WASHINGTON — New wind generators will be required to provide reactive power following a FERC order last week eliminating their exemption from having to provide the service (RM16-1).
Inverters, necessary for wind turbines to provide reactive power, have become much less expensive since FERC exempted the resource from having to provide the service.
Reactive power, essential for controlling the voltage of the grid, can be measured at three points: the generator itself, the generator substation or the point of interconnection. Synchronous generators’ reactive power is measured at the interconnection point.
The commission’s order revises the commission’s pro forma generator interconnection agreements — both small and large — to require nonsynchronous generators’ reactor power to be measured at the high side of generator substations. In its Notice of Proposed Rulemaking in November, FERC had proposed the interconnection point, but it was persuaded by commenters who said doing so would require additional investment in equipment.
FERC issued the wind exemption in Order 661 in 2005 because it was concerned that the cost of the technology needed to provide reactive power would inhibit the development of the resource. Improvements in that technology since then have made it far less expensive, and FERC said that continuing the exemption could result in insufficient reactive power as wind power grows and traditional synchronous generation retires.
Order 661 did not exempt other types of nonsynchronous generation, such solar, but FERC has been treating them similarly to wind on a case-by-case basis. The commission has sometimes required that balancing authorities demonstrate that the lack of reactive power from a non-wind, nonsynchronous generator would threaten reliability before requiring it to provide the service.
The new requirements apply to all new nonsynchronous generators, regardless of type, that have not executed a facilities study agreement as of 90 days after publication in the Federal Register. They would not apply to existing generators, including those making upgrades that require new interconnection requests. FERC said these provisions would allow generators to complete the interconnection process without delay or extra costs.
FERC approved the new requirements at Thursday’s meeting, which was open to the public again after the commission closed it last month. (See Pipeline Protesters Force FERC to Close Monthly Meeting.) Staff’s presentation of the order was interrupted by two protesters, who urged the commission to halt approval of natural gas pipelines.
“There’s a certain irony here because the protesters interrupted a presentation by staff on commission work that can enable a higher degree of penetration by wind resources while maintaining reliability,” Chairman Norman Bay said in response. “This final rule will ensure comparable and nondiscriminatory treatment of both traditional resources and new resources, such as wind and solar, in the provision of reactive power, while recognizing that some technological differences remain.”
“Today’s rule recognizes that wind and other nonsynchronous generators, which are an increasingly important part of the fleet, now have the technical ability to provide reactive power at reasonable cost, and so they’ll now be required to do so,” Commissioner Cheryl LaFleur said. “I think today’s rule highlights that wind and solar are no longer just niche technologies.”
FERC last week accepted portions of MISO’s system support resource (SSR) Tariff changes but rejected the RTO’s proposal regarding the retention and transfer of interconnection rights (ER12-2302-004).
The changes allow new generation not available at the time of reliability studies and SSR designation to become an alternative to an SSR assignment.
However, FERC told MISO its proposal on interconnection rights had gaps.
Presque Isle Power Plant Source: We Energies
MISO permits owners and operators of retiring SSR facilities to retain or transfer interconnection service. FERC said that in three filings, the RTO hasn’t yet proposed an impartial method for implementing the rule.
“MISO must propose additional procedures that ensure that the retention and transfer of interconnection service is offered on a fair, transparent and nondiscriminatory basis,” FERC said. “MISO is required to propose additional procedures, which should, among other things, allow a clear and consistent way in which generators seeking a transfer of interconnection service from a retiring generator may identify opportunities and address how such a generator would be chosen for such service.”
FERC also said MISO’s February filing to remove language regarding retention of interconnection service from its SSR procedures and insert them into Attachment X “merely moves this provision from one Tariff section to another without providing the requisite additional procedures.”
A federal judge rejected EPA’s effort to block a former official from testifying on behalf of a coal company that is suing the agency. The agency argued that Jeff Holmstead, a former EPA air pollution expert who left the agency in 2005, would have a conflict of interest because of his former position.
“That dog won’t hunt,” Judge John Preston Baily said of EPA’s argument. He also dismissed as “ridiculous” EPA’s claim that Holmstead was unqualified to testify as an expert witness.
Holmstead, who now works for law firm Bracewell, is an expert witness for Murray Energy. The company has sued EPA, alleging it has not accounted for or studied coal industry job losses resulting from its air pollution regulations, as required under the Clean Air Act.
