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.
A MISO task team is slated for retirement after successfully developing several changes to the RTO’s competitive transmission process that were approved by FERC.
The Planning Advisory Committee on Tuesday passed a motion recommending that the Steering Committee approve the immediate retirement of the Competitive Transmission Task Team. Six sectors voted in favor with three abstaining.
Brian Pedersen, MISO senior manager of competitive transmission administration, said the task team has completed its work to improve the selection process behind competitive transmission projects. The team was created last December days after the conclusion of the RTO’s first competitive process, for the Duff-Coleman 345-kV transmission project in southern Indiana and western Kentucky. (See LS Power Unit Wins MISO’s First Competitive Project.)
“In 2017, we sought out incremental operational changes to scale our competitive transmission process. From our perspective, this has been a successful process,” Pedersen said during a Dec. 19 PAC conference call.
Consequently, MISO submitted five FERC filings to amend the competitive process portions of its Tariff — all of which were accepted without changes by the commission. (See FERC OKs Changes to MISO Competitive Tx Process.)
The changes allow the RTO to:
Review and weight competitive projects that contain both substation and transmission line facilities (ER18-44);
Stagger its current proposal submission and evaluation timelines should the RTO encounter two simultaneous competitive projects (ER18-41);
Replace the annual qualified competitive transmission developer recertification process with a biennial process (ER18-40); and
Request a description of safety measures transmission developers will take during both construction and operations and maintenance (ER18-42).
A fifth filing was made to correct grammar, citation and formatting errors (ER18-39).
MISO updated its Business Practices Manuals and request for proposal forms to align with the changes, Pedersen said. He added that MISO will still take up any future stakeholder improvement suggestions “as conditions permit.”
Pedersen said the changes will be in effect for MISO’s second-ever competitive project, the $130 million Hartburg-Sabine 500-kV line market efficiency project in eastern Texas, which will be bid out in early 2018. MISO has hired two new employees to help with the evaluation and selection process for the project, which includes substation construction — a first for its competitive projects.
The project — originally intended to be approved with MISO’s 2017 Transmission Expansion Plan — is currently subject to an approval delay while the RTO awaits a FERC decision on separating cost allocation zones in Texas and Louisiana. (See MISO Board Approves $2.6B Transmission Spending Package.) The Board of Directors has pledged to approve the project no later than Feb. 5, and the RTO plans to issue its RFP on Feb. 6. The window for proposals will be open until July 20, with MISO expecting to announce a developer no later than Jan. 2, 2019.
Pedersen said the Hartburg-Sabine project will be evaluated similarly to last year’s evaluation of the Duff-Coleman project, with cost and design details weighted at 30%, project implementation at 35%, operations and maintenance at 30%, and transmission planning participation at 5%.
Forty-seven existing qualified developers will not be required to recertify next year after FERC accepted MISO’s biennial qualification process, although Pedersen said developers must still disclose annual audited financial statements along with statements of any material changes to keep the RTO aware of developments such as bankruptcies or business name changes.
Queue Task Force Extension
PAC sectors also voted overwhelmingly to extend the RTO’s Interconnection Process Task Force through December 2018. The group will oversee and suggest further improvements to MISO’s major queue process changes made at the beginning of this year. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)
BOSTON — Three developers submitted proposals Wednesday in response to Massachusetts’ solicitation for up to 800 MW of offshore wind energy, offering projects that include a transmission “backbone” and storage to enable them to perform like a baseload resource.
The state’s 2016 Act to Promote Energy Diversity mandates that the Department of Energy Resources and the state’s distribution utilities — Eversource Energy, National Grid and Unitil — sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
| BithEnergy
The state’s first request for proposals (solicitation 83C) called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determines that a larger proposal “is both superior to other proposals submitted in response to this RFP and is likely to produce significantly more economic net benefits to ratepayers.”
The three developers — all with ties to the state’s utilities — have purchased renewable energy leases off the coast from the federal Bureau of Ocean Energy Management.
Bay State Wind
Bay State Wind, a joint venture between Ørsted and Eversource, proposed a 400-MW or 800-MW wind farm 25 miles off of New Bedford. It would be paired with a 55-MW battery storage facility, “the largest battery storage system ever deployed in conjunction with a wind farm,” it said.
Ørsted, formerly DONG Energy, is the No. 1 offshore wind generator in the world. The company would use New Bedford as the staging area for construction and the base of its operations and maintenance through the wind farm’s lifetime. The storage facility and an onshore substation would be located in Somerset.
