Xcel Energy stressed its renewable credentials Thursday following the release of its second-quarter earnings, detailing recent developments that will lessen its reliance on fossil fuels.
“We are excited by the opportunity to create a cleaner sustainable energy future for our customers,” CEO Ben Fowke said during a conference call.
In July, the company filed with the Minnesota Public Utilities Commission its Upper Midwest resource plan, which calls for the retirement of the King and Sherco 3 coal plants, extending the life of the Monticello nuclear plant to 2040, and the acquisition of a combined cycle natural gas facility and construction of another. The plan would also add 4 GW of solar and 1.2 GW of wind energy as a replacement for the closed plants, putting its Northern States Power Company-Minnesota subsidiary on a path to be 100% carbon-free by 2050.
A second Xcel subsidiary, Southwestern Public Service, energized the 478-MW Hale Wind Project on time and under budget, the company said. Another wave of renewable projects is expected to be completed between 2019 and 2021. In Colorado, the legislature passed a bill that will allow Public Service Company of Colorado to pass on the cost of its plans to reach 80% and 100% carbon-free electricity by 2030 and 2050, respectively.
Xcel’s Hale Wind Project | Xcel Energy
The positive news was offset by Xcel’s earnings, which fell 7 cents short of Zacks Equity Research’s expectations. The company reported earnings of $238 million ($0.46/share), a drop from last year’s $265 million ($0.52/share).
Executives blamed the showing on unfavorable weather and increased depreciation, interest, and operating and maintenance expenses.
Fowke said the company is still “well positioned” to deliver earnings at or above the midpoint of its 2019 guidance range of $2.55 to 2.65/share. “We are very confident we will deliver on our financial objectives as we have in the past,” he said.
Investors reacted positively, driving Xcel’s stock price up $1.91 to $60.76.
Talen Energy this week agreed to pay a $1 million fine after toxic waste from one of its Pennsylvania coal plants seeped into groundwater and the nearby Susquehanna River.
The settlement comes as part of a consent decree ordering the company to close and excavate its last remaining unlined coal ash pond at the Brunner Island plant in York Haven, where some 442,000 tons of combustion waste piles up each year.
“We are proud to have been able to reach an amicable settlement that will promote transparency, accountability, and, most importantly, environmental protection,” said Mary Greene, deputy director of the Environmental Integrity Project. “Talen Energy deserves credit for stepping up to the plate and agreeing to measures that should significantly reduce pollution.”
“Talen is committed to complying with all environmental regulations and will continue to focus on the safe, efficient and reliable operation of our plants,” Debra Raggio, the company’s senior vice president of regulatory and external affairs, said in a statement Wednesday.
Talen Energy agreed to pay a $1 million civil penalty for toxic waste seepage from its Brunner Island plant that polluted the Susquehanna River in York County, Pa. | Talen Energy
EIP, in conjunction with the Pennsylvania Department of Environmental Protection, last year filed suit against Talen in federal court on behalf of three local environmental groups — Lower Susquehanna Riverkeeper Association, Waterkeeper Alliance and PennEnvironment — who claimed the company violated the Clean Water Act by improperly disposing of coal ash waste and polluting the Susquehanna, the Chesapeake Bay’s largest tributary. The groups also appealed a state board’s decision to reissue Talen’s National Pollutant Discharge Elimination System (NPDES) permit.
Talen agreed to the settlement on Wednesday, which requires the company to pay the fine, clean up the offending ash pond, monitor other waste sites for pollution seepage and contribute $100,000 to fund other local projects aimed at reducing water pollution.
“This enforcement action is one of historic proportions, since it’s the largest penalty ever assessed at a coal ash pollution site in Pennsylvania history,” said David Masur, executive director of PennEnvironment. “We are glad to see DEP working with citizen groups to reach this important settlement for the good of the commonwealth.”
Brunner Island began operating in 1961 as a coal-fired power plant. For decades, the company disposed of toxic coal ash waste in seven unlined ponds and a landfill spread across 367 acres wedged between two river tributaries known as Black Gut and Conewago creeks. Environmental groups argue the ponds allowed boron, lithium and arsenic — a known carcinogen — to seep into the groundwater, the creeks and — ultimately — the Susquehanna.
