Page 1040 – RTO Insider

May 13, 2019

NERC MRC, Trustees Meeting Briefs: May 8-9, 2019

ST. LOUIS — Below is a summary of operational issues and personnel changes discussed at meetings of the NERC Member Representatives Committee (MRC) and Board of Trustees on May 8 and 9.

NERC Five-Year Performance Assessment

The board approved the filing of NERC’s Five –Year Performance Assessment with FERC, NERC’s argument for why it and the regional entities should be recertified as the Electric Reliability Organization under the Energy Policy Act of 2005.

In renewing NERC as the ERO in November 2014, FERC ordered it to continue to improve consistency and developing performance and reliability metrics (RR14-5). It also directed NERC to compare actual project completion times with estimated times and begin analyzing repeat violations by registered entities.

After NERC files the assessment, FERC will open a docket to invite public comment on the ERO’s performance.

Among the accomplishments NERC cited during the 2014-2018 assessment period:

The use of assessments and events analysis to identify, prioritize and mitigate risks to the bulk power system.
The enactment of reliability standards on cybersecurity, physical security and planning risks.
“Enhancements” to NERC’s Compliance Monitoring and Enforcement Program (CMEP) and its Electricity Information Sharing and Analysis Center (E-ISAC).
Improved efficiency by increasing the “alignment” of NERC and its REs.

Potential Change to Committee Structure

NERC is considering a restructuring of its Operating, Planning and Critical Infrastructure Protection committees to address the increasing overlap in their activities, Mark Lauby, NERC senior vice president and chief reliability officer, told the MRC.

Lauby said the current committee structure, which has been in place for more than a decade, is “expensive and time-consuming for NERC members.”

The accelerating speed of change is causing a “blurring” of the committee silos and requires “cross-cutting [and] rethinking of many utility paradigms,” he said, noting that several REs have changed their committee models.

Because each of the three “technical” committees “identify and assess risk,” Lauby said, a “stakeholder engagement team” that includes Lauby, MRC Chair Greg Ford and Trustees Ken DeFontes and Fred Gorbet, has been working since January on potential changes. The team is considering two alternatives:

Retaining the three committees while adding an Oversight Committee to coordinate their work; or
Replacing the three committees with a new Reliability Council reporting to the board.

The team will refine its proposal through July 18, when it plans a webinar to outline its plan. It is scheduled to be presented to the MRC about Aug. 15 and the board Nov. 6, with implementation in January.

Lauby said NERC’s “advisory” committees (Compliance Certification, Standards and Personnel Certification Governance) have “distinct” missions and are not part of the review. Also exempt is the Reliability Issues Steering Committee, which Lauby said “has a unique charge and participation model.”

On Thursday, the trustees approved amendments to the Standards Committee Charter to streamline it, clarify responsibilities and eliminate content discussed in other NERC governing documents, including provisions regarding Canadian representation and field tests. The charter was last changed in 2015.

Changes to State of Reliability Report

John Moura, NERC director of reliability assessment, said the organization is changing the format of its annual State of Reliability Report, reducing its length from more than 200 pages to less than 50 and replacing some tables with infographics. The report is intended to identify system performance trends and reliability risks, and measure the health of the grid and the success of mitigation measures.

Moura said the change in format resulted from a decision to make the report more useful to regulators and industry leaders.

Before, “the audience was everybody: It was engineers, policymakers; it was anyone who wanted to know something about reliability. And if it’s for everybody, it’s for no one,” he said. “So, we were really focused on, who was our target audience? And then that really kind of set the stage for everything else. I asked the question[s]: ‘What does [PJM CEO] Andy Ott want to know about this? What does [FERC Chair] Neil Chatterjee want to know?’”

The draft was circulated to the Operating and Planning committees for comment last week.

The board will review and approve the release of the report in mid-June, with a target release date of June 19, before FERC’s June 27 reliability technical conference.

Members Cautioned on Public Statements

General Counsel Charlie Berardesco disclosed that NERC’s Feb. 22 revision to its Participant Conduct Policy resulted from a Wall Street Journal op-ed whose author cited his NERC affiliation.

Although Berardesco did not identify the author, it was an apparent reference to a Feb. 20 o p -ed by Robert Blohm that said renewable energy can’t consistently balance power supply with demand. Blohm, a managing director at consultancy Keen Resources, was identified in the article as “an elected member of the Operating Committee and the Standards Committee” of NERC.

In a letter to the editor in response, Michael Goggin, vice president of consultant Grid Strategies, was likewise identified as “an elected member” of NERC’s Planning Committee.

NERC’s revised policy states: “Unless authorized by an appropriate NERC officer, individuals participating in NERC activities are not authorized to speak on behalf of NERC or to indicate their views represent the views of NERC, and should provide such a disclaimer if identifying themselves as a participant in a NERC activity to the press, at speaking engagements or through other public communications.”

“We understand that people want to be involved and work in the arena of advocacy,” Berardesco said. “But NERC has to have the ability to control the message on behalf of NERC.”

“If you are doing an op-ed … best not to reference NERC at all because it’s confusing,” Chairman Roy Thilly added.

