ERCOT will add about 9,300 MW of additional capacity by 2019, relieving concerns that the grid’s reserve margins would drop as load continued to grow, according to a new analysis.
The updated 10-year Capacity, Demand and Reserves (CDR) report released last week shows a continuing rise in planning reserve margins — topping 20% in the “next several years.” The Texas grid operator’s reserve margin has stood at 13.75% since December 2010.
The latest CDR shows about 6,250 MW of planned resources have become eligible to be included since the May 2015 report (a net of 3,660 MW after discounting wind nameplate additions). Planning reserve margins increased for all years except 2016.
Gas turbines and wind and solar farms account for much of the expected new capacity. ERCOT said solar capacity should increase from its current 193 MW of installed capacity to 1,789 MW by 2017. Nameplate wind capacity is expected to grow 45% to more than 4,200 MW over the same period, while natural gas capacity is projected to grow 1% to more than 51,000 MW.
ERCOT’s director of system planning, Warren Lasher, said the new generation was responding to the state’s continued growth. “We continue to see the demand for electricity here increase as more people and businesses move into Texas,” he said during a Dec. 1 conference call.
“The generation mix is also growing and changing,” Lasher said. He said some of the capacity growth could be offset by fossil unit retirements as “changing environmental rules begin to take effect.”
ERCOT forecasts a peak of more than 70,500 MW next summer, growing to almost 78,000 MW by summer 2025.
Two years ago, ERCOT was predicting a 20% decrease in its reserve margin. The grid operator had come perilously close to rolling blackouts during a blistering summer of 2011 and plant construction was practically nil.
Recent summer temperatures have not reached predictions and new capacity has come online since then, but ERCOT also revised its planning standards last year. Staff has incorporated growth trends in customer accounts, or premises, to better project regional demand growth.
“We have been able to provide a more accurate look at future demand and energy use,” said Calvin Opheim, ERCOT’s manager of load forecasting and analysis. “I’ve been very happy with how our new forecasting model has performed.”
The latest CDR forecasts peak loads averaging more than 500 MW higher through 2021 than the forecast used for the May CDR. ERCOT said the report is based on average weather over the past 13 years and includes additional electricity demand from a liquefied natural gas facility near Houston, which is scheduled to be fully operational by summer 2019.
The CDR’s data on generation comes from information provided by resource owners.
The report counts as capacity 4,700 MW of coal generation ERCOT expects to retire as a result of EPA’s Clean Power Plan and Regional Haze Program. The draft Regional Haze rule would require scrubber upgrades or retrofits at 12 coal-fired units by 2020. A final rule is expected in several months. The next CDR update is scheduled for release in May 2016.
ERCOT Sets Another New Wind Peak
ERCOT set a new record for wind generation Nov. 25 with 12,971 MW. That accounted for nearly 37% of the grid’s load at the time (9:10 p.m.).
Entergy said last week it is sticking to its plan to close the FitzPatrick nuclear generating station, despite a rescue attempt by New York officials and an offer by Exelon to provide it fuel at cost.
FitzPatrick nuclear plant (Source: Entergy)
Entergy announced last month that competition from low-cost natural gas generation will force it to retire the 838-MW plant in late 2016 or early 2017, when the plant would otherwise be shutting temporarily for refueling. (See Entergy Closing FitzPatrick Nuclear Plant in New York.)
Then came news that New York Gov. Andrew Cuomo wants the Public Service Commission to mandate that 50% of the state’s electricity come from renewable sources by 2030. Cuomo also called for incentives to keep the state’s nuclear plants operating until then. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)
At the urging of Cuomo administration officials, Exelon agreed to acquire enough fuel for FitzPatrick and to give Entergy until next June to decide whether to use it based on the clean energy mandate. The PSC said that the proposed “fuel bridge” would allow Entergy to delay its decision without purchasing the $50 million worth of fuel now.
The offers weren’t enough to change Entergy’s mind.