Talen discontinued using its last remaining pond in June and will accelerate plans for excavation in accordance with the settlement, disposing of all leftover waste by Dec. 31, 2031. The company must also perform regular testing to ensure the liner and leachate collection system at its landfill site remain functional. Doing so will keep the plant in compliance with its NPDES permit.
Lisa Hallowell, senior attorney for EIP, said the agreement will “reduce the impact of toxic coal ash pollution on ground and surface waters, better control the plant’s wastewater discharges, ensure discharge of heated water is protective of aquatic life, and improve water quality for the Lower Susquehanna River and its tributaries.”
Raggio said the settlement — still awaiting approval from the U.S. District Court for the Middle District of Pennsylvania — is memorialized in the consent decree and demonstrates the company’s willingness to proactively maintain compliance with its permits. Talen also converted much of the plant’s output to natural gas in 2016, but the company expects it will continue burning coal for the next decade.
“In this settlement, Talen is addressing inherited legacy issues at these ash basins as we continue efforts to reduce Brunner Island’s environmental footprint by utilizing natural gas and phasing out coal,” she said.
“We hope more coal plants nationwide will follow this example,” said Larissa Liebmann, an attorney for the Waterkeeper Alliance. “It is imperative to our nation’s waterways and communities that industry not only excavate leaking coal ash basins but take additional measures to protect public health and the environment.”
DES MOINES, Iowa — With the U.S. Senate bolting from D.C. on Friday for a five-week recess, it’s becoming apparent that FERC will be operating with only three commissioners until at least well into September, according to a lawyer with the agency.
Patrick Clarey, a FERC attorney and liaison to SPP, told stakeholders Monday that a lack of paperwork from the White House suggests the commission may be at “three [commissioners] for a bit.”
FERC will soon find itself two short of a full panel when Commissioner Cheryl LaFleur, who has been on the commission for nine years, retires at the end of this month. (See FERC Heaps Praise on Departing LaFleur.) The fifth seat has been open since the death of Commissioner Kevin McIntyre in January.
The vacancies have drawn the attention of Sen. Joe Manchin (D-W.Va.), ranking member of the Energy and Natural Resources Committee. In a statement released by his press secretary Tuesday, Manchin urged the Trump administration to simultaneously nominate two individuals, one Republican and one Democrat, to fill the empty seats.
“FERC was established as a five-member commission and has historically operated above the political fray,” the statement read. “In today’s changing energy environment, it has never been more important to the security of our nation to maintain this precedent. I urge President Trump to nominate two individuals … so the Senate can consider and confirm them together in the bipartisan manner that has become the norm and restore a fully functioning commission.”
The White House has yet to submit a nominee replacing McIntyre. FERC can have no more than three commissioners from the same political party, with the president’s party holding the advantage. Traditionally, the Senate caucus for the party not holding the White House recommends its party’s nominations to the president, who usually complies.
The commission will continue to have a quorum with Chairman Neil Chatterjee and Commissioner Bernard McNamee, both Republicans, along with Democratic Commissioner Richard Glick.
Chatterjee has the most seniority, having been confirmed in August 2017. He became chairman last October, when McIntyre had to step down as his illness worsened. Glick was confirmed in November 2017 and McNamee last December.
FERC operated without a quorum for six months in 2017 before the confirmation of Chatterjee and Robert Powelson, who left the commission in August 2018.
CAISO secured the largest chunk of the Western Energy Imbalance Market’s $86 million in gross benefits during the second quarter as the solar-heavy ISO exported nearly 2.16 million MWh to its neighbors during the period — more than seven times the volume of the market’s next biggest exporter.
The quarterly benefits report released by CAISO on Wednesday showed the market’s estimated benefits rose 21% compared with a year earlier and just slightly from the first quarter. (See Cold Forces NW to Dip More Deeply into EIM as Avista Joins.)
The report illustrates a continuation of a trend in which CAISO exports large amounts of surplus solar energy to fellow market participants during the spring as California demand recedes because of mild weather. The ISO’s exports were up nearly 14% compared with the second quarter of 2018. (See EIM Benefits Surge to $71.2M in Q2.)
But despite that boost in exports, CAISO’s benefits declined by almost 16% year over year to $23.53 million, the result of competition from lower-priced exports. The Arizona Public Service balancing authority area (BAA), which also boasts strong solar capacity, saw its net exports surge by more than one-third to 305,752 MWh, while its overall benefits declined slightly to $8.55 million.
