Page 1401 – RTO Insider

August 29, 2016

MISO Advisory Committee Briefs

MISO has narrowed candidates for the Board of Directors to six, Nominating Committee stakeholder member Matt Brown said.

Brown told the Advisory Committee that the nominating panel interviewed 10 candidates in mid-August and selected a primary and secondary choice for each of the three open seats. The RTO started with a list of about 30 candidates.

“We’re really trying to pick individuals with the most impressive backgrounds, and not the ones that fit a mold,” Brown said.

MISO Board of Directors in Detroit (RTO Insider) advisory committee — MISO’s current board at their June meeting in Detroit © *RTO Insider*

Under MISO rules, the board must be made up of individuals with varying expertise. For this search, the RTO requires a person with transmission operations expertise, one with transmission planning expertise and one with experience in finance, accounting, engineering and utility regulation. Brown said the committee is also looking for candidates who have experience in technology or cybersecurity.

“It’s been a very enlightening process, and I think the search firm did a great job in locating candidates, and we had a very successful interview process,” Brown said. From a stakeholder perspective, Commissioner Weber and I are very excited about the six candidates and their caliber,” Brown said. Indiana Utility Regulatory Commissioner Angela Weber occupies the other stakeholder seat on the Nominating Committee.

Directors Judy Walsh, Michael Evans and Paul Feldman will hit MISO’s term limit when their current terms expire Dec. 31. MISO enacted a limit of three consecutive three-year terms last year. The Nominating Committee can seek a waiver to allow a fourth term if it believes it is needed “to retain [the director’s] skills or expertise, to maintain geographic or other diversity of the board, or is otherwise in the best interests of” MISO.

The board will review the committee’s six choices and make a selection by mid-September. Members will vote on the candidates between Sept. 15 and the Oct. 24 Informational Forum, at which the results will be announced.

The terms begin in January and expire at the end of 2019.

Close to Fall, MISO Stakeholder Entities Still Setting 2016 Priorities

The Resource Adequacy Subcommittee is seeking the approval of just two priorities for the year.

The RASC’s proposed priorities for 2016 are to improve the Planning Resource Auction and enhance gas-electric coordination.

RASC Chair Gary Mathis said he received scant feedback on the priorities. Mathis said he thought the timing had something to do with it. “2016 is more than half over,” he pointed out.

AC Chair Audrey Penner said stakeholders will begin earlier on 2017 priorities, starting with a strategic planning session at the end of September. She added that the groups would work to streamline the new priorities planning process in its second year.

“This is our first kick at the can, and we’ll get better year after year,” Penner said.

Meanwhile, Planning Advisory Committee Chair Bob McKee submitted five priorities nearly identical to the AC’s own priorities approved in May. (See “Committee Endorses 5 Final Priorities,” MISO Advisory Committee Briefs.)

“There was not a lot of conversation, but no concerns have been raised,” McKee said of the AC’s priority-setting.

Penner said the PAC and RASC’s 2016 priorities would be up for AC approval at the September meeting.

— Amanda Durish Cook

August 29, 2016

SoCal Gas Restrictions Unlikely to Impede Winter Grid Operations

By Robert Mullin

Southern California’s winter grid operations are unlikely to be compromised by natural gas pipeline restrictions stemming from the shutdown of Aliso Canyon, even in the event of a once-in-a-decade cold snap, according to an interagency assessment released Monday.

Still, tight gas supplies could leave the region vulnerable to load shedding during a significant grid contingency — such as the loss of transmission import capability or unexpected outages at outside generators serving the region, the report says.

The Southern California Gas (SoCalGas) storage facility north of Los Angeles was closed after a leak released massive amounts of methane between October and February, prompting the company to impose daily balancing requirements on its customers in order to ensure reliable gas delivery to gas-fired generators during the summer’s peak season for electricity demand. (See CAISO Seeks Rapid Response to SoCal Gas Restrictions.)

california aliso canyon natural gas winter grid operations — Graph plots out CAISO’s utilization rates of gas-fired generation in the Los Angeles Basion over the course of 2015.

The report was produced by technical staff from CAISO, the California Public Utilities Commission, the California Energy Commission (CEC), Los Angeles Department of Water and Power (LADWP) and SoCalGas — the owner and operator of the region’s pipeline system.

Cold Day Design Standard

The region’s one-in-10-year “cold day design standard” would require SoCalGas to send out 5.2 Bcfd on its system, the report shows. However, without the ability to withdraw from Aliso Canyon, the company is limited to a maximum sendout capacity of 4.7 Bcfd, assuming there are no other storage or pipeline outages and a full utilization of receipt point and storage withdrawals.

Gas supplied to electric generation could be curtailed if the region’s total demand exceeds 4.5 Bcfd under a scenario in which generators utilize 100% of their gas receipts or 4.2 Bcfd under 85% utilization, the report said, indicating the importance for generators to tightly balance their schedules with their gas burns.

Nevertheless, the region’s electricity grid is expected to operate reliably “so long as the total SoCalGas supportable gas delivery and supply is greater than 4.1 Bcfd under normal pre-contingency conditions and 4.2 Bcfd to support N-1 contingency conditions” — such as the loss of a key generating unit or transmission line serving a load pocket.

