Page 1423 – RTO Insider

June 20, 2016

CAISO Study Would ID Gas Generators Vulnerable to Early Retirement

By Robert Mullin

Concerned that large numbers of gas-fired generators will retire early because of competition from lower-cost renewables, CAISO last week proposed a study to identify the most vulnerable units in its balancing area.

The initiative to gauge the risk of “economically driven” retirements is a result of California’s 50% by 2030 renewable portfolio standard, enacted last year.

That mandate — along with other state and federal environmental measures — is expected to increasingly leave nonrenewable resources at the margins of the ISO’s wholesale markets, reducing the income stream for gas generators already dealing with depressed power prices.

Transmission planners would use the study’s findings to assess how potential gas retirements would affect reliability and congestion in ISO load pockets, including local capacity requirements (LCR) areas — regions with increased resource adequacy requirements based on limited import capability. The ISO’s largest metropolitan areas — the Los Angeles Basin, San Diego and the San Francisco Bay Area — are all LCR areas.

ISO staff said the study will not evaluate the impact of gas retirements on overall system resource adequacy, instead limiting its focus to local impacts.

“We’ll go through all the LCR areas one by one,” said Yi Zhang, CAISO regional transmission engineer lead, during a June 13 conference call to discuss the study with stakeholders.

The ISO will accept comments on the proposed study — including its necessity — until June 27.

Study results are intended to inform the ISO’s 2016-2017 transmission planning cycle and the long-term planning process.

The study would screen for potential gas retirements by first overlaying the ISO’s 2015-2016 production cost models — the framework for determining the most cost-efficient generation configuration for serving load — with expected portfolio changes stemming from the 50% renewables mandate. The latest LCR results would also be factored into the assessment.

Based on that information, CAISO would apply three criteria to identify whether a gas unit exhibits a high potential for early retirement:

A capacity factor below the typical value for the type of generator;
No revenue from ancillary services; and
Not required to meet LCR.

A unit meeting the first two criteria, but also needed to meet LCR in a designated area, would likely avoid retirement — except in LCRs with surplus generation.

“If one area has a surplus, there may be some risk of early retirement,” Zhang said.

Calpine Vice President Mark Smith questioned the soundness of CAISO’s criteria for determining the financial viability of units deemed vulnerable.

“You know retirement is fundamentally an economic decision [for generating companies],” Smith said. “Why aren’t you using financial information to assess this rather than the criteria you’ve chosen?”

He contended it would “a very, very dangerous assumption” that any units will be compensated to “stay around.”

Calpine earlier this year idled its gas-fired Sutter Energy Center in Northern California, saying the plant was not economically viable. In 2012, the California Public Utilities Commission directed the state’s three investor-owned utilities to enter into contracts with the 578-MW, combined cycle plant to keep it operating for reliability reasons, but those agreements expired later that year. The PUC has resisted the idea of California developing a capacity market — or any system of capacity payments — to keep such plants available.

sutter energy center (calpine), CAISO, gas generators — Calpine idled its gas-fired Sutter Energy Center in Yuba City, California earlier this year for econmic reasons. *Source: Calpine*

“Trying to do a bottom-up analysis of individual units and trying to understand the value chains they have access to is a far broader exercise,” replied Neil Millar, CAISO executive director of infrastructure development.

“This is our first time to take on this analysis and our focus is the risk to the grid,” Millar said, adding that the ISO will refine its approach in the future.

Zhang said CAISO plans to share a list of potential retirements during a September stakeholder meeting.

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.”

June 20, 2016

FERC OKs Change to MISO SSR Process

FERC last week accepted portions of MISO’s system support resource (SSR) Tariff changes but rejected the RTO’s proposal regarding the retention and transfer of interconnection rights (ER12-2302-004).
The changes allow new generation not available at the time of reliability studies and SSR designation to become an alternative to an SSR assignment.

However, FERC told MISO its proposal on interconnection rights had gaps.

Presque Isle Power Plant (Source We Energies) - FERC MISO SSR process interconnection rights — Presque Isle Power Plant *Source: We Energies*

MISO permits owners and operators of retiring SSR facilities to retain or transfer interconnection service. FERC said that in three filings, the RTO hasn’t yet proposed an impartial method for implementing the rule.

