Declining wind output drove down Avangrid’s first-quarter earnings by 11% compared to a year earlier, company officials said last week.
Avangrid posted net income of $217 million ($0.70/share), down from $244 million ($0.79/share) in the same quarter a year ago. The drop was driven primarily by a $46 million decrease in the company’s Renewables business, from $50 million in Q1 2018 to $4 million this year. Wind production during the period averaged 14% below 2018 levels, reflecting “the impacts of storms and severe weather,” CFO Doug Stuver said in an earnings call Thursday.
BOEM map shows Vineyard Wind wind energy lease area offshore Martha’s Vineyard and Nantucket. | BOEM
The drop in the Renewables business was partially offset by an $18 million increase in the company’s Corporate segment “due to favorable tax impacts,” Stuver said.
Total revenue for the quarter was down by 1.2%, from $1.865 billion in 2018 to $1.842 billion.
CEO James Torgerson told analysts that despite the hiccup in wind output, Avangrid expects nearly 1 GW of renewables under construction to come online this year and has increased its pipeline by 1.6 GW to 15.4 GW, which includes 4.4 GW of solar.
Its Vineyard Wind offshore project, a joint venture with Copenhagen Infrastructure Partners, is on track, “with nearly 70% of the supply chain secured,” Torgerson said. The project’s contracts with the electric distribution companies recently received Massachusetts Department of Public Utilities approval. “Now, we are targeting to have all 800 MW in operation by the end of 2021,” he said.
With their Liberty Wind project, Avangrid and Copenhagen also submitted a bid in New York’s first offshore wind solicitation, with options for 400, 800 and 1,200 MW. (See Four Bidders Vie for NY Offshore Wind Project.) The New York State Energy Research and Development Authority is expected to announce the winner this spring.
The companies also submitted to Rhode Island two proposals of 200 MW and 300 MW each, with the selection of bidders expected in May.
American Electric Power said it is off to an “excellent start for 2019,” beating analysts’ expectations for the first quarter and completing a deal with Sempra Energy that adds more than 700 MW of wind generation.
AEP on Thursday reported earnings of $572.8 million ($1.16/share), exceeding Zack’s consensus estimate by 6 cents and beating 2018’s first-quarter profits of $454.4 million ($0.92/share).
The Columbus, Ohio-based company began the week by announcing its competitive renewable subsidiary, AEP Clean Energy Resources, had completed the purchase of Sempra Renewables for $1.05 billion. The deal includes Sempra’s 724-MW portfolio of operating wind generation, battery assets and development staff.
Sempra Renewables’ Boulder Solar II project | Sempra Renewables
Asked during a conference call with financial analysts why AEP is buying, and not building, wind and solar, CFO Brian Tierney said the deal takes the company to “the next level.”
“We’re very selective in the assets we looked at, looking for high-quality contracted assets with creditworthy counterparties,” Tierney said. “What this opportunity brought with it was a lot of wind, some battery, contracted with high-quality counterparties, but it also brought a team with it, and that team is something that we didn’t organically have from a development standpoint. So we got not just a team, but also development projects in the pipeline that we wouldn’t have had otherwise.”
The acquisition means AEP has now spent $1.5 billion of the $2.2 billion it has committed to renewable energy projects.
“We’re looking at opportunities as they become available,” Tierney said.
CEO Nick Akins did not participate in the call. AEP said Akins was not “feeling well,” but he expects to be back at work “soon.”
The company’s share price rose from its $83.52 open on Thursday to close the week at $84.71. It is up 32.1% since reaching its nadir of $64.11 in June.
VALLEY FORGE, Pa. — PJM stakeholders approved a charter on Thursday for a senior task force dedicated to implementing market rule changes in the wake of the 890 million-MWh GreenHat Energy default.
“The board message is quite clear that it’s not going to happen again,” Vince Duane, PJM’s general counsel of law, compliance and external relations, told the Markets and Reliability Committee. “If we are going to offer products that present this kind of risk, we need to be robust and confident that we can manage the risks associated with it.”
The Financial Risk Senior Management Task Force will assemble beginning May 2 to consider changes to credit and risk management requirements, market rules, membership qualifications and the stakeholder process in response to an independent probe of the default that uncovered structural flaws. PJM wants stakeholders to form solutions and make recommendations for Tariff and Operating Agreement revisions to the MRC and Board of Managers by the end of year.
