FERC dismissed concerns from several stakeholders last week in approving the Ohio Valley Electric Corp.’s integration into PJM (ER18-459, ER18-460).
The commission said OVEC and PJM had satisfied the Operating Agreement requirements for integrating the company, rejecting objections by stakeholders including American Municipal Power, the Ohio Consumers’ Counsel and the Public Utilities Commission of Ohio. The protesters expressed concern that OVEC’s integration will result in significant upgrade costs and increase the existing generation oversupply without providing more load for PJM generators to serve. (See OVEC Integration not up for Debate, PJM Says.)
The commission also accepted grandfathering of several power agreements and delivery commitments.
OVEC, which is headquartered in Piketon, Ohio, owns 2,200 MW of generation capacity but will have no load after a U.S. Department of Energy contract ends sometime before 2023. The company was created in 1952 to service a uranium enrichment plant near Piketon that ceased operations in 2001. The department ended the 2,000-MW contract in 2003 but maintains a load that can be 45 MW at its maximum but is generally less than 30 MW.
The company’s two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — are already pseudo-tied into PJM, and its eight “sponsors” can sell their portions of the output into the RTO’s markets. The generation would become internal to PJM following membership, eliminating the pseudo-ties.
Clifty Creek Power Plant Complex | Crowezr
The commission said it didn’t buy members’ arguments that a cost-benefit analysis should be required prior to integrating OVEC — a request which the OCC also made separately to PJM — because there’s no precedent for it and the benefits to consumers from RTO membership “outweigh” integration costs. The commission said those benefits are “increased efficiency for transmission planning and generation investment, reduced transaction costs, improved grid reliability, limited discriminatory practices and improved market operations.”
It also said concerns about future costs aren’t warranted because those costs will be allocated based on PJM’s Tariff and OVEC’s sponsor companies will continue to pay for OVEC’s share. The order noted that PJM’s studies indicated no transmission upgrades will be required to integrate OVEC. “With the exception of a single deliverability violation, which OVEC has committed to remedy, the existing equipment and facilities are adequate,” the commission said.
PJM’s Independent Market Monitor had raised concerns about OVEC’s aging plants becoming eligible for reliability-must-run contracts if they decide to shut down, but the commission said the issue is beyond the scope of the integration request.
WASHINGTON — The cybersecurity expert whose firm discovered the malware that caused blackouts in Ukraine in 2016 told state regulators that hackers targeting the U.S. electric industry are growing more numerous and more skilled.
“There are five dedicated teams targeting infrastructure sites in North America, including eight different campaigns targeting sites,” Robert M. Lee, CEO of cybersecurity firm Dragos, told the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Feb. 11. “This is an extreme uptick.”
In June, Lee’s company identified malware it named CrashOverride as the likely cause of a disruption in December 2016 that cut one-fifth of Kiev’s power consumption for an hour. (See Experts ID New Cyber Threat to SCADA Systems.)
The attack occurred about a year after the December 2015 attack on Ukraine — the first time hackers had taken down a portion of the power grid. The 2015 attack used the BlackEnergy program, which highjacked the supervisory control and data acquisition (SCADA) systems, taking control of operator workstations and locking the operators out.
CrashOverride — which can control circuit breakers without any manual involvement — takes advantage of the simplicity of SCADA. “CrashOverride was just knowledge of the 2015 attack getting codified in malware to make it scalable,” Lee said. “A lot of times we tell ourselves, ‘There’s computer vulnerabilities; if we patch the computer vulnerabilities, we’re OK.’ But that’s not the actual risk. … [The 2016 Ukraine attack] was just adversaries learning the industrial systems and using them against themselves — almost becoming malicious insiders even though they were remote.”
The 2016 outage lasted only an hour. But, Lee said, CrashOverride is still dangerous because it “can work without any modification across all of Europe, most of the Middle East and most of Asia.”
The malware is an illustration of the increasing sophistication of hackers, Lee said. As recently as 2014, he said, there were only two campaigns against infrastructure sites. 2015 saw not just the first attack on Ukraine but also a cyberattack that caused physical damage at a steel mill in Germany — only the second attack to produce such results, after the Stuxnet attack on Iran’s nuclear centrifuges.
Last year, the first known malware specifically targeting industrial safety systems was identified, Lee said. The malware, which targets Schneider Electric’s Triconex safety instrumented system, was deployed against at least one victim in the Middle East. “It was going after safety systems in oil and gas production facilities. The only purpose of a safety system is to protect human life. If you go after it willfully … you are either intending to kill people or you’re just OK with doing so.”
