Page 1624 – RTO Insider

July 28, 2016January 23, 2024

Governance Plan Critics Urge Slowdown of Western RTO Development

By Robert Mullin

Critics of CAISO’s most recent draft proposal of principles for governing a Western RTO contend the ISO is moving too quickly to get a plan to California lawmakers before the close of the current legislative session in September.

Speaking at a joint state agency workshop in Sacramento on Tuesday, multiple industry participants expressed concern that the ISO’s expedited effort to complete a proposal will result in a governance framework that defers too many issues to be resolved in the future.

The workshop — hosted by CAISO, the California Public Utilities Commission and the California Energy Commission — marked the last public forum in which stakeholders could discuss the proposal before it gets forwarded to Gov. Jerry Brown, who is expected to transmit a final version to lawmakers in August. California law requires the legislature to approve the ISO’s transformation into an RTO, a process that would result in the state losing direct authority over the grid operator.

‘One of the Largest Issues’ in CAISO History

“Regionalization is one of the largest issues facing the ISO in its history,” said Carolyn Kehrein, principal consultant for the Energy Users Forum, which represents large energy customers in California. “Unfortunately, the changes [to the original proposal] were made to meet a quick turnaround.”

Among those changes were provisions that clarify the composition and responsibilities of a transitional committee tasked with creating a final governance plan; reaffirm that any such plan must respect individual states’ sovereignty over electricity matters they currently regulate; and set a specific timeframe for the appointment of a final RTO board (See Revised Western Governance Plan Highlights State Authority.)

The revised proposal defined the makeup of a Western States Committee (WSC), which would consist of state-appointed representatives and two nonvoting members representing publicly-owned utilities and federal power marketing administrations (PMAs). A provision requiring load-weighted voting on the WSC was altered to enable the transitional committee to develop a process that factors in “some form of weighted voting based on load,” such as a supermajority requirement.

An expanded CAISO would first take in PacifiCorp’s service territories, but the ISO is preparing for other transmission owners to join in the near future.

CAISO also added a provision for the RTO to adopt a capacity market at the request of member states, while eliminating a provision for tracking greenhouse gas emissions — a measure the ISO contended was more suited for inclusion in market operations than as a principle in an overarching governance plan. The GHG mechanism would have monitored carbon emissions from all thermal plants participating in the RTO, not just those located in California.

Western States Committee Powers

“Our biggest concern is — how many more revisions will there be before this is final?” said Matt Freedman, an attorney with The Utility Reform Network (TURN), which represents small customers. “This feels like a working draft.”

Freedman said his organization was concerned that the WSC’s powers were reduced in the revised proposal, which now stipulates that the RTO’s board can — in certain circumstances — override the requirement for the committee’s approval for Section 205 filings with FERC.

TURN was also worried about the “watering down” of an earlier prohibition on capacity markets, as well as the removal of the reference to GHG tracking.

Sierra Club staff attorney Travis Ritchie wondered how California would manage its GHG program without making emissions tracking a core principle, saying that the absence of tracking in the Energy Imbalance Market has allowed carbon leakage into the state’s power market.

“We need to agree what our fundamental principles are before opening up this market,” Ritchie said. “We have to set out our clear requirements first.”

Tony Braun, an attorney representing the California Municipal Utilities Association (CMUA), criticized the proposal for deferring the decision to create an RTO market advisory committee to the transitional committee.

“We think the transitional committee scope is too broad,” Braun said. “I don’t think the states are going to go for it.”

He cautioned the ISO not to move too quickly to advance a proposal to lawmakers given the number of “outstanding issues” related to governance.

‘Shouldn’t be Rushing’

“We shouldn’t be rushing forward now. The train is not going to come off the tracks,” Braun said. “Let’s not get embedded in a discussion in the legislature this year.”

“It seems to me that you’re placing a heavy burden on the people in the building just north of this,” said Imperial Irrigation District (IID) General Manager Kevin Kelley, referring to legislators in the nearby state capitol.

Kelley said that his utility, which operates its own balancing authority area in Southern California’s Inland Empire region, is opposed to CAISO’s regionalization because it will require the state to relinquish its oversight over an organization that suffered costly market manipulation during the 2000-2001 Western Energy Crisis. IID last month sued CAISO to force public disclosure of protected information related to the ISO-commissioned studies supporting regionalization.