Four senators introduced a bill that would require coal companies to prove they have the resources to clean up mining areas after they close. Coal companies have been able to simply declare they can afford cleanup costs, without any financial assurance, a process called “self-bonding.”
The recent spate of coal company bankruptcies has called into question the ability of distressed coal producers to handle the cleanup costs.
“We need to make sure the taxpayer isn’t on the hook for cleanup work by bankrupt coal companies anymore,” Sen. Maria Cantwell (D-Wash.) said in a statement. “Self-bonding clearly isn’t working, and we need to stop this dicey practice from continuing.”
Green Groups ask FERC for PennEast Pipeline Hearing
A group of environmental organizations is asking FERC to hold an evidentiary hearing on the need for the PennEast pipeline that would deliver natural gas from Pennsylvania mostly to New Jersey utilities.
“FERC must have substantial evidence of significant public benefit to approve PennEast’s application, but the company’s existing record fails to meet that test,” said a senior attorney with the Eastern Environmental Law Center. The center charges in a complaint that PennEast used the fact that six owners of the pipeline have contracted for about 75% of the proposed pipeline’s capacity as evidence of public need.
The New Jersey Sierra Club, however, didn’t join in the suit, saying the tactic would be unsuccessful. “What we’re more concerned about is that FERC and PennEast fix any defects they have in their applications and filings,” said Jeff Tittel, Sierra Club director.
The Department of Energy has identified 93 projects in 28 states that will receive $82 million in grants to advance nuclear energy research.
“Nuclear power is our nation’s largest source of low-carbon electricity and is a vital component in our efforts to both provide affordable and reliable electricity and to combat climate change,” Energy Secretary Ernest Moniz said. “These awards will help scientists and engineers as they continue to innovate with advanced nuclear technologies.”
The Nuclear Regulatory Commission named Kimberly A. Howell as director of its Office of Investigation.
Howell, who has 20 years of federal law enforcement experience, was deputy assistant inspector general for investigations in the Office of Personnel Management. Before that, she held investigative positions with the Food and Drug Administration, the Secret Service and the Postal Service.
NRC’s investigation office creates new policies, procedures and standards for investigating licensees, contractors, vendors and other third-party organizations.
Despite a stay issued by the U.S. Supreme Court, EPA said it would go forward with a plan that issues incentives for states that comply with implementation of the Clean Power Plan.
“Taking these steps will help cut carbon pollution by encouraging investment in renewable energy and energy efficiency,” EPA’s Janet McCabe said. The Clean Energy Incentive Program gives states compliance credits for pushing forward renewable and efficiency projects.
The Supreme Court suspended enforcement of the Clean Power Plan until an appeal by states could be settled. “EPA is attempting to downplay the significance of the stay and argue against clear legal precedence as a last-ditch effort to scare states into spending scarce resources complying with a rule that could very well be overturned,” said Sen. James Inhofe (R-Okla.), chairman of the Environment and Public Works Committee.
EIA Report: CPP Will Push Development of Renewables
An Energy Information Administration report concludes that EPA’s Clean Power Plan would accelerate the development of renewable energy at an annual rate of nearly 5%.
“California sees strong growth in renewable generation by 2030 as a result of the state renewable targets,” the EIA said. “Similarly, the Northwest region is expected to increase renewables generation as well. The Northeast shows an increase in both natural gas and renewables generation by 2030, and a small decline in nuclear generation due to planned retirements.”
EIA’s estimates were based upon the assumption the plan would be implemented. The plan is currently on hold as a result of a Supreme Court stay.
Entergy’s Indian Point Unit 2 Back Online After Repairs
Entergy’s Indian Point Unit 2 nuclear plant went back into service late Thursday after a refueling outage, inspection and repairs. The repairs included replacement of 278 bolts and plates that were discovered damaged during an inspection.
A group of environmental organizations filed an unsuccessful emergency petition with the D.C. Circuit Court of Appeals to prevent Entergy from bringing the plant back online. Friends of the Earth and other groups said Entergy hasn’t provided a root cause analysis of the bolt degradation issue.
The Nuclear Regulatory Commission said there are no safety concerns. Entergy will conduct a separate bolt inspection at Unit 3 early next year.
A federal appeals court upheld a ruling that Minnesota’s 2007 clean energy law illegally regulated out-of-state utilities by requiring state power producers who import electricity to reduce greenhouse gas emissions elsewhere.
