Clean Line Energy Partners announced Friday that it has sold all the assets of the Oklahoma portion of the multistate Plains & Eastern Clean Line transmission project to NextEra Energy for an undisclosed sum.
In a press release, Clean Line said the transaction would continue the “forward momentum” of the Plains & Eastern project and “install a new sponsor to a transmission solution to the burgeoning wind sector in Oklahoma” and SPP. Under the agreement, the company will retain its assets east of Oklahoma.
NextEra, which bills itself as the world’s largest generator of wind and solar energy, is the largest owner of wind generation in the Oklahoma, with 1.7 GW of operating capacity.
Plains & Eastern Clean Line Project Schematic | Clean Line Energy Partners
Clean Line spokesperson Sarah Bray told RTO Insider that while the Plains & Eastern’s goal is to “deliver low-cost renewable energy … to communities where there is substantial demand,” the market has evolved and eastern Oklahoma “now presents a strong delivery point for Plains & Eastern.” Alluding to NextEra’s financial strength and operational capabilities, Bray said, “We believe that they are the right owner to take the project over the finish line.”
Officials from the two companies have not disclosed the transaction’s terms, though it apparently includes the transfer of the “significant portion” of the Oklahoma right of way Clean Line has already acquired.
The Plains & Eastern is a proposed 720-mile HVDC transmission project that would move 4 GW of wind energy from the Oklahoma Panhandle through Arkansas to Memphis, Tenn., with a 500-MW drop-off in Arkansas. Clean Line has been involved in commercial negotiations with potential customers, both wind generators and load-serving entities seeking power.
Clean Line has said the project’s construction would begin once developers have contracts for 2 GW of capacity.
The project has been under development for eight years and has regulatory approvals from the Oklahoma Corporation Commission and the Tennessee Regulatory Authority. The U.S. Department of Energy issued a “record of decision” in 2016 after nearly six years of study and evaluation, saying it would participate in the project’s development under Section 1222 of the 2005 Energy Policy Act. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)
However, Clean Line has yet to receive a go-ahead from regulators in Arkansas, where the project has met stiff resistance from landowners and the state’s all-Republican congressional delegation. The lawmakers in March asked Energy Secretary Rick Perry to “preserve states’ rights” and reverse the department’s decision to partner on the project. They also are sponsoring a bill that that would prevent DOE from using eminent domain for Section 1222 transmission projects without the approval of both the governors and utility commissions of affected states.
But on Thursday, a federal judge in Arkansas rejected a lawsuit by two landowner groups challenging the department’s authority to partner with Clean Line. In his order, Judge D.P. Marshall Jr. of the U.S. District Court for the Eastern District of Arkansas overruled Downwind LLC and Golden Bridge LLC’s contention that the federal government exceeded its authority and denied landowners a chance to participate in the process.
“In the circumstances presented, Arkansas doesn’t get to decide where the transmission line is located,” Marshall wrote. “And the state doesn’t have a veto over whether this line gets built.”
Clean Line Executive Vice President Mario Hurtado applauded the decision.
“This critical decision confirms the strong legal basis for the Department of Energy’s decision to participate in the Plains & Eastern project, and keeps the door open for future infrastructure projects and the use of Section 1222,” he said.
WILMINGTON, Del. — PJM’s long-awaited capacity construct redesign will have to wait at least another month for endorsement by a key stakeholder committee, and its path to implementation includes additional hurdles after that.
Stakeholders at last week’s Markets and Reliability Committee meeting voted to defer an endorsement vote on the Independent Market Monitor’s MOPR-Ex proposal until the committee’s Jan. 21 meeting. PJM confirmed that even if it does receive endorsement, staff won’t recommend that the Board of Managers approve filing it for FERC approval; they will instead recommend their own proposal, despite not earning stakeholder endorsement.
John Horstmann of Dayton Power and Light made the deferral motion, which was seconded by Bob O’Connell of Panda Power Funds. Horstmann offered that a delay would give stakeholders a chance to review FERC’s response to the Department of Energy’s Notice of Proposed Rulemaking on price supports for coal and nuclear facilities, which is due by Jan. 11. It also provides additional time, without delaying a scheduled vote at the Jan. 25 Members Committee meeting, to review changes to the proposal requested by stakeholders and incorporated by the Monitor to secure endorsement. (See PJM Monitor Battles Exelon on MOPR-Ex Proposal.)
The proposal was developed by the Monitor as an extension of the minimum offer price rule (MOPR) in effect in PJM until FERC rejected it earlier this month on remand from a U.S. appeals court. (See On Remand, FERC Rejects PJM MOPR Compromise.) Its critics have been vocal, but it was the only proposal to receive endorsement at the Capacity Construct/Public Policy Senior Task Force (CCPPSTF), which spent the past year considering revisions to PJM’s capacity design. As the task force concluded earlier this year, many stakeholders preferred the status quo, but the RTO’s rules prevent that from being a voting option. Fearing that, without a clear stakeholder mandate, PJM would file its own two-stage repricing proposal, voters coalesced around the Monitor’s proposal, which is seen as having the least impact on the existing design.
But to secure enough votes for endorsement at the MRC, the Monitor revised the version approved by the CCPPSTF. That move has muddied the endorsement process and confused some stakeholders. It has also incensed other stakeholders, who argue that the Monitor is hypocritically picking winners and losers in drafting a rule ostensibly designed to avoid picking winners and losers.
Exelon’s Jason Barker questioned Monitor Joe Bowring on revisions to an exemption to the MOPR for resources developed under state renewable portfolio standards. Exelon, which offered its own two-stage repricing proposal in the CCPPSTF, contends that the Illinois zero-emissions credit (ZEC) program, which benefits several of its nuclear facilities, should be included in the exemption.
Bowring argued that he doesn’t “get to write the rules,” so his proposal must operate within the structures developed by states.
“We are taking those standards as they exist. … We deleted portions that would have resulted in most, if not all, RPS programs being not in compliance with this,” he said. “I know you would like to conflate ‘zero-emissions’ with ‘renewable,’ but they are not the same thing. This is the RPS, not the ZEC standard.”