Kelley suspected the “driver” of regionalization was a “for-profit corporation” — namely, PacifiCorp.

“I would encourage you not to hurry it up because that’s what PacifiCorp wants you to do,” he added.

Supporters Weigh In

The revised proposal also had its supporters.

“We do feel like this process [for creating the proposal] has been very transparent,” said Jennifer Gardner, staff attorney for Western Resource Advocates, an environmental group. “We’ve been pleasantly surprised that recommendations were taken to change the second proposal.”

Gardner called the regional market “the best opportunity to improve business as usual” in the West and said that any proposal taken to the legislature “should be as broad as possible to not tie the hands of the transitional committee.” She said that GHG tracking on a regionwide basis would be important for assessing the environmental benefits of the market.

Jonathan Weisgall, vice president of legislative and regulatory affairs at PacifiCorp parent Berkshire Hathaway Energy, said CAISO’s regionalization studies made it “very clear” that the region’s 2030 GHG reduction goals “won’t happen without a market.”

In the “unlikely event” that regionalization did increase emissions from PacifiCorp’s coal plants, the company would work to mitigate them, Weisgall said.

“In our Midwest utility [MidAmerican Energy], where we’re moving to 80% renewables, we could not do that without a regional ISO,” Weisgall said.

Preserving State Authority

Jan Strack, a transmission planning manager with San Diego Gas & Electric, said his utility has been in favor of expanding the market for a long time. He said the infrastructure for the market is already in place and that it wouldn’t cost much money to expand it. Strack also contended that an expanded market would enable California to achieve its GHG goals at a lower cost.

“We need to avoid some roadblocks [in the governance plan],” Strack said. “The first one is preserving state authority.

“At the same time, we have to recognize that FERC has authority over interstate commerce,” he added. “That’s one area we would be uncomfortable handing over to the Western States Committee.”

“We support regionalization of the ISO and the associated market because, frankly, they work,” said Robin Smutny-Jones, director of California policy and regulations for Avangrid. “That’s why there’s been a proliferation of RTO-like structures across the country and around the world.”

Smutny-Jones acknowledged the RTO would need to work through contentious issues such as transmission access charges and regional resource adequacy, both of which would be left to a newly constituted RTO.

“But other states have done it, and the West can too,” she said.

July 26, 2016

New York ESCO Order Vacated by Court

By William Opalka

A New York judge has vacated the Public Service Commission’s February “reset order” that sought to overhaul the business practices of retail energy suppliers.

The July 22 order by acting state Supreme Court Justice Henry Zwack said energy service companies (ESCOs) were denied due process by the commission, especially by the strict time frame for compliance (870-16, et al.).

The order bars the PSC from enforcing a requirement that ESCOs guarantee retail and small commercial customers will pay no more than they would for default service (excluding contracts offering at least 30% renewable power) (15-M-0127, et al.).

It also throws out a requirement that ESCOs receive “affirmative consent” from such customers before renewing them from a fixed rate or guaranteed savings contract into one that provides renewable energy but does not guarantee savings.

Zwack left standing language the commission added to its business practices imposing tougher enforcement measures against those who prey on vulnerable or uninformed customers.

While regulators insisted they acted to protect customers from deceptive business practices, ESCOs said the order effectively killed customer choice in New York.

The order “is arbitrary and irrational in that it imposes the unexplained and harsh 10-day implementation period for the order, which amounts to a major restructuring of the retail energy market — or even its collapse,” Zwack wrote in his 26-page opinion. “The court is perplexed that implementation would be so immediate, when by the PSC’s own admission so many questions remain.”

PSC officials said they will address the judge’s procedural concerns promptly.

The commission acted in response to what it said was unscrupulous business practices by some retailers. ESCOs immediately challenged the order in court and also sought a rehearing by the PSC. (See Retailers Ask for Rehearing of NY Guaranteed Savings Order.) A stay was granted in March as the court challenge was pending.

Retail Energy Supply Association spokesman Bryan Lee said the group was “gratified that the court vacated the … order, finding the PSC action to be ‘irrational, arbitrary and capricious’ and failed to offer ESCOs ‘an opportunity to be heard in a meaningful manner and at a meaningful time.’ The court found that ESCOs were ‘stripped of any meaningful opportunity to participate in the promulgation of the reset order.’”