“It’s not lost on any of us at PJM that this is going to be an investment of time and resources, and we want to make sure it’s efficient and that we are risk-managing products that are being used and are valuable,” Duane said. “If it doesn’t meet that litmus test, I think we have to ask why we are doing it.”
The PJM Board of Managers released the independent review of the GreenHat debacle in March. The report concluded naive staff and weaknesses in the RTO’s credit rules allowed the small trading company to amass the largest portfolio of financial transmission rights in PJM history without the financial resources to cover its losses. The latest estimates suggest the default will cost members up to $430 million. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)
CEO Andy Ott told the Market Implementation Committee on April 10 he will oversee organizational and procedural changes within the RTO but will rely on stakeholders to guide the process for market rule changes. Some of those internal changes include hiring a chief risk officer and replacing CFO Suzanne Daugherty, who retired before the release of the board’s report. The search for both is ongoing, Ott said Thursday.
Stakeholders endorsed the charter with just two objections and three ostensions. But several stakeholders expressed concerns about moving forward with the overhaul without the guidance of a CRO or CFO, noting the report’s recommendation to incorporate expert knowledge into the reforms.
The MRC delayed a vote on two proposals to allow surety bonds as a form of collateral until PJM hires the CRO and CFO. (See “Surety Bonds,” PJM MRC/MC Preview: April 25, 2019.)
“I think there are serious questions that should be reviewed,” said Susan Bruce, on behalf of the PJM Industrial Customer Coalition. “Maybe the answers become obvious. We have a responsibility to make sure that all of the products are delivering a value for this physical market. Retail customers shouldn’t end up being the insurance or backstop for products that aren’t delivering value.”
Greg Poulos, executive director of the Consumer Advocates of PJM States, mentioned his members’ interest in investigating the role of surety bonds, forfeiture rules and other FTR product specifics.
“Having the CRO in place is a critical component of leading these things … their perspective on surety bonds would be very helpful,” he said.
Later Thursday, Ott gave the Members Committee a briefing on his “action plan” for responding to the default, which includes the creation of two new departments (Markets Risk Modeling, and Market Analytics and Surveillance); the realignment of the Law, Compliance and External Relations Division “to improve communication and coordination”; and the creation of a Risk Oversight and Markets Surveillance Committee to be chaired by the CRO with executive-level representation from Finance, Markets and Legal.
Ott said his goal is for PJM to improve its ability to identify “changes in behavior” by market participants to prevent future defaults. “I, for one, want my organization to get better,” he said.
The RTO would seek input from the Independent Market Monitor on tracking market participants’ positions, he said, but the IMM would not be involved in evaluating players’ credit and collateral.
Bruce Bleiweis of DC Energy questioned giving IMM Monitoring Analytics a role, saying market participants had warned the Monitor that GreenHat’s FTR position was “growing dramatically auction after auction. Yet we’re still where we are today.”
“You have no idea what went on, so don’t draw conclusions about things you don’t know,” Monitor Joe Bowring responded to Bleiweis. “It is our job … to monitor all parts of the market.”
Bowring said the default resulted from the failure to assess the risk posed by the interaction of GreenHat’s increasing positions and its “gaming” of the RTO’s credit requirements by adding FTRs in the opposite direction of its existing positions.
Greg Carmean, executive director of the Organization of PJM States Inc., said the RTO should consider whether it should take on a “financial regulator role” or whether it should allow another entity to sell FTRs and other financial products. If PJM retains the responsibility, he said, it should ensure that the cost of the expanded staff is borne by the “cost causers.”
Ott acknowledged PJM may rethink its “can-do culture,” which has led the RTO to take on new duties at stakeholders’ requests. “We can’t be all things to all people,” he said.
PHILADELPHIA — New research suggests that offshore wind farms offer huge potential for capacity gains in PJM’s footprint — but it will take a significant buildout of transmission to unlock that possibility.
University of Delaware professor Willett Kempton said a hypothetical buildout along the Eastern Coast from New Jersey to North Carolina could add approximately 80 GW to the grid.
“If we are going to do carbon-free generation, this is a really large resource that could do that,” he said while presenting his findings at Raab Associates’ Energy Roundtable in the PJM Footprint on Wednesday. “It would add 44% to today’s generation mix and it can all be carried to shore using only today’s transmission equipment.”