In a subsequent email to RTO Insider, Bowring added that FERC has ceded regulatory authority over RPS programs and that the U.S. Supreme Court provided additional leeway for states in setting renewables standards in its decision rejecting Maryland’s plan to subsidize generation. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
As a result, there is only a limited ability for FERC-approved rules to affect the market participation of generation developed under RPS programs. The MOPR-Ex is intended to respect existing programs while introducing an element of competition, Bowring said.
“I can tell you most of the [state] advocate offices would not vote for the other version, but with this modification made … I think you gained the support of most of the advocate offices,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS). “Status quo is the preferred option, but this is the next best option because of the RPS exemption.”
Monitor’s Lead
The situation is further confused by PJM taking a back seat in developing necessary revisions to its governance documents.
“We are trying to facilitate at this point,” said PJM CFO Suzanne Daugherty.
Carl Johnson, who represents the PJM Public Power Coalition, took the RTO to task for what he saw as the “extraordinary” situation in which it would “not actively draft the Tariff language” for a proposal endorsed by a task force and said he plans to address it in the future.
Staff defended themselves, saying they “didn’t decline” to write the language but “engaged with the IMM staff and legal counsel” to determine that it might be better for the Monitor to write the first draft to ensure its intentions are accurately reflected.
“PJM is continuing to do its legal analysis, but PJM has been in close connection with the IMM,” PJM attorney Chris O’Hara said.
He noted that analysis might determine that applying the MOPR to any qualifying facility (QF) under the Public Utility Regulatory Policies Act isn’t defensible, “but that would entail a complete rewrite to what the stakeholder group did.”
PJM’s Stu Bresler announced that staff’s “recommendation to the board would be that we not file that proposal” because “it does not accommodate state public policy decisions” and raises discriminatory concerns.
Bowring responded that in the event of a “super-majority” stakeholder endorsement, “we would then consider making that filing ourselves, so one way or the other, we expect the proposal to get to the commission.”
Such a filing would be under Section 206 of the Federal Power Act, he confirmed.
Poulos asked whether PJM would recommend the status quo; Bresler clarified that is the pre-2012 MOPR rule, which was in place prior to the filing FERC recently rejected.
“No, that would not be our recommendation to the board,” he said, adding that PJM would recommend its repricing proposal to replace the existing MOPR rule.
MOPR Status
FERC’s rejection also muddies PJM’s capacity auction schedules. The RTO asked FERC for a waiver on its deadline for filing MOPR exemptions for its Feb. 26 Incremental Auction, PJM’s Jen Tribulski said. Generators will have until Jan. 12 to request exemptions for the third IA for delivery year 2018/19. Unit-specific exemptions for the Base Residual Auction for 2021/22 will be due on Jan. 10. All exemptions are based on the pre-2012 rule.
WILMINGTON, Del. — PJM’s initiative to internalize all generator payments moved forward at last week’s Markets and Reliability Committee meeting when stakeholders endorsed the RTO’s proposed problem statement and issue charge to examine price formation procedures for its energy markets.
Adam Keech, PJM’s executive director of market operations, faced scrutiny during an initial presentation Thursday, but returned later in the meeting with a significantly revised version that was endorsed by acclamation with 12 objections and 14 abstentions.
James Wilson, who consults with consumer advocates for several states within the RTO’s footprint, took issue with PJM defining the “price formation goal” as “maximizing the social welfare objective.”
“It sounds like the problem statement is trying to narrow what the stakeholder process can focus on,” he said.
Keech assured that wasn’t the intention. Caveats were added to the endorsed version to explain the objective and indicate that it was “in addition to” other goals.
He also said he was unsure if FERC’s order that day for the RTO to clarify or modify its fast-start resource pricing would be part of that evaluation. (See related story, FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Stakeholders sought assurances for a variety of tangential evaluations that Keech said PJM would undertake, though the endorsed proposal does consider as out of scope any discussions about impacts on and changes to capacity markets, among other things.
“I don’t think we have any intention of skipping out on the analysis here,” he said, but acknowledged “there may be other changes we’d like to make, but they’re not necessarily needed … for this group to move forward.”
Calling it a “dramatic change,” Independent Market Monitor Joe Bowring proposed an alternative analysis that called for individual examination of energy market components.
“If we’re going to do this review, let’s do it comprehensively so we come to the right conclusion,” he said.
“It’s a lot cleaner than PJM’s in terms of identifying the problem and what needs to be worked on,” Wilson said of Bowring’s proposal.
“I think there are some things in here that maybe give us a little bit of concern,” Keech said, but “the concept of including operator actions in LMP certainly [does] not.”
Because PJM’s proposal was endorsed, the Monitor’s was never considered for a vote.
Fuel-Switch Clarifications Endorsed
A debate that escalated at the Dec. 12 Operating Committee meeting was resolved after stakeholders endorsed clarifying text along with manual changes addressing gas pipeline contingency plans. The text box indicates that PJM “may need to direct” switching to an alternate pipeline or fuel on a pre-contingency basis and that it “will use best operator efforts” to move interruptible users off before firm service users. The revisions were endorsed by acclamation with seven objections and four abstentions.
Earlier in the meeting, stakeholders endorsed revisions to Manual 3: Transmission Operations and Manual 13: Emergency Operations, which include processes for addressing gas pipeline disruptions that affect generator reliability.
PJM’s Dave Souder announced that his staff are developing a problem statement and issue charge on the topic to be unveiled at the Jan. 10 Market Implementation Committee meeting.
Dave Pratzon of GT Power Group expressed concern that PJM “doesn’t have authority to tell a generator which” fuel source to use.
“This is a major expansion of PJM’s authority,” he said. “We need to think about it in terms of Tariff changes.”
O’Connell, who proposed the clarifying text, acknowledged the concern but said it will need to be addressed later.
“There needs to be some kind of bright line. How far inside the fence can PJM go?” he said. “We were in general agreement that trying to address those issues was more than we could bite off in the time frame we had.”
Incremental Auction Revisions Endorsed
Despite some stakeholder frustrations, proposed Incremental Auction (IA) revisions received endorsement with a sector-weighted vote of 3.55, surpassing the 3.33 threshold. They next go for endorsement at the Jan. 25 Members Committee.