Zwack reaffirmed that the PSC maintains jurisdiction over retail rates, turning aside a challenge from the ESCOs.

“The court’s affirmation that the PSC has legal jurisdiction over ESCOs is an important win for the PSC and millions of consumers in New York,” PSC spokesman James Denn said in a statement. “The procedural flaws highlighted by the court have been addressed, or will be, as we continue to move forward with Gov. [Andrew] Cuomo’s far-reaching plan to protect customers from unscrupulous ESCOs. Make no mistake, we are putting an end to deceptive ESCO practices that harm electric and gas customers.”

Zwack’s ruling does not affect a PSC order earlier this month imposing a moratorium on ESCOs signing up additional low-income customers. Regulators issued the order after a collaborative effort failed to develop a formula under which customers could be guaranteed savings. (See NYPSC Declares Moratorium on Low-Income Sign-ups.)

In a statement released Tuesday, PSC Chair Audrey Zibelman defended the commission’s actions.

“When ESCOs were charging multiple times the prices that utilities charge for energy, and consumer complaints of deceptive marketing practices poured in by the hundreds, the commission took bold action in February to protect consumers,” she said. “Unfortunately, as a result of the litigation, ESCO customers are still paying millions of dollars more every month than they should be paying for electric and gas services. But this injustice will be short-lived. … The commission will easily address the procedural concerns raised by the court and will continue our work to ensure that all electric and gas consumers in New York have the protections they need and deserve.”

July 26, 2016

FERC OKs Settlement, Orders Earlier Refunds in MISO Voltage Cost Allocation Case

FERC last week approved a settlement in a dispute between WPPI Energy and MISO over how to allocate voltage and local reliability (VLR) costs to pseudo-tied load (ER12-678-006).

The commission also granted WPPI rehearing in a related case, ordering MISO to pay refunds from September 2012 rather than July 2014 in a reallocation of costs for revenue sufficiency guarantees paid to resources providing VLR support (ER12-678-004, EL14-58-001).

In 2012, FERC approved MISO’s proposal to allocate VLR costs to all loads in a local balancing authority area (BAA), including pseudo-tied loads — load that is effectively transferred from a source local BAA, in which that load is physically located, to a different host (or “sink”) BAA. In a later order, the commission had reasoned that “the local BAA of the host load is responsible for voltage management in the pseudo-tied local BAA, and therefore MISO’s proposal comports with cost causation.”

FERC reversed course in June 2014, saying it had “erred” in approving MISO’s cost allocation and setting the issue for settlement discussions.

The commission said the settlement resolves the issue of “whether MISO should allocate VLR costs incurred in responding to a localized constraint to a market participant such as WPPI based on its load that is physically remote from the constraint, because that load has been pseudo-tied into the LBA area affected by the constraint.”

The settlement will revise MISO’s Tariff by adding a new term, “internal commercially pseudo-tied load,” and new language requiring submission of meter data by market participants that have such loads. MISO agreed to resettlements of WPPI’s VLR payments as soon as possible after the installation of necessary software changes and WPPI’s submission of required meter data.

In the related order, the commission agreed with WPPI that refunds from the reallocation should be effective as of Sept. 1, 2012, the date MISO’s original rate proposal went into effect, rather than July 9, 2014, the date FERC originally set.

July 25, 2016

FirstEnergy Closing Largest Coal Plant in Ohio; Bay Shore also in Peril

By Suzanne Herel

FirstEnergy will retire four units at its largest coal-fired power plant in Ohio and sell or deactivate its Bay Shore plant by 2020, the company said Friday, citing “challenging market conditions.”

Together, the units represent 856 MW, of which 136 MW is generated by Bay Shore in the City of Oregon, Ohio. Units 1-4 of the seven-unit W.H. Sammis Plant in Stratton produce 720 MW. The remaining two units there will continue to provide 1,490 MW of baseload generation.

first energy, coal, ohio, bay shore — Sammis Power Plant *Source: Bechtel*

The 78 employees at Bay Shore would be offered jobs elsewhere in FirstEnergy if that plant were deactivated, and the company would work with any potential buyer to arrange their retention. Likewise, the 368 employees at Sammis would be offered other job opportunities, the company said.