“MISO must propose additional procedures that ensure that the retention and transfer of interconnection service is offered on a fair, transparent and nondiscriminatory basis,” FERC said. “MISO is required to propose additional procedures, which should, among other things, allow a clear and consistent way in which generators seeking a transfer of interconnection service from a retiring generator may identify opportunities and address how such a generator would be chosen for such service.”

FERC also said MISO’s February filing to remove language regarding retention of interconnection service from its SSR procedures and insert them into Attachment X “merely moves this provision from one Tariff section to another without providing the requisite additional procedures.”

— Amanda Durish Cook

June 20, 2016

Federal Briefs

A federal judge rejected EPA’s effort to block a former official from testifying on behalf of a coal company that is suing the agency. The agency argued that Jeff Holmstead, a former EPA air pollution expert who left the agency in 2005, would have a conflict of interest because of his former position.

“That dog won’t hunt,” Judge John Preston Baily said of EPA’s argument. He also dismissed as “ridiculous” EPA’s claim that Holmstead was unqualified to testify as an expert witness.

Holmstead, who now works for law firm Bracewell, is an expert witness for Murray Energy. The company has sued EPA, alleging it has not accounted for or studied coal industry job losses resulting from its air pollution regulations, as required under the Clean Air Act.

More: The Hill

Senate to Consider Coal Cleanup Bill

Four senators introduced a bill that would require coal companies to prove they have the resources to clean up mining areas after they close. Coal companies have been able to simply declare they can afford cleanup costs, without any financial assurance, a process called “self-bonding.”

The recent spate of coal company bankruptcies has called into question the ability of distressed coal producers to handle the cleanup costs.

“We need to make sure the taxpayer isn’t on the hook for cleanup work by bankrupt coal companies anymore,” Sen. Maria Cantwell (D-Wash.) said in a statement. “Self-bonding clearly isn’t working, and we need to stop this dicey practice from continuing.”

More: The Hill

Green Groups ask FERC for PennEast Pipeline Hearing

A group of environmental organizations is asking FERC to hold an evidentiary hearing on the need for the PennEast pipeline that would deliver natural gas from Pennsylvania mostly to New Jersey utilities.

“FERC must have substantial evidence of significant public benefit to approve PennEast’s application, but the company’s existing record fails to meet that test,” said a senior attorney with the Eastern Environmental Law Center. The center charges in a complaint that PennEast used the fact that six owners of the pipeline have contracted for about 75% of the proposed pipeline’s capacity as evidence of public need.

The New Jersey Sierra Club, however, didn’t join in the suit, saying the tactic would be unsuccessful. “What we’re more concerned about is that FERC and PennEast fix any defects they have in their applications and filings,” said Jeff Tittel, Sierra Club director.

More: Mercer Me

DOE Issues $82 Million in Nuclear Research Grants

The Department of Energy has identified 93 projects in 28 states that will receive $82 million in grants to advance nuclear energy research.

“Nuclear power is our nation’s largest source of low-carbon electricity and is a vital component in our efforts to both provide affordable and reliable electricity and to combat climate change,” Energy Secretary Ernest Moniz said. “These awards will help scientists and engineers as they continue to innovate with advanced nuclear technologies.”

More: Department of Energy

NRC Names New Director of Office of Investigation

The Nuclear Regulatory Commission named Kimberly A. Howell as director of its Office of Investigation.

Howell, who has 20 years of federal law enforcement experience, was deputy assistant inspector general for investigations in the Office of Personnel Management. Before that, she held investigative positions with the Food and Drug Administration, the Secret Service and the Postal Service.

NRC’s investigation office creates new policies, procedures and standards for investigating licensees, contractors, vendors and other third-party organizations.

More: DailyEnergyInsider

EPA Moves Ahead with CPP Incentives Despite Stay

Despite a stay issued by the U.S. Supreme Court, EPA said it would go forward with a plan that issues incentives for states that comply with implementation of the Clean Power Plan.

“Taking these steps will help cut carbon pollution by encouraging investment in renewable energy and energy efficiency,” EPA’s Janet McCabe said. The Clean Energy Incentive Program gives states compliance credits for pushing forward renewable and efficiency projects.