The ruling by the 8th U.S. Circuit Court of Appeals was a victory for North Dakota and its utility and coal interests, which argued that the Minnesota law unconstitutionally hampered their ability to sell electricity from coal-fired power plants and to build new coal generators. The law, known as the Next Generation Energy Act, restricted electricity imports from power plants that increase greenhouse gases, unless they reduce those emissions.
The court’s decision does not affect the law’s requirement that Minnesota utilities get 25 to 30% of their electricity from renewable sources such as wind and solar.
MISO released a work plan last week detailing how it and PJM will use the next six months to improve coordination of generation retirements.
The RTOs’ cooperation on generator retirement studies was one of six directives mandated by FERC in an April order (EL13-88) that stemmed from a 2013 complaint from Northern Indiana Public Service Co. (See MISO, PJM Working to Comply with NIPSCO Order.)
At last week’s Planning Subcommittee meeting, MISO said it and PJM will develop a proposal on retirement studies coordination by July.
MISO said it would work on the issue in meetings of the subcommittee, Planning Advisory Committee, and the RTOs’ Interregional Planning Stakeholder Advisory Committee and Joint and Common Market.
Neil Shah, MISO adviser of seams administration, said the RTOs would be starting from scratch. “The joint operating agreement doesn’t have any retirement coordination language,” he said.
The RTOs differ on retirement rules. MISO requires 26 weeks’ notice prior to retirement, giving it time for a 75-day reliability assessment; PJM requires a 90-day notice and only 30 days of reliability assessment. Further, MISO keeps retirement information confidential unless a reliability concern is identified. PJM has no such confidentially rules and makes retirement information publicly available.
Shah said MISO would submit its work plan to FERC with an informational status filing that is due June 20. Additional status filings are due Aug. 19 and Oct. 18.
He also said MISO plans to share draft JOA language with stakeholders at the RTOs’ Nov. 15 joint and common issues meeting in time to file proposed JOA revisions with FERC by Dec 15.
Pseudo-Ties to Require System Impact Studies; Would be Barred from Sink Switching
MISO wants to conduct system impact studies on all pseudo-tied units with transmission service requests and forbid them from switching sinks until the requests expire.
The RTO is proposing a system impact study be required for all pseudo-tie transmission service requests and that firm point-to-point transmission service be required for the life of the pseudo-tie.
MISO has also proposed that pseudo-tied exports be sourced from a designated generating facility in its commercial model and be modeled in the external balancing authority. Pseudo-tied imports must be sourced from the local balancing authority where the generating unit is physically located and must sink into the MISO local balancing authority where the unit is being pseudo-tied.
“Participants are changing pseudo-ties to another sink after they have a transmission service request,” MISO senior transmission planning engineer Ankit Pahwa said. “It’s a shortcoming in the existing process … and a gray area that has not been covered yet.”
Pahwa said the proposed changes have been coordinated with PJM. He added that participants with existing pseudo-tied transmission service requests would be grandfathered from an impact restudy.
Currently, transmission service requests are evaluated based on an OASIS available flowgate capability evaluation, with only long-term requests — 18 months or longer — requiring a system impact study. Neither long-term nor short-term requests require a source/sink analysis, Pahwa said.
“From MISO’s perspective, we want to be 100% sure that we capture the transmission service impacts if a pseudo-tie moves to a different [local balancing authority],” Pahwa said.
“I think what we’re wrestling here is, does there need to be different treatment for pseudo-ties … much like there are different evaluations for network resource interconnection service for reliability purposes? At the minimum, you need to be sure you have the appropriate type of analysis,” MISO’s Jeff Webb said.
Webb said more conversations with other RTOs were needed before a final proposal. Stakeholders have until July 15 to comment on MISO’s proposal.
MISO Delves into MTEP 16 Studies
MISO is in the midst of developing model scopes for the 2016 Transmission Expansion Plan (MTEP 16), said Dave Ditner of the RTO’s system modeling department. The RTO’s modeling will include a 2017 summer peak with wind contributions of 15.6% and 2021 modeling of summer peak, summer shoulder and light load scenarios with wind contributions ranging from 15.6 to 90%.
