC on Friday approved NYISO’s more stringent testing requirements for generators providing black start and system restoration services (ER17-2271). The changes, effective Oct. 8, require that generators participating in the Consolidated Edison local system restoration plan comply with all applicable testing requirements imposed by mandatory reliability standards.
The New York State Reliability Council (NYSRC) last November approved proposed reliability rule 133, which requires that all generators providing restoration services annually test their ability to energize a dead bus without support from the transmission system. NYSRC coordinates its reliability rules with NERC and the Northeast Power Coordinating Council.
New York skyline when half the city was in blackout due to a power failure during Hurricane Sandy in 2012. Midtown, with the Empire State Building, is in the background with the darkened East Village and other parts of downtown in the foreground.
Con Ed in 2016 became a NERC-registered transmission operator and must comply with NERC reliability standard EOP-005-2.3.
The commission’s Oct. 6 order dismissed a protest from NRG Energy that the proposed change would give Con Ed “sole discretion to change black start testing rules at any time, without NYISO stakeholder or commission review, or adequate notice to affected generators.” NYISO had responded to NRG that any changes to its System Restoration Manual are subject to review by stakeholders, posted for review at least 15 days prior to a scheduled committee approval and must be approved by 58% of voting members of the applicable committee.
FERC agreed: “Of note, in this case, NYISO stakeholders have already reviewed and unanimously approved revisions to the System Restoration Manual that include specific black start testing requirements in the Con Edison plan.”
LS Power’s Republic Transmission last week won FERC approval for incentives to construct MISO’s first competitively bid transmission project.
FERC granted Republic’s requests for a return on equity adder of 50 basis points for participating in an RTO for the Duff-Coleman transmission project. The commission also approved the company’s request for recovery of prudently incurred costs if the project is abandoned for reasons beyond Republic’s control and use of a hypothetical 55% debt/45% equity capital structure until commercial operation (EL17-52).
Duff to Coleman planned route in yellow | Republic Transmission
FERC noted that its approval of the adder is subject to the overall 9.8% on ROE cap Republic promised in its project proposal.
FERC backdated the rate approval to May 15. While FERC was without a quorum for six months, Republic begun developing the Duff-Coleman project under the assumption that it would receive all requested incentive rates.
“Republic’s investors entered into the selected developer agreement and agreed to rate concessions with an expectation that the project would qualify for, and receive, the limited incentive rates requested prior to the expenditure of significant funds,” FERC said. The commission also found that MISO’s 2015 Transmission Expansion Plan established that the project will deliver cost benefits by relieving congestion and improving reliability, a requirement of incentivized rates under Order 679, which established incentive-based rates for transmission development over a decade ago.
Duff to Coleman route in red near Ohio River | Republic Transmission
For the remainder of 2017 and most of 2018, Republic will work on project design, environmental permitting and securing rights of way. Construction is slated to begin the fourth quarter of 2018.
Republic said it expects to encounter “construction risks and challenges,” most notably acquiring federal permitting to cross the Ohio River.
FERC on Friday rejected a bid by New England transmission owners to increase their returns on equity to the levels enjoyed before they were lowered by a 2014 commission order that was vacated by an appellate court earlier this year.
The commission said it would address the actual rate in a later remand order (ER15-414, EL11-66).
The D.C. Circuit Court of Appeals ruled in April that the commission had “failed to provide any reasoned basis” for setting the base ROE for a group of New England TOs at 10.57%, adding that the commission failed to meet its burden of proof in declaring the existing 11.14% rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
National Grid’s Sandy Pond Substation in Ayer, Mass.
Led by Emera Maine, the TOs requested reinstatement of their previously allowed ROEs in June. Other parties included Central Maine Power, Eversource Energy, National Grid and Avangrid subsidiary United Illuminating.
The TOs claimed that the court’s decision “automatically” restored the parties to the rate in effect prior to the vacated Opinion No. 531. Because the commission lacked a quorum at the time of the filing, the TOs asked to begin collecting at the higher rate 60 days after the commission regained a quorum, which it did on Aug. 9, when new Chairman Neil Chatterjee and Commissioner Robert Powelson joined the commission. (See Quorum Restored, FERC Holds First Open Meeting Since January.)
To reduce the administrative burden on the commission, the TOs said they would leave the question of surcharges for the period before the court’s decision until FERC issued a remand order for Emera.
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The commission disagreed that the D.C. Circuit decision returned TOs to their previous ROEs: “As the Supreme Court explained in Burlington Northern Inc. v. United States, which involved the substantively similar provisions of the Interstate Commerce Act, a ‘federal court[’s] authority to reject … rate orders for whatever reason extends to the orders alone, and not to the rates themselves.’”
The commission concluded that leaving the current ROEs in place would not make the TOs any worse off following a remand order for Emera because, on remand, the commission will exercise its “broad remedial authority” to make whatever ROE the commission determines to be just and reasonable effective for the refund period and the entire period.”
In addition, the order said an immediate return to the previously allowed ROEs would “significantly complicate the process of implementing the commission’s order on remand.”
In 2014, FERC determined that a discounted cash flow (DCF) analysis of a proxy group of companies comparable to TOs produced a zone of reasonableness of 7.04 to 11.74%. The commission also concluded that TOs’ new just and reasonable ROE should be set at the upper midpoint of the zone of reasonableness — i.e., halfway between the midpoint and the top of the zone of reasonableness.
The D.C. Circuit ruled that the commission had not adequately shown that the existing ROE was unjust and unreasonable. The court explained that the Federal Power Act’s statutory “zone of reasonableness creates a broad range of potentially lawful ROEs rather than a single just and reasonable ROE.”
