Page 1631 – RTO Insider

June 27, 2016

Governance Plan Fails to Dispel Western RTO Concerns

By Robert Mullin

CAISO last week stepped up efforts to convert skeptics of a Western RTO, convening a forum in Denver to discuss a proposed set of governing principles and dispel concerns that California interests would dominate a West-wide entity.

“What we’re doing actually matters, and it has enormous upsides,” CAISO board member Ashutosh Bhagwat said of the effort.

CAISO is leading the push for an RTO in the West, in part driven by a 2015 California law requiring the grid operator and state energy agencies to explore ISO expansion to improve the state’s ability to meet its 50% renewable energy mandate.

The ISO also seeks to accommodate the timelines of PacifiCorp, which hopes to join the ISO in 2019 but must gain regulatory approval from five Western states before doing so.

Bhagwat said the diversity of resources in an expanded ISO would improve renewable integration and reduce costs for customers in California and the broader region.

EIM Experience

“Experience with the [Energy Imbalance Market] has proven this,” Bhagwat said. “We’re doing this because there is a lot to be gained.”

Contending that the West is “behind the rest of the country” in creating an RTO, Bhagwat also acknowledged “legitimate concerns” among Western industry stakeholders about how the organization would be governed.

“We’ve tried to address them,” he told the forum, referring to the ISO’s proposed principles for governance, which would seek to preserve state regulatory authority, provide all participating states the means to influence RTO policy and reshape the ISO into an entity no longer overly subject to the prerogatives of California.

Still, RTO skeptics — and some supporters — contended that an expanded ISO would be overly subject to California’s influence even with the principles in place.

They cited one major sticking point: the transition to an independent and regionally representative board of directors.

CAISO’s proposal calls for the RTO’s initial board to include the five members of the ISO’s current board and four new members selected by other RTO states through a process approved by those states. Initial board members would have terms staggered in such a way that California-appointed members would always hold a majority through a transition period.

That transition would conclude with the initial board selecting a final, independent board through a nominating process developed by a transitional committee of stakeholders. The nominating process — along with other governance elements proposed by the committee — would be subject to approval by the initial board.

A second sticking point: The transitional committee itself would be appointed by the ISO’s current board.

‘The Mother of all California-Centric Concerns’

“The proposal for the initial board is the mother of all California-centric concerns,” said Bryce Freeman, administrator of the Wyoming Office of Consumer Advocate.

Freeman pointed out that the proposal did not provide an explicit deadline for the transition period, meaning the current ISO board would constitute a majority for an unspecified amount of time. Any policies “hammered out under that arrangement would be accountable to the California political process,” he said.

Freeman also noted that the five PacifiCorp states would be forced to jockey for just four seats on the initial board.

caiso, western rto — Governing principles for a Western RTO will initially need buy-in from the five states containing PacifiCorp’s service territories.

“Whose ox gets gored in that process?” he asked.

“When we get to the final stage of things, California still gets what I’ve been calling a veto over everything anyway,” added Abby Briggerman, an attorney representing inland industrial energy consumers in the West.

Continued reliance on the ISO’s current board is also the American Wind Energy Association’s biggest concern, said Caitlin Liotiris, a consultant representing the organization, which is a strong supporter of the expansion.

Montana Public Service Commissioner Travis Kavulla echoed Freeman’s concerns about the open-ended nature of the initial board. He said it would have more influence on governance than the final board, as governance design would actually be developed and approved during the transition period.

Market-Oriented Board

Kavulla instead suggested the establishment of a market-oriented board populated by members with expertise in electricity market operations, while the “big questions” regarding tariff design and governance would be left to another body.

“That leaves the more complex matters of market design to the people actually running the ISO,” said Kavulla, the current president of the National Association of Regulatory Utility Commissioners.

While Kavulla didn’t specify what body should have authority over the tariff and governance issues, CAISO’s proposal calls for the formation of a body of state regulators “to provide policy direction and input on matters of collective state interest.”

That body would be funded by the RTO but incorporated as a separate entity, with one regulator from each state serving as a voting member. Publicly owned utilities (POUs) within the RTO footprint would appoint one nonvoting representative to act in an advisory capacity.

CAISO intends for the body of state regulators to have “primary authority” over RTO initiatives related to matters like transmission cost allocation and “aspects” of resource adequacy — meaning the RTO would be required to seek the body’s approval for any Section 205 filing with FERC.

“It has been noted that this body has a lot of reserve authority and power,” Kavulla said, adding that it should be staffed with experts to advise its members and support that authority.

Public Power Role

Mark Gendron, Bonneville Power Administration (BPA) senior vice president of power services, suggested a full voting role for the public power representatives.