Lee said grid operators and other industries face two strategic challenges. “We don’t truly understand or appreciate our industrial threat landscape,” he said. “So, we get a lot of best practices or compliance standards written off of business network security, not industrial network security to address the real risk.
“The second challenge is there’s not a lot of people who are industrial cybersecurity experts. The Department of Homeland Security puts that at around 500 people in North America … so you’re not going to scale that across the industry.”
Lee said small electric cooperatives and water utilities may be particularly vulnerable because of their limited staffs. He said his company has done “charity” work for one small water utility where “the one IT guy actually mows the lawn on Fridays.”
Tim Roxey, NERC’s chief security officer, said there are fewer than 500 people who have the necessary cybersecurity expertise and understanding of both NERC’s Critical Infrastructure Protection standards and federal government rules.
“You don’t find a whole lot of beer conversations around the bar about the Administrative Procedures Act, and yet these things are fundamental … to how we actually … develop the standards, implement the standards [and] enforce the standards,” he said.
There is some good news on that front, however. In an earlier presentation at the NARUC meeting, Dennis P. Gilbert Jr., Exelon’s chief information security officer, reported on his company’s adoption of the National Initiative for Cybersecurity Education (NICE) Workforce Framework. Developed by the National Institute of Standards and Technology, the program provides organizations with a common lexicon for describing cybersecurity careers by category, specialty area and work role. It involves creating new job titles and performing a market salary assessment.
Gilbert said Exelon was happy to reward many of their cybersecurity team members with 10 to 35% pay raises, citing better morale and a lower attrition rate of 5% — reducing the costs of having to recruit and train new workers in the “high demand, low density” career field.
Jim Hempstead, managing director of Moody’s Investors Service’s Global Infrastructure Finance Group, who shared the panel with Lee and Roxey, explained how cyber risks figure in credit rating agencies’ evaluation of companies’ ability to pay their debts.
“We do not explicitly incorporate cyber risks into the credit analysis for the utility industry or for any of the other” industries, Hempstead said. “The transparency and disclosure around cyber risks are unreliable. There’s just not enough disclosure as to what the events are. And there’s not enough disclosure as to what is actually happening behind it.”
Instead, Hempstead said, Moody’s conducts scenario analyses that treat cyberattacks like extreme weather — a low-probability, high-impact event.
“We have seen over and over again utility companies that are able to absorb the impact of a severe event that in many instances has significant financial consequences, but the company is still able to right itself and put itself back on track.
“Now that means the cyberattack [modeled] is not a permanent destruction of critical infrastructure,” Hempstead added, distinguishing it from the dire scenarios painted by Ted Koppel in his controversial 2015 book “Lights Out.” (See Critics: Koppel Doomsday Scenario Ignores Prep.)
“If Ted Koppel is correct and everything east of the Mississippi is affected by cyber for 18 months, that’s outside the bounds of what we’re incorporating in our analysis,” Hempstead said. “But because utilities are viewed by Moody’s as critical infrastructure assets, we believe there will be an extraordinary government intervention to assist the company in putting itself back on track.”
Hempstead said Moody’s is concerned that the cybersecurity regulations for the utility industry “could create a culture of compliance where the defenses are relaxed because the compliance check boxes are getting checked. That’s, we don’t think, the right mentality. Cyber risk is an enterprise risk issue and therefore it resides at the board of directors. And we are very encouraged at how many boards of directors in the utility sector are very focused on cyber.”
Lee said some of his customers have been reluctant to embrace innovation for fear of being found in violation of reliability standards. Others express concern over how Dragos’ subscription-based services will impact their bottom lines. “Right now, one of the biggest pushbacks I get from a lot of my customers across the utility industry is, ‘Hey is there any way we cap ex this?’” he said. “We have to figure out how to make sure that the [security effort] that is already moving in the right direction is not hampered by the way we want to do accounting.”
In an earlier presentation, Bill Lawrence, director of NERC’s Electricity Information Sharing and Analysis Center (E-ISAC), shared lessons learned from GridEx IV exercise in November, which simulated physical and cyberattacks on the electric system. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.) E-ISAC works with the Department of Energy and the Electricity Subsector Coordinating Council (ESCC) to inform the industry about physical and cyber threats.
“The scary thing is … everything we come up with [as an attack scenario] has happened somewhere in the world — about 99% of our entire scenario [has happened],” Lawrence said. “So, things with drones, things with modular malware, things with drains on resources in both computer and physical security.”
A public report on GridEx IV is due at end of March. A meeting will be held in November to plan for GridEx V, to be held in 2019.