The EIM defines benefits as cost savings from serving load, increased merchant profits and the avoided curtailment of surplus low-cost renewable energy.
Following the pattern of previous springs, PacifiCorp once again absorbed the largest share of the cheap power, taking about 1.88 million MWh of net imports into its PacifiCorp-East (PACE) and PacifiCorp-West (PACW) BAAs, up 27% from a year earlier. The utility’s benefits surged 30% to $15.15 million.
Map shows the transfer paths available among Western EIM participants. | CAISO
Powerex doubled its year-over-year net imports to 360,341 MWh, signaling that a relaxation of EIM local market power mitigation rules — which had previously forced the hydro-rich company to bid energy into the market when it actually intended to buy — had freed its hand to engage in its customary practice of buying heavily during periods of oversupply. (See CAISO Board OKs Market Power Mitigation Remedy.) The Canada-based marketing arm of BC Hydro saw its benefits jump 37% to $3.06 million.
Portland General Electric earned the third-largest share of market benefits at $10.89 million, followed by the EIM’s newest member, Balancing Authority of Northern California at $8.81 million. Trailing APS in the benefits roundup were Idaho Power ($8.33 million), NV Energy ($4.62 million) and Puget Sound Energy ($3.06 million).
NV Energy maintained its position as the BAA with the largest volume of wheel-through transfers at 659,897 MWh (far outpacing its combined 382,167 MWh of exports and imports), followed by APS at 514,915 MWh and PACW at 252,686 MWh, showing the various paths California’s solar exports followed to serve the coal-heavy PACE territory.
The EIM helped its participants avoid curtailment of 132,937 MWh of renewable energy during the quarter, displacing about 56,897 metric tons of CO2 emissions. The market has reduced CO2 by 403,546 metric tons since 2015.
The ISO estimates the EIM has yielded $736.26 million in gross benefits since it was launched with PacifiCorp as its first member in November 2014. Future participants include Salt River Project and Seattle City Light, scheduled to join in April 2020; Los Angeles Department of Water and Power, NorthWestern Energy, Turlock Irrigation District and Public Service Company of New Mexico (2021); and Tucson Electric Power and Avista (2022).
Transmission owners will not be covered by revisions to NERC reliability standard PRC-024-2 concerning inverter-based generation resources, the standard development team said Wednesday (Project 2018-04).
In a comment period that closed July 26, respondents gave a “resounding yes” to extending the standard to cover the setting of voltage and frequency protective relays on generator step-up (GSU) transformers or collector transformers, NERC standards developer Mat Bunch said. Twenty-nine entities endorsed covering the GSUs, with eight in opposition. (See Comments due July 26 on Revised Inverter Standard.)
This illustration is the frequency curve for reliability standard PRC-024-2. The standard specifies a “no-trip” area for voltage and frequency excursions, as measured at the point of interconnection to the bulk electric system. A report on the Blue Cut fire disturbance concluded that solar development owners and inverter manufacturers have misinterpreted the area outside of the “no-trip” curve as a “must-trip” requirement. | PRC-024-2 Gaps Whitepaper, NERC Inverter-Based Resource Performance Task Force
But Bunch said the standard will not cover TOs that own a GSU or collector transformer and are not registered as generator owners because the comments did not identify any such TOs in the U.S. “This is not a continent-wide issue at this time,” Bunch said. “We still can’t find one in the U.S.”
TO Hydro-Québec TransÉnergie said it owns the GSUs associated with about 37 GW of generation that it does not own. “We are not registered as a GO since we do not own any generators,” the company said.
Bunch said most of the “no” votes were indications of opposition to TOs being covered.
“What I heard back from people unofficially [was] if TOs weren’t included, industry could probably support … the standard,” Bunch said. “I do know that people were voting ‘no’ on the standard only because of the TO issue.”
Comments
The SDT is working to develop a revised standard to address issues identified in the Inverter-Based Resource Performance Task Force’s PRC-024-2 Gaps Whitepaper. The task force was formed in 2017 following the August 2016 Blue Cut wildfire, when 1,200 MW of solar disconnected, and the October 2017 Canyon 2 fire, which resulted in the loss of more than 900 MW.