“That might be a good home for BPA as a [federal power marketing agency],” said Gendron, whose organization operates 78% of the transmission in the Northwest and markets the output from 31 hydroelectric projects.

Gendron’s suggestion received support from Marshall Empey, COO of Utah Associated Municipal Power Systems, which represents community-owned utilities throughout the West.

“The reason we want this as public power is that regulators don’t represent us,” Empey said.

Steve Beuning, director of market operations at Xcel Energy, voiced a different perspective.

“I’m concerned to think of any stakeholder that might have more of a stake than me — such as public power getting a defined role,” Beuning said.

Kavulla noted that the interests of POUs are represented on the state committees of other RTOs. None of those committees set aside a seat for POUs.

“That level of trust might not exist in the West,” he added, referring to the fact that the region’s public utility districts are not subject to state oversight and maintain an arms-length relationship with utility commissions.

Briggerman spotlighted what she considered to be yet another flaw in the design of the state body: a provision that policy changes would require not just a majority vote, but approval by members representing a majority of load in the RTO footprint. California would hold a clear majority in an RTO that includes just PacifiCorp.

“This just sort of echoes my general theme that California has too much authority in this proposal,” Briggerman said.

“At the end of the day, [a Western RTO] is going to take mutual trust between California and non-California,” Kavulla said.

June 24, 2016

Hunt Reopens Oncor Bid in Lawsuit Against PUCT

By Tom Kleckner

Hunt Consolidated’s bid for Texas utility Oncor may not be over after all.

The Hunt group filed a lawsuit Thursday in state court against the Public Utility Commission of Texas, seeking a review of its March order that accepted the proposed acquisition but imposed restrictions that led to the deal’s unraveling.

The lawsuit says the PUC made a number of errors in its ruling on plans to split Oncor into two companies and incorporate a real estate investment trust (REIT) structure (Docket No. 45188).

The order approved the creation of Oncor AssetCo, which would own the transmission and distribution facilities, while Oncor Electric Delivery Co. (OEDC) would rent the facilities to provide electric delivery services. As a REIT, AssetCo would avoid paying federal income taxes if it derived at least 90% of its profits from property rents.

But the PUC’s order included conditions that made it less attractive to investors, including requiring federal tax savings be set aside for possible refunds to customers. The REIT structure would have allowed Hunt to funnel as much as $250 million a year in tax savings to shareholders.

According to the lawsuit, the PUC “prejudiced” the group’s rights by finding the leases between the Oncor companies would be tariffs subject to commission approval; by not treating AssetCo and OEDC on a consolidated basis for ratemaking purposes; by failing to give the restructured Oncor the standard income tax allowance; and by failing to vacate the final order and dismiss the docket.

The lawsuit says the PUC made “administrative findings, inferences, conclusions and decisions” in violation of the state Public Utility Regulatory Act and that were not “reasonably supported by substantial evidence in the record.”

“Because the merger agreement terminated, there was no longer a transaction for the PUCT to approve,” the lawsuit says. “At that time, the PUCT still had jurisdiction over the final order. … Therefore, the PUCT should have vacated the final order and dismissed the proceeding without prejudice. This would have avoided the errors.”

“It sounds like they want to reopen the case, which is confusing at best,” said PUC spokesman Terry Hadley when notified of the lawsuit Thursday evening. “This is unusual.”

“Businesses often file appeals within the court system to preserve their legal rights going forward,” Hunt spokesperson Jeanne Phillips said in a statement. “That is the intent here.”

The Hunt bid appeared to be dead in May, when the PUC rejected all motions for rehearing in the case and let its March order stand. The Hunt group and creditors of Oncor’s bankrupt parent, Energy Future Holdings, had asked the commission to vacate the order and dismiss the proceeding, thus leaving open the possibility of a new application. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)

A litigation analyst for Bloomberg Intelligence, Julia Winters, told Bloomberg News that if the Dallas-based Hunt group’s lawsuit is successful, “there’s a chance they would get back to the negotiating table with the debtors and move forward on a deal to buy Oncor.”

“It would be a lot easier to move forward with the plan that was already on the table and approved by the bankruptcy court,” Winters said.

The Hunt group has been pursuing an acquisition of Oncor, the largest transmission and distribution utility in Texas, for several years. Oncor is widely seen as the key to EFH’s bid to restructure almost $50 billion in debt and emerge from two years of bankruptcy. (See EFH Files New Chapter 11 Plan.)

NextEra Energy is also thought to be a potential suitor.

The original plan EFH filed with a Delaware bankruptcy court included a Hunt-led purchase of Oncor for more than $17 billion.

Hadley said the PUC would have no additional response to the lawsuit. It will be represented in the proceeding by the Texas attorney general’s office.