William Kenney, an expansion planning engineer for MISO’s Southern Region, also presented the finalized MTEP 16 voltage study scope. The study will use nine 2021 power flow models, including summer, winter and a shoulder with wind at 40%. MISO will release the final MTEP 16 voltage stability study in October.
Additionally, seven transfers will be studied in model year 2021 under the MTEP 16 transfer analysis scope:
MISO North to SPP;
Two different paths from Manitoba Hydro to MISO North;
PJM in Northern Illinois to PJM Ohio;
Missouri and Illinois to PJM Ohio;
SPP to Southern Co.’s territory; and
MISO South to SPP.
MISO will finalize the transfer analysis in mid-August.
Storage May Be Removed from Non-Transmission Alternatives
MISO presented stakeholders with draft language on Business Practices Manual 020, continuing a nearly yearlong discussion on non-transmission alternatives.
The RTO is suggesting separating energy storage devices that could solve a transmission issue from BPM language on non-transmission alternatives. MISO is also recommending discussion on whether storage can serve as a non-traditional transmission alternative move to the Planning Advisory Committee, MISO’s Matt Tackett said.
In April, MISO proposed classifying storage as a non-traditional transmission alternative. (See “Energy Storage Prompts 2nd Transmission Alternative Category,” MISO Planning Subcommittee Briefs.)
Indianapolis Power & Light’s Lin Franks said storage provides frequency control and voltage control much like transmission.
MISO will present a second draft of the BPM language at the August Planning Subcommittee meeting.
The ERCOT Board of Directors approved extending a reliability-must-run contract with NRG Energy for its Greens Bayou Unit 5 plant in the Houston area. The RMR, ERCOT’s first in five years, will run through June 30, 2018, at which time additional generation and transmission infrastructure is expected to be in service.
Greens Bayou Source: NRG
The 371-MW natural gas-fired generator was originally scheduled to be mothballed June 27, but ERCOT’s RMR contract June 3 made the unit available to the market through September. (See ERCOT to Keep NRG’s Greens Bayou Plant Running for Summer.)
Staff analysis indicates Greens Bayou Unit 5 is needed to maintain or support reliability in the region over the short term.
“Having that unit available will reduce the likelihood of having to engage a constraint-management plan, which would likely mean load shed,” said Warren Lasher, ERCOT’s director of system planning.
Under the RMR agreement’s terms, ERCOT will make a standby payment to NRG of $3,185/hour during on-peak hours, whether or not the unit runs.
Directors Carolyn Shellman, of CPS Energy, and Read Comstock, of Direct Energy, both encouraged additional discussion on the ISO’s RMR practices at the next board meeting. “I think we should encourage a holistic review of the RMR protocols,” Comstock said.
Lasher said staff will begin evaluating must-run alternatives, which it will bring to the board in August. The Technical Advisory Committee is also creating a task force to focus on the issue.
“I would like to see the market solve these situations, so we don’t have to,” Director Judy Walsh said.
Staff said the region’s reliability concerns will subside before the summer peak of 2018, when the $590 million Houston Import transmission project — “the ultimate [RMR] exit strategy,” Lasher called it — is expected to be completed. New generation is also on the way, with NRG’s 390-MW PH Robinson peaking facility expected to come online later this summer and Exelon’s 1,148-MW Colorado Bend combined cycle plant to follow in July 2017.
ERCOT also added 75 MW of power last week when NRG converted a gas turbine at its Houston-area W.A. Parish facility into a cogeneration unit. The unit was originally built to produce steam and electricity as part of the Petra Nova post-carbon capture and sequestration joint venture with JX Nippon Oil & Gas Exploration. The unit went into mothballs May 19 during its conversion process.
Magness: Mild Weather Cuts into Admin Revenue
CEO Bill Magness said ERCOT’s year-to-date revenues are $2.3 million over budget, despite a $2.2 million shortfall in the administrative fee that is attributed primarily to mild weather this year. He said the ISO is on track to finish $3.1 million above budget, thanks to positive variances in resource management, hardware and software, and employee benefit costs.
“It looks like we can create a favorable variance, but we don’t know what the weather’s going to be like,” Magness said.
ERCOT’s senior meteorologist, Chris Coleman, said this summer will “likely” not be as warm as last summer — the 17th hottest in Texas over the past 121 summers — or 2011, when sustained heat led to several peak-demand records and seven emergency alert notifications.