Trustees’ Pay Unchanged

Trustee DeFontes told the board’s Corporate Governance and Human Resources Committee that NERC will not be changing the trustees’ salaries, which were last increased in August 2018. The board agreed then to increase the annual retainer by $15,000 to $127,500 in three $5,000 steps between 2019 and Jan. 1, 2021. The board chair’s retainer is being raised to $175,000 in three steps over the same time period. Committee chairs receive an additional $10,000 and vice chairs are paid $5,000 annually.

Budget Updates

The ERO expects to end the current fiscal year about $3 million (1.5%) over budget, largely because of SERC Reliability’s expansion into Florida, NERC Controller Andy Sharp told the board’s Finance & Audit Committee on Wednesday.

SERC is projected to run $5.1 million over budget because of its absorption of the Florida Reliability Coordinating Council, which expects to run $1.6 million below budget, a net increase of $3.5 million.

NERC and the remaining REs are expected to be at or near budget for the year, Sharp said.

Through March 31, the “ERO Enterprise” was $2.9M (5.9%) under budget for expenses and capital spending.

Chief Financial and Administrative Officer Scott Jones gave the committee a preview of the proposed 2020 budget, which anticipates a 3.8% increase after a 9.5% increase in 2019.

The projected assessment for 2020 is $72 million (+4.5%) from 2019, which was itself up 9.5% from 2018.

Costs for the E-ISAC are growing 13.3% while the rest of NERC will be flat to lower, Jones said.

Jones said “inflationary pressures on pay,” especially for technical roles, have forced NERC to boost its annual salary increases to 3.5% from a historical 3%.

Jones said NERC has had to become “more flexible” on pay ranges because of the competition for talent. “We’ve had a history of being very rigid on the pay side. When we budget something … we sort of box ourselves in a little bit for that particular role,” he said. “When we find good people, especially on the ISAC side, we want to negotiate hard and fair, but we also want to make sure we get good people.”

First drafts of the budget are expected to be posted about May 17, with comments due June 28. The final draft will be posted July 15, with comments due July 31.

Personnel Changes

The meetings included several personnel matters:

CEO Jim Robb announced the appointment by the board of new vice presidents Mechelle Thomas, chief compliance officer, and Howard Gugel, head of standards and engineering.
George Hawkins | © RTO Insider

Nominating Committee Chair George Hawkins announced that the committee agreed to renominate Thilly and Trustee Suzanne Keenan to new terms and has hired executive search firm Leadership Lyceum to seek a new candidate to replace Janice Case, who will end her final term in February 2020. The trustees will review candidates at their next quarterly meeting in August. (The board increased to 12 members with the election in February of Colleen Sidford, representing Canada. It will drop back to 11 in February 2020 following the departure of Case and Frederick W. Gorbet.)

The trustees also approved the following committee appointments:

Critical Infrastructure Protection Committee: John Greaves, Georgia Power, replaces Brian Harrell, formerly of Duke Energy as SERC’s representative. Doug Currie, Hydro One, replaces Francis Bradley of the Canadian Electricity Association as the CEA representative.
Reliability Issues Steering Committee: Woody Rickerson, ERCOT, replaces Dave Osburn, Oklahoma Municipal Power Authority, for a term ending Jan. 31, 2020.
Compliance and Certification Committee: Appointed Nicole Mosher, Nova Scotia Power, representing the Northeast Power Coordinating Council. Reappointed Gregory Campoli, NYISO, representing ISOs/RTOs; Ted Hobson, JEA, representing FRCC until its dissolution; Jim Stanton, SOS International, representing Small End-Use Electricity Generators.
Planning Committee: Appointed Richard Kowalski, ISO-NE, as an ISO/RTO representative for the remainder of the 2018-2020 term. Kowalski will fill a vacancy resulting from the passing of Dana Walters of NYISO.

— Rich Heidorn Jr.

May 12, 2019

PJM Advocates: Slow Down on Market Reforms, Except FTRs

By Christen Smith

CAMBRIDGE, Md. — Most of PJM’s recent market rule changes — including those still pending before FERC — came and went too quickly for the liking of advocate groups, though their desire for deceleration stops at an overhaul of financial transmission rights.

“Getting oversight is critical,” said Ruth Ann Price, Delaware Deputy Public Advocate, during the Public Interest & Environmental Organizations User Group’s meeting with the RTO last week. “PJM must decide with some urgency whether it wants to create a department internally [to oversee] FTRs or have this function go outside to a third party.”

The annual meeting between PJM and the Public Interest & Environmental Organizations User Group | © *RTO Insider*

Restructuring FTR rules remains a paramount stakeholder task after an independent probe identified the shortcomings in PJM’s market design and internal culture that allowed a small trading shop, GreenHat Energy, to amass the largest portfolio of FTRs in PJM history without the collateral to back it up. (See Report: ‘Na i ve’ PJM Underestimated GreenHat Risks.) The 890 million MWh default could wind up costing PJM more than $430 million, former CFO Suzanne Daugherty told stakeholders in January. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)

“This is something that is totally out of the realm of consumers, but yet and still, they will pay the burden of this debacle,” Price said. “For PJM to continue this market, there need to be cultural changes in PJM that understand the oversight necessary.”