Last year, the units headed toward closure or sale generated 4% of the electricity produced by all of FirstEnergy’s plants.

“We have taken a number of steps in recent years to reduce operating costs of our generation fleet,” FirstEnergy Generation President Jim Lash said in a statement. “However, continued challenging market conditions have made it increasingly difficult for smaller units like Bay Shore and Sammis Units 1-4 to be competitive. It’s no longer economically viable to operate these facilities.”

The announcement comes as the staff of the Public Utilities Commission of Ohio has proposed a rider for FirstEnergy that would allow it to recover $131 million annually from customers over three to five years so it may retain an investment-grade credit rating as it struggles to maintain some of its aging, mostly coal-fired plants. (See PUCO Staff Recommends $131M Annual Rider for FirstEnergy.)

FERC in April had ruled that an eight-year power purchase agreement PUCO had approved for FirstEnergy, and another for American Electric Power, would be subject to federal review. The ruling prompted FirstEnergy to return to PUCO with a modified proposal that commission staff said should be rejected in favor of the recommended rider.

FirstEnergy’s announcement was welcomed by environmental advocates who had denounced the company’s power purchase request as a corporate bailout.

“Closing these outdated, dirty power plants not only shows FirstEnergy finally recognizes the market momentum toward coal’s inevitable demise, the decision is great news for Ohio customers, who avoid paying a massive subsidy to keep the units afloat,” said Dick Munson of the Environmental Defense Fund.

According to the Sierra Club, FirstEnergy’s announcement brings the total amount of coal generation that has retired or is set to retire in the state since 2010 to 10,093 MW.

“Today’s announcement is further proof that Sammis is an outdated and costly coal plant that customers should not be forced to prop up,” said Shannon Fisk of Earthjustice. “We will continue to fight efforts that could be used to bail out other FirstEnergy coal units, as now is the time for significant investments in renewable energy, energy efficiency and grid modernization activity that will create jobs and economic development throughout Ohio.”

Bay Shore Unit 1, whose boiler is fueled by petroleum coke, went online in 2000. Units 2-4 were deactivated in 2012 because of environmental regulations.

Units 1-4 at Sammis date to 1959 through 1962. Units 5-7 came online from 1967 to 1971.

According to FirstEnergy, it pays $1.7 million annually in Bay Shore property taxes. The company pays more than $7 million in property taxes on the Sammis plant, making it the largest taxpayer in Jefferson County.

July 25, 2016

ERCOT Discusses Wind Integration at GCPA Luncheon

By Rory D. Sweeney

AUSTIN, Texas — Wind energy is quickly becoming a dominant force in ERCOT’s resource mix, and the grid operator is making changes to address it.

Speaking to a packed house at a Gulf Coast Power Association luncheon last week, Kenan Ögelman, ERCOT’s vice president of commercial operations, said ERCOT is adding a desk in its control room to monitor renewables and rethinking its ancillary services needs.

“That’s how big a deal this is both in terms of managing the system conditions and giving the correct response to what happens,” he said. “We feel we need people dedicated to watching that.”

Fast response, rapid ramping and managing inertia are the biggest needs, he said.

Wind production on ERCOT’s system surpassed nuclear production in 2015 and its growth curve is “more exponential than linear,” Ögelman said.

Kenan Ögelman, vice president of commercial operations at ERCOT, discusses the dominance of wind on his system at the GCPA's July luncheon in Austin. — Kenan Ögelman, vice president of commercial operations at ERCOT, discusses the dominance of wind on his system at the GCPA’s July luncheon in Austin. © *RTO Insider*

“The mix of resources is changing,” he said. “The characteristics of those resources is also different than what we had previously, so doing business as we had — as far as ERCOT goes — is different.”

ERCOT’s ancillary services were designed in the 1990s and assumed heavy reliance on gas cogeneration facilities.

Its reliability unit commitment, for example, reimburses unused units but is capped and doesn’t allow for recovering all costs, Ögelman said. The current market isn’t pricing that service efficiently, which is sending inappropriate pricing signals, he said.

Chief among ERCOT’s needs is maintaining reliability. Although ERCOT’s wind-speed data date back to the 1950s, monthly output can vary unpredictably. However, as the lowest-cost resource on the system, wind tends to be dispatched, Ögelman said.