“This summer is one of the more difficult forecasts I’ve put together,” Coleman said. “Most indicators suggest a milder summer. I can guarantee you we will not see a repeat of 2011.”
Coleman said ocean temperatures, the primary influence on weather patterns, have been above normal in both the Pacific and Atlantic Oceans. He also said the transition from the second-strongest El Niño on record to what he expects to be a neutral or weak La Niña could lead to above-normal temperatures in the late summer.
The meteorologist said he does see “more potential for hurricane activity in the Gulf of Mexico” than his first four years with ERCOT. Coleman predicted five hurricanes, of which one or two could be in the Gulf, and the potential for two storms to make landfall in Texas.
“It doesn’t mean Texas will be hit by a tropical storm or hurricane,” he said, “but if there are three to five in the Gulf, the potential is greater.”
Dan Woodfin, ERCOT’s director of system planning, said it would take “really, really extreme” weather conditions to affect the grid’s operations. The ISO said last month it has more than enough natural gas and renewable energy capacity to meet its projected summer peak this year. (See ERCOT Briefs: Ample Capacity; Outage Procedures.)
“We’re not expecting a 2011 summer,” Woodfin said. “We have procedures in place should something out of the ordinary happen.”
The Rio Grande Valley, long a trouble spot for congestion, “looks better this summer than it has in quite a few years,” Woodfin said. He said a 345-kV line was completed last month and a cross-valley project went into service two weeks ago, easing some concerns.
LP&L Integration Could Unlock More Panhandle Wind Energy
Lasher shared staff’s report on how to integrate Lubbock Power & Light into ERCOT, which recommends a plan that would allow for further export of the Texas Panhandle’s ample wind energy supplies.
Lasher said staff’s “option 40W” will cost $364 million and result in 141 miles of new 345-kV rights of way, but it could also help export 4,246 MW of wind energy elsewhere on the grid.
“It’s not the low-cost option,” he said, “but it’s preferred specifically because it’s consistent with the longer-term needs ERCOT has identified for the region.”
LP&L announced last September it planned to disconnect from SPP and join ERCOT by 2019. Xcel Energy, whose Southwestern Public Service subsidiary serves LP&L’s load, asked FERC in May for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan. (See Xcel Asks for $88.7M Fee for Lubbock Switch to ERCOT.)
Staff combined studies supplied by LP&L and Sharyland Utilities, which has transmission assets in the Panhandle, and folded them into its own analysis. The final report will be filed in the Public Utility Commission of Texas’ LP&L docket (# 45633).
Changes to Calculation of Market’s Physical Responsive Capability
ERCOT’s methodology for determining ancillary service requirements will change July 1 when it adjusts the reserve discount factor (RDF) in the market’s physical responsive capability (PRC) calculation on quick-response online generation.
The board unanimously approved staff’s recommendation on the adjustment, pleasing PUC Commissioner Ken Anderson, who has raised concerns over an event last August when the ISO’s scarcity pricing adder, the operating reserve demand curve (ORDC), did not appropriately reflect a reduction in the PRC.
“In defense of ERCOT, these changes are looking to solve the problem we saw last August … the disconnect between the ORDC and PRC,” he said.
On Aug. 13, operators deployed non-spinning reserve service as the PRC dropped to 2,371 MW. However, ERCOT’s real-time online reserve capacity was 3,629 MW, which was reflected in wholesale prices.
ERCOT buys responsive reserve service to ensure sufficient PRC is available. The measure approved by the board aligns the ISO’s systemwide discount factor, lowering it from 2% last year to 1%. It also makes operational adjustments to the RDF.
Board Approves 13 Revision Requests
The board pulled one nodal protocol revision request (NPRR) from the consent agenda but gave it its unanimous approval following a brief discussion.
NPRR758 is designed to provide improved transparency to market participants when transmission outages that could create congestion are submitted with less than 90 days’ notice. It would identify outages that have historically resulted in high congestion costs, as adjusted through stakeholder review to account for upgrades and other changes.
“I’m concerned we don’t have a clear-cut requirement to how we came up with the list and published it,” said Nick Fehrenbach, manager of regulatory affairs and utility franchising for the City of Dallas, before offering up the motion for approval. “We need clear requirements and how we can change them, or we’re leaving ourselves in a quandary.”
TAC Chair Randa Stephenson, of the Lower Colorado River Authority, said the subcommittee and ERCOT staff will “work to ensure a list of high-impact outages is available to public knowledge.”