Price emphasized the need to fill Daughtery’s vacant CFO position and find a qualified chief risk officer — as recommended in the GreenHat report — sooner rather than later, preferably before the August capacity auction. She also encouraged PJM to expand the Independent Market Monitor’s authority to include regulation and monitoring of FTRs.

CEO Andy Ott said during his keynote address at PJM’s Annual Meeting last week that he continues working hard to implement staffing changes as quickly as possible, though finding qualified candidates to manage the RTO’s FTR market rule changes takes time.

Transmission Wave

The Consumer Advocates of PJM States advised the RTO to “follow the money” as it navigates transmission planning and the anticipated wave of new projects in the coming decades.

“We appreciate the commitment to ensuring competition on the market side,” said Mike Gahimer of the Indiana Office of Utility Consumer Counselor. “We’d like for that same focus to occur on the transmission side.”

Advocates agree that while PJM lacks jurisdiction over supplemental projects — those proposed by transmission owners and identified as not necessary for reliability, operational performance or economic criteria — the growing share of such projects also lacks federal and state oversight.

The transparency of PJM transmission planning has long been a topic of debate among stakeholders, with several expressing concern that the ballooning share of supplementals — $5.7 billion in 2018, according to CAPS — may displace the priority of baseline projects, which only totaled just over $2 billion that same year. PJM is currently in the midst of a special Planning Committee process to revise existing manual language that details the intersection of these projects. (See “RTEP Removal Language Vote Deferred, Again,” PJM MRC/MC Briefs: April 25, 2019.)

“What PJM is saying is, ‘Trust us we got this’,” Gahimer said. “I’m more of a trust-then-verify guy, and I don’t think PJM has got this.”

PJM Should Prioritize Costs, Too

Advocates want PJM to care about project costs as much as they do, said Erik Heinle of the D.C. Office of the People’s Counsel.

“PJM has an obligation to be honest and transparent about the potential costs of any initiative at the beginning and throughout the stakeholder process,” he said, noting that inaccurate modeling and a failure to recognize the interplay of markets often leaves consumers paying twice.

The rushing to file market changes — including proposals for fuel cost policy, distributed energy resources, storage and black start resources — leaves some stakeholder groups unable to analyze the true impact of the proposals and provide valuable feedback.

“Adequate stakeholder review is not just a courtesy, but ensures the impacts of changes are fully vetted and lessens the chances of design flaws,” he said.

The advocates proposed the formation of a Strategic Planning Committee to meet four or six times a year to better inform the transmission planning process and ensure that costs and market impacts are fully understood.

May 12, 2019

MISO to Fix Communications System Shortcomings

CARMEL, Ind. — MISO is seeking to improve how owners of load-modifying resources interact with a key communications system that some market participants think hampered the RTO’s response to a grid emergency this past winter.

Stakeholders have criticized the nonpublic MISO Communications System (MCS) webpage — where LMR owners update their availability — as being difficult to navigate, with some suggesting it hinders clear communication during grid emergencies. The RTO is in the process of upgrading the system to a more updated format.

Speaking at a Resource Adequacy Subcommittee meeting Wednesday, Customized Energy Solutions’ Ted Kuhn said the MCS may have contributed to confusion during the Jan. 30 maximum generation event, for which the RTO issued about $2 million in penalties for LMR underperformance. (See “MISO: $2 Million in Penalties for Jan. 30 LMR Underperformance,” MISO Reliability Subcommittee Briefs: May 2, 2019.)

“There was a lot of misunderstanding about what was going on. There were people that were getting, in my opinion, poor information from the MCS. … Things are not set up the way they should be,” Kuhn said.

In April, Consumers Energy’s Jeff Beattie asked if MISO had considered that it was working on improvements to the MCS at the time of the January emergency before it issued penalties. Beattie said some market participants may have misconstrued the timing of the request for LMRs as being across peak hours instead of just during the emergency.

MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO has reached out to LMR owners to talk about how to improve communication protocols. MISO is also creating additional training classes for owners of LMRs.

The RTO foresees a 70% chance of calling on LMRs this summer. (See MISO Foresees Summer Emergency, LMR Use.)

— Amanda Durish Cook

May 12, 2019

MISO Ponders Changes After Latest PRA

By Amanda Durish Cook

CARMEL, Ind. — MISO last week proposed to change the deadlines and deliverability requirements for next year’s Planning Resource Auction as it continued to release detailed data from this year’s event.

At a Resource Adequacy Subcommittee meeting Wednesday, MISO Manager of Capacity Market Administration Eric Thoms kicked off his presentations on a lighthearted note as his team continues to break down the auction results.

“There’s a common term floating around: post-PRA hangover,” Thoms joked. “A lot of caffeine helps.”

Last month, MISO’s annual capacity auction cleared at $2.99/MW-day in all zones but Lower Michigan’s Zone 7, which cleared at $24.30/MW-day. Prices declined sharply compared with last year’s nearly uniform $10 clearing price. Altogether, the RTO committed 134.7 GW worth of capacity for the 2019/20 planning year beginning June 1. (See Most MISO Zones Clear at $3/MW-day in 2019/20 PRA.)