ISO-NE on Thursday defended its proposed two-stage capacity auction, responding to criticism by its External Market Monitor and others.
In its Feb. 13 response to protests, the RTO asked the commission to approve its Competitive Auctions with Sponsored Policy Resources (CASPR) program, saying the Monitor’s “proposed cure would be worse than the disease” (ER18-619). Monitor David Patton filed a protest Jan. 30 saying that he supports “the objective and approach” of CASPR but that the RTO’s proposal has a “critical design flaw” that will result in “inefficient investment and retirement decisions and over the long term … raise costs substantially to New England’s customers.”
Also filing protests in response to the Jan. 8 CASPR filing were Massachusetts Attorney General Maura Healey; municipal utilities (New England Consumer-Owned Systems); Connecticut; the Natural Gas Supply Association; a coalition of environmental groups (Clean Energy Advocates); the New England Power Generators Association; and several merchant generators. (See CASPR Filing Draws Stakeholder Support, Protests.)
The CASPR proposal grew out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 to address state regulators’ concerns about ratepayer costs associated with policy-driven resources and generators’ fears that out-of-market procurements of renewable generation would suppress capacity prices.
Under ISO-NE’s proposal, it would clear the Forward Capacity Auction as it does today, applying the minimum offer price rule (MOPR) to new capacity offers to prevent price suppression. In the second Substitution Auction (SA), generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR. The proposal would phase out the current Renewable Technology Resource (RTR) exemption, which has allowed ISO-NE to clear 200 MW of renewable generation in its capacity auction annually (to a maximum of 600 MW) without regard for the MOPR.
ISO-NE’s External Market Monitor included this example in its protest, saying excluding new conventional resources from the substitution auction (left) would clear only 400 MW of sponsored resources, with three existing resources retiring and sponsored resources foregoing $31.2 million in capacity payments. Under the Monitor’s proposal (right) 500 MW of sponsored resources would clear and only one plant would retire. Sponsored resources’ foregone capacity payments would total only $2.7 million. | Potomac Economics
Bad Cure
ISO-NE said it prohibited new conventional resources from participating in the secondary auction “to protect the Forward Capacity Market’s ability to guide competitive and cost-effective entry and exit decisions to maintain resource adequacy.”
But Patton’s Jan. 30 filing said the exclusion of new conventional resources from the SA will cause “new resources to clear and enter when they are not economic or needed and existing resources to retire that are economic to continue operating and whose costs of remaining in operation (i.e., going forward costs) are much lower than the entry costs of new resources that are entering.”
Patton would allow new conventional resources to clear through the SA “so they may be efficiently displaced by the sponsored resources.”
“This was a component of the ISO’s original proposal, but it decided to alter its proposal by excluding the new conventional resources from the Substitution Auction,” Patton wrote. “By doing this, the supply and demand (and prices) that will determine when a new conventional resource enters will ignore supply from the sponsored resources.”
The RTO retorted that “the EMM’s proposed cure would be worse than the disease” by creating “more, and more significant, problems than the overbuild problem it seeks to fix.”
One such problem would be fictitious entry, in which developers with no intention of building generation enter the FCA just to secure the severance payment in the second auction. The EMM’s fix? New conventional resources that are displaced by a sponsored resource would receive no payment.
The RTO said that could scare off new competitive generation, resulting in high capacity clearing prices — the “price blowout problem.”
Patton said that fear is “misplaced.”
“The risk described by the ISO is a risk that is common to all investment decisions and is efficient for the investor to consider in making its investment decision. Any time new resources are entering the market, whether they are sponsored resources or competing conventional resources, this will reduce the expected profitability and increase the risk to subsequent investment,” he wrote.
The EMM would modify the MOPR applied to sponsored resources in the primary FCA so that they can clear at a moderate price, potentially replacing the market-based clearing price with an administratively determined one.
“In addition to its complexity, this multilayered solution is both unfair and ineffective,” the RTO said.
Impossible to Win?
“In this situation, the conventional new resource has responded to the market’s price signal and succeeded in securing a capacity supply obligation (CSO) because it was willing to sell its capacity in New England at the primary auction’s clearing price,” the RTO said. “To strip such a resource of its award without compensation would alter the meaning of the clearing price, as a high price no longer would serve its fundamental purpose as a market signal to encourage commercial investment.”
The EMM’s proposal makes it impossible to “win” an auction, and the outcome differs fundamentally from “the outcome of a normal competitive auction in which an investor fails to clear because its offer price exceeds the market’s clearing price,” the RTO said.
ISO-NE also objected to the EMM’s proposed “price-setting by administrative dictate,” which it found “problematic, both practically and philosophically.”