While the report finds that the area affected by the gas restrictions should have sufficient transmission and electricity supply from outside resources during winter, it acknowledges that neighboring balancing areas may have to provide emergency assistance “depending on the magnitude and timing of gas curtailments.”

The report offers another caveat: “If supportable SoCalGas supply falls below 4.1 Bcfd during peak winter gas demand conditions, it may be necessary to withdraw from Aliso Canyon to avoid electric load interruption.”

Recent history suggests that gas should be available despite a lack of injections into the facility for almost a year.

“Because of the effectiveness of the Aliso Canyon summer action plan, as of the time of this report, no gas has been withdrawn from Aliso Canyon to maintain electric reliability,” the report notes.

15 Bcf in Storage

The facility still contains about 15 Bcf of working gas in storage, unchanged from the volume that the PUC last January ordered be left in the facility to cover summer needs.

Summer has seen CAISO manage two heat-driven conservation alerts without having to tap that supply, and the grid’s gas needs are sure to drop significantly during winter. Last year, the ISO utilized less than half as much gas-fired generation in the Los Angeles Basin during winter than in summer.

LADWP, which operates its own balancing area, passed through its summer peak season without the benefit of its 287-kV Mead‐Victorville Line 1, which is slated to return to service by winter. The additional transmission capacity should provide 5,010 MW of winter import capability, compared with a forecast peak load of 4,309 MW. The upshot: The utility could meet its reliability requirements without relying on any of the basin’s local gas-fired generation, absent the loss of any of its four synchronous condensers needed for voltage regulation and support.

The interagency assessment was accompanied by a winter action plan developed to reduce the potential for gas curtailments large enough to interrupt Southern California’s electric service. Among the measures is a recommendation that CAISO impose a generator gas burn ceiling for very cold days.

“Effectively, it curtails some of the electric generation load in advance and increases the probability that SoCalGas will not have to curtail further,” the plan says.

The plan also recommends that:

The PUC require that SoCalGas implement a demand response program that rewards large natural gas consumers for reducing demand when requested;
SoCalGas maintain requirements that non-core gas customers tightly balance their schedules with actual use and develop a similar provision for core customers;
The CEC and PUC investigate what “affiliate impediments” would prevent SoCalGas parent company Sempra Energy from buying LNG from its own Costa Azul LNG facility in Mexico and delivering it into the Southern California gas system; and
The CEC identify and solicit additional sources of gas supply, including more in-state production.

The California agencies are seeking comments on the winter action plan, the subject of an Aug. 26 public workshop.

August 29, 2016

Hydro Owner Wants in on New York Nuke Subsidy

By William Opalka

A hydropower owner is seeking rehearing of New York’s Clean Energy Standard, which limited the state’s new zero-emission credits (ZECs) to nuclear generators (15-E-0302).

Ampersand1 (Ampersand) - Ampersand Hydro New York Clean Energy Standard — *Source: Ampersand Energy Resources*

In a petition filed Aug. 23, Ampersand Hydro said it was arbitrarily excluded from the New York Public Service Commission’s “discriminatory” Aug. 1 order. The filing appears to be the first in what is anticipated to be numerous challenges to the commission’s order.

Ampersand said the PSC erred by “arbitrarily and capriciously failing to develop an implementation plan that permits small hydro generation resources to also be treated as a zero-emission facility and unjustly and unreasonably discriminat[ed] in providing nuclear generation facilities a significant competitive advantage over competing generation resources, including small hydro generation.”

Ampersand says small hydropower should enjoy the same treatment as nuclear under the standard: 12-year contracts with a subsidy of $17.48/MWh for the first two years with adjustments every two years thereafter.

The commission order calculated the subsidy based on EPA’s social cost of carbon, minus revenue paid to the state under the Regional Greenhouse Gas Initiative.

The PSC said the payments were justified because nuclear plants are unprofitable in a low natural gas price environment and New York’s clean energy goals are at risk if the plants close. Ampersand said it is subject to the same market and clean energy dynamics. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)

Ampersand2-(Ampersand) Ampersand Hydro New York Clean Energy Standard — *Source: Ampersand Energy Resources*

“The CES order explicitly recognized that an important generation resource with zero emissions, small hydro generation resources, may be not able to survive in the competitive wholesale energy market in New York and therefore might be forced to retire,” the company wrote. “Significantly, however, the CES order failed to provide any discussion of why generation resources that no party challenges are zero-emission, renewable resources should be denied ZECs. Instead, the CES order merely deferred any action in favor of additional studies.”

Ampersand specializes in acquiring and rehabilitating small hydropower stations. The Boston-based company controls 12 small merchant hydro stations in New York totaling 18.7 MW with an expected annual production in excess of 70,000 MWh.

August 29, 2016

Proposal to Revisit PJM Capacity Model Receives Tepid Response

By Rory D. Sweeney and Rich Heidorn Jr.

WILMINGTON, Del. — A stakeholder group calling for a comprehensive review of PJM’s capacity market won support from consumer advocates and state regulators last week, but industrial consumers and generators were cool to the idea.

The one point no one disputed at Thursday’s Markets and Reliability Committee meeting: Winning consensus on rules to replace the Reliability Pricing Model is a long shot.

“We might have a very low probability of coming to consensus on this process,” acknowledged American Municipal Power’s Ed Tatum, who introduced the proposal. “But it’s not zero.”