MISO is still releasing more detailed data on this year’s auction.

Thoms said multiple zones in MISO contained marginal resources that set the $2.99/MW-day price.

This year’s auction was the first to include external resource zones based on external balancing authorities. As a result, MISO cleared about 1,533 MW from SPP, PJM, Ohio Valley Electric Corp., LG&E Energy Transmission Services, Associated Electric Cooperative Inc., Southwestern Power Administration and the Tennessee Valley Authority.

MISO said the auction results were generally consistent with its loss-of-load expectation (LOLE) study, though LOLE load forecasts were slightly higher than those submitted by load-serving entities. The PRA’s system coincident peak of about 124.9 GW was slightly lower than the LOLE study prediction of 125.5 GW.

Timeline Change Next Year

MISO is considering changing some timelines before for the 2020/21 PRA, including deadlines for demand response testing, submission of generator verification testing data, behind-the-meter registration, unforced capacity values and the posting of preliminary auction data. In most cases, the various deadlines would be extended into the winter instead of late fall.

MISO is also proposing to open and close the offer window during “normal business hours.”

“My staff doesn’t like getting up at 12:01 a.m. to open the offer window and close it at 11:59 p.m. on a Friday night,” Thoms said.

The RTO would like to open the PRA’s four-day offer window at 8 a.m. ET and close at 6 p.m. Currently, the offer window runs from 12:01 a.m. on the first day of the auction through 11:59 p.m. on the fourth day.

“We’ve never received any offers at 2 a.m.,” Thoms added.

MISO said it may make a Tariff filing in summer to alter the PRA timeline.

New Deliverability Rules

MISO will also require that its traditional resources be deliverable to their full installed capacity (ICAP) values by the 2020/21 planning year auction.

The capacity deliverability rules will apply to resources with both network resource interconnection service (NRIS) and energy resource interconnection service (ERIS). However, the rules will not apply to intermittent resources — including wind, solar and storage devices — whose deliverability requirements will be based on some sort of historical or average output. The exact process has yet to be proposed.

Darrin Landstrom, MISO resource forecasting adviser, said the change in deliverability requirements won’t have a big impact on cleared megawatts in the auction. He said some generators may have to request broader transmission service, which could take up to a maximum of 105 days for study and approval. MISO estimates that about 1.4 GW of capacity clearing this year’s auction may not be deliverable to installed capacity levels.

Both the Independent Market Monitor and the Coalition of Midwest Power Producers (COMPP) have contended that MISO doesn’t properly account for deliverability because its LOLE study assumes that all capacity resources are fully deliverable on an ICAP basis. However, the RTO allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. FERC: No Merit in MISO Deliverability Complaint.)

MISO requires capacity resources to demonstrate deliverability either by having NRIS, which stipulates that the entire ICAP be deliverable, or ERIS, which requires that firm transmission service be reserved up to the UCAP level.

The RTO has said it doesn’t hold capacity resources to different standards because it doesn’t require NRIS resources to perform to ICAP levels, instead requiring both to demonstrate deliverability up to their UCAP levels for the purposes of the capacity auction. But the RTO is now proposing to require ICAP-level performance across the board beginning with the 2020/21 auction.

MISO is seeking stakeholder opinions and suggestions on the new deliverability requirement through the end of the month. The RTO said it may make changes to its Business Practices Manuals.

COMPP’s Mark Volpe said he thought the changes might constitute a new “condition of service” that would require parallel changes to the Tariff as well as the BPMs.

MISO General Counsel Michael Kessler responded that the RTO’s legal team would monitor the proposal to see if it requires a Tariff revision.

Seasonal Plans

MISO is meanwhile still making plans to adopt a seasonal component for its capacity auction but will hold the proposal until the 2021/22 planning year. (See MISO Gives Tentative Nod to Seasonal Capacity Design.) RTO staff are currently conducting analyses on introducing a seasonal construct.

May 12, 2019

Changes Add Uncertainty to Mexico’s Power Market

By Tom Kleckner

HOUSTON — During a recent workshop on the Mexican power market, Tenaska’s Bob Anderson ran through the litany of woes wrought on the market since President Andrés Manuel López Obrador took power last year.

The canceled power auctions, the gutting of the regulatory commission, the reconstitution of the state-run electric business — the government’s heavy hand in creating more uncertainty in an already fragile market.

Still, Anderson said, Tenaska’s vice president of business development, you will find some investors willing to take a chance in the Mexican market.

“It won’t be Tenaska,” he said. “We at Tenaska are not speculative traders.”

“I am a bit more sanguine about this,” Que Advisors’ Peter Nance said. “My experience in Latin America tells me that rules will change, but there will still be opportunities for private capital. Nevertheless, the new situation may be considerably different than the old, and there may be certain participants that are disadvantaged by the changes.”

“It’s a real-life three-ring circus, but the clowns are in charge,” said a more sardonic Mannti Cummins, who is working to develop a wind farm in Baja California Sur. (See Land Rights a Challenge to Mexico Tx Developers.)

