Page 1054 – RTO Insider

April 19, 2019

MISO Previews Abridged MTEP Report

By Amanda Durish Cook

MISO is considering moving ahead with a plan to streamline its report detailing the projects in its annual Transmission Expansion Plan (MTEP) beginning with this year’s.

Project Manager Sandy Boegeman on Wednesday told MISO’s Planning Advisory Committee that the RTO is considering removing brief histories of previous MTEPs, some descriptions of regional studies, an introduction to the resource adequacy construct, and descriptions of MTEP futures development and independent load forecasting.

Last month, MISO said it planned to reconfigure the MTEP report to emphasize the justifications and analyses behind the list of proposed projects while condensing planning process narratives. The RTO aims to create a more concise and readable report, which typically runs about 200 pages and always includes descriptions of the studies and processes used to recommend projects. (See MISO Considering Slimmed-down MTEP Report.)

MISO hopes the new format will help guide the RTO’s Board of Directors in its deliberations over project approvals, Boegeman said.

Jesse Moser, MISO director of economic and policy planning, said the RTO is also examining the accessibility and usability of the planning section of its website to ensure that information removed from the report is easier to locate online. He said the web improvements could take a few years to complete.

“We’re trying to do this in a way that retains what’s important,” Moser said.

Veriquest Group’s Dave Harlan said that removing futures development information from the report may inadvertently weaken its rationale for some transmission projects.

“To just sort of poke around on the website … is a burden that’s going to frustrate everyone,” Harlan said. He asked MISO to create a “definitive” appendix of website links in the report supporting the necessity of the projects in the plan.

Moser said he and his team would consider the idea and asked for additional stakeholder feedback by May 3.

PAC Chair Cynthia Crane urged stakeholders to think about what pieces of the report are essential and which should be memorialized. The PAC is scheduled to vote on whether to recommend the MTEP 19 report at its Oct. 16 meeting.

April 18, 2019

FERC: ISO-NE Won’t Change EE Rules Without Stakeholder Talks

By Robert Mullin

Call it a false alarm.

In rejecting a request for a declaratory order on Tuesday, FERC provided the petitioners exactly what they were seeking: assurance that ISO-NE will not alter its energy efficiency performance standards outside the stakeholder process.

In February, Advanced Energy Economy (AEE) and the Sustainable FERC Project petitioned FERC to issue a declaratory order that would prevent ISO-NE from retroactively revising Forward Capacity Auction 13 qualification packages to include new measurement and verification (M&V) standards not previously applied to EE resources. They also asked FERC to clarify that the RTO must seek commission approval to make any such changes. (See Groups Seek to Head off ISO-NE EE Changes.)

In their initial filing, the groups said their petition arose from reports that ISO-NE staff had made a series of phone calls to Forward Capacity Market participants with qualified EE capacity resources. During those calls, staffers said the RTO intended to change how it measures the demand reduction value of EE resources for participation in the FCM.

Graph shows New England’s projected energy savings from energy efficiency projects. | *ISO-NE*

The petition alleged the changes could include new “net-to-gross” conversion factors to revalue EE resources, meaning the resources could only offer into the FCM their net energy savings, rather than their gross reduction to load from baseline federal standards. The petitioners noted the factors were “never previously required of, nor imposed on, market participants” nor defined or described in the RTO’s Tariff or manuals.

The groups contended ISO-NE staff indicated the RTO would potentially make the changes retroactively and without seeking commission or stakeholder approval, “even though the contemplated changes could significantly change the quantity of the resources that have already qualified for, and cleared, the most recent Forward Capacity Auction, FCA 13.”

The petition garnered widespread support, including from public interest organizations, the Massachusetts attorney general and Eversource, which asked that ISO-NE follow the New England Power Pool stakeholder process before making any changes.

FERC on Tuesday dismissed the petition as “premature,” citing ISO-NE’s own statements in response to the petition and its lack of action on the issue (EL 1 9-43).