Practically, the EMM methodology would create reliance on a predetermined estimate that may or may not reflect the true net cost of new entry (CONE), and “to the extent that number is wrong, FCM’s clearing price may be inflated or deflated,” the RTO said.
Philosophically, the EMM’s proposal would result in an outcome largely dependent on administrative parameters. The outcome, like that of the RTR exemption that CASPR seeks to replace, “ameliorates system overbuild but undermines the competitiveness of capacity prices,” ISO-NE concluded.
Applying the Monitor’s proposal to FCA 12 would have resulted in total costs of $4.15 billion, an increase of $908 million, or 28%, the RTO said.
“There can be no perfect solution that completely meets the objectives to maintain competitive pricing and accommodate state-sponsored resources,” ISO-NE said. “When required to trade between these competing objectives, the ISO prioritizes competitive prices.”
RTR Exemption
The RTO also defended its proposal to phase out the RTR exemption, calling it a “blunt instrument.”
The conditions that made the RTR exemption just and reasonable upon its adoption will no longer exist going forward, the RTO said: “Instead, load growth has slowed, the region has excess capacity, and, most significantly, the states have announced plans to contract for substantial amounts of sponsored capacity.”
NextEra Energy and NRG Energy insisted that the commission eliminate the RTR exemption immediately, saying it suppresses prices. CASPR would phase out the exemption by allowing the exempt megawatts that have accrued in earlier auctions — currently 481 MW — to be used over the coming three years through FCA 15.
NextEra argued that the three-year phase-out made no sense because the conditions that supported the exemption no longer exist. The RTO answered that a measured transition was necessary to maintain investor confidence and lower costs over the long term. It noted that the commission has accepted similar transition mechanisms in other capacity market proceedings.
Attorney General Healey opposed CASPR as not allowing “for any regular or reliable integration of sponsored policy resources” into the FCM. She recommended a mechanism like the “backstop” proposed by the New England States Committee on Electricity, which would guarantee entry of up to 200 MW of sponsored policy resources annually regardless of whether they were matched by retirements.
She also suggested the commission could remand the proposal to the RTO with an order to reinstate the RTR exemption.
The RTO said that, given current market conditions, a 200-MW RTR exemption would depress FCA clearing prices by up to 87 cents/kW-month. Continuing the RTR exemption or adding a backstop would undermine CASPR “because no sponsored policy resource would elect to sell capacity at a low price in the Substitution Auction when it could instead receive the higher primary auction price through the exemption,” ISO-NE said.
The CAISO Board of Governors last week enacted new governance policies and named Governor David Olsen as chairman. It also reviewed the ISO’s policy roadmap for 2018.
In a teleconferenced meeting Thursday, the board enacted a new process whereby governors will hold yearly elections for chair. The five-member board voted to replace sitting Chair Richard Maullin with Olsen, who was originally appointed to the board in 2012 by Gov. Jerry Brown.
Governor Angelina Galiteva said that with CAISO involved in more regional matters and the Western Energy Imbalance Market (EIM), the board felt members should have the opportunity to participate as chairs and share some of the growing workload. The board went through an analysis to study best practices, she said.
“This is something we thought over and talked about for quite a while,” Galiteva said. The board elected her to the newly created position of vice chair, nominated by Governor Mark Ferron and seconded by Governor Ashutosh Bhagwat.
“We are entering a period where there could be some rapid change we are part of or instrumental for,” Maullin said, as other board members thanked him for his service in his role. Maullin’s term on the board ended Dec. 31, and he said remaining on the board depends on the California State Senate, which confirmed him as chair in July 2015. He was reappointed by Brown in January 2015.
Cook Briefs Board on 2018 Roadmap
CAISO Director of Market and Infrastructure Policy Greg Cook briefed the board on the 2018 Policy Initiatives Roadmap and Annual Plan, saying the presentation to the board represents the final step in the implementation process.
In January, Cook briefed the EIM Governing Body on the plan, which includes a proposal to extend the ISO’s day-ahead market to the EIM. (See CAISO Plan Extends Day-Ahead Market to EIM.) Each balancing authority area would retain reliability responsibility, and states would retain control over integrated resource planning. Transmission planning and investment remains with each BAA and local regulatory authority.
Cook shared some of the tasks associated with the day-ahead market extension, including the alignment of transmission access charge paradigms to ensure EIM entities recover transmission costs consistent with the existing bilateral network, and consistent billing determinants across the day-ahead market footprint for market efficiency. There will also be distribution of congestion rents collected through the day-ahead market and a day-ahead resource sufficiency evaluation, among other requirements.