Mexico City is the largest city in North America. | © *RTO Insider*

José María Lujambio Irazábal, who heads the energy practice for Mexican law firm Cacheaux Cavazos & Newton, said the changes will result in a stronger state-run utility (the Federal Electricity Commission (CFE)), a weaker regulatory body (the Energy Regulatory Commission (CRE)) and a neutered Ministry of Energy (SENER).

A former member of President Felipe Calderon’s administration (2006-2012), Lujambio Irazábal said CFE will enjoy a “privileged position” under the new administration. Its octogenarian CEO Manuel Bartlett Díaz is determined to “Make CFE Great Again,” Anderson said, having felt insulted by the 2014 reforms designed to open up Mexico’s electricity market. “He will tell you the ignorant ways that was done,” he said.

Cummins called it a back-to-the-future agenda, designed to strengthen CFE by reconsolidating the various generation businesses created by the reform. The focus is now on maintaining the utility’s aging fossil plants, as that will mean jobs.

“Any unit that CFE has that can run, should run. You’re talking about 500 different maintenance jobs to prepare for this summer,” Anderson said, noting the upgrades will make about 4 GW of additional capacity available this summer.

That should be a welcome development for the Mexican grid, which has seen its reserve margin drop from about 6% last year to less than 2% this year, said Rebecca Bollenbach of Essentia Advisory Partners. She said Mexico suffered through 44 cases of “emergency situations” and more than 1,000 alerts last year.

“Six percent is [grid operator] CENACE’s happy place right now,” Bollenbach said. “When ERCOT looks at a 6%, 7% reserve margin, everyone gets real nervous.”

Already this year, the Yucatan Peninsula has been twice hit with major power outages, leaving millions of people across three states in the dark for more than an hour.

Perhaps that’s why in April, CFE’s board approved an expansion plan to develop 13 GW of new facilities, all owned and operated by the utility. The first major projects involve five combined cycle gas-fired plants with an aggregate capacity of 2.76 GW, at a cost of $2.4 billion.

“That’s a substantial shift from the last administration,” Nance said.

‘Real Doozies’

In the meantime, López Obrador’s administration canceled a long-term auction, the fourth in a series, planned for last December. Bartlett Díaz has said there will be no more power auctions.

“Why should we buy electricity when we can produce it ourselves?” he told El Financiero, a business publication. “We are not going to discuss this; the CFE is not a company that buys electricity. It is a company that produces and distributes electricity. Why should anyone force us to buy electricity?”

It apparently won’t be the CRE, which had its budget reduced by 31.1% in December and then fired about 60% of its workforce.

“That’s a great amount of technical and intellectual capital out the door,” Anderson said.

López Obrador was also able to fill four vacancies among the seven CRE commissioners, appointing them himself when he was unable to gain approval from the Mexican Senate. All four newcomers come from petrochemical backgrounds.

“Some real doozies,” Cummins said. “Heavy on state control, lacking orientation of any sort to electrical markets.”

“Some of them are not real experts,” said Lujambio Irazábal, a former general counsel at CRE. “Who will regulate the market and impose sanctions when needed?”

Lujambio Irazábal said SENER, Mexico’s counterpart to the Department of Energy, is facing many of the same issues.

“With no undersecretary of electricity appointed, a dramatic lack of expertise and no political commitment to keep promoting new developments in the market, who will design and implement electricity policy?”

López Obrador himself has been all over the map. He initially promised new coal plants, thus reducing Mexico’s dependence on U.S. gas, before April’s announcement of five combined cycle projects. He has talked about repowering the country’s hydro installations, and the administration has publicly announced a goal of 100,000 solar rooftop installations by 2024.

“If you want to make jobs, many jobs can result from installing stuff on rooftops,” Nance said.

Mexico’s demand for power continues to grow at an annual rate of 2 to 3%. While the country has 75 GW of capacity on the grid, about a third of it is aging and unreliable or dependent on similarly aging transmission lines. Demand is expected to hit 50 GW for the first time this year.

In addition to canceling remaining power auctions, the López Obrador administration also pulled tenders for two major transmission projects up for international bids: the $1.2 billion, 870-mile, 500-kV connection between Mexicali in Baja California and Hermosillo, Sonora, in northwestern Mexico; and the $1.7 billion, 1,000-mile, 500-kV Oaxaca project between Mexico City and Veracruz.

The projects were “not a priority for the government,” Bollenbach said.

“You still have 3% growth nationwide. How are you going to meet that demand?” Nance questioned. “In an operational sense, there’s a very, very low reserve margin for certain hours of the year. Eventually, someone has to build something.”

Anderson called the language private investors hear “very aggressive … so most of us just back away.”

He said the market needs to express why the reforms are so important. “It wasn’t to tip the scale for private companies. It was to create market efficiencies,” Anderson said.

Foreign investment is not dead, however. Spain’s Iberdrola recently said it plans to spend $1.3 billion in five new generation plants — two combined heat and power, two wind farms and a combined cycle plant — as part of an initiative to invest $5 billion in Mexico over the next six years. The power will be marketed to “private enterprise” as part of an agreement with the Confederation of Industrial Chambers.