The Supreme Court suspended enforcement of the Clean Power Plan until an appeal by states could be settled. “EPA is attempting to downplay the significance of the stay and argue against clear legal precedence as a last-ditch effort to scare states into spending scarce resources complying with a rule that could very well be overturned,” said Sen. James Inhofe (R-Okla.), chairman of the Environment and Public Works Committee.

More: The Hill

EIA Report: CPP Will Push Development of Renewables

An Energy Information Administration report concludes that EPA’s Clean Power Plan would accelerate the development of renewable energy at an annual rate of nearly 5%.

“California sees strong growth in renewable generation by 2030 as a result of the state renewable targets,” the EIA said. “Similarly, the Northwest region is expected to increase renewables generation as well. The Northeast shows an increase in both natural gas and renewables generation by 2030, and a small decline in nuclear generation due to planned retirements.”

EIA’s estimates were based upon the assumption the plan would be implemented. The plan is currently on hold as a result of a Supreme Court stay.

More: Morning Consult

Entergy’s Indian Point Unit 2 Back Online After Repairs

Entergy’s Indian Point Unit 2 nuclear plant went back into service late Thursday after a refueling outage, inspection and repairs. The repairs included replacement of 278 bolts and plates that were discovered damaged during an inspection.

A group of environmental organizations filed an unsuccessful emergency petition with the D.C. Circuit Court of Appeals to prevent Entergy from bringing the plant back online. Friends of the Earth and other groups said Entergy hasn’t provided a root cause analysis of the bolt degradation issue.

The Nuclear Regulatory Commission said there are no safety concerns. Entergy will conduct a separate bolt inspection at Unit 3 early next year.

More: Entergy; Friends of the Earth

Court Upholds Blocking Minn. Clean Energy Law

A federal appeals court upheld a ruling that Minnesota’s 2007 clean energy law illegally regulated out-of-state utilities by requiring state power producers who import electricity to reduce greenhouse gas emissions elsewhere.

The ruling by the 8th U.S. Circuit Court of Appeals was a victory for North Dakota and its utility and coal interests, which argued that the Minnesota law unconstitutionally hampered their ability to sell electricity from coal-fired power plants and to build new coal generators. The law, known as the Next Generation Energy Act, restricted electricity imports from power plants that increase greenhouse gases, unless they reduce those emissions.

The court’s decision does not affect the law’s requirement that Minnesota utilities get 25 to 30% of their electricity from renewable sources such as wind and solar.

More: Star Tribune

June 20, 2016

MISO Planning Subcommittee Briefs

MISO released a work plan last week detailing how it and PJM will use the next six months to improve coordination of generation retirements.

The RTOs’ cooperation on generator retirement studies was one of six directives mandated by MISO, PJM Working to Comply with NIPSCO Order.)

At last week’s Planning Subcommittee meeting, MISO said it and PJM will develop a proposal on retirement studies coordination by July.

MISO said it would work on the issue in meetings of the subcommittee, Planning Advisory Committee, and the RTOs’ Interregional Planning Stakeholder Advisory Committee and Joint and Common Market.

Neil Shah, MISO adviser of seams administration, said the RTOs would be starting from scratch. “The joint operating agreement doesn’t have any retirement coordination language,” he said.

The RTOs differ on retirement rules. MISO requires 26 weeks’ notice prior to retirement, giving it time for a 75-day reliability assessment; PJM requires a 90-day notice and only 30 days of reliability assessment. Further, MISO keeps retirement information confidential unless a reliability concern is identified. PJM has no such confidentially rules and makes retirement information publicly available.

Shah said MISO would submit its work plan to FERC with an informational status filing that is due June 20. Additional status filings are due Aug. 19 and Oct. 18.

He also said MISO plans to share draft JOA language with stakeholders at the RTOs’ Nov. 15 joint and common issues meeting in time to file proposed JOA revisions with FERC by Dec 15.

Pseudo-Ties to Require System Impact Studies; Would be Barred from Sink Switching

MISO wants to conduct system impact studies on all pseudo-tied units with transmission service requests and forbid them from switching sinks until the requests expire.