June 23, 2016

PGE to Shut Down Diablo Canyon, California’s Last Nuclear Plant

By Robert Mullin

Pacific Gas and Electric said Tuesday it will shut down California’s last nuclear power plant in 2025 under an agreement reached with a coalition of environmental, labor and anti-nuclear groups.

The utility said it will develop a portfolio of renewable resources, energy efficiency and energy storage to replace output from its 2,240-MW Diablo Canyon facility, located on the state’s central coast near Avila Beach.

That condition was a victory for environmental groups that had opposed the plant on safety grounds but wanted to avoid an outcome in which gas-fired generation would replace the plant’s greenhouse gas-free output.

“It will be the first nuclear power plant retirement to be conditioned on full replacement with lower-cost, zero-carbon resources,” said the Natural Resources Defense Council, one of the parties that negotiated the agreement.

PG&E Diablo Canyon nuclear power — PG&E’s Diablo Canyon nuclear plant is the utility’s single largest source of energy production. *Source: PG&E*

Other parties included Friends of the Earth, Environment California, International Brotherhood of Electrical Workers Local 1245, the Coalition of California Utility Employees and the Alliance for Nuclear Responsibility.

Under the proposal, the company would also commit to serving 55% of its customer load with renewables by 2031.

The state’s revised renewable portfolio standard, enacted last year, calls for 50% renewables by 2030. PG&E cited the RPS, the recent doubling of state energy efficiency goals, growth of distributed energy resources and the potential loss of retail customers to alternative suppliers known as community choice aggregators as key factors in the decision to retire the facility.

Quake Risk

Environmentalists have long been concerned with the plant’s location near several earthquake fault lines, including one 3 miles from the plant that was discovered three years after construction began in 1968. Calls for its closure were renewed after the 2011 quake and tsunami that led to a meltdown at the Fukushima Daiichi nuclear plant in Japan.

Another major consideration: the inability of a baseload plant like Diablo Canyon — which cannot be quickly cycled up and down — to respond to the “overgeneration and intermittency conditions” stemming from increased penetration of solar and wind resources.

In response to the 50% RPS, CAISO will put a premium on the capability to respond to renewables’ variability. The ISO is currently developing a “flexible ramping” product to encourage the development of resources to fulfill that need.

Diablo Canyon accounts for about 20% of annual electricity production in PG&E’s service territory and 9% of production in the state. While the utility points out the plant is currently needed to help maintain system reliability, it said that its absence will reduce the need for solar curtailments during peak solar production and improve the integration of RPS resources.

“California’s energy landscape is changing dramatically with energy efficiency, renewables and storage being central to the state’s energy policy,” PG&E CEO Tony Earley said. “As we make this transition, Diablo Canyon’s full output will no longer be required.”

2025 Retirement Assumed

The California Public Utilities Commission has not yet asked CAISO to perform any special studies related to the retirement, ISO spokesman Steven Greenlee told RTO Insider.

CAISO’s 2016-17 transmission planning process — which looks 10 years into the future — already assumes Diablo Canyon will be retired by 2025 because of state restrictions on “once-through cooling,” the process of drawing coastal or river water to cool turbines. That water is then expelled back into the environment at higher temperatures, affecting marine life. State regulators required the plant to end the practice by 2024.

Any reliability issues stemming from retirement will be identified in the current transmission planning analysis, according to the ISO.

“We will not present a recommendation [on retirement], but PG&E’s decision allows the ISO to begin planning for a grid without Diablo Canyon and a grid that better integrates renewable resources in support of the state’s goals,” Greenlee said. In 2009, PG&E filed with the Nuclear Regulatory Commission to extend the licenses for Diablo Canyon’s two reactors for an additional 20 years. This week’s proposal stipulates that the company will ask to suspend that proceeding. In return, the other parties to the agreement promised not to seek the facility’s closure before the last license expires in August 2025.

They also agreed not to oppose PG&E’s efforts to fully recover costs for the shutdown from California ratepayers. That stipulation requires the parties “to not oppose amortization and cost recovery of Diablo Canyon’s costs in PG&E’s 2017 general rate case” submitted to the PUC.

The agreement is subject to approval by the PUC. PG&E has asked regulators to render a decision by Dec. 31, 2017.

June 21, 2016

FirstEnergy Foes Ask FERC to Step in Again in Ohio Dispute

By Ted Caddell and Suzanne Herel

Groups opposing FirstEnergy’s plan to win subsidies from Ohio regulators asked FERC last week to again intervene in the dispute (EL16-34, et al.).

The Electric Power Supply Association, Dynegy, NRG Energy and others filed a joint protest, asking FERC to block the company’s revised bid to win revenues from Ohio ratepayers for its merchant generation. The Sierra Club, the Environmental Defense Fund and the Ohio Consumers’ Counsel also filed protests.