“There’s still room for international capital. My view is that it will just be put to work in different ways,” Nance said. “With the pending CFE restructuring, you could have a separate business unit focused on new technologies that could partner with other firms. That might be where development takes place. Improved partnerships with CFE might be a more expected and typical outcome of all this.”

May 12, 2019

MISO Requests Storage Compliance Delay into 2021

By Amanda Durish Cook

CARMEL, Ind. — MISO last week said it now plans to have a market participation model for energy storage resources in place by early 2021, having filed a request for delay of FERC’s fourth-quarter compliance deadline.

Director of Market Design Kevin Vannoy confirmed the proposed time l ine at a Market Subcommittee meeting Thursday.

MISO announced in April that it would seek at least another year to comply with More Info Needed on MISO Storage Participation Plan.) Vannoy said MISO’s filing focused more on providing explanation about the proposal instead of altering it.

Vannoy said when considering the “70-odd” requirements in FERC’s storage rule, some aspects of MISO’s plan make sense to RTO staff, but not third parties reviewing the proposal.

MISO now seeks an order on the storage participation plan by July. The RTO was originally beholden to a Dec. 3 go-live date for compliance with the storage order.

In the filing, MISO said the “complexity and expense” of its storage participation plan would negatively affect its ongoing effort to replace its aging market platform.

Vannoy said not receiving a FERC order on its proposal by April further backlogged “an already stressed schedule,” bogged down by the market platform replacement and a higher-than-expected cost to implement the storage plan with a third-party vendor.

MISO’s recent filing defined the phrase “very small” electric storage resources as those under 1 MW, answering one of FERC’s questions. The RTO has requested limiting participation of very small storage resources to 50 in the first year of compliance and 150 in the second year. FERC’s rule directed that all storage devices 100 kW and larger be allowed the opportunity to participate in RTO markets.

Vannoy said the limit on small storage devices is necessary to limit “administrative processes for the paperwork and modeling that can be somewhat burdensome.”

MISO also clarified that market participants will be responsible for maintaining their state of charge and updated an attached agreement on distribution-connected storage to clarify that storage owners will have to make metering arrangements.

At last month’s Informational Forum, CEO John Bear said MISO staff are currently studying energy storage case studies, including the Hornsdale Power Reserve in Australia, to determine how storage will fit into long-term planning.

Vannoy promised to return to the Market Subcommittee this summer to update stakeholders.

May 12, 2019

Energy Market Competitive in Q1, PJM Monitor Says

By Christen Smith

Reduced uplift, plunging energy prices and shrinking net revenues punctuated a competitive first quarter in PJM’s energy market, the Independent Market Monitor said Thursday.

Load-weighted, average real-time LMPs declined 39% over the first three months of 2019, averaging $30.16/MWh. The Monitor’s analysis concludes that lower fuel costs explained 40% of the $19.29/MWh drop, while attributing the rest to decreased load, adjusted dispatch and smaller markups. Units operating near short-run marginal cost set the price in most instances, the Monitor said.

Both energy uplift charges and congestion costs tanked by more than 75%, while net revenues for all new units declined by double digits, including 65% for combustion turbine, 42% for combined cycle, 85% for coal plants, 37% for nuclear and 93% for diesel. Renewables likewise saw declines of 40% in onshore wind, 36% in offshore wind and 22% for solar. The Monitor said net revenue represents a “key” measure of market performance and investor incentive to support more generation.

“Energy net revenues are significantly affected by energy prices and fuel prices,” the Monitor said. “Energy prices were lower in the first three months of 2019 than in the first three months of 2018 as a result of lower gas prices in the east. Coal prices were slightly higher.”

PJM energy market — Map of net real-time generation by zone: January through March 2019 | *Monitoring Analytics*

The analysis determined local market structure was not competitive, however, because of “highly concentrated ownership of supply” that led to a failure of the three-pivotal-supplier test.

The Monitor recommended PJM include end-of-life projects in the FERC Order 1000 competitive process in order to boost market performance. He also encouraged PJM to reject temporary commitment exceptions for generators based on unenforced pipeline tariff terms that include “inferior transportation service procured by the generator.”

“The MMU observed instances when generators submit temporary parameter exceptions based on claimed pipeline constraints even though these constraints are based on the nature of the transportation service that the generator procured from the pipeline,” the Monitor wrote. “In some instances, generators requested temporary exceptions based on ratable take requirements stated in pipeline tariffs, even though the requirement is not enforced by the pipelines on a routine basis. If a unit were to be dispatched uneconomically using the inflexible parameters, the unit would receive make-whole payments based on these temporary exceptions.”

May 10, 2019

Overheard at IPPNY Spring Conference 2019

ALBANY, N.Y. — With Democrats now in control of both chambers of the state legislature, New York power producers might reasonably expect faster legislative support for Gov. Andrew Cuomo’s goals of 70% renewable energy by 2030 and a carbon-neutral grid by 2040.

But uncertainty still looms around those efforts, according to John Reese, senior vice president of Eastern Generation and chairman of the Independent Power Producers of New York (IPPNY).