The revisions — which would change in what IAs and for how much PJM can offer excess capacity commitments — received criticism at the Dec. 7 MRC for being presented as if the Incremental Auction Senior Task Force (IASTF) had endorsed them. In fact, the task force vote fell seven votes short of endorsement. Exelon’s Sharon Midgley moved for the vote.
Bowring criticized the proposal for making it “too easy to get out of your capacity commitment” and voiced support for PJM’s original proposal. The endorsed version was a variation of that proposal.
Marji Philips with Direct Energy reiterated previous criticism that “the process was subverted into a lot of other interests” away from the company’s original goal when it proposed initiating the IASTF.
“In this case, we believe this is actually worse than the status quo at this point,” she said. “This addresses a lot of other problems, but not the ones that it was initially designed to.”
“We support this package as a compromise,” said Susan Bruce, who represents the PJM Industrial Customers Coalition. “It is not perfect, but in this case, we do not want perfect to be the enemy of good enough. … We look at this as PJM taking on a commitment on behalf of load.”
“It’s not a benefit for load. It’s a benefit for suppliers because those suppliers with excess will be able to undercut” PJM’s mandated BRA price offer, CPower’s Bruce Campbell said. He offered to support anyone who motioned Package D, a competing proposal, but received no takers.
Customers, Competitors Battle TOs on Project Cost Caps
The fight over whether PJM should consider cost cap guarantees on more than construction costs in transmission-development proposals rages on.
PJM’s Sue Glatz presented proposed changes to the Operating Agreement that would include caps on construction costs in the RTO’s proposal evaluation, but LS Power’s Sharon Segner presented a counterargument that cost cap considerations should extend to factors such as return on equity and annual revenue requirements.
The proposal is “very divergent from other FERC-approved tariffs” and “doesn’t actually answer the question about how PJM will consider cost estimates versus cost-containment provisions,” Segner said.
American Municipal Power’s Steve Lieberman “strongly” supported Segner’s position, and Bowring also endorsed it.
Representatives of several transmission owners supported PJM’s proposal. Alex Stern of Public Service Electric and Gas and Tonja Wicks of Duquesne Light acknowledged they were initially against adding cost cap provisions but eventually changed tack.
“It was a balanced negotiation, so we relented to have cost cap language” included as long as it remained restricted to construction costs, Wicks said.
PJM’s proposal will be up for endorsement at the January meeting, and Segner will need to make a separate proposal if desired.
Acclamation Votes
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 1: Control Center and Data Exchange Requirements. Revisions developed to update NERC references and procedures related to outages and system-restoration planning. PJM members will be required to send the RTO data on transmission megawatt and MVAR flows and bus voltages at greater than or equal to 100 kV, down from 345 kV.
Manual 10: Pre-Scheduling Operations. Revisions developed to comply with NERC standards as part of a periodic review of the manual. Generators will be required to notify PJM of operating conditions that could result in a single contingency causing an outage of multiple generators.
Manual 14D: Generator Operational Requirements. Revisions developed as part of a periodic review. Generators will need to be modeled in eDART consistent with the PJM energy management system model.
Revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. Members endorsed the auction surplus proposal at the Dec. 13 MIC meeting, which allocates all surplus to auction revenue rights holders. The changes will be implemented for the 2018/19 planning period. (See related story, “FTR Changes in the Works,” PJM MIC briefs: Dec. 13, 2017.)
Members will be asked to endorse changes to the procedures for the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
The Arkansas Public Service Commission last week asked the D.C. Circuit Court of Appeals to overturn a FERC decision that rejected the state regulator’s request to exclude Entergy Arkansas from making backdated “bandwidth” payments to its affiliate companies.
The PSC made oral arguments before a three-judge panel on Dec. 15 in a bid to protect the utility’s Arkansas customers from bearing the costs of the payments (16-1193). A decision from the court is likely months away.
Under the Entergy System Agreement, which expired in 2016, low-cost Entergy operating companies made annual payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the Entergy system average.
The PSC is appealing FERC’s 2015 rejection of a request to shield Entergy Arkansas Inc. (EAI) from making $11 million in retroactive 2005 bandwidth payments and related interest assessed after EAI’s withdrawal from the system agreement in 2013. The state regulator contends the system agreement made no provision for assessing payments after withdrawal, which meant the utility had no continuing obligation to its sister companies (EL01-88-013).
FERC rejected the Arkansas commission’s argument that EAI’s 2005 bandwidth payments — $167.3 million for a seven-month period in 2005, plus $56.5 million in compounded interest — amounted to “exit fees,” saying the payments were “obligations specifically required by the system agreement and are for a period when Entergy Arkansas was subject to the system agreement.” (See FERC Sets Hearings for Entergy’s Cost Allocations.)
FERC also ruled that nothing in a previous order rejecting an Entergy compliance filing related to the agreement indicated that EAI would be excluded from further compliance filings.
Dennis Lane, lead counsel for the PSC, told the court the commission was not challenging an earlier figure of $156 million in 2005 payments, which he said EAI had already paid.
“We’re not asking [FERC] or the court to say we didn’t owe any of the bandwidth payment,” Lane said. “We’re not asking for [the $156 million] to come back. We’re just asking for the $11 million, plus any interest related to that, because that amount was determined after the system agreement was terminated.”
PSC Executive Director John Bethel told RTO Insider that if his agency were to prevail, “the preferential effect would bar payment of the payments and interest due after 2013.”
Lane told the court EAI is heavily reliant on coal, while its sister companies have a lot more natural gas generation.
“During the time period when the bandwidth got out of whack, natural gas prices were very high,” Lane said. “The bandwidth was a rough way to get those production costs back in.”
| Entergy
FERC framed the issue in a brief as whether “assuming jurisdiction, the commission reasonably determined that Entergy Arkansas remains obligated to make bandwidth remedy payments for a seven-month period in 2005,” notwithstanding its withdrawal from the system agreement.
The commission argued the time was not ripe for immediate judicial review. “The orders challenged here resolved only Entergy Arkansas’s liability for the 2005 bandwidth payments; they do not address the amount of that liability,” FERC said. It pointed out the liable amounts are the subject of “ongoing, vigorous litigation” before the commission.