The proposed problem statement seeks a structure that will be more “resilient” to unforeseen shocks, such as state-subsidized generation.

The framework for the capacity market is the result of a FERC-brokered settlement in 2007. But there have been numerous rule changes since then, including most recently the introduction of Capacity Performance, which increased penalties and rewards for performance.

Delaware Municipal Electric Corp., Old Dominion Electric Cooperative, the PJM Public Power Coalition, the Public Power Association of New Jersey, Dominion Virginia Power and retailer Direct Energy have signed on as co-sponsors of AMP’s initiative. (See Co-ops, Munis Call for Reset of PJM Capacity Model.)

Direct Energy’s Jeff Whitehead said changes to the capacity constructs are “already happening,” citing the stakeholder initiatives created to address concerns over CP. In addition to task forces addressing seasonal capacity and mitigating generators’ risk of nonperformance, there are ongoing debates over calculating CP penalties, generator ramp rates and treatment of external assets.

To those who don’t support the problem statement, he asked, “Where do you want these debates [to occur] if not here?”

Additional Supporters

The coalition picked up support at the meeting from Dan Griffiths, executive director of the Consumer Advocates of PJM States; John Farber of the Delaware Public Service Commission staff; and Greg Pakela of DTE Energy Trading.

Farber said ad hoc reactions to CP, such as the seasonal capacity initiative, have created uncertainty. “That uncertainty only creates risk, and risk creates cost,” he said. “The worst position for PJM is to do nothing.”

Pakela said PJM needs to prepare for the future, predicting it’s “a matter of time” before states find a way to subsidize in-state generation that passes muster at FERC. Such efforts may increase as states seek to meet their emission targets under EPA’s Clean Power Plan, he said.

But Susan Bruce, who represents the PJM Industrial Customer Coalition, said although her group “has never been a big fan of capacity markets,” it wasn’t eager to open up the issue again.

“The devil we know may be better than the devil we don’t,” she said.

Stakeholders representing generators were particularly wary. “While I encourage you to look at other market designs, I’ll challenge you to find one that’s better,” Dynegy’s Jason Cox said. Models used by MISO and CAISO, he said, are “vastly inferior.”

He also questioned the premise of the initiative, asking “How can you design a construct to deal with issues you don’t even know about yet?”

Nothing in it for Supply?

Neal Fitch of NRG Energy and Tom Hyzinski of Talen Energy said it was unclear to them what the “problem” is and questioned Tatum on the scope of the proposed inquiry.

“Soup to nuts within resource adequacy?” Fitch asked.

Yes, responded Tatum.

Based on input from stakeholders, Tatum revised the proposed issue charge before the meeting to narrow its scope. The revised charge says it will limit its discussion of shortage pricing and the energy and ancillary services markets “to those that would be necessitated by any recommended changes to the capacity construct.”

“We don’t want to take on the world here,” Tatum said.

“You’re assuming that you’ll come up with something that will be bulletproof?” Hyzinski asked Tatum.

“No,” Tatum responded. “I think there might be something more resilient. I don’t know if there is or not.”

Mike Borgatti of Gabel Associates called it “a pocketbook issue.”

“Suppliers don’t want to be paid less. Load doesn’t want to pay more,” he said. “I struggle to explain to my clients on the supply side of the house what the opportunity is” pursuing the discussion.

Whitehead acknowledged his company’s interests, saying the current uncertainty is undermining competitive retailers’ business model. Predictable prices based on market fundamentals, he said, “allows us to contract forward and sleep at night.”

Tatum and Steve Lieberman of ODEC said their employers are caught in the middle as load-serving entities that also own generation. This issue “hits us on both sides,” Lieberman said.

Tatum said AMP likes the opportunity provided by markets to build its own generation or seek cheaper options offered by others. “If we can get supply for less than building our own, that’s a good thing,” he said.

PJM, Monitor Weigh In

PJM officials and Independent Market Monitor Joe Bowring were silent during the 70-minute discussion, until a stakeholder asked for their positions.

“There’s no harm in discussing things,” Bowring said. “I actually think CP is pretty robust and a pretty good design. It can always be improved.”

“If the intent is to replace the capacity market with a bilateral approach,” he added after the meeting, “I think that is a bad idea.”

PJM CFO and MRC Chair Suzanne Daugherty responded: “PJM believes in the stakeholder process. If the stakeholders support [the initiative], we do also.”

Facilitator Sought

A vote on the problem statement could come as soon as next month’s MRC meeting. PJM stakeholders rarely reject problem statements, which require only majority support to proceed. Winning approval for Tariff changes, however, would take a two-thirds sector-weighted vote.

If the problem statement moves forward, Bruce suggested, the discussions should be moderated by a facilitator independent of market participants and PJM. Other stakeholders supported Bruce’s request.

“I’m guessing that we’re not all looking for the capacity market to do the same thing,” she said. “It’s beyond ‘missing money’ at this point.”

August 29, 2016

CAISO Proposes Broadening LSE Definition

By Robert Mullin

CAISO is proposing to amend its Tariff to expand the definition of a “load-serving entity” to include any organization granted authority to serve its own electricity needs.