“We find that the harm alleged in the petition is speculative in light of ISO-NE’s clarification that it has not made any proposal, nor does it currently have any plans, to change its M&V standards,” the commission wrote. “Furthermore … because ISO-NE has not proposed a change to its M&V standards, there is not concrete proposal for the commission to evaluate to determine whether a Tariff filing is required. As such, there is no controversy or uncertainty necessitating a declaratory finding at this time.”

ISO-NE said it was all a misunderstanding.

“As the script used by an ISO staff member for calls to energy efficiency providers makes clear … the ISO was informing energy efficiency providers that it is in the process of evaluating the implication of potential changes in federal energy efficiency standards and new information regarding net-to-gross savings ratios,” the RTO said in its March 7 initial resp o nse to the petition. “The communications do not reflect that the ISO was proposing a practice change or intending to make one.”

The RTO said it was evaluating current M&V practices because expected changes in lighting efficiency standards under section 321 of the Energy Independence and Security Act of 2007 “could substantially affect the baseline against which the savings from efficient lighting programs are determined.”

It also cited “a growing disparity between gross savings and net savings values for energy efficiency resources” reflected in updated state studies on the performance of energy efficiency measures.

“These factors warrant evaluating current practices regarding the measurement of energy savings for energy efficiency resources to assess whether changes to the ISO’s measurement standards are appropriate,” ISO-NE said.

But it said any changes would require modifications to ISO-NE manuals or Tariff and would be done “only after any such changes are vetted through the stakeholder process and any Tariff changes are filed and accepted by the commission.”

The commission’s order included comments reassuring to the petitioners. “In particular, in its second answer [to the petition], ISO-NE committed that it would only implement a gross-to-net savings methodology for determining the capacity value of energy efficiency resources through a Section 205 filing.”

AEE said it was happy with the outcome.

“As the commission states in its order, ISO New England has committed that it will not make changes to the measurement and verification standards for energy efficiency resources without engaging stakeholders and making a filing with FERC,” Jeff Dennis, AEE managing director, said in a statement. “We appreciate this commitment by ISO-NE in its answer to our petition, and the commission’s recognition of it, which brings needed clarity and certainty for energy efficiency resource providers.”

April 18, 2019

NERC Standards Committee Briefs: April 17, 2019

The standard authorization request (SAR) was prepared by the Inverter-Based Resource Performance Task Force (IRPTF), based on disturbance analyses and the development of the PRC-024-2 Gaps Whitepaper. The IRPTF identified potential modifications to PRC-024-2 to “ensure inverter-based generator owners, operators, developers and equipment manufacturers understand the intent of the standard.” (See NERC to Try Again on Invert e r Rules.)

One of the most significant changes is in Section 4.1.2., where NERC proposes expanding applicability to include transmission owners “that own a bulk electric system (BES) generator step-up (GSU) transformer or collector transformer.”

It also requires inverters not trip or “enter momentary cessation” — an interruption in their injection of current into the grid — within the “no trip zone,” except for “documented and communicated regulatory or equipment limitations.”

Slight Change to Standards Efficiency Review Retirements

The standard drafting team for Project 2018-03 Standard Efficiency Review Retirements informed the committee of a need for a minor tweak to existing rules.

Reliability standard INT-009-2.1 Requirement R1 references standard INT 010-2, which has been selected for retirement. The team will remove references to INT 010-2 from the remaining standard to avoid confusion.

The drafting team arose from NERC’s 2017 Standards Efficiency Review (SER) to consider the retirements of all or part of more than 30 reliability standards. (See “Team Gets Go Ahead on Standards Retirement Review” in NERC Standards Committee Br i efs: Jan. 23, 2019.)

Standards Drafting Team Set for Response to FERC Order 851

The committee unanimously approved nine nominees for a standards drafting team to respond to the directives in FERC O r der 851, which approved NERC’s revised geomagnetic disturbance standard.

NERC created Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) in response to FERC’s directives to improve how its initial GMD standard, approved in 2016, addressed the risks from “locally enhanced” events.