“We have explored every legitimate commercial arrangement that might have changed the decision regarding Fitzpatrick’s retirement,” Entergy spokeswoman Tammy Holden told The Post-Standard. “There is no viable alternative left to consider. The plant will retire at the end of 2016 or early 2017, as we previously announced and have formally advised” the Nuclear Regulatory Commission.
VALLEY FORGE, Pa. — PJM is drafting manual changes to document the parameter adjustment process under Capacity Performance rules.
The process allows a generation operator to request an adjustment if it believes its resource’s physical constraints will prevent it from meeting the parameters assigned by PJM.
Related revisions to Manual 11: Energy and Ancillary Services Market Operations will be presented for endorsement by the Markets and Reliability Committee this month.
At last week’s Operating Committee meeting, the RTO gave a presentation comparing the unit-specific parameter adjustment process with parameter limited schedule (PLS) exceptions.
Unit-specific adjustments would be permitted only because of ongoing, long-term operational limitations, said PJM’s Alpa Jani. Staffing, for example, would not qualify as a physical operating constraint.
PLS exceptions will be used to address short-term, temporary issues such as equipment damage.
Adjustment requests must be submitted to PJM no later than Feb. 28 before the delivery year. If the situation arises after that date, a waiver must be obtained from FERC.
Members also reviewed PJM’s new soak time parameter. Soak time is defined as “the minimum number of hours a unit must run in real-time operations, from the time the unit is put online (breaker closure) to the time the unit is at economic minimum or dispatchable.”
Until the new parameter is added to PJM manuals, adjustment requests similar to the soak time definition will be documented in the minimum run time parameter, and soak time will be noted in PJM internal documentation so it can be updated when a long-term solution is implemented.
In a related matter, the Market Implementation Committee approved an issue charge presented by Bob O’Connell on behalf of PPGI Fund A/B Development to study the process of requesting exceptions to the default parameter limited schedule. (See “Parameter Limited Schedule Exemption Process to be Reviewed” in PJM Market Implementation Committee Briefs.)
The work will be conducted as part of regular MIC meetings and will seek to identify improvements to existing practices for requesting and obtaining PLS exceptions. The group is expected to recommend manual and possible Tariff changes to the MIC by April.
Members Mull Performance Assessment Hour Notifications
PJM also gave the OC a presentation in response to stakeholder questions about performance assessment hours under Capacity Performance.
Generators are subject to steep penalties for failing to meet their capacity obligations during performance assessment hours — periods for which PJM has declared an emergency action. (Base capacity resources are exempt from such penalties except during the June-September summer peak season.)
Members discussed the best way for PJM to communicate the start and stop times of a performance hour. PJM is proposing to post the information in a banner on its Emergency Procedures web page. The notice would direct resource owners to a page where they will be able to find what is expected of them.
Several stakeholders said the information is so crucial that an alert should be placed on the PJM homepage.
PJM Assistant General Counsel Jen Tribulski cautioned that the placement of the notice on the site would not affect market sellers’ responsibility to perform.
“You’re excused from the penalties during the assessment hours if PJM didn’t call on you,” she said. “If we’ve called on you and we have not dispatched you down, you are expected to perform, regardless of whether there’s any notification on our website.”
Also under review is a new signal providing a “desired” basepoint that would be used during performance hours, but it’s not clear whether the signal would recognize a resource’s economic max or unforced capacity commitment.
Members also were told that all units must operate under their local reliability constraints, but having to do so will not excuse them from penalties for not meeting performance requirements.
Charter Approved for Metering Task Force
The committee approved a charter for a task force charged with reviewing metering policies and requirements and implementing best practices.
The group will consider classifications such as real-time telemetry versus revenue metering, generator versus transmission system metering and large generation versus distributed generation applications.
The task force will report recommended manual revisions to the OC. Its work is expected to take six months.
FERC last week rejected SPP’s proposal to create a new class of seams transmission projects, saying its plan was too broadly drawn (ER15-2705).
The commission’s Nov. 30 order said that SPP did not distinguish “the criteria to be deemed a seams transmission project from the criteria to qualify under SPP’s Order No. 1000 interregional processes.” It said the revisions “do not contain any prohibitions or limitations to support SPP’s assertions” that projects eligible for its Order 1000 interregional processes may not be classified and evaluated as seams transmission projects.