The Tariff currently recognizes as LSEs only those entities that sell electricity or serve load to end users, a description that covers utilities, federal power marketing agencies and community choice aggregators. A special exception was made for the State Water Project (SWP), a California agency that directly engages the wholesale market to cover its own energy requirements.

CAISO Load-serving entity — CAISO is seeking to expand the definition of an LSE to accomodate San Francisco’s Bay Area Rapid Transport agency. *Source: Bart*

The ISO is seeking a broader definition to accommodate the San Francisco Bay Area Rapid Transit District (BART), which, like the SWP, serves its own load but does not meet the standard definition of an LSE.

“We’ll see what other entities will participate under this definition, but we’re not sure there are any at this point,” Perry Servedio, senior market design and regulatory developer at CAISO, said during an Aug. 23 stakeholder call to discuss the proposal.

At the end of the year, BART’s transmission contract rights on the Pacific Gas and Electric network, which predate the existence of the ISO, will expire. Those rights will convert to CAISO service, leaving the agency exposed to congestion charges.

For a recognized LSE facing a similar circumstance, CAISO provides a remedy: The LSE can cover its exposure by seeking an allocation of congestion revenue rights (CRRs) in the initial round of the ISO’s annual allocation process. The ISO treats the expiring contract rights as if they were expiring annual CRRs.

But that process is not available to BART.

As an interim measure, CAISO last month filed with FERC to seek another temporary exception to the definition in order to enable BART to participate in this fall’s 2017 CRR allocation (ER16-2327).

By expanding the definition, the ISO hopes to eliminate the need for one-off exceptions. The revised Tariff would categorize BART and SWP as LSEs “granted authority pursuant to California state or local law, regulation or franchise to serve their own load.”

The amended language sent up red flags for some stakeholders, who worried that any California entity granted such authority would qualify as an LSE and therefore be required to procure adequate reserves to support their load.

Ernie Hahn, senior resource manager with the Metropolitan Water District of Southern California, said his agency is concerned about what the change would mean upon expiration of its transmission contract rights with Southern California Edison.

“This came out of the blue and we’re a little distressed by it,” he said. “We don’t understand what the [resource adequacy] implications will be.”

“Our intent is not to require entities to do this,” said Brad Cooper, CAISO senior manager of market design and regulatory policy. “To the extent that there’s an arrangement like yours, you’re not considered an LSE.”

But David Zlotlow, CAISO senior counsel, confirmed that the district would face the requirement once its contract expires.

“I object to the change because you haven’t given us enough time to prepare for the [resource adequacy] requirement,” Hahn said. He encouraged the ISO to make an “incremental change” to the definition, similar to the SWP exception.

“When I read this, it suggests to me that entities serving load behind the meter will get captured by this,” said Steven Kelly, director of policy at the Independent Energy Producers Association.

“A day or two ago, in anticipation of this call, we had that same thought,” Zlotlow said. “There might be a word or two to add to this definition.”

“Do storage devices or pumped storage qualify as LSEs because they serve their own load?” asked Mark Smith, vice president at Calpine.

“No, because they’re not serving end users, they’re just sending back to the grid,” Zlotlow replied.

Jan Strack of San Diego Gas & Electric said the change raises questions about what entities are affected, and how.

“I think you need to be sort of thoughtful about how wide this net gets thrown,” Strack said.

“We definitely want to hear from you if we’re missing something with this definition — or if we need to tighten it up,” Servedio said.

Stakeholder comments on the proposal are due Sept. 2. ISO staff plan to submit the changes for board approval in October.

August 29, 2016

PJM Markets and Reliability Committee Briefs

WILMINGTON, Del. — PJM officials have gained support for a new method of releasing excess capacity, but told the Markets and Reliability Committee on Thursday they were not sure the plan is ripe for a stakeholder vote.

The RTO procured 10,017 MW of new capacity commitments in the Capacity Performance transition auction for delivery year 2017/18. PJM’s Jeff Bastian told the MRC the capacity would likely clear at $0 in February’s third incremental auction under current rules — a price PJM and stakeholders agree would ignore the reliability benefits of retaining the capacity.

Direct Energy and NextEra Energy — which had proposed their own formulas last month — said they supported PJM’s proposal, under which the RTO would retain more capacity at lower prices but release more at a higher price. The plan would release excess capacity on an upward sloping trajectory, ranging from 0 MW at $10.74/MW-day to all 10,017 MW being available at $144/MW-day.

The PJM Industrial Customer Coalition also said Thursday it supports the change.

Direct Energy’s Jeff Whitehead said PJM should bring the issue to a vote at the Market Implementation Committee next month. He said he plans to introduce a problem statement to consider capacity releases for future years.

Whitehead said it is very difficult to quantify the additional reliability value of the excess capacity. “We could end up in analysis paralysis,” he said in pushing for an MIC vote. “We’ve been discussing this for a while.”

Gabel Associates’ Mike Borgatti, representing NextEra, said the PJM proposal has “evolved” and that although it differs from NextEra’s proposal, “we’re comfortable with this.”

But other stakeholders expressed reservations, and PJM’s Chantal Hendrzak, the MIC chair, said, “I don’t know that we’re quite ready” for a September MIC vote.