The stakeholder comments came in response to a “supplemental” standard authorization request (SAR), which expanded the project’s scope to include the GSU and collector transformers and consider TO requirements.
Dominion Energy said GSUs and collector transformers “have never been part of PRC-024” and that the project’s scope “should NOT be expanded to an issue that has not been substantiated and reliability risk identified.”
Southern Co. contended the supplemental SAR did not make the case for expanding the scope, saying “the protection elements on main station transformers have not been reported to have been, nor are known to have been, the cause of plant tripping due to transmission system voltage or frequency disturbances.”
American Electric Power raised procedural concerns, saying NERC’s Standards Process Manual does not allow “multiple, concurrent SARs to govern a single NERC project.”
“If this project’s scope or direction needs to be revised, the current and governing SAR should be revised accordingly rather than developing an additional SAR to somehow expand upon its predecessor,” AEP said.
Ontario’s Independent Electricity System Operator said it supported the amended SAR but that it didn’t go far enough. “The scope should also include auxiliaries critical to maintain plant output. The supply to other critical auxiliaries, like lubricating systems, [and] governing and excitation systems that allow the generating unit to maintain its output level, must also meet PRC-024 requirements for reliability.”
The ISO/RTO Council Standards Review Committee noted that PRC-024 was developed when generators and GSU transformers were generally controlled by the same asset owner. “As such, coordination between generator protection schemes and associated transmission equipment may not have required any explicit requirements and the PRC-024 applicability to only the generator side of the interconnection was sufficient. Today, with the separation of ownership of assets at the generator point of interconnection, NERC must ensure the intent of PRC-024 is met through adding explicit requirements which may or may not fall within the original construct of the standard,” it said.
In the first ballot, which ended May 31, the proposed standard was supported by a weighted vote of 3.085-2.815 (52.3% in favor). It will be posted for a second ballot Sept. 13, closing Oct. 28.
A standard must receive two-thirds support before going to the final ballot. Once that threshold is reached, the drafting team and NERC staff will review the comments received and determine whether additional changes are necessary. If there are substantive changes, it is posted for an additional 45-day ballot. If the changes are minor, it would proceed to a 10-day final ballot, according to NERC spokeswoman Kimberly Mielcarek.
NERC has hired Lyceum Leadership Consulting to find replacements for former CFO Scott Jones and General Counsel Charles “Charlie” Berardesco, who is retiring this month. (See NERC Seeking New CFO, Counsel in Apparent Shakeup.)
Lyceum will conduct the executive search and provide candidates to NERC CEO Jim Robb.
As part of its search, Lyceum posted an hourlong audio program describing NERC’s role and including Lyceum founder Thomas Linquist’s interview with Robb and Berardesco.
With the departures of Scott Jones and Charles Berardesco, NERC CEO Jim Robb will have replaced three of his top officials. NERC’s proposed 2020 business plan also reduces Robb’s direct reports to five from eight. | NERC
Lyceum said candidates to replace Berardesco should possess legal and regulatory experience; strategic orientation (“creative and capable of thinking broadly about business … viewed as a potential successor to the CEO”); skills in “collaboration and influencing”; a results orientation (“ability to anticipate and prevent problems”); team leadership and people development; and cultural sensitivity (“ability to work as part of a business with a strong and diverse culture”).
Lyceum expects to accept applications through Sept. 18 and submit a “longlist” of candidates on Sept. 20, with the shortlist determined Sept. 27. Interviews will be scheduled in late October and early November.
DES MOINES, Iowa — Nick Brown remembers clearly back to 1985, when, as a young planning engineer, he took a leap of faith and joined an Arkansas company called Southwest Power Pool as Employee No. 7.
Back then, SPP was a much smaller regional organization and had yet to be incorporated. The Nebraska utilities had not joined, the Integrated System hadn’t been integrated and operations in Arizona were unthinkable.
“I just jumped at [the opportunity],” Brown said. “A lot of people thought I was crazy for … joining an organization that was not even incorporated at the time. It didn’t exist.”
On Tuesday, Brown, 60, told SPP’s Board of Directors he will be retiring after almost four decades in the electric industry and 35 years with the RTO, 16 as its CEO. His retirement will become effective in April 2020, by which time SPP will be a reliability coordinator and offering market services to companies in the Western Interconnection. (See SPP on Track for WECC RC Certification.)