Kempton and his co-author, Elpiniki Apostolaki-Iosifidou, analyzed the impact of building an HVDC system with nine points of interconnections. The researchers estimated the system would have a 50% capacity factor, resulting in a 40-GW output on average. The conservative capacity estimates could be boosted through improved weather forecasting, more access to storage technology and PJM rule revisions, Kempton said. The new gigawatts would account for 43% of total PJM capacity, he said.
Other panelists said PJM must proceed with caution when planning such systems, noting the many pitfalls that come with securing proper permits, navigating seafloor access and attracting transmission developers.
“It’s a complex regime,” said Clint Plummer, head of U.S. market strategies and new projects for Orsted. “There’s opportunity for savings and reliability benefits by getting transmission policy on this right. There are real problems if it’s not done right.”
Norway-based Orsted bills itself as the world’s largest developer of offshore wind, with 5.6 GW of operational farms in the U.S., Europe and Taiwan. He said mistakes in Germany’s planning process taught developers that an integrated and streamlined approach to construction and operation works best, though it costs more upfront.
“Germany’s segmented approach didn’t work well because grant awards were mismatched between transmission and generation,” he said. “There were hundreds of millions of dollars of cost that accrued to us as developers of offshore wind … and then the transmission wasn’t there. We were basically paying the mortgage on that wind farm without any income coming in.”
One way to mitigate the costly risks of building an offshore wind networked transmission system is to secure permits before specific facilities are procured through state requests for proposals and ensure planning of every aspect before construction begins, said Theodore Paradise, senior vice president of transmission strategy and counsel at Anbaric. This means accounting for the unique challenges of the seafloor, including ocean trenching and navigating the limited points of onshore interconnection.
“Permitting can take significant time,” Paradise said, noting that securing those components ahead of time could be used as a “de-risking” tool. “It’s important you do it the right way.”
State legislatures in Maryland, New Jersey and Virginia have set goals of procuring a combined 6,700 MW of wind power over the next decade. So far, developers have contracted for less than 6% of those targets.
Cynthia Holland, director of federal and regional policy for the New Jersey Board of Public Utilities, said the state’s push to 3,500 MW of wind will make significant progress over the next five years. Bids for 1,100 MW have already been received, with a second 1,200-MW solicitation planned for summer 2020 and third scheduled for July 2022.
The first round of wind farms will likely use generation lead lines that connect onshore, though the BPU remains open to using networked transmission systems or HVDC lines for future projects.
Ken Seiler, PJM’s executive director of planning, said the RTO sees significant potential and benefits to the grid in offshore wind, but it remains hesitant about building transmission without committed generation. PJM staff is working with stakeholders to examine this process in further detail in the Merchant Transmission and Offshore Wind Task Force. (See “PC Moves Forward on Offshore Interconnection Rights,” PJM PC/TEAC Briefs: Feb. 7, 2019.)
“We recognize the interest and we recognize the value of offshore wind,” he said. “‘Build it and they’ll come’ — we aren’t sure that’s the best approach for integrating offshore wind with the existing grid.”
The CAISO Energy Imbalance Market’s Governing Body will search for a candidate to replace former member Kristine Schmidt after she resigned earlier this month to join embattled PG&E Corp.’s board, EIM leaders said Wednesday.
Schmidt was selected April 3 to sit on PG&E’s 13-member board along with her onetime boss at FERC, former Commissioner Nora Mead Brownell, who was named chair. The board appointments are likely to be approved at PG&E’s next in-person shareholder meeting, probably in June. (See Former FERC Commissioner Brownell Named PG&E Chair.)
EIM Chair Valerie Fong said at Wednesday’s Governing Body meeting that Schmidt had to resign from the EIM because “she would be conflicted. She couldn’t be on both boards.” Schmidt resigned April 1, Fong said.
Governing Body members thanked Schmidt for her service and wished her well. Schmidt joined the body’s teleconference briefly and also expressed her gratitude.
An EIM nominating committee will seek to fill the seat.
Also, at Wednesday’s meeting, Fong and colleague John Prescott were both re-elected by the only two members allowed to vote — Carl Linvill and Travis Kavulla. Normally, Fong and Prescott would have been asked to leave the room for the vote, but they were only requested to cover their ears.
