Page 1240 – RTO Insider

October 12, 2017

NYISO Business Issues Committee Briefs: Oct. 11, 2017

RENSSELAER, N.Y. — NYISO year-to-date monthly energy prices averaged $35.34/MWh in September, a 3% increase from a year earlier, Michael DeSocio, senior manager for market design, said Wednesday in presenting the ISO’s market operations report to the Business Issues Committee.

Locational-based marginal prices (LBMPs) averaged $29.57/MWh for the month, down 3.3% from August and 4.3% from September 2016.

The ISO’s average daily sendout was 437 GWh/day in September, down from 477 GWh/day in August and 458 GWh/day a year earlier.

New York natural gas prices gained 5% in September, averaging $2.27/MMBtu at the Transco Z6 hub. Prices were up 72.2% from a year ago. Distillate prices gained 32.3% year-on-year, with Jet Kerosene Gulf Coast averaging $13.40/MMBtu, up from $11.53/MMBtu in August. Ultra-Low Sulfur No. 2 Diesel NY Harbor averaged $12.80/MMBtu, compared with $11.65/MMBtu in August.

The ISO’s local reliability share was 16 cents/MWh, one-third higher than the previous month, while the statewide share “is trending lower at -50 cents/MWh,” compared with -31 cents/MWh in August, DeSocio said. Total uplift costs were lower than in August.

In speaking about the Broader Regional Markets report, DeSocio only highlighted that FERC last month accepted NYISO’s proposed Tariff revisions regarding cost recovery for the Ramapo PARs, as filed by the ISO in June. NYISO foresees negotiating with PJM by year-end the cost sharing for the replacement of PAR 3500.

Proposed Tariff Changes for Energy Storage

NYISO Business Issues Committee natural gas — Solar inverter battery

The committee approved proposed Tariff and Ancillary Services Manual changes to define the role of inverter-based energy storage in providing synchronized reserves.

Daniel F. Noriega, NYISO associate market design specialist, presented the BIC-proposed Tariff changes that would allow generators and demand-side resources that use inverter-based energy storage technology to provide spinning reserves.

The ISO last year asked the Northeast Power Coordinating Council (NPCC) to clarify whether such resources can provide synchronized reserves. The NPCC responded that “a storage resource with inverter technology complies with the original intent of the synchronized reserve requirement and therefore shall qualify towards a [balancing authority’s] complement of synchronized reserves.”

NYISO in January presented its Market Issues Working Group with proposed Ancillary Services Manual revisions to reflect that clarification. Stakeholders provided feedback on the wording, which NYISO incorporated in the updated proposal presented Wednesday. NYISO intends to bring the proposed Tariff and manual changes to the Operating and Management committees for action this month.

Fuel Cost Adjustment Calculation to be Refined

The BIC also approved a proposal that would more closely align the real-time and day-ahead impact tests and penalty calculations used to identify generator misuse of fuel cost adjustments (FCAs). The current day-ahead process is considered more precise because it tests the impact on real-time LBMPs based on market reruns.

NYISO Mitigation Reference Analyst Nicholas Shelton explained that FCAs allow generators to submit a fuel type or fuel price — or a combination of both — along with their energy offers. Once the ISO validates the FCA is within posted thresholds, a generator can update its incremental energy and minimum generation reference levels to reflect the new information. The ISO’s Market Mitigation & Analysis unit reviews all FCAs, and those that fail the conduct and impact tests may be subject to penalty.

The ISO has found that reviewing FCAs from only the prior seven days does not ensure enough data are available to draw conclusions about tendencies toward an upward bias in prices. The proposed changes would combine the day-ahead and real-time market penalties into one section and lengthen the FCA review period to 90 days from the previous seven days.

According to the proposal, the 10% threshold used in screening for bias has become increasingly restrictive with the decline in natural gas prices, so that a $2/MMBtu price translates into a very tight threshold. Rather than using a 10% threshold to identify bias, the proposal would rely on the greater of 10% or 50 cents/MMBtu.

The proposed changes will go to the Management Committee in October and, if approved, be submitted to the Board of Directors in November prior to filing with FERC.

— Michael Kuser

October 12, 2017

Spike Sends ERCOT Houston Prices Past $1,000/MWh

Editor’s note: An earlier version of this story incorrectly used data from the ERCOT North zone, and not the Houston Hub.

By Tom Kleckner

ERCOT’s Houston Hub saw real-time prices spike as high as $1,251/MWh on Monday during an early fall heat wave.

Hub prices first cracked $1,000/MWh during the 15-minute interval ending at 1:45 p.m. on Oct. 9, and then again during each of the 11 intervals between 2:30 and 5 p.m. The systemwide hub average peaked at $520.59/MWh during the 3:15 p.m. interval.