The board’s consent agenda resulted in the approval of nine more NPRRs, two system change requests (SCRs) and a nodal operating guide revision request (NOGRR).
NPRR709: Modifies the alternative-dispute resolution procedure and clarifies parts of the settlement and billing dispute process.
NPRR752: Clarifies revision request protocol language to reflect current ERCOT practices.
NPRR754: Revises the posting frequency of the load-forecast distribution factors report. Posting is required only when the factors are changed.
NPRR761: Clarifies that a resource will not be eligible for make-whole payment startup-cost compensation in the day-ahead market when the market considers the resource as not having a startup cost.
NPRR762: Removes references to the provision of responsive reserves across the DC ties.
NPRR763: Corrects the formula for calculating qualified scheduling entities’ monthly block load transfer amount to reflect a charge, rather than a payment.
NPRR764: Changes calculations for charges to entities short their capacity obligations in reliability unit commitment. Calculations for wind and solar resources will be based on their production potential.
NPRR765: Eliminates publisher names for various fuel price indexes and provides additional clarifying language regarding the use of a substitute source for daily fuel prices.
NPRR766: Aligns the description of the systemwide discount factor with the proposed operational adjustment to the RDF in the physical responsive capability calculation; also aligns the posting for RDFs applicable to both generation and load resources.
SCR788: Updates the formula used to calculate the “generation to be dispatched” (GTBD) value and help minimize GTBD oscillations from one security-constrained economic dispatch interval to the next.
SCR790: Adds an additional level of geographical granularity — the Panhandle/North area — to reports on wind power production and forecasts.
NOGRR050: Removes ERCOT’s requirement to produce outage-scheduling reports until systems can be changed to include only transmission service providers’ outages.
FERC last week clarified its Electric Quarterly Report (EQR) reporting requirements, emphasizing that transmission providers must report transmission-related data (RM01-8, et al.).
The order also updates the EQR Data Dictionary, effective with the report for the fourth quarter of 2016, clarifying reporting requirements and fields related to “Increment Name” and “Commencement Date of Contract Terms.” It also makes changes regarding the “Time Zone” field options and deletes fields for reporting e-Tag data.
Future minor or non-material changes to EQR reporting requirements and the Data Dictionary will be posted directly to the commission’s website, and EQR users will be alerted via email of the changes.
FERC last week denied a request by PJM’s Independent Market Monitor to clarify or rehear a March order in which the commission found fault with the RTO’s use of the cost-based energy offer cap as the sole measure of short-run marginal cost in calculating capacity market caps (EL14-94, ER16-1291).
In its request, Monitoring Analytics generally supported FERC’s order but called flawed the use of market-based offers as the measure of short-run marginal costs when they are higher than cost-based offers.
“The Market Monitor contends that the extent to which a market-based offer exceeds a cost-based offer constitutes a markup, and markup is not part of a competitive offer,” the commission said.
“We continue to find that, with limited exceptions, PJM should use, for the purpose of calculating a unit-specific capacity market offer cap, a resource’s non-zero market-based offer to reflect its marginal costs,” FERC ruled. “Simply because a market-based offer exceeds a cost-based offer does not necessarily establish that the market-based offer fails to reflect a resource’s marginal costs.”
The March ruling stemmed from a 2014 FirstEnergy petition that said PJM’s Market Monitor was violating the Tariff by calculating marginal costs using the lower of the market-based offer and cost-based offer.
FERC Denies Rehearing on Order Requiring DR in Capacity Auctions
FERC denied Talen Energy’s request for rehearing of a July 22 order that required PJM to include demand response in its transition auctions for Capacity Performance (ER15-623, EL15-80).
The commission also accepted a compliance filing by PJM in response to the July 22 order.
Talen had sought to apply a ruling by the D.C. Circuit Court of Appeals that voided FERC’s jurisdiction over DR in energy markets. However, the Supreme Court later reversed that ruling. (See Supreme Court Upholds FERC Jurisdiction over DR.)
“Accordingly, we dismiss Talen’s rehearing request as moot,” FERC said.
FERC also dismissed an objection by the Advanced Energy Management Alliance Coalition regarding the method PJM proposed to measure and verify DR participation in the transition auctions, saying it was an unrelated issue.
Commissioner Tony Clark concurred in a separate statement.