PJM, which must file its plans for releasing the capacity with FERC by November, first outlined its plan before the MIC earlier this month. (See “Proposal Would Set Higher Prices for Capacity Released in 3rd I.A. for 2017/18,” PJM Market Implementation Committee Briefs.)

In the third incremental auction for the 2016/17 delivery year, PJM offered 4,818 MW at $0/MW-day but cleared 4,556 MW at an average price of $4.79/MW-day, Bastian said.

Using the same formula for 2017/18, Bastian said, the excess “could well clear at zero.”

Calpine’s David “Scarp” Scarpignato asked if the sale could be isolated from other transactions during settlement to identify the impact on costs. Bastian said a simulation might be possible, but he wouldn’t commit to it.

Jeffrey Levine of ENGIE asked if PJM would consider a stepped offer curve instead of the straight-line slope the RTO proposed.

“Yes,” Bastian responded. “This is a stakeholder process.”

Gary Greiner of Public Service Enterprise Group also questioned PJM’s curve. “I don’t think that ‘let’s start at $10.74 because that’s what we paid for it’ is a good strategy,” he said.

But supporters of the PJM proposal said it would be a step backward to consider different shaped curves.

“We are comfortable with the proposal as presented here today,” said Susan Bruce, an attorney representing the PJM Industrial Customer Coalition. “I am a little uncomfortable at the ideas of new curves being” proposed.

“I’m not in a position to argue curves,” said Dan Griffiths, executive director of the Consumer Advocates of the PJM States. He said the debate highlighted a bigger concern for ratepayers — PJM’s systematic over-procurement. “From way too much [capacity] we’re trying to figure out how to get back to just too much,” he said.

Independent Market Monitor Joe Bowring made a pitch for his proposal to not release any of the excess, suggesting any release could suppress prices.

No matter the outcome of the release, it will likely incite second-guessing, said Jason Cox of Dynegy: If the price is high, critics will ask why wasn’t more capacity offered; if it’s low, why wasn’t less offered?

“PJM’s in a really tough spot,” he said.

Revisions Proposed to Cost Development Procedures

PJM’s first read of its proposed fuel-cost policy revisions generated little discussion at the MRC.

But Bowring predicted the proposal is “very likely to be changed by FERC” because it gives PJM, rather than the Monitor, the power to approve or reject generators’ policies. That, Bowring said, would violate the RTO’s Tariff.

Bowring also said the revisions, to be contained in Manual 15, were “stretching” the definition of a market seller.

PJM says it will bring the proposal to an MRC vote in September contingent on FERC’s approval of its related Aug. 16 compliance filing on implementing hourly offers.

In response to opposition by generators, PJM earlier reduced the proposed penalties for noncompliance with the new rules. (See Heeding Stakeholders, PJM Reduces Proposed Fuel-Cost Penalties.)

PJM’s Jeff Schmitt also presented the MRC with changes resulting from a biennial review of Manual 15, which are expected to be brought to a vote in September.

Metering Standards Ready for Stakeholder Vote

After identifying gaps in understanding between staff and members on metering procedures, PJM has developed a proposal that would substantially rewrite the Manual 1 language that governs metering.

The “high level of the high-level” changes proposed focus on the definition of accuracy and how to achieve it in every metering capacity, PJM’s Ryan Nice said.

To the make the plan “palatable” to members with decades-old infrastructure, PJM is proposing a “tuned-up” grandfather clause. (See “Metering Task Force Presents Proposal to Improve Clarity,” PJM Operating Committee Briefs.)

All equipment installed after the publication of the manual would be required to be fully compliant with the new metering standard. Equipment installed earlier than 1997 would be exempt from the new requirements. Equipment installed after 1997 but before the manual’s publication would have to meet all but a few requirements.

Stakeholders will be asked to endorse the changes at the September MRC.

Manual Changes Approved

The MRC unanimously endorsed the following manual changes:

Manual 3A: Energy Management System Model Updates and Quality Assurance. Changes reflect administrative and modeling process updates.
Manual 11: Energy & Ancillary Services Market Operations. Conforming changes, updated references and spelling and grammatical corrections are the result of a periodic review.
Manual 12: Balancing Operations. Administrative and conforming updates align with NERC reliability standard BAL-001-02, which went into effect July 1, and with the frequency bias calculation in BAL-003-1.
Manual 14D: Generator Operational Requirements. Changes include updates to the cold weather generation resource preparation section. Amends cold weather testing process effective with winter 2016/17. Generators that cleared as Capacity Performance in the current delivery year will no longer be eligible for compensation for conducting the exercise but may test and receive compensation as a self-scheduled resource. (See “PJM Plans to End Compensation for CP Units Participating in Winter Testing,” PJM Operating Committee Briefs.)
Manual 37: Reliability Coordination. Updates are the result of an annual review.

— Rory D. Sweeney and Rich Heidorn Jr.

August 29, 2016

FERC Orders PJM TOs to Change Rules on Supplemental Projects

By Rich Heidorn Jr.

FERC ruled last week that PJM transmission owners’ procedures regarding supplemental projects are not in compliance with Order 890, directing the TOs to file revisions within 60 days (EL16-71).

“As implemented, the transmission planning process governed by the PJM Operating Agreement is not providing stakeholders with the opportunity for early and meaningful input and participation in the transmission planning process, as required by Order No. 890,” the commission said.