FirstEnergy asked the Public Utilities Commission of Ohio in May to withdraw an eight-year power purchase agreement — in which the company’s regulated utilities would purchase output from the company’s merchant generators — after FERC ruled April 27 that the PPA, and one for American Electric Power, would be subject to its affiliate abuse review.

firstenergy ohio ppa ferc — FirstEnergy’s Davis Besse Nuclear Power Plant *Source: Wikipedia*

In its place, FirstEnergy wants Ohio regulators to approve a customer charge that it hopes would avoid triggering federal oversight (AEP, FirstEnergy Revise PPA Requests to Avoid FERC Review.)

The modified plan “would allow for the same transfer of captive customer money to market-regulated affiliates and shareholders, but without the affiliate PPA that initially triggered FERC jurisdiction,” the EPSA petitioners wrote last week. “In short, [First Energy Services] and the FirstEnergy [electric distribution utilities] are attempting to achieve the same result as their initial proposal, while evading the commission review mandated by the April 27 order.”

Dynegy and NRG also joined other independent power producers in a letter to the PJM Study Defends Markets, Warns State Policies Can Harm Competition.)

While they did not mention the Ohio situation specifically, the companies said PJM’s markets manage resource adequacy just fine on their own.

“What PJM’s markets have not done — and should not do — is provide protection for certain suppliers who want to be shielded from market risk,” the companies told the board. “Generators that are unable to compete because their facilities are inefficient or their operating costs are too high must make rational business decisions about their future operations, but PJM should not feel compelled to change its market rules to protect them.”

They further urged the RTO to educate policymakers about the negative effects their proposals can have when they interfere with the markets.

The Sierra Club urged FERC to “not allow this brazen end-run” around the commission’s review.

“With their latest gambit, FES and the FirstEnergy EDUs apparently think that they can achieve the same results as their initial plan while evading FERC review by simply eliminating the affiliate PPA,” the Sierra Club wrote. “The modified plan poses the same threat to the commission’s affiliate transaction rules as does the affiliate PPA.”

The Environmental Defense Fund filed similar arguments and spread the word through a blog post.

“It’s not usually a good idea to dis federal regulators,” wrote Dick Munson, EDF’s director of Midwest Clean Energy. “FirstEnergy doesn’t seem to care.

“The utility does deserve credit for persistence and creativity, yet its new proposal doesn’t even pass the laugh test,” Munson continued. “To avoid FERC jurisdiction, for instance, FirstEnergy now claims its subsidy will no longer guarantee the operation of its uneconomic power plants. Yet the utility’s new surcharge is contingent on the continued operation of virtually the same number of megawatts of its nuclear and fossil generation.”

Ohio Consumers’ Counsel Bruce Weston also weighed in, asking FERC to order FirstEnergy to “show cause why it should not be found to be in violation of the Federal Power Act, FERC’s [April 27] order and/or FERC’s affiliate restrictions regulations.”

FirstEnergy’s modified request “strictly involves adjustments to retail electric rates, which is designed to be solely under the jurisdiction of the PUCO,” company spokesman Doug Colafella said. “The objective of our plan — safeguarding our customers against long-term price increases and volatility — can still be achieved without a purchased power agreement.”

June 21, 2016

Del. Lawmakers Try to Block Artificial Island Plan; Project Still on Track

By Suzanne Herel

The Delaware House of Representatives last week unanimously passed a resolution aimed at blocking a proposed stability fix for New Jersey’s Artificial Island nuclear complex that could raise bills for the state’s ratepayers.

House Concurrent Resolution 89, sponsored by Energy Committee Chair Trey Paradee, directs the state Department of Natural Resources and Environmental Control to deny any easement request related to the project as long as the current cost allocation is in place.

That formula assigns $354 million of the $410.5 million project to customers in Delaware and on the Delmarva Peninsula, according to the resolution.

A number of agencies representing those customers, along with Delaware Gov. Jack Markell, have filed their opposition with Officials Urge PJM to Reject Artificial Island Proposal.)

Under the proposal, an average residential customer could expect to see an extra $1 to $3 on their monthly electric bill. The charge would be much higher for commercial customers.

“This could cost businesses thousands of dollars a month and burden local residents for something that will not benefit them,” Paradee said. “That’s the definition of a bad deal. We might not have been successful in appealing to FERC, but we have the final say when it comes to environmental permitting.”

The project calls for the construction of a transmission line that will be buried beneath the Delaware River connecting Artificial Island to Delaware with the goal of improving reliability on the grid.

“Under current project plans, an easement will be sought from the Department of Natural Resources and Environmental Control to connect the line on the Augustine Wildlife Area … and the Augustine Wildlife Area is a renowned deer and waterfowl habitat in Delaware,” the resolution states.