According to ERCOT data, the Houston Hub has now produced 47 intervals of $1,000/MWh this year. That’s the most since 2011, the first full year of the nodal market, when the hub recorded 163 high-priced events. It only had 87 occurrences in 2012-2016.

ERCOT FERC heat wave natural gas prices — | *ICF*

Congestion has long been an issue in the Houston zone, but the high temperatures caught the market with several plants on maintenance outages.

Speaking during a Tuesday webinar, Dinesh Madan, an ICF technical director, said scarcity pricing has been “almost missing from this market.” Madan pointed to a volatile market, thanks to an overabundance of wind energy and short load forecasts.

“ERCOT is a weather-and-wind story now,” Madan said. “In 2016, the story was wind. In 2017, the story was weather.”

In 2016, wind resources generated 2,024 MW more than their forecasted output coinciding with the summer peak. In 2017, the market’s peak load was 3,428 MW below forecast, thanks to a milder summer. With ample reserves (and lower loads), ERCOT was able to withstand 2016 and 2017 peak loads despite generation outages exceeding forecasts by 1,780 MW and 2,713 MW, respectively, during each summer’s peak.

Monday’s spike came as Texas temperatures soared into the mid 90s. The ISO set a new record for October peak demand at 62,263 MW — just above projections — during the hour ending at 5 p.m., breaking the previous mark set the year before by more than 2.3 GW.

Houston Hub prices peaked at $34.11/MWh on Tuesday, when temperatures and ERCOT load both dropped.

Reservoir of Retirements

During the same webinar Tuesday, ICF Senior Vice President Judah Rose also addressed Vistra Energy’s recent decision to retire three aging coal-burning units in East Texas. (See First Shoe to Drop? Vistra to Retire 3 Texas Coal Units.)

He referred to a “reservoir” of potential retirements among ERCOT’s coal fleet, driven by fat reserve margins, low gas prices and cheaper renewable resources. Rose also pointed out that many of the coal plants, once reliant on cheap, local lignite — including Vistra’s Monticello plant — now depend on Powder River Basin coal brought in on rails from the Rocky Mountains.

“Almost ironically, these plants are facing the least environmental pressure in a long time,” Rose said, referring to the Trump administration’s efforts to roll back the Clean Power Plan. (See EPA to Announce Clean Power Plan Repeal.)

He said the Energy Department’s recent Notice of Proposed Rulemaking to FERC to support out-of-market baseload plants would likely have little effect on Texas coal units, as the agency has no jurisdictional authority over ERCOT.

Any FERC policy “will not provide additional revenue,” Rose said. “The exit of these plants will be related to low power prices.”

Rose said ICF will be watching ERCOT’s reserve margins, which the ISO forecasts will be 16.3% next year. The firm expects that margin to dip below the planning reserve margin of 15.6% in 2019.

“That’s significant, because generally, when you start getting below 15% in markets, you have the potential for all hell breaking loose,” he said. “You get a lot of potential for price spikes.”

The Monticello retirement may provide $1 to $2/MWh of upside in scarcity equilibrium in 2019, Rose said.

October 12, 2017

Perry Defends Call for Coal, Nuclear Supports

By Michael Brooks and Rich Heidorn Jr.

WASHINGTON — Energy Secretary Rick Perry on Thursday defended his call for price supports for struggling coal and nuclear plants, telling the House Energy Subcommittee “these resources must be revived, not reviled.”

rick perry nuclear coal — Perry testifying before the House Energy Subcommittee | © *RTO Insider*

Perry also pushed back on criticism that his Notice of Proposed Rulemaking, which called for “full recovery” of the plants’ costs, would undermine competitive markets.

Republicans largely expressed support for the rule. But Perry did little to counter allegations that his action was motivated by President Trump’s campaign promises to help the coal industry — repeatedly sidestepping Democrats’ questions about the costs of his proposal and the evidence supporting the need for 90 days of on-site fuel.

“The base reason that we asked for this … is that, for years, this has been kicked down the road,” Perry said.

The NOPR, published in the Federal Register Tuesday, would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and a real-time energy markets to ensure full cost recovery for any generation not subject to cost of service rate regulation that is capable of providing “essential energy and ancillary services” and has a 90-day fuel supply on site “enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.”

Essential services include voltage support, frequency services, operating reserves, and reactive power. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.

Countering Subsidies

Perry said he was attempting to counter subsidies that have benefited renewables at the expense of coal and nuclear. “There is no such thing as a free market for in the energy industry,” he said. “Government’s picking winners and losers everyday through regulations… and I’m at least honest enough to say it.”