While not a problem during high demand, it becomes one during the spring and fall shoulder periods when load is low and wind makes up a high percentage of dispatched generation. Because wind output can change dramatically, ERCOT has to manage the risk that it might disappear.

This is further complicated by the fact that it’s hard to keep non-renewables operating during low loads. The abundance of wind — running because production tax credits offset uneconomic bids — have increasingly resulted in negative prices on the system from midnight through 5 a.m., Ögelman said.

“The market is saying you have to pay to stay on,” he said.

So with generation at risk of suddenly disappearing and the market providing no incentive to diversify sources, ERCOT is seeking solutions. The process starts with more information to develop better models and forecasts. For example, some risk can be mitigated, he said, by diversifying where the intermittent generation comes from on the system. Wind resources from the three main regions — the panhandle, West Texas and the Gulf Coast — tend to provide wind supply at different times and can balance each other out. For solar, the movement of the sun across the system requires an extra hour in the morning to reach full capacity, but offers an extra hour in the afternoon.

Another challenge is that low load combined with low inertia gives the system no way to recover from disturbances, raising the threat of cascading outages, Ögelman said.

ERCOT performed a “future ancillary services” study, which found that the inertia need will vary based on the capacity of combined cycle units on the system, which provide twice as much inertia as other sources. As economical as they are, even combined cycle units can be forced offline with high enough wind penetrations.

Generation units with governors or other frequency-control devices provide automatic systemwide frequency response. However, as wind pushes them off the system, that service disappears. ERCOT is also looking at how to incentivize load, which can respond quickly and then return to normal. Frequency response provided by the load, Ögelman noted, can be more valuable than that coming from generators.

ERCOT plans to talk to stakeholders at the Technical Advisory Committee about ancillary services to see if needs can be met with market design features that stakeholders want. It will also look into how best to analyze inertial service. The tools exist, Ögelman said, but aren’t fine-tuned to what’s optimal for a market design and reliability standpoint.

The amount of intermittent resources on the system can continue to increase, he said, as long as they agree to be curtailed as necessary.

[Editor’s Note: An earlier version of this story incorrectly reported that wind production surpassed nuclear production on ERCOT’s system in 2014.]

July 25, 2016

Maine PUC Endorses Gas Pipeline Contracts

By William Opalka

Disregarding its staff’s recommendation, Maine’s Public Utilities Commission on Tuesday endorsed a plan in which electric ratepayers would help finance natural gas pipeline expansion (2014-00071).

PUC staff said last month that ratepayer subsidies were unnecessary because market conditions have changed dramatically since 2013, when the proposal was first made. (See Maine PUC Staff Advises Against Pipeline Contracts.)

The vote to ignore the staff recommendations was unanimous. The order includes a proviso that four other New England states considering similar financial support would have to follow suit for Maine’s participation. Only Massachusetts regulators have made that commitment so far and that decision is being challenged in court. (See More Pipelines for New England: ‘Gold-plating’ or Necessity?)

“There are so many more things that need to happen before a shovel gets turned or more gas begins to flow, and most of those things are outside of Maine’s control,” Tim Schneider, Maine public advocate, told the Bangor Daily News. He also opposed the staff recommendation.

The commission said they have determined the benefits of new pipeline capacity outweigh any costs.

Yet to be determined are those costs or when supply contracts might be signed. Under state law, any action would require written approval from Gov. Paul LePage.

“The fossil fuel industry hoodwinked the PUC into gambling $1 billion of Mainers’ hard-earned money on a massive new gas pipeline,” Conservation Law Foundation attorney Ben Tettlebaum said in a statement. “From Day One, this LePage-appointed commission has been desperate to find any way to justify overwhelming concessions for Big Gas, no matter the cost.”

The approval comes after the cancellation earlier this year of the Northeast Energy Direct expansion project. The largest remaining proposal is the Access Northeast project, which would increase natural gas capacity from New York to Maine. A related proposal before FERC to allow local distribution companies to sell natural gas to utilities for power generation is being opposed by some power plant owners. (See Generation Owners Seek to Block EDC-Pipeline Deals.)