“With all the changes going on, it’s hard to assess whether we’re going down the right path or a blind alley,” Reese said Wednesday at IPPNY’s 33rd annual Spring Conference.

A New York City resident, Reese cited a recent move by the mayor and City Council to improve energy efficiency in buildings and to revive the Champlain Hudson Power Express project to bring 1,000 MW of Canadian hydropower to Manhattan.

“IPPNY has been a long opponent to that project, particularly when it comes to the issue of carbon,” Reese said. “If you’re moving existing resources from one place to another, you’re not saving any carbon; you’re playing a shell game. … Certainly the preference would be to have new New York resources that contribute to the tax base, that contribute to jobs.”

The Climate Mobilization Act passed by the City Council on April 18 includes a definition of renewable energy credits that conflicts with the state’s Clean Energy Standard regarding the role of hydroelectric resources, said State Sen. Kevin Parker (D), chair of the Energy and Telecommunications Committee.

“The city’s language would allow certain large-scale hydro resources, which currently are not eligible [for RECs] under CES due to their evolving empowerments, that are not sources of methane emissions, to be eligible for the city’s program, hence the conflict,” Parker said.

“The conflicting RECs mean that the city’s end consumers and taxpayers would need to pay twice, once for the city’s REC and then again for the state’s REC [for other resources], and that Con Ed would be required to buy under the CES … which would require extra payment for Con Ed to secure eligible RECs,” Parker said.

The city’s program to import non-CES-eligible Canadian hydro also sends a negative signal to renewable energy investment in the state, especially for offshore wind, he said.

State Assemblymember Michael Cusick (D), chair of the Energy Committee, said he and Parker co-sponsored legislation that would require a feasibility study on achieving the state’s clean energy goals, “to support the incredible growth in offshore wind, energy storage and other resources.”

“The bill passed out of our committee, and I’ve spoken with people on getting that language in whatever package we have at the end of the session,” Cusick said, adding that he would also be pushing legislation on grid security, particularly cybersecurity.

IPPNY CEO Gavin Donohue thanked both lawmakers for “leading the charge” in dealing with the New York Power Authority in the competitive marketplace and legislating public procurement procedures through “a combination of practicality and reasonableness.”

NYISO Interim CEO Robert Fernandez touched on the same subject when he said, “The focus today is on buyer-side mitigation.

“At the beginning [of NYISO markets 20 years ago], many people were concerned about suppliers setting artificially high energy prices and improper wealth transfers,” Fernandez said. “Instead, today we grapple with uneconomic entry, subsidies and price suppression in the capacity market.

“We have mandatory buyer-side mitigation rules, we apply them, and it’s the economics of a particular project that will determine whether that will be subject to an offer floor or not,” he said. “That’s all that’s going to determine that. There are no outside influences telling us how to move the meter on buyer-side mitigation testing.”

Carbon Pricing and Technology

Fernandez also referred to NYISO’s work on pricing carbon into its wholesale energy markets, which has relied heavily on assistance from consulting firm Analysis Group.

“I’m hopeful that with [Analysis Group senior adviser] Sue Tierney’s help we can get the state on board and get this concept down to More Details Divulged on New NYISO Carbon Pricing Study.)

Dale Bryk, the governor’s deputy secretary for energy and environment, highlighted energy efficiency as a “huge economic engine” employing thousands of electricians and contractors throughout the state.

Cuomo in January proposed increasing the state’s renewable portfolio standard from 50% to 70% by 2030, nearly quadrupling its offshore wind energy goal to 9 GW by 2035, doubling distributed solar generation to 6 GW by 2025 and deploying 3 GW of energy storage by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)

Bryk dismissed the idea of the state using carbon offsets as an alternative to reducing pollution as “some kind of get-out-of-jail free card.”

“If you look at the experience in New York with Regional Greenhouse Gas Initiative offsets or components, they were never used,” Bryk said. “The way the program was designed, that really never made sense.

“If we’re talking about decarbonizing every sector, there really isn’t any place to get offsets, so the framing is different, but the concept of carbon neutrality and that flexibility is absolutely critical,” he said. “It’s not always linear, it’s not always numeric … we’re all-in for performance metrics, but we want to develop them in a professional way.”

Mark Younger of Hudson Energy Economics said Bryk had neglected to address carbon pricing. “I don’t see how you can do an efficient change without internalizing the externalities … which all the literature shows lets you put the solar resources in an area where they knock out carbon rather than just happen to get subsidies from the state. So how do you do this without putting a price [on carbon], not just in the electric sector, but in all the sectors?”

“We have carbon pricing with RGGI, but I think of it as a cap on pollution that’s going down over time,” Bryk replied. “You sell pollution permits, that’s your price. The driver is the cap. We want people to have a price signal and see the long-term price signal and declining cap. What I care about is pollution going down … so you don’t only have a price, you don’t lead with price. We want to have both the price signal, the cap, and energy efficiency policies, because it’s not all about price.”