The RTO is proposing a system impact study be required for all pseudo-tie transmission service requests and that firm point-to-point transmission service be required for the life of the pseudo-tie.

MISO has also proposed that pseudo-tied exports be sourced from a designated generating facility in its commercial model and be modeled in the external balancing authority. Pseudo-tied imports must be sourced from the local balancing authority where the generating unit is physically located and must sink into the MISO local balancing authority where the unit is being pseudo-tied.

“Participants are changing pseudo-ties to another sink after they have a transmission service request,” MISO senior transmission planning engineer Ankit Pahwa said. “It’s a shortcoming in the existing process … and a gray area that has not been covered yet.”

Pahwa said the proposed changes have been coordinated with PJM. He added that participants with existing pseudo-tied transmission service requests would be grandfathered from an impact restudy.

Currently, transmission service requests are evaluated based on an OASIS available flowgate capability evaluation, with only long-term requests — 18 months or longer — requiring a system impact study. Neither long-term nor short-term requests require a source/sink analysis, Pahwa said.

“From MISO’s perspective, we want to be 100% sure that we capture the transmission service impacts if a pseudo-tie moves to a different [local balancing authority],” Pahwa said.

“I think what we’re wrestling here is, does there need to be different treatment for pseudo-ties … much like there are different evaluations for network resource interconnection service for reliability purposes? At the minimum, you need to be sure you have the appropriate type of analysis,” MISO’s Jeff Webb said.

Webb said more conversations with other RTOs were needed before a final proposal. Stakeholders have until July 15 to comment on MISO’s proposal.

MISO Delves into MTEP 16 Studies

MISO is in the midst of developing model scopes for the 2016 Transmission Expansion Plan (MTEP 16), said Dave Ditner of the RTO’s system modeling department. The RTO’s modeling will include a 2017 summer peak with wind contributions of 15.6% and 2021 modeling of summer peak, summer shoulder and light load scenarios with wind contributions ranging from 15.6 to 90%.

William Kenney, an expansion planning engineer for MISO’s Southern Region, also presented the finalized MTEP 16 voltage study scope. The study will use nine 2021 power flow models, including summer, winter and a shoulder with wind at 40%. MISO will release the final MTEP 16 voltage stability study in October.

Additionally, seven transfers will be studied in model year 2021 under the MTEP 16 transfer analysis scope:

MISO North to SPP;
Two different paths from Manitoba Hydro to MISO North;
PJM in Northern Illinois to PJM Ohio;
Missouri and Illinois to PJM Ohio;
SPP to Southern Co.’s territory; and
MISO South to SPP.

MISO will finalize the transfer analysis in mid-August.

Storage May Be Removed from Non-Transmission Alternatives

MISO presented stakeholders with draft language on Business Practices Manual 020, continuing a nearly yearlong discussion on non-transmission alternatives.

The RTO is suggesting separating energy storage devices that could solve a transmission issue from BPM language on non-transmission alternatives. MISO is also recommending discussion on whether storage can serve as a non-traditional transmission alternative move to the Planning Advisory Committee, MISO’s Matt Tackett said.

In April, MISO proposed classifying storage as a non-traditional transmission alternative. (See “Energy Storage Prompts 2nd Transmission Alternative Category,” MISO Planning Subcommittee Briefs.)

Indianapolis Power & Light’s Lin Franks said storage provides frequency control and voltage control much like transmission.

MISO will present a second draft of the BPM language at the August Planning Subcommittee meeting.

— Amanda Durish Cook

June 20, 2016

ERCOT Board of Directors Briefs

The ERCOT Board of Directors approved extending a reliability-must-run contract with NRG Energy for its Greens Bayou Unit 5 plant in the Houston area. The RMR, ERCOT’s first in five years, will run through June 30, 2018, at which time additional generation and transmission infrastructure is expected to be in service.

The 371-MW natural gas-fired generator was originally scheduled to be mothballed June 27, but ERCOT’s RMR contract June 3 made the unit available to the market through September. (See ERCOT to Keep NRG’s Greens Bayou Plant Running for Summer.)

Staff analysis indicates Greens Bayou Unit 5 is needed to maintain or support reliability in the region over the short term.