July 25, 2016

FERC Proposes Adopting NAESB Standards

By Rich Heidorn Jr.

FERC last week issued a Notice of Proposed Rulemaking to incorporate in its regulations the North American Energy Standards Board’s latest Standards for Business Practices and Communication Protocols for Public Utilities (Version 003.1) (RM05-5-025).

NAESB’s new standards were adopted by its Wholesale Electric Quadrant (WEQ) and filed with the commission last October.

The commission also said it would list NAESB’s updated Smart Grid Business Practice Standards (WEQ-019) in its General Policy and Interpretations for guidance.

Version 003.1 updates earlier versions of nine standards covering such things as definitions of terms and Open Access Same-Time Information System (OASIS) standards.

It also adds a new standard establishing the Electric Industry Registry to replace the NERC Transmission System Information Networks as the tool to be used by wholesale electric markets to conduct electronic transactions via e-Tags.

The commission declined to adopt a second set of new standards, Modeling Business Practice Standards (WEQ-23), which specifies requirements for calculating available transfer capability (ATC) and available flowgate capability (AFC).

The standards were designed to complement NERC’s proposed retirement of its “MOD A” reliability standards. NERC has proposed replacing its six MOD A standards with standard MOD-001-2, focused exclusively on the reliability aspects of ATC and AFC.

The commission declined to incorporate the standard because it is still considering NERC’s proposed retirement of its ATC-related reliability standards (RM14-7) and is considering changes to the calculation of ATC (AD15-5). The commission said it will consider the NAESB standards as part of the ATC dockets.

The commission also said it would not incorporate:

Standards of Conduct for Electric Transmission Providers (WEQ-009), because it is only a placeholder for future standards; and
Contracts Related Standards (WEQ-010), because it contains an optional NAESB contract regarding fund transfers that is not required by the commission.

July 25, 2016

Solar Poised for Texas-sized Growth in ERCOT

By Rory D. Sweeney

HOUSTON — Texas, which ranks 10th in installed solar capacity among the states, boasts two assets that could see it rise in the rankings.

“We have a lot of sun and a lot of land,” Christine Wright, SolarCity’s deputy director of policy and electricity markets, told a Gulf Coast Power Association luncheon last week. “Those are two key things there that make Texas a great resource for solar.”

GCPA_Houston---content-(RTO-Insider) - ercot texas solar — Christine Wright, the deputy director of policy and electric markets at SolarCity, speaks during the GCPA luncheon in Houston on Thursday. Solar capacity is making great strides in Texas. © *RTO Insider*

Installed solar capacity is growing at a rate of 50% annually, and every time the world’s solar power doubles, the cost of photovoltaic panels falls 26%. In the 15 years since 2000, the industry’s share of generation capacity has doubled seven times, and the average cost for a solar facility in the U.S. was cut more than two-thirds to roughly $3/W.

Although Texas ranks first among states in solar potential, it has only 534 MW installed, putting it behind California, Arizona, North Carolina, New Jersey, Nevada, Massachusetts, New York, Hawaii and Colorado. The state saw $372 million in solar investment in 2015, which was a 48% increase over 2014 spending. While top-ranked California has nearly 25 times more installed capacity than Texas, Wright said ERCOT expects solar capacity to grow by a factor of 50 by 2030.

Wright said the driving forces are cost stability and customers’ demand for independence from the grid. Since solar incurs very few costs after installation and no fuel expense, it can act as a hedge against increasing energy bills. Wright referenced a 2015 Gallup poll that found approximately 80% of respondents preferred more emphasis be put on developing solar infrastructure.

Tax incentives add to the appeal. Congress extended the solar investment tax credit through 2023, and the state’s property-assessed clean energy program allows local governments to help residential and commercial applicants to secure loans for solar projects in exchange for an increased property tax assessment.

The state has enacted favorable legislation, Wright said, such as SB1626, which reduces builder restrictions on solar development, and HB706, which simplifies property tax form filing. But “we have seen that policymakers in other states don’t always make decisions that are consistent with customer demand,” which is why she said the industry needs to maintain an active education campaign. In Nevada, for example, rooftop solar drove $833 million in investment in 2015 but ground to a near halt after the state Public Utilities Commission promulgated rates that increased the bills for solar customers by more than 50%, she said.