FERC rejected SPP’s request to create a new class of seams transmission projects to supplement its approved highway-byway cost allocation.
SPP had proposed seams transmission projects as a new category to fill a gap in its transmission planning. It said the proposal would identify potential transmission projects that “may fall outside the Order 1000 interregional planning process or may not be eligible for cost allocation under SPP’s Order 1000 interregional processes,” such as projects involving external entities that are not neighboring planning regions.
SPP’s current rules designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a region-wide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.
SPP proposed to define a seams project as one operating at 100 kV or above and costing at least $5 million. It proposed a default regional cost allocation for such projects, with the RTO’s Board of Directors able to choose an alternate allocation at its discretion under certain conditions.
Xcel Energy protested the proposal, saying SPP had not provided “adequate analytical support” for the new category.
FERC agreed, saying the planning process for seams transmission projects “lacks clarity and does not adequately explain” how a seams project would progress from project identification to construction approval. It said SPP’s proposal for projects identified through joint special studies or coordination agreements “does not adequately define the methodology it will use to evaluate the project’s regional benefits.”
FERC said it wasn’t clear that regional review “will be transparent and include sufficient stakeholder involvement.”
The commission said, however, that SPP could make project-by-project filings for non-Order 1000 facilities that “may relate to seams concerns with an associated cost allocation and [justification for] the specific cost allocation.”
SPP legal staff expressed confusion over the ruling during a Dec. 3 meeting of the RTO’s Seams Steering Committee, saying it is “still digesting” the order.
VALLEY FORGE, Pa. — The Planning Committee approved changes to Manual 19 allowing distributed solar generation to be included in the load forecast model.
The group was split in its decision, with 77 voting yes, 18 voting no and 89 members abstaining.
Steve Herling, PJM vice president of planning, said adding distributed solar will lower the load forecast.
PJM’s John Reynolds explained that to create a history of solar generation, planners used the generator attribute tracking system, or GATS.
“We know where they are, how big they are and how long they’ve been there,” Reynolds said of the panels, which Herling noted are the ones not participating in the PJM market.
“We’re not talking about big solar farms,” Herling said.
Planners leveraged that with information from the National Oceanic and Atmospheric Administration to calculate where the sun was in the sky at various times and locations. Each panel was assigned to a weather station for information on cloud cover. Together, the data can estimate how much light was hitting the panels.
That calculation of solar output was aggregated to a zonal number and subtracted from the metered load, Reynolds said, noting that there is virtually no solar metered data available.
The second step was to forecast solar additions by state, for which PJM contracted IHS Energy. Planners took into consideration that some of the new solar likely would be replacing older equipment.
Planners want to break out solar generation because it is growing faster than other behind-the-meter generation and they want to get ahead of the trend.
“It’s going to be important in the future. We’re comfortable making the adjustment now with a procedure that might need refinement,” Herling said. “It might not have a big impact now, but in five years it may. We want a procedure in place now for when solar takes off.” (See “New Load Forecast Model, Related Manual Changes Adopted” in PJM Markets and Reliability Committee Briefs.)
Regardless of PSEG Wheel, 4 Reliability Projects Necessary
Even if Consolidated Edison of New York stops using the so-called PSEG wheel to deliver power into New York City, four baseline upgrades in northern New Jersey are still needed, PJM told Transmission Expansion Advisory Committee members. (See Developer Questions Need for PSE&G Projects Without ‘Wheel.’”)
The four proposals, part of the Regional Transmission Expansion Plan, include the Sewaren storm-hardening project, two sections of the Bergen-Linden Corridor and the Edison Rebuild.
The cost allocation of three of the projects would change significantly in the absence of the wheel.
Currently, Con Ed and East Coast Power each share about half of the cost of the Sewaren upgrade. The change would move all of the cost to ECP.
All affected transmission owners would pay for the two sections of the Bergen-Linden Corridor under the current scenario. Absent the wheel, Con Ed’s allocation would be moved to ECP and Hudson Transmission Partners.