After extensive stakeholder input, CAISO’s Board of Governors appointed the EIM’s first Governing Body — which included Schmidt, Fong, Linvill and Prescott — in June 2016. The EIM allows real-time interstate trading of electricity and has been widely hailed as a success, saving its participants an estimated $565 million since it began in November 2014.
PG&E Corp. and its utility subsidiary Pacific Gas and Electric filed for Chapter 11 bankruptcy reorganization in January, citing the potential for billions of dollars in wildfire liability.
The company is going through a board “refreshment” process after two years of deadly and catastrophic fires. It has faced political pressure to include more utility and safety experts on its board.
PG&E said Monday it had reached an agreement with Blue Mountain Capital Management, a major shareholder that opposed its initial board choices. The company said it would appoint one of Blue Mountain’s preferred candidates, Fred Buckman, the former CEO of Consumers Energy and PacifiCorp. Buckman will replace Richard Kelly, who resigned from the board. PG&E also said it was hiring Christopher Hart, former chairman of the National Transportation Safety Board, as a special independent safety adviser.
A NERC standards drafting team (SDT) has opened a final ballot on the elimination of all or parts of 18 reliability standards as Phase 1 of the organization’s standards efficiency review (SER) nears its conclusion.
Ballot pool members will have until May 2 to vote on the changes: the withdrawal of one proposed reliability standard, the complete retirement of 10 standards and the elimination of certain requirements for seven standards. (See chart.)
| NERC
All the proposed retirements received 88 to 99% support in segment-weighted voting in the initial ballot that closed April 12. “They all passed at pretty high percentages,” observed NERC’s Laura Anderson, standards developer for the SDT at a team meeting April 17.
NERC’s ballot body, representing its 10 industry segments, currently has 525 members.
Proposed retirements that clear a two-thirds segment-weighted threshold on the final ballot will proceed to final approval by NERC’s Board of Trustees, likely at the board’s May meeting. Votes from the initial ballot are automatically included in the final ballot, although voters can change their positions.
Pruning the Rules
The Standards Efficiency Review Retirements effort (Project 2018-03) was created to take a second look at the rules that have been created since FERC certified NERC as the electric reliability organization (ERO) in 2006.
Three teams — representing real-time operations, long-term planning, and operations planning — identified for elimination requirements that were duplicative, obsolete or that were administrative and did not provide reliability benefits. Many of the standards to be retired relate to commercial business practices governed by the North American Energy Standards Board (NAESB) Wholesale Electric Quadrant (WEQ).
NERC last month closed the comment period on Phase 2 of the SER project. The phase involves considering changes in six areas of the organization’s operations and planning (O&P) and critical infrastructure protection (CIP) standards, including evidence retention time frames, moving requirements to guidance, simplifying training requirements and consolidating data exchange requirements. (See “Chair Urges Comments on Standards Efficiency Review,” NERC Standards Committee Briefs: March 20, 2019.)
The comments on the Phase 1 recommendations indicated how much the industry has changed since NERC became the ERO and gained enforcement authority.
For example, Black Hills Corp. said requirements 16 and 17 of standard TOP-001-4 provide no reliability benefit. The rule is intended to ensure prompt action to prevent or mitigate instability, uncontrolled separation or cascading outages.
The requirements direct transmission operators and balancing authorities to provide their system operators with authority to approve planned outages of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels.
The requirements “don’t even align with most, if not all, standard business processes,” Black Hills’ Maryanne Darling-Reich said. “The outage coordinator, [supervisory control and data acquisition emergency management system], IT networking and communications departments determine the impacts of all ‘planned’ outages of telemetry equipment. Most system operators do not even have the technical knowledge to make a substantiated decision to delay or postpone this work.”
MOD Standards
Eight of the 18 standards proposed for retirement were from NERC’s modeling (MOD) family of rules. The SDT proposed the elimination of seven of the MOD standards, including those on calculations of capacity benefit margins, transmission reliability margins and transfer capability — requirements incorporated in NAESB standards.
The standard authorization request (SAR) that initiated the SER project said that available transfer capability (ATC) and available flowgate capability (AFC) are “commercially based values used to facilitate a market for unused transmission capacity in an open access environment and that the values do not directly control the operation of the [bulk power system]. … [Transmission operators] are ultimately responsible for operating the grid in a reliable manner consistent with system operating limits, not ATC/AFC values.”