When asked if the resolution could kill the project, Sharon Segner of LS Power, which is constructing the marine crossing, responded, “Absolutely not. It is a nonbinding resolution that must be passed by both the House and Senate in Delaware. A Delaware resolution does not have the force of law. In addition, a resolution expires at the end of the legislative session, which is in two weeks in Delaware.

“We continue to support the Delaware Public Service Commission’s efforts in addressing the cost allocation for the Artificial Island project, as this is the real challenge for Delaware. We hope FERC grants both the rehearing request of the Delaware PSC and LS Power.” (See Stakeholders Ask FERC to Rehear Cost Allocation Order.)

PJM issued a statement urging policymakers not to delay the project. “We are sympathetic to the concerns about cost allocation, which must be resolved by the federal commission,” it said. “It would be unfortunate to delay this necessary project and its reliability benefits.”

Following complaints about the cost allocation for this project as well as the proposed Bergen-Linden Corridor upgrade, FERC held a technical conference in January. It asked: Is there a definable category of projects for which the DFAX method might not be appropriate, and could a fair approach be developed for those occasions? The commission on April 22 upheld the cost allocation for both projects. (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)

The Artificial Island project faces other hurdles. After Public Service Electric and Gas submitted estimates nearly doubling the cost of its scope of work to $272 million, PJM planners decided to consider alternate configurations. One is to terminate the new transmission line at Hope Creek instead of Salem. However, if the scope of the work is changed substantially, it could require PJM to solicit new bids under FERC Order 1000. (See Artificial Island Cost Increase Could Lead to Rebid.)

June 20, 2016

Cathey’s Inner Geek Helps SPP Incorporate New Technologies

By Tom Kleckner

LITTLE ROCK, Ark. — It doesn’t take much for SPP’s Casey Cathey to let his inner geek flag fly.

Casey Cathey, SPP (copyright RTO Insider) — Casey Cathey, SPP © *RTO Insider*

“Have you heard about Solar Reserve’s salt tower?” he asks, jumping to his feet and grabbing a marker. Cathey steps to the whiteboard and begins to sketch a representation of the 110-MW Crescent Dunes Solar Energy Plant in Nevada. It is capable, its developers say, of providing enough firm solar energy to power 75,000 homes.

Cathey explains how the 10,000 tracking mirrors encircle the 640-foot molten salt tower, following the sun’s movements to concentrate sunlight onto a large receiver at the top of the tower. Molten salt flows through the receiver and down piping inside the tower, eventually being stored in a thermal tank. The salt is then passed through a steam-generation system that provides electricity as needed.

“I’m sorry, but I really geek out about things like this,” a visibly excited Cathey says.

It comes with the job. As manager of operations analysis and support, Cathey led the group that produced a 2015 wind-integration study that revealed SPP could successfully handle wind-integration levels as high as 60%. That same group is now working on a follow-up analysis, the newly renamed Variable Generation Integrated Study.

Cathey also represents SPP on the ISO/RTO Council’s Emerging Technologies Task Force, which has further exposed him to the new technologies and challenges facing the electric industry.

“What we’ve learned is everyone has problems,” he says. CAISO “has too much solar; we have a lot of wind; [and] Toronto has reduced their nuclear plants to offset the wind.”

Front-Row Seat

Cathey almost can’t believe his luck at having a front-row seat to the latest in technological innovation.

“It’s pretty amazing, especially with the people I get to meet and talk to. Ph.D.s, Popular Science, Elon Musk,” he says. “I used to put that stuff on a pedestal, but then you get to meet them and see where we’re at and where we’re going, and you start to realize where the human race is in terms of technology.

“There are a lot of brilliant people out there, but at the same time, there’s a lot of things we can do better,” he added. “There’s a lot of stuff we can improve on.”

For now, Cathey and SPP are working to educate themselves on wind and solar energy, behind-the-meter resources, and batteries, flywheels and other energy storage technologies. The more staff knows, Cathey says, the better they can forecast.

What’s Out There?

“We’re focused on our current business functions as a balancing authority and market reliability. It’s starting to be a little worrisome that we don’t know what’s out there, and we don’t have rules in place to report it.”

Cathey says SPP currently has a requirement that any behind-the-meter resource capable of producing 10 MW or more has to register in the Integrated Marketplace, so it can be modeled correctly. He says loopholes in the requirement allow for derating resources or splitting them up, saying the ratings of some resources do not always tell the whole story.

“The worst risk is if there are many smaller facilities we don’t know about, we could potentially coordinate outages incorrectly and we would not know the real impacts on the Bulk Electric System,” he says. “At these small magnitudes, they’re not going to bring down the system, but if we don’t know about certain generation and we’re not coordinating it, we could have a problem with efficiency and reliability.