“What’s going on at the commission is disputes over the actual methodology and the dollar figures,” said FERC counsel Carol Banta.
Entergy’s bandwidth payments have long been a source of contention for the five regulatory agencies that have jurisdiction over the corporation’s six operating companies. The system agreement and all of its service schedules ended in August 2016, with all of the operating companies having joined MISO.
Judge Patricia Millett at one point expressed surprise that Entergy was not represented in the courtroom.
“I’m kind of shocked they don’t seem to care at all,” she said. “They’re paying these millions and millions and millions of dollars.”
Banta said she could not speak for Entergy but responded with her understanding of the bandwidth agreement.
“Because they’re operating affiliates owned by a holding company, in most instances, as far as Entergy is concerned, it’s a zero-sum game. It’s one affiliate paying another affiliate,” Banta said.
CAISO’s Department of Market Monitoring on Wednesday discussed the ISO’s third-quarter market results with participants, but it referred a stakeholder query about a key development in the market to the ISO itself.
“It was an eventful quarter,” Lead Market Monitoring Analyst Amelia Blanke said during her presentation in the conference call.
The department noted that day-ahead system marginal prices hit $770/MWh on Sept. 1, when CAISO’s load came within 150 MW of its all-time system peak of 50,270 MW, set in July 2006. The Monitor said high temperatures and demand, along with the evening ramp-down of solar production caused the price surge. (See Tight Supplies, Solar Ramps Drive CAISO Summer Spikes.)
| CAISO Department of Market Monitoring
Powerex analyst Mike Benn pointed out that “load biasing” in CAISO has increased dramatically over the past year. Load biasing seemed to be too large, especially in the morning and evening hours when the system is ramping, Benn said, questioning whether the procedure was being used to correct inherent market flaws rather than adjust short-term deviations.
Load bias, also called “imbalance conformance,” describes the last-minute adjustments an operator makes to the load forecast ahead of a market run to account for potential inaccuracies and inconsistencies in the forecast. There are multiple reasons for adjusting loads, including managing load and generation deviations, automatically correcting time errors, variations in schedule interchange, reliability events and software issues.
“That is a valid question,” Director of Market Monitoring Eric Hildebrandt told Benn. “I think that should be passed on to the ISO. That is exactly why we provide this kind of information for stakeholders like yourself.” He added that CAISO “addressed the issue in various forums.”
CAISO indicated that third-quarter load adjustments in the hour-ahead and 15-minute markets climbed from about 600 MW last year to more than 1,100 MW this year.
In an attempt to address the issue, the ISO on Nov. 29 issued a straw proposal for “imbalance conformance enhancements” to clarify its authority to use the tool and implement process changes. The ISO expects to post a final draft proposal Jan. 24 and seek approval from the ISO Board of Governors in March. The DMM has voiced its support for the proposal.
The department said that most of the high prices during the quarter occurred as a result of high bids clearing the market, with extremely high bids in many instances clearing after use of the “load bias limiter.” Introduced in 2012, the limiter adjusts load in the market model to better reflect actual conditions during the market’s pricing run so that power balance is no longer being violated, reducing the potential for a “penalty parameter” to drive up the clearing price.
The DMM also said total payments for the ISO’s flexible ramping product were about $5.1 million in the third quarter, down from $7.5 million in the previous quarter. About 55% of payments during the quarter were made to generators in the ISO rather than external units.
FERC on Thursday ordered NERC to lower the threshold for mandatory reporting of cyber incidents, saying that the lack of any reports in 2015 and 2016 suggests gaps in the grid’s protections (RM18-2, AD17-9).
NERC’s Critical Infrastructure Protection (CIP) reliability standard only requires reporting of incidents if they have “compromised or disrupted one or more reliability tasks” (CIP-008-5, Cyber Security – Incident Reporting and Response Planning).
“Therefore, in order for a cyber-related event to be considered reportable under the existing CIP reliability standards, it must compromise or disrupt a core activity (e.g., a reliability task) of a responsible entity that is intended to maintain bulk electric system [BES] reliability,” the commission said. “Under these definitions, unsuccessful attempts to compromise or disrupt a responsible entity’s core activities are not subject to the current reporting requirements.”
In a Notice of Proposed Rulemaking, the commission said the standard should be revised to require reporting of incidents “that compromise, or attempt to compromise, a responsible entity’s Electronic Security Perimeter (ESP) or associated Electronic Access Control or Monitoring Systems (EACMS).”
FERC cited NERC’s 2017 State of Reliability report, which noted that “while there were no reportable cybersecurity incidents during 2016 and therefore none that caused a loss of load, this does not necessarily suggest that the risk of a cybersecurity incident is low.”
The current “mandatory reporting process does not create an accurate picture of cybersecurity risk since most of the cyber threats detected by the electricity industry manifest themselves in … email, websites, smart phone applications … rather than the control system environment where impacts could cause loss of load and result in a mandatory report,” NERC said.
Control room | Schneider Electric
The organization recommended redefining reportable incidents “to be more granular and include zero-consequence incidents that might be precursors to something more serious.”
NERC noted that the 2016 annual summary of the Department of Energy’s electric disturbance reporting form OE-417 included two suspected and two actual cyberattacks. In addition, the Department of Homeland Security Industrial Control Systems Cyber Emergency Response Team (ICS-CERT) responded in 2016 to 59 cybersecurity incidents within the energy sector, which includes the electric subsector.
“Based on this comparison, the current reporting threshold in reliability standard CIP-008-5 may not reflect the true scope and scale of cyber-related threats facing responsible entities,” FERC said.
Deadlines, Data Requirements
FERC said NERC’s revision should set a deadline for filing a report following a cyberattack attempt and specify the information required in the reports to “improve the quality of reporting and allow for ease of comparison by ensuring that each report includes specified fields of information.”
Schneider Electric acknowledged this month that its Triconex control system, which is used by power plants worldwide, was the target of an attack by nation-state hackers | Schneider Electric
Current rules require responsible entities to provide the Electricity Information Sharing and Analysis Center (E-ISAC) with initial notification within an hour of determining a “reportable” incident, which may be made by phone call, email or web-based notice. The rules do not specify what should be included in the report, nor do they set a deadline for completing the full report.