Perry said the grid is normally resilient during “blue sky” days and said his support for an “all of the above” generation mix was proven during his time overseeing wind growth as governor of Texas. “But the wind does not always blow. The sun doesn’t always shine. The gas pipelines — they can’t guarantee every day that supply is going to be there.”

He said the NOPR was intended to “kick start a national discussion about resiliency and about the reliability of the grid.” Noting the vociferous opposition his proposal provoked, he chuckled, “And best I can tell we were pretty successful in doing that. …We’re having this conversation now that we really haven’t had in this country.” (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)

Indeed, about 50 companies, regulatory agencies and trade groups have intervened or made comments in the docket FERC opened to respond to the NOPR (RM18-1).

Not Supported by DOE Study

Rep. Frank Pallone (D-N.J.) said the NOPR was not supported by the grid study DOE released in August, asking Perry what analyses DOE or its national labs had done to support the proposal.

Perry did not respond to the question, instead challenging Pallone’s premise. The DOE study, he said, didn’t address “with specificity the events I’m concerned about,” he said, citing the 2014 polar vortex.

In fact, the report had about 17 references to “extreme weather” or the polar vortex. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)

Perry also sparred with Rep. Michael Doyle (R-Pa.), who said said the committee had held eight hearings on markets and reliability. “We’ve actually been having the conversation you claimed to be starting,” he said.

“This has been discussed for a long time, as you rightfully said,” Perry conceded. But he said it was now time for action.

“Our RTO made that adjustment” after the polar vortex, Doyle said, referring to PJM’s Capacity Performance rules, which increased the penalties and bonuses for capacity resources during grid emergencies. “We feel pretty confident of our capacity in Pennsylvania.”

“’Pretty confident’ is not going to get it [done]” Perry shot back.

Doyle also pressed Perry on discrepancies between the NOPR, which repeatedly says FERC “must” act and the secretary’s reference to a conversation. (See FERC’s Independence to be Tested by DOE NOPR.)

“Is it a directive to FERC to do this or a conversation?” Doyle asked.

“Both,” Perry said.

“So, it’s a directive then?” Doyle asked.

“My words are what my words are. I don’t back off from them,” Perry said.

“It can’t be both,” Doyle protested. “So, which one is it?”

“Well actually it is both. I can be both. We can have a conversation and I think [FERC] must move. I think they must act. We’ve kicked this can down the road as long as we need to.”

Rep. Kathy Castor (D-Fla.) also said the NOPR conflicted with the findings of the grid study and said it would cost consumers and businesses billions. “There is just no rational basis for this new FERC rule that you’re trying to move through as quickly as possible,” she said.

“If the request … the NOPR to FERC is what you say it is, [FERC] won’t go forward with it,” Perry responded.

October 11, 2017

PJM Stakeholders Battle over Cost Cap Rules

By Rory D. Sweeney

VALLEY FORGE, Pa. — Only a few PJM stakeholders attended Monday’s special Planning Commission session on cost-containment provisions in bids on transmission projects, but they came prepared to defend their opposing positions.

PJM FERC cost-containment provisions Interregional Transmission Planning — Glatz | © *RTO Insider*

PJM’s Sue Glatz reviewed proposed changes to Manual 14F to incorporate cost-containment principles that were identified by stakeholders in previous meetings of the group, including submission requirements, what submission information will be kept private and evaluation guidelines.

Much of the debate at the Oct. 9 meeting occurred over what should or should not be specifically stated in the manual.

Sharon Segner, with merchant transmission developer LS Power, disputed PJM’s plan to require bidders to explain the rationale behind requested exclusions from the proposal’s cost cap. The decision could be for competitive reasons that don’t aid PJM’s analysis but might harm the bidder, she said.

Jodi Moskowitz of Public Service Electric and Gas supported PJM’s plan to require the supporting rationale for exclusions. She questioned why the requirement was a concern given that supporting information should be treated on a confidential basis.

“Isn’t a lot of this information redacted?” she asked.

Segner requested that the manual language guarantee the confidentiality of bidders’ explanations for any exceptions to their proposed cost cap, such as if the prices for certain materials change drastically or the anticipated siting route fails to receive approval.

“If you’re asking for supporting rationale [to be included within proposals], it should be made clear in the business practice language that that rationale will not be made public,” she said.

Glatz said she would investigate what changes might better protect “commercially sensitive language.”

Creating Clarity

Stakeholders disagreed on whether to enunciate that PJM will not consider any cost-cap guarantees beyond those related to construction costs, although they “may be included in the project proposals,” and that winning bidders are free to “propose, through the FERC ratemaking process, other cost-cap mechanisms associated with the project.”