Planners to Recommend ComEd’s Loretto-Wilton Center Project
PJM planners in February will recommend the Board of Managers approve a market efficiency project to relieve constraints on a 345-kV line from Loretto to Wilton Center, Ill.
Proposed by Commonwealth Edison, the $11.5 million project will mitigate sag limitations on the line and replace the station conductor at Wilton Center.
The projected in-service date is 2019.
PJM Continues to Study Effect of Clean Power Plan
PJM is updating its analysis of the economic and reliability impact of EPA’s Clean Power Plan and expects to coordinate its work with MISO.
The primary study years will be 2023 and 2026. PJM also will look at years 2028 and 2030, but with less detailed modeling.
It will examine five mass- and rate-based scenarios for regional as well as individual state compliance.
States have until September to submit their compliance plans or request extensions from EPA.
The work is expected to be complete by July 31, and the TEAC will receive an update at its February meeting.
Connecticut regulators asked FERC last week to dismiss a complaint from a renewable energy developer that contends the state’s energy procurement practices violate the Public Utility Regulatory Policies Act.
The Connecticut Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority said Allco Renewable Energy’s complaint is without merit because it is challenging a procurement program created by state law “that is different than, and a supplement to, Connecticut’s federally mandated PURPA program” (EL16-11).
Allco asked FERC to void the state’s award of a contract to a 250-MW wind farm in Maine. It cited FERC and federal court rulings that say states have no authority to procure energy except under PURPA, which is limited to qualifying facilities (QFs) of 80 MW or less. (See Solar Developer Asks FERC for PURPA Enforcement.)
In their response, Connecticut officials said commission action is not warranted because Allco is not actually challenging the state’s PURPA program. “Petitioner does not complain about any aspect of Connecticut’s PURPA program and, in fact, concedes the ‘potential availability of a PURPA contract,’ but elects not to participate in the program,” the officials wrote.
“Petitioner is a disappointed bidder in the Connecticut renewables solicitation conducted two years ago,” they added. The officials said their procurement programs do not violate PURPA or the Federal Power Act. “Cognizant of the commission’s exclusive authority over wholesale sales of energy, the Connecticut agencies have not set or modified rates or otherwise acted on matters within the commission’s FPA authority,” they said.
Allco filed the complaint with FERC on Nov. 9 after a federal appeals court said the company had not exhausted its administrative remedies in challenging the state procurement.
Allco said that the appeals court’s decision endorsed its contention that the state had violated PURPA by preempting federal authority over wholesale contracts. However, the appeals court issued an amended decision on Dec. 1, disputing Allco’s characterization. The court said it “express[es] no view on the merits of Allco’s preemption theory.”
Ed Tatum Jr., long one of PJM’s most vocal stakeholders, will be taking his deep voice and courtly demeanor to MISO as American Municipal Power’s vice president of transmission.
Tatum, who has more than 30 years of industry experience, previously was vice president of RTO and regulatory affairs for Old Dominion Electric Cooperative.
In his new post, he will be developing strategies to reduce transmission costs for Columbus, Ohio-based AMP, which has 132 members in nine states.
“I have known the folks from AMP for many years in both the PJM and FERC forums and have always enjoyed working with them. They are smart, innovative, eager to effectuate meaningful and positive change, and fair,” Tatum told RTO Insider. “When this position opened up, we sat down, and I quickly realized this was an excellent opportunity for me — even with the consideration of leaving ODEC and Richmond after almost 30 years!”
In his new position, Tatum will continue to participate in PJM stakeholder committees as well as those of MISO, advocating on transmission- and reliability-related issues. He also will be involved in interpreting and implementing regulations developed by FERC.
Tatum also has worked with Oglethorpe Power Cooperative in Tucker, Ga., and the Rural Electrification Administration in D.C.
He holds a bachelor’s in electrical engineering from the University of Virginia and a master’s in business administration from the University of Richmond.
“Costs and other issues associated with transmission are extremely important to our members,” said AMP CEO Marc Gerken. “As transmission-dependent utilities, AMP members increasingly look to us for strategies and opportunities to control these costs.”
