Page 1471 – 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, 2017May 20, 2025

FERC Approves NY Black Start Rule Change

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.”

— Michael Kuser

October 10, 2017

FERC Grants Developer Incentive Rates for Duff-Coleman Project

By Amanda Durish Cook

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).

FERC CAISO LS Power Duff-Coleman — 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.

MISO selected Republic’s $49.8 million proposal for the 30-mile, 345-kV line in Southern Indiana and Western Kentucky in December. (See LS Power Unit Wins MISO’s First Competitive Project.)

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.

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.

October 10, 2017

FERC Rejects New England Tx Owners on ROE

By Michael Kuser

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.)

return on equity FERC ROE — 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.

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.”

October 10, 2017

SPP Seams Steering Committee Briefs: Oct. 4, 2017

SPP stakeholders last week briefly discussed a recent American Electric Power complaint filed at FERC against the RTO and MISO related to overlapping congestion charges for pseudo-ties.

The Section 206 complaint (EL17-89) alleges that MISO violated its joint operating agreement with SPP by assessing congestion charges to AEP subsidiary Southwestern Electric Power Co. load that is pseudo-tied out of MISO and into SPP.

In its complaint, AEP said the MISO Tariff and Business Practices Manual are unjust and unreasonable in how they assess the congestion charges.

SPP and MISO have negotiated a memorandum of understanding to address the overlapping charges. The RTOs have said the MOU borrows elements from MISO’s coordination efforts with PJM but won’t result in major changes in coordination. (See MISO Interregional Plans with SPP Echo PJM Efforts.)

The overlapping congestion complaint is the first against SPP; stakeholders have filed five similar complaints against MISO and PJM. (See MISO, PJM to Try Again on FERC Pseudo-Tie Filings.)

Staff said Friday it will file a response at FERC but won’t comment until then.

Light M2M Activity Results in $161K in Payments to SPP

In what staff described as a light month for market-to-market activity between SPP and MISO, the latter paid SPP more than $161,000 in August, reversing two months of payments in the opposite direction.

Permanent flowgates accounted for most of the congestion, binding for 37 hours and resulting in $148,794 in M2M settlement charges to MISO. Temporary flowgates were binding for 83 hours, 131 hours less than the month before, giving SPP an additional $12,495.

SPP has collected $20.7 million in payments from MISO as of August. The M2M process between the two RTOs began in March 2015.

AEP’s Jacoby Continues as Chair

The committee approved its recommendation for AEP’s Jim Jacoby to serve a full two-year stint as chairman, effective Jan. 1. Jacoby’s term will expire Dec. 31, 2019.

— Tom Kleckner

October 10, 2017

FERC Rejects Cost Allocation for SPP-AECI Seams Project

By Tom Kleckner

FERC on Friday rejected SPP’s proposed cost allocation for its seams project with Associated Electric Cooperative Inc. (AECI), a Missouri-based collection of six generation and transmission cooperatives.

The commission ruled SPP had not shown that the proposed allocation on a regionwide, load-ratio share basis was “roughly commensurate” with the project’s benefits (ER17-2256, ER17-2257).

The project includes a new 345/161-kV transformer at AECI’s Morgan substation and uprating a related 161-kV line, both near Springfield, Mo. SPP estimated the project, intended to address persistent thermal and voltage problems, would cost $18.75 million. SPP asked FERC to approve a cost-sharing and usage agreement among the RTO, AECI and City Utilities of Springfield — along with Tariff revisions incorporating SPP’s negotiated share of the revenue requirements — in August.

FERC SPP Seams out-of-cycle project — | *AECI*

SPP General Counsel Paul Suskie said that although the RTO is disappointed, “we’re undeterred and confident we’ll be able to continue to work … with members to develop an appropriate cost allocation for this and future seams projects.”

“The ability to develop necessary and beneficial transmission improvements along our seams remains a high priority for SPP and its members,” Suskie added.

SPP had proposed to regionally fund the projects, as they solved congestion issues on its side of the seam. The RTO agreed to cover 89.1% of the $13.75 million transformer and 97% of the $5 million uprate, with AECI covering the remainder and being responsible for the projects’ construction, operations and maintenance.

The RTO said it planned to allocate its share of the two projects by inserting their revenue requirements into the annual transmission revenue requirement of its highway/byway regional cost allocation methodology. Highway/byway funding considers facilities of 300 kV or above as highway facilities, with their costs allocated on a regionwide, postage-stamp basis; facilities between 100 and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide.

Projects below 100 kV are allocated entirely to the host zone, while upgrades that operate at two difference levels — such as transformers — are allocated based on the facilities’ lower operating voltage.

Xcel Energy and Westar Energy protested the RTO’s filing.

Xcel opposed the Morgan transformer’s cost allocation, contending that SPP provided insufficient evidence that the proposed cost allocation reflects its benefits. The company said there is no “default rule” that customers in SPP’s 19 transmission zones “should bear the costs of a transmission facility in cases where the owner of the facility is located outside [the footprint].”

The company also said SPP failed to provide information on the project’s benefits to transmission owners or loads in the Southeastern Regional Transmission Planning (SERTP) region that would justify a broader cost allocation to AECI’s fellow SERTP members.

FERC sided with Xcel’s argument that SPP had not provided specific information on the transformer project’s regionwide benefits and had not offered “sufficient evidence to demonstrate that these claimed economic benefits accrue throughout the SPP footprint.” The commission said the RTO’s own analysis indicated the project does not provide economic benefits to at least 11 of the 19 transmission zones.

Because SPP failed to support its cost allocation, FERC said it did not need to address Westar’s allegation of a lack of transparency regarding SPP’s negotiations with AECI. The utility had argued all affected parties have a right “to analyze the methodology and rationale by which SPP and AECI negotiated and substantiated the cost allocation ratios proposed in the filings.”

The commission said its rejection does not preclude the RTO from proposing an alternative allocation or making another filing that demonstrates the project provides regional benefits.

SPP stakeholders in July reiterated their support of the project, despite a nearly 50% cost increase due to additional work to upgrade the 161-kV line. (See “Board Reaffirms Seams Project with AECI,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)

The commission in 2015 rejected SPP’s attempt to create a new class of seams transmission projects, saying its plan to identify projects outside the Order 1000 interregional planning process was “too broadly drawn” (ER15-2705). FERC did allow SPP to make filings on a project-by-project basis for non-Order 1000 facilities. (See FERC Rejects SPP Proposal for Seams Transmission Projects.)