“We understand the capabilities and types of generation out there, but … we’re pretty much in the same boat as a lot of other ISOs and RTOs. We don’t know what we don’t know, and [other RTOs] don’t know. The loads themselves don’t know.”

To get better information, SPP has surveyed its members about their behind-the-meter resources.

The RTO hasn’t yet settled on a name for the resources. MISO calls them DERs (distributed energy resources) while ERCOT refers to them as DG (distributed generation). And SPP?

“We don’t have a term yet, but I’m sure it’ll be a different acronym when we come up with it,” Cathey says with a laugh. “Right now, we just want to know about it, so that our models are accurate.”

The RTO will eventually require more stringent reporting on distributed generation, Cathey says — and despite some stakeholder fears, the requirement will not force them to register the resources in the market or to inhibit their contributions to state renewable portfolio standards.

SPP does have an acronym for stored energy resources: SERs. Staff has drafted a revision request that would add energy storage capability to the Integrated Marketplace’s rules, enabling the resource to be registered as a generator type for regulation only. Staff has tweaked the revision request to take advantage of PJM‘s and MISO’s experience with the technology.

Cathey says SPP’s current rules are not “conducive to allow us to embrace that technology.”

“You can actually help out the system by plugging [the batteries] in … they’re providing regulation-down service,” says Cathey, who expects the first SER to show up by year-end. “That extends the life of conventional resources, because we’re not [ramping] them up and down. We’re sending the battery up and down.”

SPP’s current wind-integration study was renamed to include technologies like these, but its primary focus remains wind. The RTO has already seen wind integration reach 48.32%, a record for all North American ISOs and RTOs. It currently has 12,397 MW of installed and available wind capacity, with another 33,819 MW in development.

Cathey says the current study, which will use updated models and assumptions to analyze frequency response and transient response, is an extension of the 2015 study. It will take a “much more thorough” look at voltage, he said. The first study ignored thermal constraints and used an hourly ramp, but the second study will honor thermal ratings and use a five-minute ramp, “so it’s much more realistic.”

“Frequency and ramp, that’s one aspect we’re really interested in,” he says. “Is there a real problem when we have 50%, 60% wind penetration, while honoring thermal constraints? Are we Chicken Little, or is this an actual problem?”

SPP is working with Powertech Labs to develop a module that honors thermal constraints and is placed on top of its voltage-security assessment tool. Cathey says the RTO is past the R&D phase with the technology, which will eventually be rolled out to other ISO/RTOs.

“The model basically … lets us know we need to concentrate further on [a] scenario and build in more planning and operational processes,” he says.

Data, Data and More Data.

Cathey is also helping out with SPP’s Synchrophasor Strike Team’s work, which is intended to ensure the RTO isn’t pushing phasor measurement units (PMU) without stakeholder buy-in.

PMUs are devices that measure the voltage, frequency and angle of the grid’s electrical waves, using a common time source for synchronization. The devices can take samples hundreds of times a second, while the standard SCADA systems can have scan rates of 10 to 30 seconds.

“If we’re making measurements at that scale, we can determine whether there are issues with the models,” Cathey says. “But the problem with PMU incorporation is the data is so much. An operator needs to understand if it’s just a blip on the system for a nano-second. You’re talking petabytes [1 million gigabytes] of data. You’re well beyond terabytes.”

Staff is currently working on how best to filter the data and make it more manageable for operators. In the meantime, SPP has posted a revision request that would require all new generators to have a PMU. The request has been vetted within the strike force, which will determine whether the cost-benefit analysis justifies requiring existing generation to be retrofitted with PMUs.

Oklahoma Gas & Electric, which has installed more than 200 PMUs as part of a Department of Energy grant, has become a proponent of the technology, Cathey said.

“They’re the [subject-matter experts] for the industry, not just our area,” he says. “According to OG&E, the cost is not that much. Where the cost comes into play is if your substation or your switchyard is not capable of accepting the PMU.

“These are things we don’t traditionally think about. We think about power, getting it from Point A to Point B and whether the line can sustain it. … Now, we’re thinking about very engineering-centric problems.”

Which is exactly the way Cathey likes it.

June 20, 2016

FERC Accepts ISO-NE Auction Results

By William Opalka

FERC accepted the results of ISO-NE’s 10th Forward Capacity Auction last week, again rejecting allegations of market manipulation and concluding that the prices were just and reasonable (ER16-1041).

Brayton Point power plant, ISO-NE forward capacity auction, ferc — Brayton Point *Wikipedia*

The auction, covering the 2019/20 commitment period, saw prices drop to $7.03/kW-month from last year’s $9.55/kW-month. It was the first decline in four years. (See Prices Down 26% in ISO-NE Capacity Auction.)