WASHINGTON — The transportation bill President Obama signed last week includes provisions intended to protect the grid from terrorist attacks and natural disasters, giving the secretary of energy emergency powers and creating a Strategic Transformer Reserve.
The legislation, which will provide $305 billion in highway funding over five years, cleared the Senate 83-16 on Thursday, following a 359-65 vote in the House. Obama signed the bill Friday.
The bill represents both a vindication and a rebuke of former FERC Chairman Jon Wellinghoff’s controversial campaign to raise awareness of the grid’s vulnerability to sabotage.
It also checked off an item on current Chairman Norman Bay’s wish list. Testifying before the House Energy and Power Subcommittee last Tuesday, Bay said it was essential that the government have emergency powers to respond to a cyberattack.
“That emergency authority does not need to reside with FERC. It could reside elsewhere in the federal government,” Bay said. “But someone needs to have it.”
Presidential Declaration
Title 55 of the bill includes five “Energy Security” sections, including Section 61003, which authorizes the president to declare a grid security emergency in response to a geomagnetic storm, electromagnetic pulse, or cyber or physical attack. Such a declaration would authorize the energy secretary to issue emergency orders to protect or restore electric infrastructure critical to “national security, economic security, public health or safety.”
The emergency orders could apply to the North American Electric Reliability Corp., regional entities and owners and operators of critical electric infrastructure.
The bill gives the secretary six months to develop rules of procedure regarding the exercise of emergency authority. FERC would be permitted to order cost recovery for such actions assuming the costs were “prudently incurred and cannot reasonably be recovered through regulated rates or market prices.”
Entities complying with emergency orders would not be liable for violating the Federal Power Act, FERC orders or reliability standards as long as they did not act in a “grossly negligent manner.”
Another provision, Section 61002, clarifies that generators won’t be liable for exceeding emissions limits while operating under emergency orders. Such orders would be required to minimize environmental impacts and limited to 90 days but could be renewed.
Strategic Transformer Reserve
Section 61004 requires the secretary to submit a plan to Congress within a year for the development of a Strategic Transformer Reserve, including enough large transformers (100 MVA or higher) and trailer-mounted emergency mobile substations “to temporarily replace critically damaged large power transformers and substations that are critical electric infrastructure or serve defense and military installations.”
Wellinghoff a Lightning Rod
The provisions are a response to the April 2013 attack on Pacific Gas and Electric’s substation in Metcalf, Calif.
Metcalf Substation
At least two gunmen were believed involved in the attack on the 500/230-kV substation near San Jose, causing more than $15 million in damage that idled the substation for nearly a month. The gunmen targeted transformer radiators, firing an estimated 150 rounds and hitting 10 of 11 banks.
Wellinghoff, who served as FERC chairman from 2009 to 2013, called the Metcalf attack “the most significant incident of domestic terrorism involving the grid” to date.
The former chairman found himself under fire after The Wall Street Journal quoted him in articles about a confidential FERC analysis that concluded the country’s entire grid could be shut down for weeks or months by disabling only nine critical substations. Transformers are typically custom designed and can take 18 to 36 months to replace.
The newspaper did not identify the locations of those substations or its source for the study, but it quoted Wellinghoff saying “there are probably less than 100 critical high voltage substations on our grid in this country that need to be protected from a physical attack.”
NERC, members of Congress and Wellinghoff’s former FERC colleagues complained that the disclosures had jeopardized, not improved, security.
Wellinghoff also came under scrutiny in February, when Department of Energy Inspector General Gregory Friedman warned that FERC’s protection of information on the vulnerability of the grid is “severely lacking” and suggested that Wellinghoff had not been truthful when questioned about the disclosures. (See DOE IG Warns FERC Information Security ‘Severely Lacking.’)
Critical Electric Infrastructure Information
Section 61003 requires FERC to develop regulations governing how it classifies information as critical electric infrastructure information (CEII), including “appropriate sanctions … for commissioners, officers, employees or agents of the commission who knowingly and willfully disclose critical electric infrastructure information in a manner that is not authorized.” The section also exempts CEII from disclosure under federal, state or local public records laws.