“I write separately to note my policy and procedural disagreements with the underlying order as fully explained in my separate statement of July 22, 2015,” he said.
Clark dissented from that order, saying it was improper procedurally because the commission had previously approved “unambiguous” Tariff language barring DR and energy efficiency from the auctions.
CAISO transmission planning staff last week proposed studies on the implications of gas shortages on grid reliability.
The planners outlined the studies in a June 13 stakeholder call, saying they will consider the risks to Northern California as well as the more vulnerable southern part of the state.
The disparity between the regions stems from design differences in their pipeline systems and the synergy between Southern California’s storage facilities and its pipeline network.
“Gas storage in the [Los Angeles] Basin is critical [to pipeline operations],” said ISO senior advisor David Le, referring to the gas system’s dependence on the Aliso Canyon storage facility.
Le pointed out that the Aliso Canyon — closed earlier this year because of a gas leak — is vital not only for its massive 86 Bcf storage capacity, but also for its ability to quickly supply large volumes of gas to support pipeline pressure.
Aliso Canyon usually accounts for more than 65% of the inventory held in Southern California’s four major storage sites. The facility also boasts a daily withdrawal capacity of 1.86 Bcf, which helps keep 17 gas-fired generators in the basin supplied with gas under strained conditions.
That withdrawal capability is usually tapped during summer months to help generators meet peak demand. CAISO says that, because of the “magnitude and speed” of the generators’ consumption, pipeline capacity is often insufficient to supply their needs without the ability to backfill from storage such as Aliso Canyon.
CAISO plans to model multiple scenarios stemming from the closure of Aliso Canyon to assess the potential long-term impact of the gas system’s balancing act on Southern California’s grid reliability. Planning staff will develop scenarios in which gas pipeline operators and gas generators lose access to other storage facilities in the region in addition to Aliso.
The study is intended to take a long view, looking at the implications of such gas curtailments to inform transmission planning for 2021 and 2026 as California advances on its 50% renewables mandate.
A parallel study would examine the likelihood for gas curtailments in Northern California, a region with a “much different” gas system, according to Binaya Shrestha, CAISO regional transmission engineer lead.
To provide context for his assertion, Shrestha pointed to the February 2011 gas outages that cut supplies to a number of San Diego-area generators. “Southern California is [subject to] historical outages, but in Northern California, there hasn’t been any curtailment of that level for gas-fired plants,” he said.
That success can be attributed in part to both the line capacity and topology of the gas system.
The proximity of gas storage facilities to Northern California’s backbone pipeline provides flexibility for the region’s gas system.
The region’s backbone pipeline — Line 401/402 — has a firm capacity of more than 2 Bcfd. Additional supply arrives via the Mojave gas system originating in the southern part of the state, which serves about 2,200 MW of generation in the ISO’s Pacific Gas and Electric zone.
Furthermore, nearly all of Northern California’s eight major gas storage facilities are distributed along the length of Line 401/402. That arrangement provides operational flexibility because gas can be injected into the system from multiple sites.
Those facilities also equip the region’s gas suppliers with a combined 238 Bcf in inventory capacity — double that in Southern California — and more than 4.5 Bcf in withdrawal capacity.
Still, the ISO wants to better understand the dynamics of gas supply in Northern California to investigate what chain of events leading to curtailments could compromise the region’s electric reliability.
Stakeholders must submit comments about the gas-electric studies by June 27. Findings will be incorporated into the ISO’s draft transmission plan early next year.
WASHINGTON — RTOs will be required to align their settlement and dispatch intervals and implement shortage pricing during any shortage period under new price formation rules approved last week by FERC (RM15-24).
FERC Order 825 requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. Although all RTOs currently dispatch resources in five-minute intervals, ISO-NE, MISO and PJM settle those transactions based on the average price for all dispatch intervals during the hour.
This misalignment distorts price signals, as compensation is based on average hourly prices rather than specific periods, including those of greatest need. “These distorted price signals can mute a resource’s financial reward for being able to quickly respond to system needs and create a disincentive for resources to respond to price signals,” Stanley Wolf, of FERC’s Office of Energy Policy and Innovation, said at the commission’s open meeting Thursday.
Additionally, in some RTOs, an energy or reserve shortage is required to last a minimum amount of time before shortage pricing is triggered. “Due to such delays, short-term prices fail to reflect potential reliability costs, as well as fail to reflect the value of both internal and external market resources responding to a dispatch signal,” Wolf said.