FERC said the reporting timeline “should reflect the actual or potential threat to reliability, with more serious incidents reported in a more timely fashion.”
The commission suggested requiring information on three “attributes,” as used in DHS’ multisector reporting and summarized in its annual report: the functional impact that the incident achieved or attempted to achieve; the attack method or “vector” (such as a phishing attack for user credentials or a virus designed to exploit a known vulnerability); and the level of intrusion that was achieved or attempted.
In addition to being filed with the E-ISAC, as is now required, the incident reports also would be sent to ICS-CERT. NERC also must file an annual — and public — summary of the reports with FERC with identifying details anonymized. “We believe that the ICS-CERT annual report, which includes pie charts reflecting the energy sector’s cybersecurity incidents by level of intrusion, threat vector and functional impact, would be a reasonable model for what NERC reports to the commission,” the NOPR said.
Comments Sought
Comments on the NOPR will be due 60 days after publication in the Federal Register. The commission specifically sought comment on whether to exclude EACMS from the new standard and establish the ESP as the minimum reporting threshold instead.
NERC defines an ESP as the “logical border surrounding a network to which BES cyber systems are connected using a routable protocol.” EACMS include firewalls, authentication servers, security event monitoring systems, intrusion detection systems and alerting systems.
“Therefore, EACMS control electronic access into the ESP and play a significant role in the protection of high- and medium-impact BES cyber systems. Once an EACMS is compromised, an attacker could more easily enter the ESP and effectively control the BES cyber system or protected cyber asset,” FERC said.
“The EACMS … are the systems that control access to the ESP. … You could consider it being the doorway,” Kevin Ryan, an attorney in the General Counsel’s office, explained during a presentation at the commission’s open meeting Thursday. “This … limits the proposal to high- and medium-impact BES cyber systems so we can see what happens in the future. But we’re not touching on low-[impact systems] at this point.”
The commission also asked for comment on alternatives to modifying the mandatory reporting requirements, such as whether a request for data or information pursuant to Section 1600 of the NERC Rules of Procedure “would effectively address the reporting gap … and satisfy the goals of the proposed directive.”
Safety ‘Pyramid’
The NOPR was approved unanimously.
“One thing that has been observed and studied across many industries — not just electricity but in aviation, medicine and other industries — is a well-established … statistical correlation between minor issues or near misses that are far more frequent and … rare major events,” said Commissioner Cheryl LaFleur, referring to what is known as “the safety pyramid.”
“We need to learn from the things that don’t happen but that could have happened in order to prevent the big thing that you’re afraid of happening,” she continued. “I think it’s important that we identify and track attempted incursions into the grid’s cyber defenses to help us learn from them, study the trends [and] see what we might need to do to standards.”
Commissioner Richard Glick, attending his first meeting, said, “We’ve been pretty lucky in the United States so far — at least on the electric side — in not having any significant consequences from cyber efforts.
“But we’ve seen it around the world already,” he added, noting the 2015 and 2016 attacks in Ukraine and Schneider Electric’s Dec. 14 disclosure that one of its control systems — used by power plants worldwide — was the target of an attack.
Malware
The attack, believed to be the work of nation-state hackers, targeted Schneider’s Triconex industrial safety technology, which is used by nuclear generators and oil and gas plants.
Triconex brochure cover | Schneider Electric
Investigators said the hackers used malware to take remote control of a workstation running Triconex’s safety shutdown system, then sought to reprogram controllers used to identify safety issues. One investigator called it a “watershed” attack that will likely be repeated.
The malware, which security firm FireEye named Triton, is the third type of computer virus known to be able to disrupt industrial processes. It was preceded by Stuxnet, which the U.S. and Israel allegedly used to attack Iran’s nuclear weapons program, and CrashOverride (also known as Industroyer), believed to have been used in the December 2016 attack in Ukraine. (See Experts ID New Cyber Threat to SCADA Systems.)
In proposing tighter disclosure rules, FERC also rejected The Foundation for Resilient Societies’ January 2017 petition asking the commission to set new standards for malware detection, mitigation and reporting (AD17-9).
The commission said new standards were not necessary based on existing reliability standards and ongoing efforts.
“For example, provisions of currently effective reliability standards, including CIP-005-5 and CIP-007-6, address malware detection and mitigation. Ongoing efforts described by NERC and other commenters, such as the development of a supply chain risk management standard, should also address malware concerns,” FERC said.
Georgia regulators Thursday voted to allow Georgia Power and its partners to complete the two nuclear reactors under construction at the Vogtle Electric Generating Plant near Waynesboro.
The state’s Public Service Commission unanimously approved a motion by Commissioner Tim Echols finding that the reactors, which would be the plant’s third and fourth generating units, should be completed.
The shield building wall of Plant Vogtle’s Unit 3 in November 2017 | Georgia Power
The new units, like the rest of the plant, are jointly owned by Georgia Power, Oglethorpe Power, the Municipal Electric Authority of Georgia and Dalton Utilities. In July, they became the only nuclear generating units still being built in the U.S. when SCANA and Santee Cooper canceled the expansion of the V.C. Summer plant in South Carolina after cost overruns related to both plants forced Westinghouse Electric, the prime contractor, to declare bankruptcy in March.
Chairman, President and CEO Paul Bowers | Georgia Power
In a statement, Georgia Power CEO Paul Bowers praised the commission’s decision, calling it “important for Georgia’s energy future and the United States.”
Echols’ motion was based on the assumption that Congress will extend nuclear production tax credits that would benefit the project. If it does not, the motion says, “the commission may reconsider the decision to go forward.”
The motion also reduces the approved revised capital cost forecast for construction of the units to $7.3 billion from $8.9 billion to reflect the parent guarantee payments that Toshiba, which owns Westinghouse, has made to Vogtle’s co-owners. Georgia Power, a subsidiary of Southern Co., said the payments, which totaled $3.68 billion, will reduce the cost of constructing the new units by $1.7 billion.