Keith Casey, the ISO’s vice president of market and infrastructure development, told the board that implementing the day-ahead across the EIM will provide additional benefits, but it “certainly will fall short of the full benefits we would get with full participation under a regional construct.” These would include efficiency of a single balancing authority over a larger footprint, as well as transmission planning and resource adequacy benefits.
“We believe it has important benefits … but I do want to stress it will fall short of the full integration benefits,” Casey said.
PG&E Continues Criticism of RMRs
During a public comment period, Eric Eisenman, director of ISO relations and FERC policy for Pacific Gas and Electric, told the board that PG&E has no issue with anything in the roadmap but that addressing the increasing use of reliability-must-run designations (RMRs) and the capacity procurement mechanism (CPM) is the utility’s “highest priority.” He reminded the board of the “robust discussion” it had over RMRs at its November meeting when the designation of the gas-fired Metcalf Energy Center was approved. (See Board Decisions Highlight Market Problems.)
“PG&E continues to be very concerned about a slew of RMRs for 2019 that would be designated later this year,” Eisenman said. “But at this point, we just don’t know what is going to happen.” He urged CAISO to implement more extensive “Phase 2” changes in its RMR/CPM initiative in time for 2019 designations. The ISO has indicated it only intends to address must-offer requirements for RMR and CPM units in that time frame.
Casey said the ISO is looking at transmission alternatives to prevent situations that might otherwise lead to RMRs, including working with PG&E to address “low-hanging, fast upgrades” in the subarea where the Metcalf plant sits. The improvements would alleviate about 600 MW of local capacity requirements and are included in a transmission plan due to be finalized in March, he said.
“There is much we can do — we have a great deal of flexibility with the transmission plans to do those types of studies,” but it would be challenging to complete the improvements by fall 2019, he said.
“We share PG&E’s urgency about getting after these RMR reforms,” Casey said.
CAISO is in the midst of developing a package of enhancements to the RMR/CPM process, which is proving to be a contentious proposal among market stakeholders. (See CAISO, Stakeholders Debate RMR Revisions.)
FERC on Thursday approved a package of modifications to improve market efficiency developed by CAISO for the Western Energy Imbalance Market (EIM). It also issued several other decisions related to Western states and energy markets.
The commission said the EIM measures would improve efficiency by automating manual processes, providing greater transparency into bilateral transactions and enabling increased participation in both the EIM and CAISO.
The approved changes include automated matching of import/export schedule changes between resources inside and outside the EIM, as well as the ability to automate changes to mirror system resources at intertie scheduling points between CAISO and an EIM entity (ER18-461).
“We find that the automated matching and the automatic mirroring functionalities will result in more efficient EIM market outcomes by automating manual processes that are prone to errors and better maintain balance between resources and load following intertie schedule changes,” FERC said.
The EIM Governing Body approved the package of changes in November, after CAISO had scaled down the initiative based on consultations with stakeholders. (See EIM Governing Body Approves ‘Consolidated’ Initiatives.) The changes also facilitate bilateral settlements and improve the market’s modeling accuracy by expanding the functions of non-generator resources.
CAISO had requested approval of the measures by Feb. 15 to allow for the participation of Powerex and Idaho Power in the EIM on April 4.
Deseret Earns MBR Authority
The commission last week also approved Deseret Generation & Transmission Co-operative’s updated market power analysis for the Northwest region, granting the utility market-based rate authority effective Sept. 12, 2016. Utah-based Deseret became a public utility in 1996 after paying off its debt related to rural utility service (ER16-2186).
Deseret owns the 458-MW Bonanza coal-fired plant and a 25% interest in the 430-MW Hunter 2 coal-fired unit, both in the PacifiCorp balancing authority area.
FERC Approves PG&E/Port of Oakland Agreement
The commission also approved an interconnection agreement between Pacific Gas and Electric and the Port of Oakland but suspended the agreement and subjected it to hearing and settlement judge procedures (ER17-2536).
The Port of Oakland is a major container shipping facility and a municipal electric supplier.
The port acts a municipal electricity supplier that serves customers located at the Oakland International Airport, which it owns and operates, using PG&E’s transmission and distribution facilities.
Last year, the port submitted an application to convert its Cuthbertson substation from retail service to wholesale interconnection service under PG&E’s transmission owner tariff, but PG&E identified an issue with the tariff based on the substation’s power factor, which it said has to be resolved before it can provide wholesale service.