The team also proposed not implementing MOD-001-2, which has been awaiting FERC approval since February 2014 (RM14-7). It was intended to ensure calculations of available transmission system capability support reliability and that the methodology and data behind the calculations are disclosed to applicable registered entities.
The SAR said MOD-001-2 was not needed because although ATC and AFC values can influence real-time conditions, other standards, including subsequent improvements to TOP rules, ensure that real-time operations observe system operation limits. The “commercially based values and market related issues [regarding ATC/AFC] should not be addressed through NERC reliability standards,” it said.
Despite the high level of support for the retirements, there were some forceful dissents.
Duke Energy, for example, said it could not support the elimination of the seven existing MOD standards if MOD-001-2 is withdrawn.
“We disagree with the commercial-based focus that the drafting team took in the technical rationale document,” Duke’s Kim Thomas wrote. “While these MOD standards (and ATC calculation) may have some commercial-based elements to them, they also put in place valuable boundaries that help promote consistency in how the industry calculates these values. Removing these boundaries does not promote reliability for the bulk electric system and introduces additional burden to the real-time system operator.”
Southern Co. took a similar position, saying that transferring the seven MOD standards to NAESB without enacting MOD-001-2 would upset the “appropriate balance of addressing reliability-related concerns, while incorporating any market related issues.
“Simply stating that ATC/AFC calculations are primarily commercially focused elements and that there are mechanisms in place to address reliability in real time is an oversimplification of the ATC/AFC concept,” Southern’s Marsha Morgan wrote. “Inaccurately modeling and assessing transfer capability which considers real physical transmission limits on both the host and neighboring systems can create extremely complicated situations in real time that can unduly burden system operators.”
PJM, which was neutral on the elimination of MOD-001-2, supported the proposal to transfer the other MOD standards to NAESB, saying “reliability components of congestion management are handled amongst Eastern Interconnect parties through various established coordination processes.”
It warned against additional revisions to the NAESB WEQ rules, “especially those driven by issues unique to particular seams or between specific entities, as those issues may not be realized by other parties.”
“Therefore, blanket revisions may unnecessarily impact reliability and/or market aspects for other entities,” PJM’s Preston Walker said.
INT Standards
Also proposed for retirement are four interchange scheduling and coordination (INT) standards relating to interchange coordination, dynamic schedules, pseudo-ties and transmission loading relief procedures.
The SAR said the standards are duplicative of NAESB rules and that two of them are unenforceable because the “purchasing selling entity” is no longer a NERC registered function.
Duke also opposed the retirement of requirements 3.1, 4 and 5 of INT-006-4.
“We are not confident that this issue is adequately covered in the NAESB standards. Unlike the NERC standards which aim to promote reliability, the NAESB standards are commercially focused, and are not viewed as essential to maintaining a reliable system,” Thomas said. “We believe that not having these conditions outlined could negatively impact reliability.”
Morgan disagreed, saying requirements 4 and 5 are duplicative of the NAESB e-Tagging specifications “and are not a reliability-related task performed by a NERC registered entity.”
A new MISO task team on Monday kicked off an effort to develop a scheme to compensate resources that deliver restoration energy in the event that the RTO’s wholesale market ceases to function.
“There’s no Tariff provisions for compensation during an islanding event,” MISO Director of Market Services John Weissenborn explained at the first meeting of the Compensation for Restoration Energy Task Team. He noted that MISO’s black start and NERC recommendation-based schedules are insufficient to cover all generation as it comes back online.
Stakeholders said having a restoration pricing structure in place may prevent yearslong legal battles over compensation following blackout conditions.
MISO has yet to make any decisions but is considering implementing either a dollar-per-megawatt filed rate or recovery based on verifiable costs. Multiple stakeholders said they preferred the latter over the former.
Weissenborn asked stakeholders to think about how an islanding event would interrupt the day-ahead market and how MISO might measure the imbalance and compensate afterward. He also pointed out the RTO would have to confer with state regulators to assess the implications of having a new rate schedule in place.