Brown was elected CEO in December 2003, replacing John Marschewski. Since then, he has overseen the organization’s recognition by FERC as an RTO and the implementation of balancing and wholesale day-ahead markets. He has also focused the company on expansion into the Dakotas and as far west as Wyoming and Montana. SPP has invested nearly $10 billion in transmission facilities, and its footprint now extends to 14 states.
When the RTO was finally incorporated as a nonprofit in 1994, Brown notarized the legal documents. It still represents an important event to him.
“It still amazes me that this organization existed for 53 years and didn’t legally become a company until we incorporated,” Brown told RTO Insider. “It’s amazing how far we’ve come since then.”
“I have great appreciation for Nick’s contributions to an incredible amount of the RTO’s success,” Southwestern Public Service President David Hudson said. “His many years of service are remarkable.”
“It’s impossible to think of SPP without thinking of Nick Brown,” board Chair Larry Altenbaumer said. “[SPP’s] culture of collaboration was shaped and nurtured under Nick’s leadership.”
Mike Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy, has worked with Brown for 23 years and credited his vision, leadership and focus for SPP’s “great success.”
“He has helped foster the organization’s growth while meeting the needs of the members and focusing on end-use customers for those 35 years,” Wise said. “It was his desire to have an effective stakeholder-driven culture where all members who participate have a voice.
“SPP wouldn’t be here today at all in the way that it is without Nick Brown as a leader.”
Brown said his decision was a mutual one between him and his wife, Susan, and not driven by SPP’s recent mushrooming growth.
“I’ve been thinking about this for a long time. The timing was right,” he said. “There’s no right time. A lot of people have postulated that Nick’s going to wait for this or he’s going to wait for that. SPP will always be a work in progress. It didn’t make sense to me to wait any longer.”
He becomes the second RTO CEO to step down in the last two months. PJM’s Andy Ott retired in June. (See PJM CEO Andy Ott toRetire.)
Outside of serving on corporate boards, Brown said he doesn’t have much planned except to spend time with his four children and two grandchildren, all of whom live within 5 miles of his house.
Asked if he intended to travel, Brown said, “I’ve traveled almost every week for 35 years. I don’t view travel as one of my retirement passions.”
Altenbaumer said Brown will work with three board members to ensure a smooth transition for his successor. SPP has engaged management consulting firm Russell Reynolds to conduct a “comprehensive search” for Brown’s replacement.
Brown became a vice president and corporate secretary in 1998 before assuming the CEO’s role. He began his industry career with Southwestern Electric Power Co.
He holds physics and math degrees from Arkansas’ Ouachita Baptist University and an electrical engineering degree from Louisiana Tech University. A registered professional engineer, a master electrician and an instrument-rated pilot, Brown is a member of several engineering, technical and professional honor societies.
“I’ve never regretted [my decision] for a single day,” Brown told the board, Members Committee and other stakeholders. “It’s been a true pleasure over the years working with many of you around the table. April 1 is next year, so don’t get too excited. This organization runs through my veins; it just does.”
“While we have some very big shoes to fill, we have an organization with a future that is every bit as bright and exciting as it has been,” Altenbaumer said. Turning to Brown, he said, “My thanks to you for everything.”
Missouri regulators are wrapping up a probe into the self-commitment and self-scheduling of generation into wholesale energy markets, questioning whether the practice is good for customers.
Though the Missouri Public Service Commission might take steps to begin curbing the investor-owned utility practice of self-scheduling resources in MISO and SPP, regulators so far have not suggested any action, instead labeling the investigation opened last month as a simple fact-finding mission. The agency said it‘s currently examining whether the practice benefits or harms ratepayers.
The PSC also directed the state’s utilities to explain their approach to resource bidding and how they decide between self-scheduling and bidding into the market (EW-2019-0370).
Commission staff will file a report on their findings no later than Aug. 16.
Comments on the docket have so far fallen along predictable lines, with utilities defending self-commitments as necessary for the health of fossil-fueled resources and environmental nonprofits criticizing the practice as a means to keep uneconomic coal plants operating.