Commissioner Colette Honorable called the order — the first final rule in the commission’s efforts to reform price formation in the organized electricity markets — a “milestone.” The commission began evaluating price formation in 2014 and issued a Notice of Proposed Rulemaking in September. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
“These requirements will help ensure that rates for energy and operating reserves are just and reasonable and will align prices with resource dispatch instructions and operating needs, provide appropriate incentives for resource performance and maintain reliability,” FERC said.
The final order clarifies that the rules would apply to all supply resources, including demand response.
The new requirements take effect 75 days after publication in the Federal Register. Each RTO will be required to make a compliance filing 120 days after that detailing the tariff changes needed to implement the new rules. The order stipulates that FERC will allow an additional year after the compliance filing deadline for the settlement interval changes to go into effect, while it will allow another 120 days for the shortage pricing changes.
“I know that it will take some time and effort for the RTOs to comply with the portion of the rule on settlement intervals; it won’t necessarily be easy,” Commissioner Cheryl LaFleur said. “However, I think it’s critically important that markets send clear, accurate, timely and undiluted price signals.”
A U.S. House of Representatives committee last week approved legislation that aims to stop Clean Line Energy Partners’ plans to build a 700-mile HVDC transmission through Oklahoma and Arkansas.
Womack
The House Committee on Natural Resources advanced the Assuring Private Property Rights Over Vast Access to Land (APPROVAL) Act by a 19-11 vote June 15. The bill is sponsored by Rep. Steve Womack, one of the members of an all-Republican Arkansas congressional delegation that is united in opposition to the Clean Line project.
The bill would amend the Energy Policy Act of 2005 to prohibit the secretary of energy and federal power agencies from using eminent domain for transmission rights of way without first receiving approval from a state’s governor and regulatory body. It also restricts the transmission line’s siting to existing federal right of way or land managed by federal entities.
Womack said the bill is “another positive step toward passage in a long and hard-fought battle to allow states to retain the historic precedent of authority for interstate transmission projects.”
“It is our firm belief that the [Energy Department] has overstepped its bounds, and reversing this decision through the passage of the APPROVAL Act remains a top priority,” Womack said, speaking for the rest of his state’s delegation.
Houston-based Clean Line issued an opposing statement, saying that if the bill became law, “it would kill jobs by creating significant barriers to the many businesses in Arkansas … that build American infrastructure, as well as raise electric power costs.”
“Denying American consumers access to the lowest-cost clean energy resources is never good policy,” added Clean Line, which noted more than $100 million in private funds have been invested in the project.
Clean Line’s Plains & Eastern Clean Line is a $2.5 billion, privately funded project that is supposed to deliver 4,000 MW of wind power from the Oklahoma Panhandle through Arkansas to the Mississippi River. The line would interconnect with the Tennessee Valley Authority near Memphis, after first dropping off 500 MW at a converter station in central Arkansas.
Clean Line Project Map Source: Clean Line Energy Partners
Clean Line proposed the project in response to the Energy Department’s 2010 request for proposals for transmission projects under Section 1222 of EPACT 2005, which authorizes the department to participate in “designing, developing, constructing, operating, maintaining or owning” new transmission.
The department approved the project in March, saying it would participate through the Southwestern Power Administration, a federal agency that markets hydroelectric power from 24 dams in six states. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)
The Arkansas Sierra Club said it opposes Womack’s bill.
“The Clean Line project has been in the works since 2010 and has undergone a very thorough and expensive public permitting process in accordance with federal law,” said the Sierra Club’s Arkansas director, Glen Hooks. “Rep. Womack’s bill seeks to change that law after the permitting process has been underway for years. That’s not only bad for our state’s air and economy, it’s blatantly unfair to the company.”
Arkansas Sen. John Boozman has filed a matching bill that is co-sponsored by the state’s junior senator, Tom Cotton. The Senate Committee on Energy and Natural Resources held a hearing on the bill in May but has taken no action on it since then.
“Arkansans should be heard in discussions that impact their lands,” Boozman said in a statement released by his office. “Our bill restores the role of states, which in the past had the freedom to approve or reject electric transmission projects. These decisions should not be made behind the closed doors of a federal agency in Washington, D.C.”
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