MISO would likely rely on an after-the-fact settlement to compensate resources, Weissenborn said, adding that the task team should examine how current settlement rules might apply to a restoration pricing structure and how normal settlements would resume after an event.
The system would not be able to price nodes within an area experiencing an islanding event, Weissenborn said, asking stakeholders to think about whether they would want to come up with a nodal price per load.
MISO has said it would complete all billing with no expectation that local balancing authorities calculate settlements. However, stakeholders asked how the RTO would ensure that prices are separated down to the LBA.
The RTO may use a five-year-old white paper on the subject as a starting point for the pricing structure. (See Old Analysis Could Guide MISO Restoration Pricing Effort.) In that paper, MISO proposed using either 110% of a FERC-approved rate or a $100/MWh price, whichever is greater. As FERC-filed rates include start-up costs, the RTO said a real-time revenue sufficiency guarantee would not apply.
Weissenborn said using a static, filed rate would be “a relatively simple solution,” and MISO could use the $100/MWh figure as a pricing floor. “We would have a filed rate, and we can come up with an output to multiply by,” he said. But he added that pricing should ensure that generators recover start-up costs, which are amortized over commitment periods in MISO’s usual energy pricing.
He also said that many generation owners and MISO staff involved in the 2013 white paper are no longer participating in the RTO. Using the white paper as a basis for a pricing structure without knowing the reasons behind the proposal might prove tricky when making a case to FERC, he said.
‘Extreme Event’
The task team will also have to consider how resource owners would establish eligibility for the new rate schedule, Weissenborn said.
Xcel Energy’s Kari Hassler said MISO might “glean” some aspects of pricing from recent emergency events. In the most recent maximum generation emergency in late January, emergency pricing floors defaulted prices to above $600/MWh.
“This is going to be more an extreme event,” Hassler reminded staff, saying a $100/MWh figure was probably too low considering the extraordinary circumstances of a system blackout and islanding.
Entergy’s Al Ralston said he remembered hurricanes that hit the company’s service territory in 2005 and 2008, causing “thousands of megawatts unable to be served” after several generators, substations and transmission went down. He said in those cases, Entergy — not yet a MISO member — used bilateral agreements to negotiate prices after the fact.
“We wanted to have prices that allowed generators to recover their legitimate costs and, at the same time, didn’t allow generators to gouge the load,” Ralston said. He asked MISO to devise a “reasonably” straightforward pricing method that would achieve both goals.
However, he also said plants must sometimes be evacuated or are difficult to reach because of flooding. He asked MISO about costs in excess of normal operations, such as to feed and board plant operators. He also warned that a restoration event can sometimes take weeks, and MISO may not want a static price in place that allows generators to make unchecked profits.
“This is not something that just happens and it’s over in a day,” Ralston said.
“I do agree with you. We have to have a good balance,” Weissenborn said as he took notes.
Stakeholders also suggested MISO put rules in place to create a temporary stakeholder group following a restoration event to educate resources on what they can and cannot submit in a verifiable cost-based offer. Some also suggested MISO’s Independent Market Monitor could work to verify offers after a restoration event.
Weissenborn also asked stakeholders to keep in mind that MISO would not be in control of dispatch as the system is restored.
“I think the harsh reality is we’re not energizing resources based on economic decisions as we restore the system. It’s based on ‘let’s start getting load back,’” Weissenborn said.
Ralston said the characterization was “exactly right.”
The task team will meet two more times, including on May 1, before presenting a pricing recommendation to the Market Subcommittee.
CARMEL, Ind. — MISO expects to call on load-modifying resources (LMRs) this summer despite its own estimates that it will have about 149 GW of total projected capacity on hand to cover a predicted 125-GW seasonal peak.
During an annual summer readiness workshop April 23, Resource Adequacy Coordination Engineer Eric Rodriguez said MISO says there is a 70% probability that it will have to declare an emergency in order to access 12 GW of LMRs in summer. The RTO will face challenges if it experiences a large number of resource outages coupled with high load.
Using data from the National Oceanic and Atmospheric Administration, MISO is expecting above-normal temperatures for its South region and the eastern portion of the footprint. Rodriguez said the summertime projections are “fairly typical.” The RTO expects July and August to contain the most risk.