Order 851, approved in November, directed NERC to revise the standard further to require the implementation of corrective action plans for responding to vulnerabilities to “supplemental” GMD events and to authorize case-by-case extensions of deadlines on corrective action plans. (See Revised NERC GMD Standa r d Approved.)

– Christen Smith

April 17, 2019

NERC Standards Committee Briefs: April 17, 2019

Slight Change to Standards Efficiency Review Retirements

The standard drafting team for Project 2018-03 Standard Efficiency Review Retirements informed the committee of a need for a minor tweak to existing rules.

Standards Drafting Team Set for Response to FERC Order 851

The committee unanimously approved nine nominees for a standards drafting team to respond to the directives in FERC O r der 851, which approved NERC’s revised geomagnetic disturbance standard.

– Christen Smith

April 16, 2019

NYISO Studies Grid Transformation, Fuel Security

By Michael Kuser

RENSSELAER, N.Y. — A new NYI S O study will examine the energy market and reliability implications of a grid being transformed faster by public policy than by market forces, stakeholders learned Monday.

“We are addressing the reliability, resilience and flexibility needs of the grid transitioning to a greener New York,” Nicole Bouchez, NYISO principal economist, told the Installed Capacity/Market Issues Working Group during an April 15 meeting that discussed the study’s out l ine.

New York state policies will add large volumes of zero variable-cost resources to the market, with 15,000 MW of new intermittent resources expected to lead to the retirement of 4,000 to 6,000 MW of conventional generation over the next decade, the outline said.

“We’re trying to figure out what has been done and what needs to be done, so we want stakeholder feedback,” Bouchez said.

The ISO will release the first draft of the study May 22 for discussion on May 30, ahead of the Board of Directors’ June meeting, followed by another draft at the end of August to help inform the board’s strategic planning meeting in September, she said.

NYISO thinks the market needs appropriate investment signals to attract, retain and operate new and existing resources while avoiding additional out-of-market compensation.

“The goal here is not to get ourselves into an RMR [reliability-must-run] world,” Bouchez said. “We will be looking at market revenue sufficiency; I think in many ways that’s the most ambitious part of this whole paper.”

Transitional Roles

David Clarke, director of wholesale market policy for Power Supply Long Island, asked about the transitional role of carbon pricing.

“There are ways carbon pricing can lead to short-term carbon savings,” Clarke said. “The big question is, ‘Can the state count on the market to achieve its goals?’ Is there a robust market structure that can reliably get you to 2040?”

Bouchez said the ISO sees the situation differently; the state is the one achieving its clean energy goals, with the wholesale market trying to accommodate the changes while remaining effective. (See NYISO Seeks to Refine C a rbon Price Equation.)

Erin Hogan, representing the New York Department of State’s Utility Intervention Unit, asked the ISO to provide more precise definitions of the state’s goals. The study refers to a carbon-free grid by 2040, for example, when in fact the current announced target is a carbon-neutral grid, which is not the same thing, she said.

Raj Addepalli, representing the Alliance for Clean Energy New York, asked whether the ISO knows of anyone in the world with experience fully operating a system on resources with no variable costs and how markets can be structured in such a scenario.

Bouchez noted California has been thinking about the topic somewhat longer than New York but has not yet figured it out.

Miles Farmer of the Natural Resources Defense Council asked if the ISO has plans to address the inconsistency between its market mitigation rules and the state’s announced plan to pursue 100% emissions-free resources. He contended mitigating state-supported resources does not make sense with “a state-driven market entry model.”

“We will be looking at the mitigation rules and their compatibility with the desire of the state to have programs that value different attributes,” Bouchez said.

The ISO also announ c ed April 23 as the date for a second presentation by Analysis Group on the outli n e of a new study to provide additional insights into pricing carbon into NYISO’s wholesale electricity markets. The firm’s Sue Tierney and Paul Hibbard will present initial analysis results May 14, and the ISO expects to post the final results by the end of May. (See Ana l ysis Group Presents NYISO Carbon P r icing Study Plan.)