The Utility Workers Union of America has claimed the Brayton Point generating plant in Massachusetts has been withheld from the last three auctions to drive up capacity prices. The plant, purchased by Dynegy in 2015 from Energy Capital Partners, is scheduled to close next year. (See FERC Again Rebuffs Brayton Point Union.)

“We emphasize, as the commission has stated in previous orders, that the commission’s Office of Enforcement reviewed Brayton Point’s bidding behavior in FCA 8 to determine whether further investigation of Brayton Point was warranted and ‘found credible justifications for the owners’ retirement decision and elected not to widen its investigation to include Brayton Point,’” FERC said. “We are not persuaded by Utility Workers Union’s allegations that market manipulation affected FCA 10, as the record is devoid of any evidence to that effect, and we similarly reject Utility Workers Union’s request for a stay pending discovery and further adjudication of that allegation.”

The commission also said that a “rigorous” review by ISO-NE’s Internal Market Monitor determined FCA 10 was competitive.

FERC Backs ISO-NE in Tariff Dispute

In a separate order, the commission rejected a complaint that alleged ISO-NE violated its Tariff when it refused to qualify an increase in a Massachusetts generating plant’s output for FCA 10 (EL16-48).

Northeast Energy Associates, owner of the Bellingham generating station, agreed with ISO-NE that an additional 10 MW of capacity was a “significant increase” but disagreed on whether it should be treated as new or existing capacity. New capacity is required to submit a composite offer linking incremental summer qualified capacity to existing winter qualified capacity.

NEA said the 10 MW should have been added to the existing summer qualified capacity without a composite offer and asked the commission to order ISO-NE to include the increase as if it had cleared FCA 10 — a move that would result in capacity payments to NEA of almost $844,000.

FERC sided with ISO-NE, saying that NEA, which is owned by subsidiaries of NextEra Energy and GDF SUEZ Energy Resources, misread the Tariff.

“We agree with ISO-NE that … the Tariff is clear that a significant increase must abide by all the provisions applicable to a new generating capacity resource,” FERC wrote.

This is the second time FERC has addressed a capacity increase for Bellingham. Previously, FERC granted a waiver to allow the plant to participate when the company submitted a late interconnection deposit. ISO-NE wanted to disqualify the resource, but the commission said a good-faith effort was made to submit a timely payment after NEA discovered its oversight. (See FERC Overrides ISO-NE, Grants Waiver for Late Capacity Payment.)

June 20, 2016

FERC Proposes Protections on CEII

By Michael Brooks

WASHINGTON — FERC last week issued a Notice of Proposed Rulemaking to implement legislation enacted last year to protect the grid from terrorist attacks (RM16-15).

The Fixing America’s Surface Transportation (FAST) Act, signed by President Obama in December, was mainly a highway funding bill, but it also amended the Federal Power Act to require FERC to update its critical energy infrastructure information (CEII) regulations. (See Transportation Bill Includes Grid Security Measures.)

The NOPR details how the commission plans to update its procedures for designating CEII, sharing CEII with other government agencies and sanctioning employees for unauthorized disclosures.

“Obviously, maintaining the confidentiality of critical infrastructure information is absolutely essential to our work in this area, particularly on reliability,” Commissioner Cheryl LaFleur said. “The FAST Act contains important new authority for the commission that allows us to both protect critical information and confidentially share it with government and private parties.”

LaFleur in particular praised Congress’ exemption of CEII from Freedom of Information Act disclosure.

The sanctions for unauthorized release of CEII stemmed from former Chairman Jon Wellinghoff publicly discussing a confidential FERC analysis on the grid vulnerability to physical attacks. The NOPR says that any FERC employee who knowingly discloses CEII would be subject to termination and/or criminal prosecution. Commissioners who do so would be referred to the Energy Department’s Inspector General.

FERC Chairman Norman Bay would not detail what criminal statutes an employee would be prosecuted under, only saying that CEII is not the same as classified material.

Comments on the NOPR are due 45 days after its publication in the Federal Register.

NERC Databases

FERC also amended its regulations to require NERC to provide the commission and staff access to three of its databases (RM15-25).

The rule gives FERC access to NERC’s transmission availability data system, generating availability data system and protection system misoperations databases. (See FERC to Look over NERC’s Shoulders on Reliability.) It will not take effect, however, until the commission issues a final order implementing the FAST Act provisions.

June 20, 2016

New York Transmission Developers Ask FERC to Order a Do-over

By William Opalka

Three competitive transmission developers asked FERC last week to order NYISO to issue a new request for proposals for transmission upgrades to alleviate congestion and bring renewable energy downstate (EL16-84).

The RFP was issued in February in response to a New York Public Service Commission order that declared a public policy need for two projects in the Mohawk and Hudson valleys to deliver energy to load centers in and around New York City. (See NYPSC Directs NYISO to Seek Tx Bids.)