For Reliability
Ameren Missouri said while it self-commits several of its units in the MISO market at minimum output levels under the RTO’s must-run commitment mode, it does not self-schedule its units’ dispatch.
The utility explained it self-commits its coal fleet when those units will be expensive to restart, are being tested or to stave off forced outages or higher maintenance costs due to inefficient unit cycling. The company also pointed out its Callaway Nuclear Energy Center must remain online, so it designates the nuke as a must-run resource in MISO.
Ameren said MISO probably experiences more self-commitments than SPP due to it having more nuclear generation in its footprint.
Callaway Nuclear Energy Center | Fluor
Kansas City Power & Light similarly claimed its fossil units are only self-scheduled in SPP for “safety, reliability, economic and environmental compliance reasons.”
KCP&L said it must sometimes manage the number of thermal cycles for the sake of a plant’s longevity or run a steam-fired power plant to maintain reliability during cold weather.
“SPP’s market model isn’t always able to consider risks to KCP&L customers’ reliable power supply,” the utility said.
KCP&L said it also self-commits for compliance and post-outage testing, to keep wind generation economic and to commit units with startup times greater than 24 hours, something SPP doesn’t currently offer.
“The SPP market model does not currently do a good job committing large, baseload units with long lead times, large startup costs and long minimum run times,” KCP&L said.
In comments, Ameren Missouri raised a similar complaint with MISO’s day-ahead market algorithm, saying the limited, 24-hour advance economic evaluation is inadequate for making decisions on generation with long lead times that can also become worn out by cycling.
MISO — which has long kicked around the idea of implementing a multiday market — recently announced it will roll out a new and comprehensive multiday operating margin forecast — although it will not tie financial commitments to the new forecast. (See “MISO Eyeing 6-Day Margin Forecast” in MISO Market Subcommittee Briefs: July 11, 2019.)
Ameren Missouri said it strives to sell energy into the market only when it stands to benefit customers, but that it also must take unit longevity into account when making commitment decisions.
Wasteful?
Renewable energy advocates Advanced Power Alliance (APA) and Clean Grid Alliance (CGA) pointed to a spring Grid Strategies report that concluded self-scheduled resources should be brought into the organized markets. The report estimated self-scheduled coal plants caused excess fuel costs of at least $85 million in PJM and $127 million in MISO in 2017. The groups also cited 2018 Union of Concerned Scientists research that estimated coal generation self-scheduling in PJM, MISO, SPP and ERCOTplaces a $1 billion burden on ratepayers annually.
APA and CGA said self-scheduling and self-commitments muddy the intended transparency of RTO markets, adding self-scheduled generation is “often less responsive to market prices” and can increase prices passed on to consumers when other market generation is available at a lower cost.
“The issue before the commission in this case goes directly to the heart of market activity within MISO and SPP. The self-commitment and self-scheduling of generation can undermine the transparency created by these markets, as well as the overall goal of producing a reliable and economic generation commitment and dispatch that is good for consumers,” the groups said.
“It is no secret coal generators nationwide have struggled to remain economically competitive, which has a detrimental effect on ratepayers,” the Sierra Club commented. “Excessive and unwarranted self-generation by these same generators could compound the negative economic effects on ratepayers.”
The environmental group urged the PSC to compel utilities to provide the same, detailed reasons behind the instances of self-commitment and self-scheduling they provide to MISO and SPP.
The head of the standard drafting team considering modifications to NERC’s frequency response standard predicted generators will oppose a standard that mandates they provide the service.
Ethos Energy Group’s David Lemmons, chair of the team considering revisions to BAL-003-1.1 (Project 2017-01) said at least 60% of respondents to the group’s survey “said don’t do a generator requirement.”
“In the past, we’ve discussed issues that might be brought up related to the need for a governor requirement — one being: Performance is sufficient without it right now. Why are we trying to add more to it?” Lemmons said during a July 23 meeting.
The second objection has to do with transmission tariffs. Lemmons said a generation owner that is a load service provider recounted to him a conversation he had with his balancing authority.
“He said my BA came to me — he’s also my [transmission service provider] — and said my generator was not performing very well [in providing frequency response] and I have to improve. I said, ‘No I don’t. I’m paying for that [service] under … the tariff.”