The motion does not impose a cost cap on the construction, but it also doesn’t guarantee recovery of all costs. It also reduces the return on equity used to calculate the costs Georgia Power and its partners are allowed to recover if Unit 3 is not operational by June 1, 2021, and on Unit 4 if it isn’t running by June 1, 2022. Georgia Power expects Unit 3 to be operational by November 2021 and Unit 4 by November 2022.
By Michael Kuser, Tom Kleckner, Rory D. Sweeney and Rich Heidorn Jr.
FERC dropped its plan for a one-size-fits-all rule on fast-start pricing Thursday, instead issuing individual orders requiring PJM, SPP and NYISO to change their tariffs.
In December 2016, the commission issued a Notice of Proposed Rulemaking that would have set generic rules to ensure RTOs and ISOs incorporate fast-start resources into energy and ancillary services pricing. (See FERC: Let Fast-Start Resources Set Prices.)
But the commission said Thursday it was withdrawing the NOPR, persuaded by commenters who suggested the changes would be burdensome and that it would be better to allow RTOs to implement pricing practices tailored to their regions and generator types.
“Having considered these comments, we are persuaded to not require a uniform set of fast-start pricing requirements that would apply to all RTOs/ISOs. Instead, we will pursue the goals of the NOPR through Section 206 actions involving NYISO, PJM and SPP focusing on specific concerns with each RTO’s/ISO’s implementation of fast-start pricing consistent with the concerns outlined in the NOPR,” the commission said (RM17-3).
Cane Run Unit 7, a fast-start 640-MW combined cycle plant went into service for Louisville Gas and Electric and Kentucky Utilities in 2015 | LGE/KUje
FERC said it had preliminarily concluded that the three regions did not adequately allow fast-start resources to set LMPs, resulting in prices that were not just and reasonable and that muted investment signals.
The commission spelled out about a half dozen tariff changes each that it seeks from PJM (EL18-34) and SPP (EL18-35), and two from NYISO (EL18-33).
Commissioner Robert Powelson called the orders an “appropriate balance.”
Commissioner Cheryl LaFleur said that NYISO “has been an early leader in fast-start pricing … but we still see the possibility through targeted reform to improve certain aspects of their Tariff.”
She added that the commission was not ignoring CAISO, MISO and ISO-NE “just because we were feeling charitable around the holidays.”
“MISO and ISO-NE have largely already implemented the best practices that are outlined in the” Section 206 orders, she said. “With respect to the California ISO, I at least, was persuaded … that this line of reform would provide limited benefit for them relative to their other priorities that are going on right now.”
The commission called on all three regions to relax fast-start resources’ economic minimum operating limits by up to 100% so that they are considered dispatchable from zero to their economic maximum operating limit for setting LMPs.
It also said the three RTOs must modify their pricing logic: PJM and SPP to allow the commitment costs of fast-start resources (start-up and no-load costs) to be reflected in prices, and NYISO to make changes capturing units’ start-up costs.
It also said PJM and SPP needed to spell out their rules and practices regarding fast-start pricing in their tariffs, and include in their definitions of quick-start resources a requirement that those resources have a minimum run time of one hour or less.
The commission ordered the regions and other interested parties to file initial briefs within 45 days after the notice of the Section 206 proceedings are published in the Federal Register. Reply briefs are due within 30 days after initial briefs.
The commission took issue with the way the three regions relax fast-start resources’ economic minimum operating limits to allow them to set prices, as detailed below.
PJM Order
FERC said PJM has special pricing rules only for block-loaded units — resources whose economic minimum operating limits equal their economic maximums, meaning they have no dispatchable range. The RTO seeks to let them set price by relaxing the economic minimum operating limit of online block-loaded resources by up to 10%.
The commission said PJM’s practices may not be just and reasonable because they don’t allow block-loaded resources’ economic minimum to be relaxed by more than 10% and because they limit the relaxation to only block-loaded resources.
Jenbacher2 Reciprocating Engine | GE Power Generation
“We remain concerned that without allowing relaxation by up to 100%, prices will sometimes be set by the offers from lower-cost flexible units that are dispatched down in order to accommodate the output of fast-start resources,” FERC said. “As a result, PJM’s practices may not reflect the marginal cost of serving load when a fast-start resource is needed to quickly respond to unforeseen system needs, which may result in inaccurate price signals.”
The commission also found fault with PJM’s dispatch practices.
“An efficient dispatch can only be reliably determined by modeling the actual system costs and actual system constraints within a market run that minimizes production costs. That is, fast-start pricing logic would ideally not change the dispatch of resources away from the cost-minimizing dispatch but would only alter the manner by which prices are established. PJM does not appear to develop real-time dispatch instructions in this way.”
Because PJM’s practice does not respect the “power balance constraint,” FERC said, the RTO “unnecessarily increases the cost of serving load and puts stress on the frequency regulation resources that are necessary for maintaining system reliability.”
In addition, it said PJM should:
Include in its definition of fast-start resources a requirement that those resources be able to start up within one hour or less (including notification time);
Apply the relaxation of a resource’s economic minimum operating limit to all fast-start resources, not just block-loaded units; and
Dispatch fast-start resources “consistent with minimizing production costs, subject to appropriate operational and reliability constraints.”
PJM stakeholders briefly discussed the order at Thursday’s Markets and Reliability Committee meeting. When members considered a proposal from the RTO to evaluate its energy market price formation procedures, American Electric Power’s Brock Ondayko asked if the fast-start order would be part of that evaluation.
Adam Keech, PJM’s executive director of market operations, noted the order’s short window for reply comments and said, “Certainly from our perspective, we would prefer discussion [on that issue] earlier [rather] than later.”
He said he had not been able to digest the order and had “no idea” if any of the procedures agreed upon for the evaluation are “at odds” with it.
Keech urged stakeholders to endorse the evaluation “to get the discussion started.” The proposal received significant revisions but was eventually endorsed.
SPP Order
The commission found SPP’s approach to pricing quick-start resources to be “inconsistent with minimizing production costs.”
FERC said SPP’s real-time balancing market practices for quick-start resources begins with a “screening run” that identifies a set of resources to be excluded from the binding solution. The screening run identifies an economic dispatch solution under the assumption that quick-start resources may be dispatched below their economic minimum operating limit, the commission said.