Fuel Security

NYISO also said Monday it will take a second look at assumptions being used in a separate study commissioned to assess winter fuel and energy security for the New York Control Area.

Hibbard presented additional details on the study, reviewing weather and natural gas market assumptions.

“The 17-day cold snap from last year is used in the new model, but it also includes three days from an older and more severe cold period,” he said.

Graph shows degree days and local distribution company natural gas demand for the 17-day modeling period to be used in the fuel security study. | *NYISO*

Based on review of local distribution company documents, Hibbard said essentially all pipeline export capacity from New York to New England is assumed to be under firm contract to deliver flowing gas or transport stored gas, with 889 MMcfd of natural gas available for electric generation after accounting for retail gas demand in New York, equivalent to roughly 5 GW of electricity generation under severe cold conditions.

Hogan asked what kind of validation process Analysis Group used “to make sure [it was] in the ballpark with results.”

“We’re trying to see where the risks are to the electric power system based on natural gas supply constraints, not the worst-case or best-case scenario,” Hibbard said.

Wes Yeomans, the ISO’s vice president of operations, said, “Remember, on the supply side, we’re going to have Indian Point out and no coal. … Things will be different in 2023 from what they were in earlier forecasts.”

One stakeholder mentioned the importance of considering the impact of energy storage on fuel demand, given the state’s programs to help finance development of 800 MW of new energy storage resources. (See NYPSC Expan d s Storage, Energy Efficiency Programs.)

Weather assumptions for the fuel security study will now include data from a previous 3-day severe cold snap. | *NYISO*

“We likely will not change base assumptions in the initial scenario but will address storage and various other stakeholder concerns in the scenarios and as part of the findings of the analysis,” Hibbard said.

Analysis Group currently expects to present initial findings of the energy security study in May, additional findings in June and final results in July.

April 16, 2019

FERC to PJM: Clarify Allowable Costs for Energy Offers

By Christen Smith

FERC handed PJM a mixed ruling Monday on a set of proposed Tariff and Operating Agreement revisions intended to equalize the cost recovery treatment of gas-fired plants with that of other thermal generators.

The commission approved the Tariff changes, agreeing PJM’s existing rules “unduly discriminate” against combined cycle and combustion turbine generators by preventing them from recovering inspection costs as a “maintenance adder” in their energy prices.

Those types of variable costs are considered related specifically to electricity production and should be recoverable in the energy market, the commission said (ER19 –210). Many nuclear and fossil generators currently factor these expenses into their avoidable-cost rates in the capacity market.

In approving the Tariff changes, FERC rejected the PJM Independent Market Monitor’s argument that major maintenance costs incurred as a result of electricity production should be recovered in the capacity market because they are not short-run marginal costs. The PJM Load Coalition likewise insisted variable operations and maintenance costs belonged in capacity market offers only.

The commission also dismissed concerns that the changes risked double recovery by generators in both the energy and capacity markets.

FERC agreed with PJM that its existing rules for maintenance cost recovery discriminates against CC and CT generators | *Panda Power Funds*

“We accept PJM’s Tariff revisions to clarify that all resource types are prohibited from recovering variable maintenance costs that are directly attributable to the production of electricity in their avoidable-cost rate in the capacity market,” the commission wrote.

But FERC found related changes in PJM’s Operating Agreement to be “unjust and unreasonable” because “the definitions of maintenance adders and operating costs fail to provide sufficient clarity with respect to permissible cost components of cost-based energy market offers.”

The commission directed PJM to submit a compliance filing clarifying what maintenance costs sellers can include in their energy market offers. The revised OA must do the following:

Create a single, properly defined operating cost component.
Remove “incremental fuel costs” and “other incremental operating costs” from the list of permissible components in a cost-based offer.
Add a definition for “opportunity costs” and create a new section detailing this component.
Create a new section for the “application of cost components to three-part cost-based offers.”
Move definitions for “maintenance adders” and “operating costs” to a new opportunity costs section.
Expand the list of maintenance costs to include cooling towers, fuel and water pumps, emissions-reduction catalyst equipment, and replacement of filters and cartridges.
Add sections to memorialize PJM’s process of calculating major maintenance costs based on 10- or 20-year histories.
Revise the section related to the review of maintenance adders and operating costs to require market sellers to specify the maintenance history years on which their maintenance adders are based.