“Having that unit available will reduce the likelihood of having to engage a constraint-management plan, which would likely mean load shed,” said Warren Lasher, ERCOT’s director of system planning.

Under the RMR agreement’s terms, ERCOT will make a standby payment to NRG of $3,185/hour during on-peak hours, whether or not the unit runs.

Directors Carolyn Shellman, of CPS Energy, and Read Comstock, of Direct Energy, both encouraged additional discussion on the ISO’s RMR practices at the next board meeting. “I think we should encourage a holistic review of the RMR protocols,” Comstock said.

Lasher said staff will begin evaluating must-run alternatives, which it will bring to the board in August. The Technical Advisory Committee is also creating a task force to focus on the issue.

“I would like to see the market solve these situations, so we don’t have to,” Director Judy Walsh said.

Staff said the region’s reliability concerns will subside before the summer peak of 2018, when the $590 million Houston Import transmission project — “the ultimate [RMR] exit strategy,” Lasher called it — is expected to be completed. New generation is also on the way, with NRG’s 390-MW PH Robinson peaking facility expected to come online later this summer and Exelon’s 1,148-MW Colorado Bend combined cycle plant to follow in July 2017.

ERCOT also added 75 MW of power last week when NRG converted a gas turbine at its Houston-area W.A. Parish facility into a cogeneration unit. The unit was originally built to produce steam and electricity as part of the Petra Nova post-carbon capture and sequestration joint venture with JX Nippon Oil & Gas Exploration. The unit went into mothballs May 19 during its conversion process.

Magness: Mild Weather Cuts into Admin Revenue

CEO Bill Magness said ERCOT’s year-to-date revenues are $2.3 million over budget, despite a $2.2 million shortfall in the administrative fee that is attributed primarily to mild weather this year. He said the ISO is on track to finish $3.1 million above budget, thanks to positive variances in resource management, hardware and software, and employee benefit costs.

“It looks like we can create a favorable variance, but we don’t know what the weather’s going to be like,” Magness said.

ERCOT’s senior meteorologist, Chris Coleman, said this summer will “likely” not be as warm as last summer — the 17th hottest in Texas over the past 121 summers — or 2011, when sustained heat led to several peak-demand records and seven emergency alert notifications.

“This summer is one of the more difficult forecasts I’ve put together,” Coleman said. “Most indicators suggest a milder summer. I can guarantee you we will not see a repeat of 2011.”

Coleman said ocean temperatures, the primary influence on weather patterns, have been above normal in both the Pacific and Atlantic Oceans. He also said the transition from the second-strongest El Niño on record to what he expects to be a neutral or weak La Niña could lead to above-normal temperatures in the late summer.

The meteorologist said he does see “more potential for hurricane activity in the Gulf of Mexico” than his first four years with ERCOT. Coleman predicted five hurricanes, of which one or two could be in the Gulf, and the potential for two storms to make landfall in Texas.

“It doesn’t mean Texas will be hit by a tropical storm or hurricane,” he said, “but if there are three to five in the Gulf, the potential is greater.”

Dan Woodfin, ERCOT’s director of system planning, said it would take “really, really extreme” weather conditions to affect the grid’s operations. The ISO said last month it has more than enough natural gas and renewable energy capacity to meet its projected summer peak this year. (See ERCOT Briefs: Ample Capacity; Outage Procedures.)

“We’re not expecting a 2011 summer,” Woodfin said. “We have procedures in place should something out of the ordinary happen.”

The Rio Grande Valley, long a trouble spot for congestion, “looks better this summer than it has in quite a few years,” Woodfin said. He said a 345-kV line was completed last month and a cross-valley project went into service two weeks ago, easing some concerns.

LP&L Integration Could Unlock More Panhandle Wind Energy

Lasher shared staff’s report on how to integrate Lubbock Power & Light into ERCOT, which recommends a plan that would allow for further export of the Texas Panhandle’s ample wind energy supplies.

Lasher said staff’s “option 40W” will cost $364 million and result in 141 miles of new 345-kV rights of way, but it could also help export 4,246 MW of wind energy elsewhere on the grid.

“It’s not the low-cost option,” he said, “but it’s preferred specifically because it’s consistent with the longer-term needs ERCOT has identified for the region.”