Segner and Greg Poulos, the executive director of the Consumer Advocates of the PJM States, agreed that the language improves clarity, even if they didn’t agree with the policy itself. However, PSEG’s Vilna Gaston and Delaware Public Service Commission staffer John Farber opposed it because they felt it suggests powers that go beyond PJM’s actual authority.

“I think the FERC ratemaking process speaks for itself,” Farber said. “The PJM approval process should not be involved with those ratemaking issues.”

“You have no authority to say what someone can file or not file at FERC [or] what FERC can consider,” Moskowitz said.

Poulos and Segner agreed that their preference would be for “more opportunity for cost caps in other areas,” but that the language demarcates exactly what is PJM’s policy.

“I think this is a very helpful sentence because it creates clarity,” Poulos said. “It’s very clear what PJM is considering and not considering.”

“Part of the reason that this whole stakeholder process is going on is because varying types of cost containment proposals are being proposed,” Segner said. “I don’t think it’s obvious that other forms of cost containment won’t be considered unless it’s spelled out.”

“I think what I’m hearing is that people do like the clarity but don’t want something that creates the illusion” that PJM has authority to control what can be filed at FERC, Glatz said, attempting to summarize the proceeding.

‘Over the Top’

Gaston and Segner again clashed on whether to include requirements that any confidential information that is inadvertently disclosed could not be used in the future by any third parties for any purposes.

“I think that’s over the top,” Segner said in opposing the requirement, suggesting its intended purpose was to muzzle state regulators and consumer advocates.

“It’s not really about protecting the bidders against each other,” she said. “The issue is how it could be used against you later in a litigation proceeding, and you’re trying to put language in that would exclude that type of information in a litigated proceeding.”

“That’s not the intent,” Gaston said. “There’s confidential information that may be competitive information.”

Glatz said she’d ask PJM’s attorneys “how complicated that is” to include.

PJM hopes to receive endorsement for the rule changes in time for the upcoming planning year, which would mean bringing it to the Planning Committee for a vote in December at the earliest. Stakeholders asked for another meeting or video conference before then to finalize their requests. Glatz said she would search for an available date prior to the November committee meeting.

October 11, 2017

CPP Supporters Hope for Action by DC Circuit

By Rich Heidorn Jr.

Now that EPA has reversed its position on the legality of the Clean Power Plan, some supporters of the program say the appellate court that heard oral arguments a year ago should rule on the issue.

EPA CPP D.C. Circuit Clean Power Plan — Pruitt | *EPA*

In proposing to repeal the CPP, EPA Administrator Scott Pruitt said Tuesday that the Obama administration overreached its legal authority under Section 111(d) of the Clean Air Act by ordering generators to take actions “outside the fence line” of individual generators. (See EPA to Announce Clean Power Plan Repeal.)

That was one of the central issues in the appeal that Pruitt, as Oklahoma attorney general, filed along with more than two dozen other states after the CPP was issued in August 2015. In September 2016, the D.C. Circuit Court of Appeals heard oral arguments on that and other legal challenges to the plan.

In August, however, the D.C. Circuit agreed to hold the case in abeyance after President Trump’s executive order calling on EPA to reconsider the rule.

Judicial Economy

Attorney Tim Profeta, director of Duke University’s Nicholas Institute for Environmental Policy Solutions, said Tuesday that the D.C. Circuit should now rule on the case because of “the logic and judicial economy of the situation.”

“You’ve got the court of jurisdiction having heard en banc the precise legal arguments that are being made in this rule,” he said in an interview. “It’s fully briefed. It’s fully argued.”

If the court doesn’t act on the case before it, he said, “they will probably have the same case before them in new litigation that would have to be briefed and argued all over again. … There’s no reason for the court to waste its time and taxpayers’ money to relitigate the case,” he said.

David Doniger, director of the Natural Resources Defense Council’s Climate & Clean Air program, agreed. The court “could rule before [Pruitt] gets to the finish line on the repeal,” he said during a press conference Tuesday. “At least some of the judges there are looking at their wristwatches.”

Doniger was referring to the concurrence filed by Judges David S. Tatel and Patricia A. Millett on Aug. 8, when the court held the case in abeyance and ordered EPA to file reports monthly detailing the status of its review. The D.C. Circuit’s action followed the Supreme Court’s February 2016 stay preventing EPA from implementing the rule pending the legal challenges.