Deepwater Wind
Deepwater Wind’s proposal would firm its project’s wind output through an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.
Interior of Northfield Mountain pumped storage facility | Northfield Mountain
Deepwater proposed two versions of Revolution Wind, a wind farm of approximately 25 turbines to generate 200 MW, or double that size to generate 400 MW. The company had proposed an initial 144-MW phase of the project in response to the state’s 83D solicitation for 9.45 million MWh of clean energy. The state is due to announce winners of that RFP on Jan. 25.
Deepwater is the developer of the Block Island Wind Farm off Rhode Island, the nation’s first commercial offshore wind farm. It also partnered with National Grid Ventures to propose an offshore transmission “backbone” scalable to 1,600 MW that would be open to other wind developers. (See Offshore Wind Developers Ponder Tx Options.)
The company’s project would connect to land at the Brayton Point substation in Somerset.
Vineyard Wind
Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, is betting that its promise to deliver an operating project by 2019 will win the state’s favor. It submitted proposals for 400-MW and 800-MW wind farms, with approximately 50 and 100 turbines, respectively. Avangrid owns Unitil.
| BOEM
Vineyard Wind said it has already submitted applications with BOEM and the state Department of Public Utilities’ Energy Facilities Siting Board for the wind farm, about 15 miles south of Martha’s Vineyard. “By filing for construction permits, Vineyard Wind is on track to complete the permitting process in time to begin construction in 2019,” it said.
Deepwater said if it is selected it would begin construction in 2022, with the project in operation in 2023. Bay State did not mention a timeline in its press release.
The state will announce the winners of the offshore wind solicitation on April 23, 2018, and contracts are to be submitted at the end of July.
This month saw an early offshore wind project, Cape Wind, exit the stage. It announced Dec. 1 that it had notified BOEM it was stopping development of its proposed wind farm project in the Nantucket Sound and filing to terminate its offshore lease issued in 2010.
Nevertheless, the state’s solicitation has been a cause for optimism among green energy advocates, who note the attractiveness of the Atlantic’s strong winds and shallow waters. (See ‘Momentum’ Seen for U.S. Offshore Wind.)
Entergy on Monday asked FERC to clarify the deadline for NYISO to complete a final market power review for the deactivation of the Indian Point nuclear plant, or grant the company’s request to rehear the commission’s approval of a previous ISO compliance filing (ER16-120, EL15-37).
| Entergy
At issue is FERC’s November conditional acceptance of NYISO tariff revisions to implement a new reliability-must-run program. (See FERC Approves NYISO Reliability-Must-Run Plan.) The ISO in September submitted a compliance filing to implement revisions to its RMR proposal, including adding a 365-day notice period for a generator to tell the ISO it plans to retire. The commission had accepted an earlier compliance filing for the proposal, but in April 2016 directed NYISO to make further changes to the program.
In its Dec. 18 filing with FERC, Entergy said that while NYISO’s second compliance filing contained a 90-day deadline for completing reliability studies related to plant shutdowns, it did not contain a provision for a 120-day market power review deadline included in the first compliance filing. As a result, the commission’s Nov. 16 order was “arbitrary, capricious, unsupported by substantial evidence and not a result of reasoned decision-making” because FERC conditionally accepted the ISO’s compliance filings without requiring it to establish a clear deadline early in the process for deactivating generators, the company argued.
Entergy contended that without a clear deadline for review, the 2,311-MW Indian Point plant lacked certainty about its authorization to exit the market in accordance with NYISO’s tariffs.
“At the very least, the NYISO should be held to its own assertions,” Entergy said. “Here, the NYISO has emphasized the need to perform any necessary market power review at the start of this process and has expressly confirmed its ability to complete this analysis in the first four months after receiving a completed generator deactivation notice … [and] a final market power review both in presentations to stakeholders and pleadings before this commission.”
The company is seeking a March 13, 2018, deadline for NYISO to complete a market power study for the closure of the Indian Point.
Artist’s rendering of the Cricket Valley 1020 MW plant | Cricket Valley Energy
An ISO report earlier this month found that new gas-fired and dual-fuel generation coming online in the next few years, led by the 1,020-MW Cricket Valley plant in Zone G, will provide sufficient capacity to maintain reliability after Indian Point shuts down completely in 2021. (See New Builds to Cover Indian Point Closure, NYISO Finds.)