The commission said it issued the Order to Show Cause because of testimony at a Nov. 12 technical conference. (See PJM TOs Defend Jurisdiction at FERC Conference.)

The commission cited complaints by Old Dominion Electric Cooperative and American Municipal Power concerning the TOs’ handling of supplemental projects — those not required for compliance with PJM’s reliability, operational performance or economic criteria, and not state public policy projects.

“Based on the comments received at the technical conference, it appears that some PJM transmission owners are conducting significant local transmission planning activities before the need for a supplemental project is brought to PJM for discussion in the stakeholder process,” the commission said. “In addition, certain of the PJM transmission owners appear to be identifying — and even taking steps toward developing — supplemental projects before providing any opportunity for stakeholders to participate in the development of those projects through the PJM [Regional Transmission Expansion Plan] process.”

The commission said the TOs must either propose revisions to the PJM Operating Agreement, revise their portions of the PJM Open Access Transmission Tariff or their individual Open Access Transmission Tariffs, or show cause why they should not be required to do so.

“Assuming that the PJM transmission owners file revisions to the OATT, we estimate that the commission would be able to issue our decision within approximately three months of the filing of such revisions,” FERC said.

200-kV Threshold Approved

In a separate order, the commission approved PJM’s proposal to exempt reliability upgrades on facilities below 200 kV from competitive windows under Order 1000 (ER16-1335).

PJM said such projects are almost always assigned to incumbent developers, and the change would enable its engineers to focus on problems more likely to result in a competitive greenfield project. (See “Low-Voltage Projects to be Exempted from Competitive Window Process,” MRC & Members Committee Briefs.)

The commission limited the exemption to projects within a single transmission zone, saying those involving two or more zones must be opened to a proposal window.

FERC also required PJM to clarify how it will identify transmission solutions for reliability violations on facilities below 200 kV. It said PJM must also provide it with reports on those projects for the next two planning cycles to enable the commission to monitor its implementation of the process.

August 29, 2016

MISO Informational Forum Briefs

MISO’s average load during July was 87.9 GW, 4.8 GW more than June and about the same as last year, said Shawn McFarlane, executive director of strategy and enterprise risk management, during an Aug. 23 Informational Forum.

McFarlane said July temperatures were close to normal. Load peaked at 120.7 GW on July 21 during a maximum generation warning. (See “June Energy Prices Up Across Footprint; New Emergency Pricing Encounters Snag in July,” MISO Informational Forum Briefs.)

Systemwide, MISO experienced average July prices of about $30/MWh, about $1/MWh more than last July.

Price convergence in July was the lowest it has been in a year, with a 22.5% difference between real-time and day-ahead prices. At this time last year, there was an average 14.8% divergence. Collections for day-ahead market congestion, at $80.26 million for July, were also at their highest level in a year.

Wind generation contributed 4.3% of total MISO electricity production (2,457 GWh), 661 GWh less than June’s 6% share but more than in July 2015, when wind contributed 3.3% (1,975 GWh).

Queue Reform

Stephen Kozey, senior vice president for compliance services, said MISO will make a revised generator interconnection queue reform filing by the end of October. FERC rejected MISO’s proposed queue changes in March, saying they assumed the current backlog could be blamed on “speculative” projects and failed to consider other potential factors (ER16-675). (See MISO Queue Changes on Hold Pending Technical Conference.)

Kozey also reminded stakeholders that MISO has pushed back implementation of a separate, three-year forward capacity auction for retail-choice areas to the 2018/19 planning year. He said MISO now plans to file in early November. (See MISO Delays Forward Auction Filing; Issues Draft Tariff and Business Rules.)

FBI Agent Informs Stakeholders on Cybersecurity Threats

Special Agent Michael Alford, of the FBI’s Cyber Division, said cyberterrorists, foreign governments and hacktivists most often attack critical energy infrastructure, in what he called a general cybersecurity “declassified briefing” at the Informational Forum.

Alford said hacktivists will sometimes target energy companies over proposed pipelines and development, while foreign governments conduct intrusions for espionage. He said according to the FBI, the energy grid is increasingly becoming a prime target for cyberattacks.

Spear phishing, which uses phony emails to get access to information, is the most common way to enter company networks, Alford said, citing the 2015 hack on Ukraine’s power grid. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

Alford said cyber threats can begin with a single attacker contacting an employee that they’ve performed “Internet reconnaissance” on. He told attendees to be mindful of the information shared on their social network profiles, as hackers will use the pages to gain employee information.

“If you have a LinkedIn account, that’s fine, but be aware that could be used against you,” Alford said.

He said the “end goal” of IT administrators should be to have a good log-in and password system and maintain it.

“You can throw tons of money at a system and make it secure, but that’s not always needed,” Alford said, noting that different departments at the same business need different levels of security.

Alford said utility employees shouldn’t hesitate to report cyberattack suspicions to either local law enforcement or the FBI.

“If you see something, report it, because you’re probably not the only one they’re attacking,” Alford said, adding that state-sponsored attacks often target several businesses or organizations simultaneously.

— Amanda Durish Cook

August 29, 2016

NYISO Releases Plan for Integrating DER

By William Opalka

Responding to policy initiatives from Washington and Albany, NYISO last week released a “road map” for integrating distributed energy resources that seeks to build on the grid operator’s existing markets and demand response programs.