Time frames involved in system frequency response. | Claudia Rahmann, Alfredo Castillo
Susan Morris, an electrical engineer in FERC’s Office of Electric Reliability, said she didn’t see the issue as an obstacle.
“The need for frequency response has been around for a long time. I wouldn’t worry about the tariff unless there is a direct conflict, and I don’t think there is. This is not a new need. I don’t see the correlation.”
“The generation owner’s paying for the service and he [says he] doesn’t need to provide it himself,” Lemmons persisted.
“Then that’s a problem there isn’t it? Maybe they need a requirement because [crafting a generator requirement] is the right thing to do for reliability,” Morris responded.
Lemmons asked NERC staff to provide an opinion on the issue “so that this team has it available for those comments when we receive them.”
FERC appears to have addressed the issue last year, when it ordered transmission providers to amend their pro forma generator interconnection agreements to require generators have governors or other equipment to respond automatically to frequency disturbances (Order 842, RM16-6).
In a subsequent rehearing order, the commission said its ruling did not imply existing generators are entitled to compensation for providing the service. FERC also rejected suggestions it had prohibited frequency response requirements on existing facilities, saying such a conclusion would be “inconsistent with the fundamental purpose” of ensuring reliability (RM16-6-001).
Consensus Reached
The existing BAL-003 standard requires balancing authorities or frequency response sharing groups, where applicable, to maintain interconnection frequency within predefined bounds.
Phase I of the BAL-003 project proposed changes to address inconsistencies in the calculations of interconnection frequency response obligations (IFRO).
Phase II of the BAL-003 project is considering potential changes to make IFRO calculations and associated allocations more reflective of current conditions, considering load response and the generation mix. The standard authorization request requires the team to ensure overperformance by one entity will not negatively impact the evaluation of performance by another and measurements of primary frequency response are considered in addition to those for secondary frequency response.
During a day-and-a-half of meetings last week, the standard drafting team reached consensus it does not want to impose a headroom requirement on generators, Lemmons said. The team considers that a decision the balancing authorities should make “based on economics or whatever process they use today.”
The team also decided to prohibit outer loop controls that defeat governors from responding, Lemmons said. Outer loop controls are used by generators that “don’t want their output to swing because of emissions issues [or because] the transmission tariff is telling the generator to be on schedule at all times,” he said.
The team also discussed changing the standard’s current requirement that FERC Form 1 data be used to monitor frequency response.
Lemmons said the team has discussed whether to recommend changing the current standard’s use of data from Frequency Response Survey (FRS) Form 1. The options being considered include an alternate data source or eliminating the data provision requirement.
We “don’t like the 1600 path,” Lemmons said, referring to the filing of a data request under section 1600 of the NERC Rules of Procedure. “We’re concerned a non-enforceable, non-push data gathering process may cause problems.”
Duke Energy’s Tom Pruitt urged the group to move forward in selecting one of the several proposals for modification of the standard.
“We’ve got some really sharp folks [on the team] but at the same time, we seem to just keep going around and around in circles, and I want to break the habit,” Pruitt said. “If you really want to get dramatic about it, call it an intervention.”
Not everyone is sold on NERC’s proposal to merge three technical committees into a single Reliability and Security Council (RSC).
The merger of the Planning, Operating and Critical Infrastructure Protection committees, announced in June, will reduce the committee membership from a combined 100-plus to 33 voting members and five non-voting members. (See Three NERC Committees Likely to Merge.)
The draft proposal by the Stakeholder Engagement Team (SET) is intended to improve efficiency in recognition of the increasing overlap among the committees’ work. NERC officials said the Member Representatives Committee (MRC) and the NERC board had received complaints that too much manpower was being spent in supporting the technical committees.
The new Reliability and Security Council will have 33 voting members and five non-voting members, a big reduction from the 100-plus members on the three committees it will replace. | NERC
NERC’s Stephen Crutchfield told the Resources Subcommittee during a briefing July 24 the new committee will use a “hybrid” of the regional representation used by the CIPC, the sector-based membership of the PC and OC and the at-large membership of the MRC and Reliability Issues Steering Committee (RISC).
The RSC will include one voting member from each sector (except for the regional entities), 20 at-large members, a chair and vice chair. The non-voting members will include the NERC secretary, two U.S. federal government representatives, one Canadian federal representative and one Canadian provincial member, “straight out of what the OC and PC do today,” Crutchfield said.