The 125-GW peak demand forecast is nearly identical to the prior two planning years. MISO requires a 146-GW reserve margin requirement this planning year, which it expects to exceed by nearly 3 GW — both in line with last summer’s forecasts. Last year, summer load peaked at 121.6 GW on June 29, while load averaged at 86.6 GW over the season. MISO’s all-time, 127-GW summer peak occurred on July 20, 2011.
CEO John Bear said the adequate supply projection doesn’t mean MISO is “off the hook” with respect to challenging summer circumstances. However, the RTO was able to effectively manage recent emergency events in September and January because of its focus on preparation, he said.
Additionally, MISO’s coordinated seasonal assessment found nothing out of the ordinary for the upcoming summer. The assessment simulates unlikely system contingencies to detect potential voltage and thermal issues on the system. Engineer Benny Relucio said the RTO unearthed nothing for which it doesn’t already have mitigation measures in place.
NOAA summer prediction map | NOAA
MISO’s planning also assumes a near- or slightly below-average hurricane season, producing only two to three storms considered Category 3 or higher. The RTO expects the ongoing El Nino to produce more wind shear and cooler-than-average water temperatures in the Atlantic Basin, limiting hurricane activity.
“This means good news for MISO, bad news for hurricanes,” said Michael Carrion, of the RTO’s real-time operations team.
MISO will continue to conduct weekly summer readiness drills and periodic hurricane preparedness drills with market participants through late May.
RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved proposed Tariff revisions that would create a path for aggregated distributed energy resources to participate in the ISO’s wholesale market.
James Pigeon, the ISO’s manager of distributed resource integration, presented the new construct, which would entail electrically mapping each individual DER facility to local transmission nodes to incent location-specific DER investment. It would also authorize entities to provide meter services to aggregations within the DER participation model and reliability-based demand response programs.
When the Business Issues Committee recommended the new design on April 17, several stakeholders expressed concerns about issues such as mitigation and the terms for dual participation, which would allow DERs that participate in the wholesale market to also provide services to another entity, such as a utility or host facility. (See NYISO Business Issues Committee Briefs: April 17, 2019.)
| NYISO
In response to those concerns, Pigeon offered a draft Tariff clarification on dual-participation DERs, with one phrase highlighted as new: “In accordance with ISO procedures, the ISO has the authority to determine schedules and/or dispatch for these resources.”
NYISO also agreed to stakeholder requests to add language to the FERC filing letter clarifying that the ISO is the ultimate authority over such dual-participation resources.
“A definition [of DER] is one thing stakeholders wanted, so we added that” as well, Pigeon said.
The Tariff would define a DER as a:
Facility comprising two or more resource types behind a single point of interconnection with an injection limit of 20 MW or less; or
Demand-side resource; or
Generator with an injection limit of 20 MW or less.
All DERs must be electrically located in the New York Control Area and capable of responding in real time to NYISO dispatch instructions.
The MC delayed considering a new external supplemental resource evaluation (SRE) penalty scheme to improve the ISO’s ability to call on external resources that have sold into its markets, mainly because of implementation concerns raised by the Market Monitoring Unit.
The changes would take effect in the third quarter, which led one stakeholder to ask whether NYISO will consider fast-tracking the measure, given its importance and complexity. Interim CEO Rob Fernandez, who said he pulled the item from the agenda, affirmed that the ISO would.
Under the new proposal, any external resource that fails to meet delivery criteria would be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours to which a supplier fails to respond.
External capacity suppliers would not be subject to the penalty if their failure to deliver is beyond their control. The ISO would calculate deficiencies monthly, using the total number of SRE call hours in a given month that the resource could be available and the total megawatt shortfall in that month.
RENSSELAER, N.Y. — Third-party consultant Analysis Group is putting the finishing touches on a NYISO study examining the impacts of pricing carbon into New York’s wholesale electricity markets.
The study will augment the Brattle Group report process that concluded in December.
“There are lots and lots of unknowns,” Sue Tierney, a senior adviser with Analysis Group, said Tuesday as she presented the ISO’s Installed Capacity/Market Issues Working Group with an update on the new study. Tierney expects to release the technical report and an executive summary for policymakers at the end of May.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, asked whether Analysis Group would be redoing or revising Brattle’s analyses or simply accepting and building off the results. He noted that Brattle had concluded that increases in energy market prices from carbon pricing would lead to a dollar-for-dollar reduction in future renewable energy credit prices, an assumption he thought overly optimistic. He asked whether Analysis Group would be revisiting that type of conclusion by Brattle or incorporating it into its own analyses.