“As this court has held the case in abeyance, the Supreme Court’s stay now operates to postpone application of the Clean Power Plan indefinitely while the agency reconsiders and perhaps repeals the rule,” the two judges wrote. “That in and of itself might not be a problem but for the fact that, in 2009, EPA promulgated an endangerment finding, which we have sustained. … That finding triggered an affirmative statutory obligation to regulate greenhouse gases. Combined with this court’s abeyance, the stay has the effect of relieving EPA of its obligation to comply with that statutory duty for the indefinite future.”

During the oral arguments, Millett and Tatel had indicated sympathy for the Obama administration’s position that the CPP complied with Section 111(d). The term “best system of emission reduction” is “an awful broad grant” from Congress, Tatel said. “It says best system of emissions reduction,” he repeated twice, emphasizing “system.” (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

Status Report

EPA filed a status report late Tuesday informing the court of the proposed repeal and asking it to continue holding the case in abeyance. “EPA will be signing in the near future an Advance Notice of Proposed Rulemaking that will solicit information on systems of emission reduction that are in accord with the legal interpretation that has been proposed by EPA,” said the report, which was signed by Deputy Assistant Attorney General Eric Grant.

Doniger said NRDC, which intervened in the case on behalf of the Obama EPA, has the right to defend the CPP now even if the agency no longer does. “Depending on what [EPA does regarding the delayed ruling], we’ll respond,” he said. “If they don’t do anything, we may do something [to request a ruling.] … We deserve a resolution of the legality of the Obama rule.”

If it chooses not to rule now, the court could set a deadline for final EPA action or grant additional short-term delays “to keep the pressure on,” Doniger said.

An EPA spokeswoman declined to comment on the status of the D.C. Circuit case, referring questions to the Department of Justice, which also declined to comment.

During oral arguments, Justice Department attorney Eric Hostetler told the court it should back the CPP under the Supreme Court’s Chevron decision, which held that courts should defer to agencies’ interpretations of the laws they are charged with enforcing unless the court finds their actions unreasonable. “This is far from the first time EPA has relied on generation-shifting,” Hostetler said. EPA’s rule, he added, is a “proper and sensible” response for the “most urgent threat that our country has ever faced.”

Returning to Prior Interpretation

CPP critic Jeff Holmstead, a partner with Bracewell and former EPA assistant administrator for air and radiation, had a very different view.

“In today’s proposal, EPA is not breaking any new legal ground. It is simply returning to the position that EPA had taken, under all prior administrations except the Obama administration, regarding the way in which industrial facilities can be regulated under a particular provision of the Clean Air Act,” he said in a statement.

“Under the CPP, the Obama EPA claimed that this 45-year-old provision actually gave it the extraordinary power to restructure the entire U.S. power sector — requiring that coal-fired power plants be shut down and replaced by wind and solar facilities favored by the Obama administration. Virtually every major business group joined 27 states in challenging this claim, arguing that the CPP was an example of historic regulatory overreach.”

Single Source

According to a draft of the proposed rulemaking that was leaked last week, EPA said it will interpret the CAA’s “best system of emission reduction” as referring to measures “that can be applied to or at an individual stationary source. That is, such measures must be based on a physical or operational change to a building, structure, facility or installation at that source, rather than measures that the source’s owner or operator can implement on behalf of the source at another location.”

The draft indicated EPA will not seek to reverse the agency’s 2009 finding that GHGs endanger public health.

EPA’s Obligation to Act

Doniger said EPA’s “legal obligation is to have an effective standard and one that reflects how the power system actually works.”

“Pruitt is operating under a fictional view — a 125-year-old view — that each power plant is operating by itself and serving the surrounding community alone. … Pruitt is constructing a legal argument based on a factual fiction — it basically assumes that there is no grid and there is no interconnection. And that’s among the reasons why his legal view will not prevail.”

October 10, 2017

2nd Deficiency Notice Issued for MISO-PJM Pseudo-Tie Effort

By Amanda Durish Cook

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).

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.

October 10, 2017

Rejecting PJM ‘Wheel’-related Requests, FERC Sets Inquiry

By Rory D. Sweeney and Rich Heidorn Jr.

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.)

PJM FERC Linden VFT firm-flow entitlements — | *PJM*

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.

October 10, 2017

Waiver Request Lands Lee Plant a FERC Inquiry

By Rory D. Sweeney

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.

FERC reactive power waiver dynegy — Flexon | © *RTO Insider*

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.

October 10, 2017

FERC Sidesteps Michigan Tx Ownership Dispute

By Amanda Durish Cook

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.

FERC Consumers Energy reliability-must-run agreements — | *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.”

October 10, 2017

FERC to Review Illinois Plant’s Reactive Rates

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.

FERC reactive power rates tilton energy — 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).

— Amanda Durish Cook