Members will be selected based on interconnection diversity, subject matter expertise and a mix of small and large entities, he said.
“It is my opinion this whole revision in this manner is going to reduce stakeholder participation,” said Gerry Beckerle, of Ameren. “It’s going to reduce the effectiveness and will reduce the [level] of expertise we have at this level … I think this is a near-sighted effort.”
Beckerle questioned how the new organization would affect participation by non-members. “There won’t be enough room anymore in the meeting [space] correct?”
“Well, I don’t know,” Crutchfield responded. “I’ve heard people say we could have up to 300 people at the first meeting of this thing, so plan accordingly.”
“The new NERC offices meeting space is going to be capable of handling that large of a group?” Beckerle asked.
“I don’t think so,” Crutchfield said.
“I thought one of the reasons [for the change] was so they could hold these meetings at the NERC offices,” Beckerle continued.
“This team has not discussed specifically about how the meetings are going to be run,” Crutchfield said.
He added initial plans to allow nonmembers to listen via WebEx have “been kind of panned. It could be logistically a nightmare.”
The new Reliability and Security Council will have 33 voting members and five non-voting members, a big reduction from the 100-plus members on the three committees it will replace. | NERC
The current schedule calls for seeking MRC endorsement on Aug. 14 and delivering a final proposal to the board Nov. 6.
Assuming board approval, nominations for the RSC would be opened in November with appointments in January or February and the first meeting in March.
Resources Subcommittee Chair Tom Pruitt, of Duke Energy, expressed concerns over the schedule. “It seems to be a pretty aggressive timeline, personally,” he said. “I’m not sure if you go this quickly you’re going to be able to work out all of the kinks and all of the details.”
Expertise Needed
Crutchfield said “the RISC is going to be more of a forward-looking group, whereas the Reliability and Security Council will be [implementing policy]. And they both report to the board [of trustees].”
He said the proposal to have 20 at-large members is recognition that combining the OC, PC and CIPC will require members with broader expertise. “Having that at-large [membership] allows you to find the right set of people who can cover all the aspects you’re looking for — the technical, the leadership, the project management kind of oversight people … Whereas with the sector-based [membership], you may have somebody who’s just completely operations-focused. So now you’ve got to find somebody else to fill that planning role or somebody else to fill that CIP role.”
Pruitt noted the proposed merger borrowed changes some of the regional entities, such as the Midwest Reliability Organization, have adopted.
But Beckerle said the regions’ committee structure is not applicable.
“Since NERC develops continent-wide policy, I think it makes sense we have a group such as the OC, PC and CIPC to provide detailed stakeholder technical direction to NERC,” Beckerle said. The regions “have a much different role in things than they used to back when there were quite a few regional standards, procedures and policies. I think trying to compare and duplicate what’s been successful at the region level is probably not fully appropriate at the NERC level.”
MRC Questions
The reorganization also was discussed at the MRC informational session July 19.
Mark Lauby, senior vice president and chief reliability officer, said he was not concerned about a loss of stakeholder engagement.
“Where the real work is going on is in the task forces, subcommittees and working groups … [The RSC] will enable us to make all three aspects — planning, operating and cyber — a focus and address those problems together as one chunk of work rather than fragmented. And I think it will create a lot more effective solutions,” Lauby said. “I don’t think we’re going to be losing that much when it comes to engagement at that project management level.”
Board of Trustees member Robert Manning praised the Stakeholder Engagement Team for its “innovation and creativity.”
“It’s sometimes challenging to move to a new structure when we know the structure we have is very effective,” he said. “I think you guys have tried to make sure we preserve the best of what we have and open the door to efficiencies going forward.”
He added: “The nominating process [for RSC members] is going to be very, very important.”
Board of Trustees Member David Goulding agreed. “It still seems to me there’s a fair bit of criteria work [that] needs to be done [on nominating RSC members], particularly if — being an optimist — we have a lot of people wanting to actually be members. … The criteria [are] going to be … interesting … to put together.”
Membership criteria will be defined in the participation model presented to the board in November.
A webinar on the proposal is set for Aug. 8. MRC members can provide feedback via the committee through Aug. 6. Industry comments to the board will be accepted through Aug. 15.
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