She acknowledged that issues will arise as the industry gains market share, but that they are known. Efforts are being made to collect necessary data and address “growing pains,” she said, citing ERCOT’s formation of the Distributed Resource Energy and Ancillaries Market Task Force.

July 25, 2016

FERC Issues Ride-Through Requirement for Small Generators

By Rich Heidorn Jr.

Generators under 20 MW will be required to ride through abnormal frequency and voltage events under a revised pro forma small generator interconnection agreement approved by FERC last week (RM16-8).

The commission already requires generators interconnecting under the large GIA to meet such requirements.

“It would be unduly discriminatory not to also impose these requirements on small generating facilities,” the commission said, noting that technology now available to small generators, such as smart inverters, gives them the capability to comply.

The revisions require small generators to not disconnect automatically or instantaneously from the transmission system for under- or over-frequency conditions and under- or over-voltage events. “The specific ride-through settings must be consistent with good utility practice and any standards and guidelines applied by the transmission provider to other generating facilities on a comparable basis,” the commission said.

The commission said its order reflected input received in response to its March Notice of Proposed Rulemaking. (See FERC Issues Reliability Orders on Relays, Small Generators.)

FERC said its action was warranted by the increase in grid-connected solar PV generation and generator interconnection requests driven by state renewable portfolio standards.

It cited NERC’s finding that “a lack of coordination between small generating facilities and reliability standards can lead to events where system load imbalance may increase during frequency excursions or voltage deviations due to the disconnection of distributed energy resources, which may exacerbate a disturbance on the bulk power system.”

July 25, 2016

FERC Issues Revised Connected Entity, Data Collection Proposal

By Michael Brooks

WASHINGTON — Responding to a flood of criticism, FERC last week revised its proposed rules for collecting data from market-based rate traders to monitor against market manipulation, narrowing the definition of “connected entity” and streamlining the collection process (RM16-17).

The commission issued a new Notice of Proposed Rulemaking at its open meeting, abandoning a NOPR issued last September that would have required RTOs and ISOs to register market participants through common alpha-numeric identifiers, with lists of their connected entities and a description of their relationships (RM15-23).

The new proposal aligns the definition of a “connected entity” with existing MBR affiliate definitions, eliminating references to stock and ownership thresholds. The original NOPR had included as connected entities companies controlling more than 10% of another, as well as top executives and traders, a definition heavily criticized by stakeholders.

The revised definition would limit relationship reporting to only those entities engaged in FERC-jurisdictional markets and those that trade energy transaction derivatives. The new proposal also would not require reporting debt instruments or structured transactions and submitting organizational charts.

The new NOPR also adopts changes in a December proposal to reduce the amount of information MBR sellers are required to provide the commission to prove they lack market power (RM16-3). (See Less is More? FERC Proposal Would Streamline Market-Based Rate Filings.)

“Today’s NOPR attempts to avoid duplication, minimize compliance burdens, modernize data collections and make information collected through its programs more usable and accessible for the commission and its staff,” FERC said.

The commission held a technical conference on its original connected entity NOPR in December, where stakeholders criticized the proposal as cumbersome and confusing. (See ‘Connected Entity’ Proposal Too Broad, Burdensome, Market Participants Tell FERC.)

At FERC’s open meeting last week, commissioners admitted that they had had concerns about the original proposal and expressed appreciation for stakeholders’ feedback.

“I had written separately … on the connected entities proposal to express some questions and concerns, but I’m very pleased to support the revised proposal before us today,” Commissioner Cheryl LaFleur said.

“Sometimes when the commission puts out a Notice of Proposed Rulemaking, there is a huge body of evidence that we have,” Commissioner Tony Clark said. “Sometimes — and I think this is one of those cases — the commission is putting something out, and we’re always genuinely interested in your feedback, but we’re interested in hearing your feedback on something that probably just isn’t quite as well fleshed out.”

FERC also proposed a database using an extensible markup language (XML) schema to keep track of entities’ relationships. The NOPR contains a draft data dictionary that lays out how to submit the required information.

The commission said it plans a “substantial outreach” effort to get input on the NOPR. As a first step, it announced it would convene a technical conference Aug. 11 to discuss the data dictionary. Comments on the proposal are due 45 days from its publication in the Federal Register.