The developers — Boundless Energy NE, CityGreen Transmission and Miller Bros. — say NYISO violated its Tariff and FERC directives under Order 1000 when it solicited projects without conducting its own review and instead deferred to state regulators.

“We are filing a petition with FERC because the NYISO violated its FERC tariff by inappropriately deferring to the New York Public Service Commission rather than follow its FERC-approved transmission planning function,” Boundless President Rod Lenfest said in a statement.

nypsc

“Based on FERC’s own guidelines, the NYPSC has a limited role in the energy transmission planning process. While that planning process allows the NYPSC to identify to the NYISO the transmission needs for the state, here the NYPSC went even further and pushed for a particular project solution to meet those needs. Rather than consider these projects along with other alternatives that could reduce costs for consumers, the NYISO decided to consider only proposals for the particular projects identified by the NYPSC.”

The developers asked FERC “to confirm that the NYISO, not the NYPSC, is the entity that is required to study and identify the specific project solutions.”

The plaintiffs said the ISO should follow its normal study process — including its base assumptions and generator dispatch modeling — to consider competing solutions without excluding specific technologies or relying on the PSC’s assumptions and modeling.

Developers’ proposals, which were submitted in late April, are currently being evaluated by NYISO staff.

Boundless CEO E. John Tompkins said in an affidavit that the company is seeking a stay of the solicitation process in the appellate division of the state Supreme Court.

The company participated in an evaluation of potential projects last year by NYPSC staff in its AC Transmission initiative. But staff recommended that the developer be disqualified because its proposals were deemed to be not cost-effective. (See NYPSC Staff Recommends $1.2B in Transmission Projects.) Boundless also sought a rehearing of the NYPSC order that declared the public policy need, but that petition was denied in February.

Earlier this month, NYISO named 10 project finalists in a concurrent public policy proceeding designed to alleviate congestion in the Buffalo area. (See NYISO Identifies 10 Public Policy Tx Projects.)

June 20, 2016

FERC Eliminates Wind’s Reactive Power Exemption

By Michael Brooks

WASHINGTON — New wind generators will be required to provide reactive power following a FERC order last week eliminating their exemption from having to provide the service (RM16-1).

wind inverter reactive power ferc — Inverters, necessary for wind turbines to provide reactive power, have become much less expensive since FERC exempted the resource from having to provide the service.

Reactive power, essential for controlling the voltage of the grid, can be measured at three points: the generator itself, the generator substation or the point of interconnection. Synchronous generators’ reactive power is measured at the interconnection point.

The commission’s order revises the commission’s pro forma generator interconnection agreements — both small and large — to require nonsynchronous generators’ reactor power to be measured at the high side of generator substations. In its Notice of Proposed Rulemaking in November, FERC had proposed the interconnection point, but it was persuaded by commenters who said doing so would require additional investment in equipment.

FERC issued the wind exemption in Order 661 in 2005 because it was concerned that the cost of the technology needed to provide reactive power would inhibit the development of the resource. Improvements in that technology since then have made it far less expensive, and FERC said that continuing the exemption could result in insufficient reactive power as wind power grows and traditional synchronous generation retires.

Order 661 did not exempt other types of nonsynchronous generation, such solar, but FERC has been treating them similarly to wind on a case-by-case basis. The commission has sometimes required that balancing authorities demonstrate that the lack of reactive power from a non-wind, nonsynchronous generator would threaten reliability before requiring it to provide the service.

The new requirements apply to all new nonsynchronous generators, regardless of type, that have not executed a facilities study agreement as of 90 days after publication in the Federal Register. They would not apply to existing generators, including those making upgrades that require new interconnection requests. FERC said these provisions would allow generators to complete the interconnection process without delay or extra costs.

FERC approved the new requirements at Thursday’s meeting, which was open to the public again after the commission closed it last month. (See Pipeline Protesters Force FERC to Close Monthly Meeting.) Staff’s presentation of the order was interrupted by two protesters, who urged the commission to halt approval of natural gas pipelines.

“There’s a certain irony here because the protesters interrupted a presentation by staff on commission work that can enable a higher degree of penetration by wind resources while maintaining reliability,” Chairman Norman Bay said in response. “This final rule will ensure comparable and nondiscriminatory treatment of both traditional resources and new resources, such as wind and solar, in the provision of reactive power, while recognizing that some technological differences remain.”

“Today’s rule recognizes that wind and other nonsynchronous generators, which are an increasingly important part of the fleet, now have the technical ability to provide reactive power at reasonable cost, and so they’ll now be required to do so,” Commissioner Cheryl LaFleur said. “I think today’s rule highlights that wind and solar are no longer just niche technologies.”