“We are not going back and trying to tweak their results and see what we can find,” Tierney said. “You and the Brattle Group and the other stakeholders have already spent months on that, and it’s a standalone work. We’re going to be using Brattle data to run slightly different analyses … all of which are hypothetical, ‘what-if’ analyses.”
“We’re saying, ‘If you did this, what would the price impact be?’” Tierney said. “We’ll be looking at direct and indirect economic impact and induced effects. Going to the dynamic effects, a carbon price works in tandem with other New York policies to accomplish the state’s environmental goals.”
NYISO’s discussion around carbon pricing has prompted the question of whether any fossil fuel generation – like the Big Allis plant pictured – will ever again be built or re-powered in the New York City area.
Carbon Context
Since her initial presentation last month, Tierney received comments from several stakeholders, including the Long Island Power Authority, which she said had a number of questions on carbon pricing policy designs, implications of a carbon price and beneficial electrification. (See Analysis Group Presents NYISO Carbon Pricing Study Plan.)
Large consumers, such as Multiple Intervenors, wanted to know more about the implications of an incremental carbon price on business location decisions, she said, or the extent to which the study would be examining where firms should invest. She said the study would not try to guess what a carbon pricing scheme might mean for manufacturers deciding whether to stay or make more investments in the state; instead, it would use NOx and SOx emissions data to calculate particulate emissions and health impacts.
While the comments submitted so far will eventually be posted for all stakeholders to read, they are not yet available; however, a sense of some stakeholders’ positions can be gleaned from related proceedings.
In discussing Brattle’s estimates of the impacts of a carbon pricing mechanism on wholesale market and consumer prices, Tierney said that she wanted to talk about customer bill impacts in addition to price impacts.
“New York’s economy is very efficient in terms of electric energy use, more efficient than Alabama, for example, even though the latter’s prices are lower than in New York. So we don’t want to look just at price impacts; we also want to look at bills,” Tierney said.
Mager said large industrial customers look at rates, not bills, while Erin Hogan, representing the New York Department of State’s Utility Intervention Unit, said it was not fair to compare Alabama and New York because “they don’t have our heating load.”
Tierney replied that she made that comparison to highlight a point: “It’s just to illustrate that we will talk about both rates and bills. Some people discuss rates only, which is also a distortion.”
The new analysis will address the possible application of NYISO buyer-side mitigation to resources receiving RECs and zero-emission credits and other potential revenue streams outside ISO markets.
In describing how the Analysis Group might approach discussion of any direct — or indirect — relationship between the adoption of a carbon price and any action by FERC, Tierney refused to guess how the commission would act on concerns regarding the entry of out-of-market resources, the potential exercise of market power, or the potential risks and cost implications of changes in buyer-side mitigation in New York.
“We don’t know where FERC is going on this or even who’s going to be on the commission,” Tierney said.
Draft 2019 Master Plan
Ryan Patterson, NYISO capacity market design associate, presented the working group with an initial draft of the ISO’s 2019 Master Plan, a single document intended to provide a roadmap for future capacity market enhancements.
NYISO last year created the first master plan at the request of stakeholders, with each project grouped into one of three initiatives discussed in the ISO’s 2019-2023 Strategic Plan, including grid reliability and resilience, efficient markets, and new resource integration.
Mike DeSocio, the ISO’s senior manager for market design, asked what stakeholders want from this year’s master plan.
Troutman Sanders attorney Stu Caplan, representing NY Transmission Owners, said some factors were outside the control of the ISO.
“It could be a FERC compliance filing or something that requires interim attention, such as a market exploitation that must be corrected,” he told RTO Insider in an email. “The simple point is, stakeholders appreciate updates from the ISO.”
Caplan asked Patterson if it would be feasible to provide a semiannual update for those projects that enter the plan outside of the project prioritization process.
“Yes, that’s the point here,” Patterson said.
“I don’t want to suggest that the only way to get a project in is by putting it through the project prioritization process,” DeSocio said.
The ISO will release and discuss an updated draft on May 22, issue a final draft Aug. 27 and release the final Master Plan in December in conjunction with the 2020 Business Plan.
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