Any resources that are dispatched below their economic minimum operating limit are treated as “off” and excluded from consideration in the binding pricing and scheduling run. “This means quick-start resources are only considered for dispatch in the pricing and scheduling run if they are dispatched to at least their economic minimum operating limit in the screening run,” FERC said.
A second optimization pass (pricing and scheduling run) is used to determine both the binding resource dispatch levels and energy and operating reserve prices.
The commission noted two other rules that distinguish SPP’s treatment of quick-start resources from other RTOs’ fast-start pricing practices:
It provides an option for quick-start resources to submit an enhanced energy offer that includes commitment costs (start-up and no-load costs) as part of the incremental cost curve to be used both in the screening run and in the real-time balancing market’s pricing and scheduling run.
SPP does not have any minimum run time requirement for eligibility as a quick-start resource.
The commissioners said SPP’s practices are not in its Tariff, pointing to the Federal Power Act’s requirement that all practices significantly affecting rates, terms and conditions of service be on file with FERC and included in a commission-accepted Tariff.
“For example, the Tariff does not describe the process by which quick-start resources are screened out within the screening run from participating in dispatch, which appears to have a material effect on electric power rates,” the commission said. “Therefore, our preliminary review indicates that SPP’s practices related to quick-start pricing significantly affect the rates, terms and conditions of service and as such, must be filed with the commission as part of the SPP Tariff.”
The commission said SPP should:
Commit and dispatch quick-start resources in real time consistent with minimizing production costs, subject to operational and reliability constraints;
Remove the option for enhanced energy offers for quick-start resources that incorporate commitment costs in the incremental energy curve; and
Consider both registered and unregistered quick-start resources in quick-start pricing to ensure prices reflect the cost of the marginal resource.
NYISO Order
NYISO currently applies fast-start pricing logic to online and offline fixed block units that can start in 10 minutes. The ISO defines a fixed block unit as one that, “due to operational characteristics, can only be dispatched in one of two states: either turned completely off, or turned on and run at a fixed capacity level.”
The commission noted that in the first pass of the optimization process, NYISO establishes a resource’s physical base points (i.e., real-time energy schedules). In the second pass, also called the pricing run, the ISO relaxes the economic minimum operating limit of fixed block units in order to allow them to be eligible to set prices. When pricing offline fixed block units, the price can also include a unit’s start-up costs.
“However, NYISO neither relaxes the economic minimum operating limits of dispatchable resources (i.e., resources that are not block-loaded), nor does it include the start-up costs of these or any online resources for the purpose of setting prices,” the commission said.
FERC preliminarily found that NYISO’s practice of “differentiating between dispatchable fast-start resources and fixed block units appears to be arbitrary and may result in prices that do not reflect the marginal cost of serving load. NYISO’s practice of allowing only fixed block units to participate in fast-start pricing may also create incentives favoring development of block-loaded resources over dispatchable resources. Furthermore, the practice may create incentives for dispatchable resources to withhold their flexibility from the market.”
While finding that such practices may be unjust and unreasonable, the commission noted that there are methods to address concerns about the “potential consequences of relaxing the economic minimum operating limit of fast-start resources” by up to 100%.
WASHINGTON — FERC Chairman Kevin McIntyre closed out his first open meeting Thursday by announcing that the commission would re-examine its 1999 policy statement on certifying new interstate natural gas pipeline facilities.
McIntyre said the effort is in its very early stages and that the scope and format of the review are still being considered.
“Obviously, [since] 1999 … much has changed in the industry,” McIntyre said. “So, without prejudging anything, and without intending to forecast a policy direction … we believe it’s a matter of good governance to take a fresh look at this area, and to give all stakeholders and the public an opportunity to weigh in.”
The policy statement details how the commission grants developers of proposed pipelines a certificate of public convenience and necessity — allowing them to exercise eminent domain — under the Natural Gas Act of 1938. It came at a time when the gas industry, much like the electricity industry, was being restructured, and demand in the northeastern U.S. was expected to increase — somewhat of an understatement in hindsight.
“At a time when the commission is urged to authorize new pipeline capacity to meet an anticipated increase in the demand for natural gas, the commission is also urged to act with caution to avoid unnecessary rights of way and the potential for overbuilding with the consequent effects on existing pipelines and their captive customers,” the statement concludes. “This policy statement is intended to provide more certainty as to how the commission will analyze certificate applications to balance these concerns.”
Since the statement was issued, FERC has granted a certificate to virtually every proposed pipeline submitted to it; Commissioner Richard Glick noted that the amount of new pipeline capacity approved by the commission has grown by more than 500% in the past six years alone.
This has raised the ire of environmentalists and landowners, who charge that FERC “rubber-stamps” pipelines and point to the number of former staffers who have gone on to work in the natural gas industry. Protesters interrupting commission meetings have become a regular occurrence over the past two years. (There were, ironically, no interruptions at Thursday’s meeting.) Members of Congress have also written FERC on behalf of constituents to complain about inadequate public notice for commission hearings on pipelines in their jurisdictions, or a lack of time to accommodate all who wanted to speak.
But there is also a growing concern in the energy industry about the potential for overbuilding pipeline infrastructure as renewable, distributed and storage resources are becoming increasingly relied upon for electricity generation. Just before his resignation in February, former Chair Norman Bay called on the commission to analyze its reliance on signed agreements with shippers to determine the need for pipelines. (See Bay Calls for Review of Marcellus, Utica Shale Development.)
“Overbuilding may subject ratepayers to increased costs of shipping gas on legacy systems,” Bay said. “If a new pipeline takes customers from a legacy system, the remaining captive customers on the system may pay higher rates.”
McIntyre said he did not share any of those concerns, instead citing the policy’s statement age as a factor for his decision to examine it. “The fact of my having proposed this should not be read as … a complaint about our current policy. It is not,” he told reporters after the meeting. “1999 was quite a while ago, particularly in the natural gas pipeline industry. So much has changed” across all energy industries, “but it would be hard to point to an area that has changed more than natural gas.”