The port contends that PG&E’s sales for resale to it are subject to FERC jurisdiction and that it is concerned about provisions in the interconnection agreement referring to matters under the jurisdiction of the California Public Utilities Commission. The port argues that PG&E is attempting to “improperly impose” CPUC-jurisdictional exit fees on it and protests language describing the change to wholesale service as a notice of departure from PG&E, subjecting the port to departing load fees.
The port also contests that certain aspects of the agreement are unreasonable and unduly discriminatory compared with other PG&E interconnection agreements.
FERC set a public hearing subject to settlement procedures to be held within 15 days.
GridLiance Rehearing Request Rejected
FERC rejected GridLiance West’s rehearing request contending the commission erred when it failed to approve the company’s proposed use of an actual capital structure related to incentive rates for facilities it sought to acquire from Valley Electric Transmission Association (ER17-706). GridLiance West said the proposed capital structure was comparable to similarly situated transmission companies.
In its order denying rehearing, the commission said it made no final determination regarding the proposed capital structure but “found that its preliminary analysis indicated that the proposed TO Tariff had not been shown to be just and reasonable and raised issues of material fact that could not be resolved on the record before the commission.”
Idaho Commission Complaint Headed to Court?
FERC also declined to act on a petition for enforcement filed by Franklin Energy Storage against the Idaho Public Utilities Commission (EL18-50, et al.). The company argued the state commission had improperly classified its energy storage facilities as solar qualifying facilities, preventing them from being eligible for the PUC’s stated electricity rate under the Public Utility Regulatory Policies Act. The rate is available to non-wind and non-solar QFs of an average capacity of 10 MW or less.
The decision will allow the company to bring an enforcement action against the Idaho commission in the appropriate court, FERC said.
FERC on Thursday granted a waiver request from Public Service Company of New Hampshire (PSNH), allowing ISO-NE to accept its restoration plan for the Lost Nation generating unit, which the company submitted one business day after the deadline under the RTO’s Tariff (ER18-465).
Eversource Energy, PSNH’s parent company, in January completed the sale of its fossil-fuel generation units in New Hampshire to Granite Shore Power.
On Oct. 20, ISO-NE flagged the oil-fired combustion turbine in Groveton, N.H., for having a significant decrease in capacity below its cleared capacity supply obligation (CSO) of 13.97 MW for the RTO’s 2018-2019 capacity commitment period.
Covered bridge over the Upper Ammonoosuc River next to the 18-MW Lost Nation plant in Groveton, NH.
Under the rules governing the RTO’s annual reconfiguration auctions, Lost Nation had 10 business days to either purchase additional capacity to replace the shortfall or submit a restoration plan showing how it would be able to meet its obligation.
PSNH said the decrease in capacity occurred because a summer seasonal claimed capability audit was not performed. An Eversource employee intended to file a restoration plan showing that Lost Nation was dispatched four days in September 2017 and thus should be capable of supplying output to meet its awarded CSO.
The utility said that two events caused the delay in submitting the restoration plan.
First, the mother of the employee charged with submitting the plan died on Oct. 29, 2017, while the plan was out for review. Then, after a strong storm tore through the state on Oct. 30, the employee was called to storm duty and performed three consecutive 13-hour shifts until being released on Nov. 2. He was then given leave to prepare for his mother’s Nov. 4 memorial service.
Lost Nation Turbine | Eversource
The combination of events distracted the employee from submitting the restoration plan by the close of the Friday, Nov. 3 submission window; he submitted the plan the morning of Monday, Nov. 6. The RTO said it could not unilaterally waive the Tariff-imposed deadline.
In its Feb. 15 decision, the commission found that “PSNH acted in good faith by submitting the restoration plan as soon as possible after it discovered the omission.” The commission also noted that PSNH’s waiver request was uncontested.
FERC ruled Thursday that NYISO must make additional changes to comply with Order 1000, while acknowledging in a separate docket that it erred in directing the ISO to change the indemnification language in its pro forma development agreement.
The commission said transmission developers must indemnify NYISO except for acts of “gross negligence or intentional misconduct.” In ordering NYISO to remove the word “gross” from the agreement, the commission said it failed to follow its precedent in a 2015 order involving MISO (ER15-2059-002; ER13-102-008).
| NYSEG
FERC also granted NYISO a request for clarification, saying it will allow the ISO to propose a new process for evaluating alternative regulated transmission solutions and regulated backstop solutions for interconnection. The ISO’s current process is outlined in Tariff Attachments X and S.
But the commission rejected rehearing requests by the New York Transmission Owners (NYTOs), who balked at the commission’s requirement that TOs responsible for providing “backstop” solutions to a reliability need — normally the incumbent TO — sign the development agreement, as is required of nonincumbent transmission developers.