The ISO said the draft report was a response to the New York Public Service Commission’s Reforming the Energy Vision initiative, and FERC Orders 719 and 745, which require the ISO to give DR greater access to real-time markets. NYISO says it provides a framework for market rules that will be developed over the next three to five years to implement the state and federal policies.

Demand Elasticity

NYISO said it agrees with the PSC that DER “can make load more dynamic and responsive to wholesale market price signals.”

The PSC says DER can improve system efficiency if their value is properly reflected in retail and wholesale markets and if utilities are incented to consider them as alternatives to traditional capital investments. The commission envisions the creation of distribution system platform (DSP) providers that plan, operate and administer markets for distribution-level services.

NYISO said REV is largely consistent with how the ISO “administers wholesale markets, plans for bulk system needs and operates the grid.”

Competitive wholesale markets, the ISO notes, were designed in part to facilitate demand-side elasticity. “For a variety of reasons, ranging from the economics and limitations of enabling technologies, this demand elasticity has failed to materialize to a significant degree.”

But with improved technology and economic models, NYISO said, integrating DER into the wholesale markets could “build upon the efficiencies already realized under competitive wholesale market structures.”

‘A Desire to Participate’

The ISO said its new rules will accommodate “controllable resources with various capabilities and a desire to participate in the wholesale markets.”

The report says DER will be incented through economic dispatch and real-time locational prices “that [align] compensation with system requirements.”

“The NYISO intends for the DER program to align incentives and compensation based on the flexibility and measured performance of the DER (or aggregation), and market clearing prices based on the needs of the system. The intent is to treat DER comparably with other supply resources participating in the NYISO’s energy, capacity and ancillary services markets.”

DER participating in the capacity market will be required to offer into the energy and ancillary services markets “for all or a portion of the day, depending on the business model and capabilities of the DER.”

Changes Needed

The ISO said integrating DER will require changes to market design, system planning and grid operations.

“Realizing this goal will require an examination of DER performance obligations, operating characteristics, metering and telemetry requirements, measurement and verification of baselines and performance, market modeling, and an understanding of how to balance the simultaneous participation of DER in retail/distribution-level programs as well as the NYISO’s competitive wholesale market.”

A particular concern will be ensuring accurate load forecasts and metering.

DER will be required to provide data quality equivalent to the “Point Identifier1” metering used by large generators, with “real-time supervisory control and data acquisition (SCADA)-quality or better telemetry data for operations and monitoring functions, and after-the-fact revenue-quality meter data from individual resources for measurement and verification and settlements.”

These measurement and verification services may be performed by distribution service platform providers.

DR = DER

Going forward, NYISO said it will consider all DR as DER.

nyiso distributed energy resources der — *Source: NYISO*

The current Special Case Resources program “has proven to be a valuable tool for planners to project load forecasts and for operators to manage system reliability” and will be retained, albeit “with potential modifications,” the report says.

The Emergency Demand Response Program and Price Capped Load Bidding also will continue. But the current Day-Ahead Demand Response and Demand Side Ancillary Services programs would be replaced.

The ISO says the report is only a beginning. “Implementing the DER initiative will entail considerable time, effort and stakeholder engagement. This road map represents a starting point for initiating discussions that will lead to further refinement on key market design elements, functional requirements and tariff language necessary to implement the vision.”

August 29, 2016

ERCOT Technical Advisory Committee Briefs

AUSTIN, Texas — Acting on a request from Texas Gov. Greg Abbott’s office, ERCOT has drafted a revision to its planning guide requiring energy developers to notify the Department of Defense of any projects near military installations.

The planning guide revision request (PGRR 047) was unanimously approved by ERCOT’s Technical Advisory Committee last week and will be considered by the Board of Directors during its Oct. 11 meeting.

The revision requires developers seeking an interconnection agreement to include among their materials a signed affidavit that they have notified the department of its proposed project and requested its review. The declaration only requires the initiation of an informal review, not its completion.

The proposed change is in response to requests by the governor’s office and the Defense Department to require that any proposed construction covered under existing federal regulations “confirm that they have provided notice and obtained review from the [Federal Aviation Administration] and DOD to the extent required under federal law.”

Current federal regulations require any structure constructed above certain height limits (approximately 200 feet) or in proximity to military and civilian airports provide notice to the FAA and DOD siting clearinghouse.

Several projects have recently brought the issue of federal notification to the forefront.

Sheppard Air Force Base near Wichita Falls has said proposed wind developments nearby would interfere with its radar and flight training operations. A proposed wind farm near Corpus Christi in South Texas has drawn concerns that it could impact training missions at two nearby U.S. Navy airbases, despite FAA’s conclusion to the contrary. (See “FAA Stands by its Greenlight for Proposed Wind Farm,” Federal Briefs.)

Speaking before the Texas House of Representatives’ Defense and Veterans Affairs Committee on Aug. 24 in Wichita Falls, ERCOT Director of System Planning Warren Lasher said he wants to see “increased coordination and communication” between the military and wind energy developers to resolve conflicts. “This will ensure that all energy developers check with DOD well before” the developments are put into motion, he said, according to an account in the Times Record News.