His fellow commissioners — it was the first time FERC has had five commissioners in two years — all expressed support for the review.
Commissioner Cheryl LaFleur said she would like the review to focus on how FERC determines economic needs for proposed pipelines, as well as the environmental impacts.
“The policy statement … actually holds up quite well. It outlines a very broad range of factors we could look at to review need. Over time our practice has coalesced around a reliance on precedent agreements as a determiner of market need. And as I recently stated in dissents in Atlantic Coast (CP15-554, et al.) and Mountain Valley (CP16-10, et al.) pipelines, I think our review of pipeline applications would benefit from a broader consideration of need,” she said.
“Secondly, I think it’s appropriate for us to consider how we do our environmental reviews … [to consider] the downstream impacts on greenhouse gases or other downstream impacts,” she continued. “I was already looking forward to 2018 with all you fine folks, and I now am even more.”
In August, the D.C. Circuit Court of Appeals ruled that FERC’s environmental impact statement (EIS) for the Southeast Market Pipelines Project should have included “reasonable forecasting” of the project’s impact on GHG emissions.
As interim chairman, Commissioner Neil Chatterjee said in October that he didn’t expect the ruling to have a “significant” impact on the agency’s pipeline licensing. (See FERC Chair: Court Ruling Won’t Change Pipeline Reviews.)
“Although I am supportive of our current policies, I wholeheartedly agree with the chairman that it’s important the commission takes a look at how it exercises its statutory obligations,” Chatterjee said Thursday. He emphasized that he wanted input from all stakeholders. “I particularly want to speak to those who feel frustrated that their voices are not heard throughout this process. I want you to know that I empathize with that frustration.”
Commissioner Robert Powelson agreed with Chatterjee’s sentiments, but he also defended FERC’s record. “We don’t rubber-stamp interstate pipelines here,” he said. “People should have peace of mind that, one, we don’t site pipelines on speculation here at the FERC. There is due diligence. … This is about giving everybody an opportunity to be heard.”
“It’s not just that we’re approving a lot of pipeline capacity; that may be OK,” Glick said. “It’s that these pipelines are increasingly traversing populated areas, and thus have potentially greater impacts on individuals and communities, in addition to their impacts on the environment.”
McIntyre told reporters that any outcome of the review would affect the pipelines currently before the commission.
“I am approaching this topic with an open mind and want the staff and the commission to take a fresh look at all aspects of the issue,” he said.
MISO has released a draft guide detailing how it estimates costs for cost-allocated transmission projects after state officials and stakeholders called for more transparency around the process.
The guide is intended to cover any market efficiency or multi-value projects that might be approved under MISO’s 2018 Transmission Expansion Plan. State regulators in the Organization of MISO States earlier this year asked the RTO to provide more visibility on project costs. (See Commissioners Ask MISO to Share Tx Project Cost Data.)
The RTO is asking stakeholders to review the guide and suggest revisions by the end of January. After being vetted by stakeholders, the guide will become effective in March, MISO design engineer Alex Monn said during a Dec. 18 Planning Subcommittee conference call.
MISO accepts stakeholder assessments as a starting point for estimating the costs for market efficiency and multi-value projects but develops final planning-level cost projections based on its own project assumptions.
The RTO said its total estimates include a construction cost estimate, a 20% construction cost contingency fund and a 7.5% allowance for funds used during construction. MISO initially uses a straight line plus 30% calculation to estimate transmission line length, then updates the measurement using the proxy route provided by transmission developers. For substation upgrades and new builds, it similarly uses general estimates based on the area, then updates cost needs once developers submit more details.
For the construction estimate, MISO factors in land and right-of-way costs in addition to the costs of potential substations, transmission structures, conductor, accessories like shield wire and professional services such as the engineering and testing needed to assemble the line. Right-of-way acquisition terrain and grading estimates are based on the length of the new transmission line and the topography along the route. MISO also said it has the right to assume other project-specific mitigation costs “when necessary.”
Before MTEP 15, MISO relied on transmission owners to provide cost estimates for projects that fell within their service territory, but it began developing its own cost estimates after FERC issued Order 1000. The estimates are used to assess the worthiness of a project: MISO’s Tariff requires a benefit-to-cost ratio of at least 1:1 for multi-value projects and 1.25:1 for market efficiency projects.
2018 Construction Assumptions
The guidelines stipulate that MISO will assume the need for seven tangent structures per mile on 69-kV single circuit line (nine per mile for a double circuit) to three tangent structures per mile on a 500-kV single circuit line (five per mile for a double circuit). For all line ratings, MISO assumes developers use a steel pole structure type, except for 500-kV lines, which will have steel lattice towers.
The RTO also assumes a right-of-way width of anywhere from 80 feet for 69-kV and 115-kV lines, and up to 200 feet for 500-kV lines. For substations, MISO will assume 1.5 acres are needed for a 69-kV rated substation, 1.75 acres for a 115-kV substation, 2 acres for a 138-kV substation, 2.5 acres for a 161-kV substation, 4 acres for a 230-kV substation, 8 acres for a 345-kV substation and 20 acres for a 500-kV substation. Land costs for the 2018 planning year will vary by state, with the cheapest land in Montana for $677/acre and the most expensive in Illinois at $3,583/acre.
To mobilize and then break camp for all equipment and people needed for construction of a project, MISO will assume costs ranging from $51,250 for a 69-kV project to $153,750 for a 500-kV line project, up to $262,660 for certain substation work.
For terrain-clearing costs, MISO will assume $260/acre for level ground with light vegetation, $4,920/acre for forested land and $57,500/acre for wetland matting, as well as an additional $46,125/acre to secure environmental mitigation credits for wetlands. MISO will also factor in a $6,400/acre cost to grade any mountainous terrain a transmission line might traverse.
As part of the guide, MISO is also releasing state-by-state exploratory construction estimates, which represent high-level cost estimates for potential projects that still lack specifics.
The exploratory cost estimates range anywhere from $1.2 million/mile for a single-circuit 69-kV line in Iowa, the Dakotas and Montana, to $6 million/mile for a double-circuit 500-kV line in Arkansas, Louisiana and Mississippi.