“If responsible transmission owners developing regulated backstop solutions are not required to execute a development agreement, they will have an advantage over nonincumbent transmission developers both in seeking selection in the regional transmission plan for purposes of cost allocation and remaining selected,” the commission said, noting that the NYISO Transmission Owners Agreement and the agreement between NYISO and the NYTOs on the Comprehensive Planning Process for Reliability Needs are less stringent than those in the development agreement
The NYTOs consist of Central Hudson Gas & Electric; Consolidated Edison; New York Power Authority; New York State Electric and Gas; Niagara Mohawk Power; Long Island Power Authority; Rochester Gas & Electric; and Orange and Rockland Utilities.
Compliance Filings
| NYSEG
FERC also provided its clarification on alternatives to Attachments X and S in a concurrently issued order in which it accepted in part Order 1000 compliance filings NYISO made in March and September 2016. The commission accepted most of the ISO’s Tariff revisions but rejected language it said was discriminatory or unjust (ER13-102, et al.).
It ordered the ISO to make changes in its proposed transmission interconnection procedures that it found unjust and unreasonable, including language on scheduling and definitions.
It also required the ISO to make changes in its proposed Operating Agreement regarding maintenance schedules, compliance with local reliability rules and investigations of equipment malfunctions.
The commission found “incorrect” the Tariff revision that said nothing in Attachment Y affects a TO’s right to recover the costs of upgrades to its facilities regardless of whether the upgrade has been selected in the regional transmission plan for purposes of cost allocation.
“Pursuant to Order No. 1000, once NYISO selects a transmission project in the regional transmission plan for purposes of cost allocation, the regional cost allocation method set forth in Attachment Y of the [Tariff] applies, unless the project developer ‘decline[s] to pursue regional cost allocation,’” the commission said.
ISO-NE could see substantial “spillage” of renewable energy and large price separations because of transmission constraints under scenarios considered in the RTO’s 2017 Economic Study, officials told the Planning Advisory Committee on Wednesday.
The study was requested by the Conservation Law Foundation to evaluate scenarios for meeting Massachusetts and Connecticut climate laws and the Regional Greenhouse Gas Initiative’s emission caps.
The study was based on the “Renewables Plus” scenario from the 2016 Economic Study, which modeled the year 2030 — the only scenario in the 2016 study to meet the RGGI cap. (See Study: New Resources Could ‘Crowd Out’ Old in ISO-NE.)
| ISO-NE
Under Renewables Plus, the generation fleet met existing renewable portfolio standards, and new renewable or clean energy resources were added above existing RPS requirements.
The new study looked at three additional scenarios:
“EE + Offshore”: Added more energy efficiency and offshore wind while reducing imports from Canada by 1,000 MW.
“Onshore Less EE/PV”: A variation on the business-as-usual base case from the 2016 report, with onshore wind boosted to 7,000 MW (nameplate capacity) from 4,800 MW in the reference case.
“Wind Less Nuc”: Assumes the Millstone nuclear plant retires by 2030, five years ahead of its license expiration, with the gap filled by renewable/clean energy resources.
The study found all three scenarios met projected demand, even with transmission constraints based on the “as-planned” system’s internal and external transfer limits.
If transmission constraints are not relieved, the RTO would see “spillage” of wind power north of the Surowiec-South interface, leading to lower prices in Northern Maine than southern New England. For example, under the constrained scenarios, 7 to 18% of renewables would be spilled, with 22 to 89% of the spillage north of Surowiec-South.
In the constrained Wind Less Nuc scenario, average LMPs would range from $13.78/MWh in the Bangor Hydro Electric subarea in northeastern Maine, to $38.71/MWh in the NH subarea (which includes most of New Hampshire, eastern Vermont and southwestern Maine) and $37.18/MWh in Boston.
Only one scenario, EE + Offshore, is as good as the Renewables Plus scenario in meeting the RGGI 2030 emission targets. | ISO-NE
Electric production by natural gas plants fluctuates with assumptions regarding plant retirements and price-taking offers ($0/MWh) by renewable resources. EE + Offshore has the least gas-fired energy, while Wind Less Nuc has the most gas production, especially when the transmission system is constrained.
EE + Offshore had the lowest total production costs, coming in 28% below the Renewables Plus reference case assuming transmission constraints. Onshore Less EE/PV had the highest costs, 77% above the constrained reference case.
Only one scenario, EE + Offshore, is as good as the Renewables Plus scenario in meeting the RGGI 2030 emission targets.