The TAC ensured the proposed rule would only affect developments that are not already connected to the power grid. The committee set Nov. 1, 2016, as the effective date for the change, after staff tracked down Lasher at a Public Utility Commission of Texas meeting for his approval.

Related legislation is expected to be proposed when the Texas Legislature begins its 2017 session in January. A Wichita Falls representative is considering filing a proposal that would affect tax abatements for some wind projects near military bases, while a New Braunfels legislator has said she would intervene if an energy project endangered military missions, the Times Record News reported.

Changes in TAC Leadership

Last week’s meeting marked the end of Randa Stephenson’s tenure as TAC chair. Stephenson, of the Lower Colorado River Authority, was recently named the utility’s vice president of wholesale markets and support.

Stephenson said her new job came with additional responsibilities that would preclude her continued role as TAC chair. She said she was disappointed but would continue to participate through the end of the year.

ERCOT Technical Advisory Committee — Vice Chair Bob Helton, GDF Suez; Chair Adrianne Brandt, CPS Energy; ERCOT COO Cheryl Mele © *RTO Insider*

“Are you really disappointed?” asked ENGIE’s Bob Helton, to peals of laughter.

Stephenson “has been a workhorse for the TAC process for many, many years,” said CPS Energy’s Adrianne Brandt, who was unanimously approved as Stephenson’s replacement. “She’s given us almost five years of TAC leadership. It’s a lot of work and a thankless job.”

Helton was unanimously approved as the TAC’s vice chair, replacing Brandt.

TAC Sends 16 More Change Requests to Board

The committee sent 16 other revision requests to the board, endorsing eight Nodal Protocol revision requests (NPRRs) and eight revisions to the nodal operating guide (NOGRRs), the planning guide and the retail market guide (RMGRRs). All but one of the requests passed unanimously.

In addition, the TAC tasked the Wholesale Market Subcommittee to develop a long-term solution for reliability-must-run mitigated offers after a related rule change failed on appeal last month at the committee and this month before the board (NPRR 784). (See “Board Rejects RMR Mitigated-Offer Appeal, Lets Stakeholder Process Move Forward,” ERCOT Board of Directors Briefs.)

“In our discussions with stakeholders, it seems there’s general support for a long-term solution gravitating around placing RMR offers last in the stack,” said NRG Texas’ Bill Barnes, who has championed the revision request.

The 16 revision requests approved are:

NPRR 753: Gives non-modeled generators the option of using the advanced metering system data submittal process and requires the installation of ERCOT-polled settlement meters to ensure the energy flows are reflected in real-time initial statements.
NPRR 760: Ensures that operating days with no activity are captured in the denominator for calculations of credit variables. It received two no votes and three abstentions.
NPRR 778: Changes competitive retailer rules regarding move-in or move-out date changes to prevent an inadvertent error. The change should eliminate two-thirds of manual interventions currently required.

A companion change, RMGRR 139, modifies market processes to align with NPRR 778’s proposed changes.

NPRR 779 and PGRR 048: Clarify references to the Texas Reliability Entity and the Independent Market Monitor. Current protocols refer to the Texas RE in both its capacity as the Regional Entity and the Public Utility Commission of Texas Reliability Monitor. The NPRR also removes the 24-hour deadline for ERCOT to notify the Reliability Monitor of a failure to provide ancillary services. The new language clarifies that the IMM is an included party in several provisions related to the ERCOT stakeholder process.
NPRR 782: Removes inconsistencies in protocol language by changing the equations governing the settlement of ancillary services. The change affects resources unable to deliver on their ancillary services obligations because of transmission constraints.
NPRR 785: Allows ERCOT to automatically prepopulate current operating plans (COPs) for wind and photovoltaic resources with the most recent forecast for the next 168 hours. Qualified scheduling entities representing these resources can either submit the prepopulated forecast as the COP by default or submit a lower number.
NPRR 786: Corrects the allocation of transmission losses, distribution losses and unaccounted-for energy (UFE) so that negative loads do not result in loss of UFE allocations.
NPRR 787: Removes the requirement that the qualified scheduling entity receiving a verbal dispatch instruction confirmation include the name of the individual that received the confirmation within the electronic acknowledgement.
NOGRR 150: Moves voltage-support obligation language to the Operating Guide so that the requirements are recognized as binding. It also allocates voltage-support responsibility to the appropriate entity, and clarifies that the ERCOT transmission operator has the authority to instruct a QSE to modify its resource’s voltage set point.
NOGRR 158: Modifies language in the nodal operating guide relating to limits on hydro resources’ responsive reserve to ensure consistency with NPRR 669.
PGRR 049: Removes the option to submit generation interconnection or change request (GINR) applications through standard mail or fax and updates the mailing address for GINR payments to the ERCOT treasury department.
RMGRR 134: Gives non-modeled generators the option to use the advanced metering system data-submittal process and clarifies processes for unregistered distributed generation versus registered non-modeled generators.
RMGRR 140: Removes the current date restrictions to give ERCOT increased flexibility when executing a competitive retailer’s acquisition of another retailer’s customers to prevent a “mass transition event.” The change will prevent end-use customers from being transitioned to provider-of-last-resort service and reduces associated uplift to the market.
RMGRR 141: Clarifies procedures during an extended unplanned system outage.

– Tom Kleckner