LP&L announced last September it planned to disconnect from SPP and join ERCOT by 2019. Xcel Energy, whose Southwestern Public Service subsidiary serves LP&L’s load, asked FERC in May for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan. (See Xcel Asks for $88.7M Fee for Lubbock Switch to ERCOT.)

Staff combined studies supplied by LP&L and Sharyland Utilities, which has transmission assets in the Panhandle, and folded them into its own analysis. The final report will be filed in the Public Utility Commission of Texas’ LP&L docket (# 45633).

Changes to Calculation of Market’s Physical Responsive Capability

ERCOT’s methodology for determining ancillary service requirements will change July 1 when it adjusts the reserve discount factor (RDF) in the market’s physical responsive capability (PRC) calculation on quick-response online generation.

The board unanimously approved staff’s recommendation on the adjustment, pleasing PUC Commissioner Ken Anderson, who has raised concerns over an event last August when the ISO’s scarcity pricing adder, the operating reserve demand curve (ORDC), did not appropriately reflect a reduction in the PRC.

“In defense of ERCOT, these changes are looking to solve the problem we saw last August … the disconnect between the ORDC and PRC,” he said.

On Aug. 13, operators deployed non-spinning reserve service as the PRC dropped to 2,371 MW. However, ERCOT’s real-time online reserve capacity was 3,629 MW, which was reflected in wholesale prices.

ERCOT buys responsive reserve service to ensure sufficient PRC is available. The measure approved by the board aligns the ISO’s systemwide discount factor, lowering it from 2% last year to 1%. It also makes operational adjustments to the RDF.

Board Approves 13 Revision Requests

The board pulled one nodal protocol revision request (NPRR) from the consent agenda but gave it its unanimous approval following a brief discussion.

NPRR758 is designed to provide improved transparency to market participants when transmission outages that could create congestion are submitted with less than 90 days’ notice. It would identify outages that have historically resulted in high congestion costs, as adjusted through stakeholder review to account for upgrades and other changes.

“I’m concerned we don’t have a clear-cut requirement to how we came up with the list and published it,” said Nick Fehrenbach, manager of regulatory affairs and utility franchising for the City of Dallas, before offering up the motion for approval. “We need clear requirements and how we can change them, or we’re leaving ourselves in a quandary.”

TAC Chair Randa Stephenson, of the Lower Colorado River Authority, said the subcommittee and ERCOT staff will “work to ensure a list of high-impact outages is available to public knowledge.”

The board’s consent agenda resulted in the approval of nine more NPRRs, two system change requests (SCRs) and a nodal operating guide revision request (NOGRR).

NPRR709: Modifies the alternative-dispute resolution procedure and clarifies parts of the settlement and billing dispute process.
NPRR752: Clarifies revision request protocol language to reflect current ERCOT practices.
NPRR754: Revises the posting frequency of the load-forecast distribution factors report. Posting is required only when the factors are changed.
NPRR761: Clarifies that a resource will not be eligible for make-whole payment startup-cost compensation in the day-ahead market when the market considers the resource as not having a startup cost.
NPRR762: Removes references to the provision of responsive reserves across the DC ties.
NPRR763: Corrects the formula for calculating qualified scheduling entities’ monthly block load transfer amount to reflect a charge, rather than a payment.
NPRR764: Changes calculations for charges to entities short their capacity obligations in reliability unit commitment. Calculations for wind and solar resources will be based on their production potential.
NPRR765: Eliminates publisher names for various fuel price indexes and provides additional clarifying language regarding the use of a substitute source for daily fuel prices.
NPRR766: Aligns the description of the systemwide discount factor with the proposed operational adjustment to the RDF in the physical responsive capability calculation; also aligns the posting for RDFs applicable to both generation and load resources.
SCR788: Updates the formula used to calculate the “generation to be dispatched” (GTBD) value and help minimize GTBD oscillations from one security-constrained economic dispatch interval to the next.
SCR790: Adds an additional level of geographical granularity — the Panhandle/North area — to reports on wind power production and forecasts.
NOGRR050: Removes ERCOT’s requirement to produce outage-scheduling reports until systems can be changed to include only transmission service providers’ outages.

– Tom Kleckner