CLF staff attorney David Ismay said the two emission-reduction targets, which were also used in the 2016 study, were intended to “bracket” the goals RGGI might embrace in its latest program review. RGGI’s emissions cap declines by 2.5% annually through 2020. The group announced in August that it would seek an additional 30% reduction in emissions from 2020 levels.
“We expressly worked … to design all three scenarios to meet [RGGI] emissions targets,” Ismay said.
“We’re starting to get a better picture of what the grid needs to look like in order to meet our climate laws and emission regulations that are already on the books,” he explained in an interview later. “We really need a grid that’s different from what we have now. I think that will give legislators, regulators and the ISO information on the kind of mix we need to comply with these laws. … It’s really helpful to see the impact of adding 1,000 MW of EE or 1,000 MW of wind.”
Stakeholders have until April 2 to submit requests for additional economic studies. Requests should be emailed to PACMatters@ISO-NE.com.
MISO is embarking on a review of its entire economic planning process in an effort to more accurately capture the benefits of cost-shared transmission projects.
“This is not about MISO saying the existing process is broken or flawed,” Matt Ellis, of the RTO’s Economic Planning Users Group, told stakeholders at a Feb. 13 Planning Subcommittee meeting.
Ellis said MISO is looking forward to FERC-level discussion on best practices for planning and that it will continue to talk about economic models throughout 2018.
MISO especially wants to take a fresh look at:
The economic impacts of transmission outages;
Voltage and local reliability resource commitments, especially in MISO South load pockets where performance has lagged;
MISO’s emergency energy supply and how it’s being valued in economic models when it defers transmission and generation investment or prevents scarcity pricing and loss-of-load events;
Accounting for likely import and export flows in adjusted production costs; and
Forecasted renewable resource ownership and which members will actually purchase the energy and benefit when considering renewable portfolio standards.
Further, the RTO plans to hold stakeholder discussions through June on other possible measurable benefits that could be valued in the modeling of market efficiency projects. It could consider such benefits as the deferral of reliability projects; savings that could arise from opening up it contract flow path with SPP that bridges MISO South and Midwest; reduced transmission energy losses; reduced ancillary services costs; and deferral of capacity expansion stemming from increased capacity import/export limits.
| MISO
Ellis asked for member companies’ engineers to come forward with other ideas about overlooked benefits of market efficiency projects that could be assigned a monetary value.
Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that renewable standards are set by state legislatures and can be changed. Ellis responded that MISO is looking for that kind of information and other input.
He also said timely changes to MISO’s modeling could affect how it judges potential projects in its annual Market Congestion Planning Study for the 2018 Transmission Expansion Plan.
“We are fully aware that having a process review in parallel with having the process is not an ideal situation. It introduces a lot of ‘what-ifs,’” Ellis said. He promised that MISO would test any projects affected by an economic model change using both the old and new models and that it could delay implementing the new aspects of economic modeling.
MISO announced its plan the same week it proposed to lower the voltage threshold for market efficiency projects to 230 kV, and two weeks after FERC ordered a technical conference on how PJM, MISO and SPP coordinate generator interconnection studies after developer EDF Renewable Energy complained that the RTOs’ modeling standards violate the FERC requirement for transparent open access interconnection service. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
Consolidated Edison’s fourth-quarter net income increased 144% to $505 million ($1.63/share) from $207 million ($0.68/share) in 2016, the company said last week.
Total revenue for the quarter increased 9.38% to $2.961 billion.
The company reported 2017 net income of $1.525 billion ($4.97/share), compared with $1.245 million ($4.15/ share) in 2016. Total revenue was down slightly in 2017 but remained above $12 billion.
Con Edison Composition of Regulatory Rate Base as of Dec. 31, 2017 | ConEd
Con Ed said its adjusted earnings for 2017 excluded the remeasurement of deferred tax assets and liabilities upon enactment of the federal Tax Cuts and Jobs Act, the effects of the gain on the sale of a solar electric production project, and the net mark-to-market of Con Edison’s clean energy businesses.
The company’s earnings presentation showed the new law reduced the net deferred tax liabilities for its Con Ed of New York, Orange and Rockland Utilities and Rockland Electric subsidiaries by more than $5 billion collectively.
Con Ed plans to meet its 2018 capital requirements through internally generated funds and the issuance of securities. The company’s plans include issuing between $1.3 billion and $1.8 billion of long-term debt at its utilities and additional debt secured by its renewable electric production projects.
The company also plans to issue up to $450 million of common equity in addition to equity under its dividend reinvestment, employee stock purchase and long-term incentive plans. The plans do not reflect the provision to utility customers of any tax law benefits that may be required by the New York Public Service Commission or the New Jersey Board of Public Utilities.