The former chairman, currently a partner at the energy law firm of Stoel Rives, did not respond to a request for comment.
Pipeline Drills
The bill echoes steps taken by FERC and RTOs to improve gas-electric coordination following the 2014 polar vortex, when some fossil fuel plants had to shut down for lack of fuel.
It requires the energy secretary to improve DOE’s assessments of supply chain problems and to streamline processes for obtaining temporary regulatory relief to speed up emergency response. It also mandates emergency drills involving state and federal officials and oil and gas pipelines. (Section 61001, Emergency preparedness for energy supply disruptions.)
The final energy section, 61005, requires the secretary to propose within one year a method for evaluating how government policies impact energy supply and diversity, competitive energy markets, the U.S. balance of trade and national security.
The provision appears to be at least in part a response to complaints that EPA’s Clean Power Plan will weaken fuel diversity by replacing coal-fired generation with gas and renewables. Its sponsor, Rep. Richard Hudson (R-N.C.), opposes the EPA rule.
More to Do
In her own testimony before the House subcommittee last week, Commissioner Cheryl LaFleur suggested policymakers have more work to do.
“I think that the [reliability] standards that we’ve put in place, which require every transmission owner to identify the most critical facilities and protect them, are an important step,” she said. “But I think beyond that, a lot of the protection has to come from how we build the grid — building more redundancy so we kind of ‘de-criticalize’ those places so that a physical attack won’t cause as much damage, and building in more standardization so if something goes wrong we can share transformers more rather than having to build a custom one in every place.”
MISO’s research and development team has been tapped to take part in a Department of Energy project to design faster and more accurate generation dispatch software.
MISO is partnering with Pacific Northwest National Laboratory, General Electric’s Grid Solutions and Gurobi Optimization in the $3.1 million, three-year High-Performance Power-Grid Operation (HIPPO) project, which is being funded by the department’s Advanced Research Projects Agency-Energy (ARPA-E).
The project seeks to ease grid operators’ optimization challenge — dispatching the cheapest generation to meet loads while maintaining reliability — through algorithms that allow supercomputers to conduct multiple equations simultaneously.
Jeff Bladen, MISO’s executive director of market design, called HIPPO “a more robust approach to [security-constrained unit commitment] platforms that are used on a daily basis.”
“This has become increasingly challenging as the power grid grows in complexity, including the addition of intermittent renewable energy, new regulations and the increased use of natural gas and smart grid technologies,” Pacific Northwest National Laboratory said in a release on the project. “HIPPO could save consumers and power grid operators billions of dollars while also enabling greener and more sustainable grid operations.”
MISO Wants to Know if Data-Gathering Rule Spells Tariff Changes, Audits
MISO officials will be watching closely today as FERC conducts a technical conference on its Notice of Proposed Rulemaking requiring RTOs and ISOs to begin registering market participants through common alpha-numeric identifiers (RM15-23).
The NOPR, issued in September, would require market participants in RTOs to report extensive information about themselves and acquire a Legal Entity Identifier. FERC said the rule would aid its enforcement efforts by providing a way for identifying connections between companies and individuals. (See Are You Two Related? FERC Wants to Know.)
“We want to understand what the definition [of connected entities] is so we know what we need to do,” said Dustin Grethen, a credit analyst at MISO.
Grethen said MISO needs to figure out if it will have to replace the Tariff term of “affiliate” with “connected entity” and whether the RTO would be required to audit connected entities based on the information contained in the submission alone. “MISO wouldn’t be in a very good position to determine if [that data] is correct and right,” Grethen said.
Aaron Fate, MISO’s senior corporate counsel, said MISO found the NOPR a “little opaque.”
Stakeholders: Ramp Capability Needs Explanation Before Product Testing
Stakeholders called on MISO to provide more information before beginning testing of the RTO’s new ramp capability product in a month.
MISO expects to receive the software from its vendor this month, then have market participants take part in product testing in mid-January. The RTO is targeting an April 1 “go live” date pending a compliance filing with FERC.