Jacob Worenklein, chairman of Ravenswood Power Holdings, which owns the largest power plant in New York City, said the great challenge is technology, “because we can in fact reduce carbon to zero right now, but nobody would do so … because the cost would be so huge.”

“When will we get the technology and when can we expect to begin to test technology that will enable us to do exactly what we’re talking about, say, by the 2035 or so time frame?” he asked.

Bryk likened the idea of encouraging new technologies to that of being “proactive with” workforce development — “and not just assume that that’s going to happen because the investment is there.”

“Just because you have policies … even with the price signal, that doesn’t bring you all of the technological innovation that we may need,” Bryk said. “What can the state be doing to help drive that R&D work and the commercialization demo projects?”

– Michael Kuser

May 10, 2019

Exelon to Close Three Mile Island

By Michael Brooks

Exelon on Wednesday announced it will permanently shut down the nearly 45-year-old Three Mile Island nuclear plant in Londonderry Township, Pa., by Sept. 30.

The company is making good on its May 2017 promise to close the plant absent the Pennsylvania General Assembly providing it subsidies before June 1 of this year, the deadline for purchasing its fuel. Each house of the legislature has been considering its own bill supporting nuclear generation, but the Senate has adjourned until June 3, and the House of Representatives will only meet three more times before the end of the month.

“Although we see strong support in Harrisburg and throughout Pennsylvania to reduce carbon emissions and maintain the environmental and economic benefits provided by nuclear energy, we don’t see a path forward for policy changes before the June 1 fuel purchasing deadline for TMI,” Kathleen Barron, Exelon senior vice president, government and regulatory affairs and public policy, said in a statement.

“While TMI will close in September as planned, the state has eight other zero-carbon nuclear units that provide around-the-clock clean energy, avoiding millions of tons of carbon emissions every year. We will continue to work with the legislature and all stakeholders to enact policies that will secure a clean energy future for all Pennsylvanians,” she said.

But at least one state legislator earlier this week predicted the plant would close regardless of what the General Assembly did. (See Pa. Lawmaker Contends TMI Rescue Unlikely.) The bills being considered would create a third tier in the state’s Alternative Energy Portfolio Standard program, from which suppliers must buy an additional 50% of their power by 2021.

“Today is a difficult day for our employees, who were hopeful that state policymakers would support valuing carbon-free nuclear energy the same way they value other forms of clean energy in time to save TMI from a premature closure,” said Bryan Hanson, Exelon senior vice president and chief nuclear officer. “I want to thank the hundreds of men and women who will continue to safely operate TMI through September.”

Nuclear Energy Institute CEO Maria Korsnick blamed the plant’s closure on “a flawed and distorted energy market that fails to value the attributes of nuclear power.”

“The shutdown will lead to the loss of hundreds of Pennsylvania jobs, more than $1 million in taxes annually to the community and more than 7 million MWh of carbon-free energy,” she said. “It’s in our nation’s best interest for lawmakers both in state capitals and Washington to push for market solutions and polices that value all clean energy sources, or face the economic and environmental consequences for generations to come.”

Three Mile Island is home to two reactors. Exelon has owned Unit 1 since 2000, when the company formed through the merger of Unicom and PECO Energy, the latter of which owned a 50% stake in the unit. The company purchased the other half in 2003 and began operating the plant directly in 2009. The same year, the unit was granted a license extension by the Nuclear Regulatory Commission to April 19, 2034.

Unit 1 was shut down for six years after the partial meltdown of Unit 2 in 1979, the worst commercial nuclear power plant accident in U.S. history. In 1985, over fierce opposition from nearby residents and anti-nuclear activists, NRC voted 4-1 to restart operations.

Exelon plans to begin transitioning staff within six months of the plant’s shutdown, winding down in three phases to 50 full-time employees by 2022. The company will begin to dismantle the plant in 2074.

May 10, 2019

Mild Weather Undercuts CenterPoint Q1 Earnings

CenterPoint Energy on Thursday reported that mild weather that reduced customers’ power usage drove first-quarter earnings down to $140 million ($0.28/share), from $165 million ($0.38/share) a year ago.

When adjusted for one-time gains and costs, the Houston-based company’s earnings came in at 46 cents/share, falling 4 cents short of Zacks Investment Research’s consensus.

Still, CEO Scott Prochaska said he was pleased with the results.

“While weather-related impacts affected first-quarter earnings, we remain confident in our anticipated 2019 full-year performance. Our utilities continue to benefit from strong customer growth and recovery mechanisms allowing for timely recovery of capital invested on behalf of our customers,” he said.

CenterPoint’s earnings excluded costs and other impacts of its $6 billion acquisition of Vectren. The Indiana utility, the acquisition of which was completed Feb. 1, reported a one-month operating loss of $9 million, which included $20 million in merger-related expenses.

The Indiana Utility Regulatory Commission recently recommended CenterPoint consider smaller-scale options instead of a proposed 700- to 850-MW combined cycle natural gas turbine, company officials said.

“The commission wants to see investment made in ways other than a bet on a single large plant,” Prochaska told investment analysts during a call Thursday.

CenterPoint’s share price closed Thursday at $29.25, down almost 4% from the previous close.

— Tom Kleckner