The software is designed to alleviate net load variations by setting aside rampable capacity from the five-minute dispatch interval.
Dhiman Chatterjee, MISO’s senior manager of market analysis, said “more detailed discussion” is needed on whether the software will be programmed for the existing hourly integrated prices or new five-minute dispatch settlements.
MISO’s Kevin Larson said the software will be particularly helpful in managing wind generation.
Discussions on providing both up ramp capability and down ramp capability products began over two years ago, and some stakeholders said the information posted on the topic has grown stale.
“A lot of ramp capability information is from 2013,” observed Amber Metzker, Xcel Energy’s manager of market operations.
Likewise, Travis Stewart, a senior associate with Gabel Associates, asked MISO to update the Q&A document to reflect its most recent information. Jeffery Moore, with Ameren Missouri’s project management team, asked for a workshop to be held on the subject. Larson agreed; at press time, no date had been set for the workshop.
Testing, testing…
MISO is seeking to increase participation in its monthly load modifying resource drills.
Danielle Logsdon, senior project specialist, said the drills, held the second Tuesday of each month, exist to ensure reliability during shortage conditions and that generators know the process for emergency response.
According to MISO, as many as 55 market participants receive drill scheduling instructions every month. Of those, an average of six persistently take no action, even after MISO makes follow-up calls.
“Consistently, it’s the same [market participants] that do not participate,” Logsdon said.
MISO’s Demand Response Working Group asked that the Market Subcommittee take up the issue. Logsdon invited stakeholder suggestions on how to improve participation.
“I think the purpose for this surfacing is we’ve had the same level of non-participation from the same companies. That’s how they want to run their shop,” said DeWayne Todd, chair of the working group. Todd also asked stakeholders for suggestions on how to get non-participants involved in drills.
FERC last week granted Talen Energy’s request to sell four generators totaling 1,351 MW to satisfy divestiture conditions the commission ordered last year in approving the company’s spinoff from PPL and Riverstone Holdings (EC14-112-02).
The original order offered two divestiture options; the alternate proposal FERC approved last week was submitted by Talen in September. (See Talen Seeks Change in Divestiture Options.)
FERC said the plan was in the public interest and had a comparable effect on competition as the other options.
Talen already has announced sales agreements for the four plants.
One is the 399-MW Crane coal-fired facility in Baltimore, which is being purchased by an affiliate of Avenue Capital Group, a global alternative investment firm, for an undisclosed sum. (See Talen to Sell Crane, Gets FERC OK on Deals.)
The remaining three are in Pennsylvania: The 704-MW combined-cycle Ironwood plant is being sold to a subsidiary of TransCanada, based in Calgary, for $654 million. The Holtwood and Lake Wallenpaupack hydroelectric projects, with a combined generating capacity of 292 MW, are being bought by a subsidiary of Quebec-based Brookfield Renewable Energy Partners for $860 million. (See Talen Energy to Sell 3 Pa. Generators for $1.5 billion.)
Talen requested the third divestiture option after failing to negotiate a lease extension for its 158-MW combined-cycle plant in Bayonne, N.J., which was part of the original two options. The lease expires Oct. 31, 2018, and Talen has notified PJM that it intends to deactivate the plant the following day.
That plant provides steam to a tank terminal storage facility, which owns the land on which the generator sits. That facility is owned by a subsidiary of the Australian conglomerate Macquarie Infrastructure.
Macquarie filed the only protest to Talen’s divestiture request, saying the terms of Bayonne’s lease have been known for the past 28 years — contrary to Talen’s claims that the lease termination was “not foreseeable or reasonably certain to occur when Bayonne was first included in the mitigation options.”
In its protest, Macquarie said it made an offer to buy the facility, “but the second stage of the bidding process was canceled before completion.”
FERC’s decision allows Talen to retain a group of generators known as the “Sapphire Units.” To address the commission’s concerns of horizontal market power, Talen will offer them into the PJM energy market within the 5004/5005 submarket at cost-based offers.