The Monitor had pushed for the required clarifications.

FERC on Monday also accepted PJM’s quadrennial revision of its variable resource requirement curve used in the Reliability Pricing Model, effective Jan. 17 (ER19-1 05).

April 15, 2019

PJM PC/TEAC Briefs: April 11, 2019

VALLEY FORGE, Pa. — PJM’s Planning Committee endorsed capacity generation rule changes for Manual 21, save for the controversial effective load-carrying capability (ELCC) calculations deferred for a vote until next month.

The endorsed revisions include a new section devoted to obtaining, maintaining or losing capacity interconnection rights (CIRs), as well as sections for installed capacity calculations and testing requirements.

New rules on testing within temperature bounds would take effect June 1, with provisions on simultaneous testing and the ELCC effective for delivery year 2022/23. Wind and solar units losing CIRs would be notified before Jan. 1, 2025.

The committee will consider PJM’s ELCC calculations, as well as modifiers proposed by the American Wind Energy Association last month, at the May 16 meeting. (See AWEA Balks at PJM Plan on Wind, Solar Capacity.)

PJM wants endorsement from the Markets and Reliability Committee at its April 25 meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. The proposal would not affect UCAP values from prior auctions.

Market Efficiency Process Enhancement Task Force Gets Phase 3

Stakeholders agreed to a third phase for the Market Efficiency Process Enhancement Task Force after approving manual revisions that change how often PJM re-evaluates projects and shifts planning timelines.

The phase 2 proposal moves the long-term planning window back two months to January-April from November-February to align it with MISO’s processes. If approved at the April MRC, both RTOs would post economic drivers in January.

The mid-cycle model refresh would be made in late April to allow project proposers extra time to analyze their projects under the revised case prior to a final submission.

PJM’s Brian Chmielewski said the task force agreed the RTO will not re-evaluate any projects once a certificate of public convenience and necessity (CPCN) has been issued or — in the case of states without such a process — once construction has begun. Under current rules, PJM reviews the costs and benefits of economic-based transmission projects annually to ensure they remain economical. (See “PJM Readies Package on Market Efficiency Rule Changes,” PC/TEAC Briefs: March 7, 2019.)

Stakeholders modified proposed language in Section 1.5.7 of the Operating Agreement by adding “or relevant regulatory authority” to ensure projects that don’t require a CPCN or fall under the jurisdiction of any state agency will be covered under the new rules.

Phase 3 will tackle how regional targeted market efficiency projects address historical congestion using the same criteria as used in interregional TMEPs and possibly changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits.

Staff will seek MRC approval of the changes in April and Members Committee endorsement of Operating Agreement revisions in May. PJM wants the new rules effective Aug. 1 for the 2020/21 long-term window.

Revisit Benefit-cost Analysis, Monitor Says

The Independent Market Monitor wants stakeholders to reconsider how it performs benefit-cost analyses, noting the current process turns a blind eye to any drawbacks that come with a transmission project.

“The current analysis ignores anywhere where benefits are negative,” said Howard Haas, of Monitoring Analytics, as he presented the Monitor’s first read of a problem statement and issue charge addressing the matter. “If you are ignoring the effect on locations where the effect is negative and only accounting for effects where they are positive, you’re going to approve things you shouldn’t approve.”

Specifically, the Monitor says PJM’s current method ignores increased congestion in all zones resulting from a transmission project when calculating energy market benefits. Haas said the benefit-cost analysis does not account for the fact that transmission project costs are not subject to cost caps and may exceed estimated costs by a wide margin. When actual costs exceed estimated costs, the benefit-cost analysis is effectively meaningless and low estimated costs may result in inappropriately favoring transmission projects over market generation projects or the option of no project at all, he said.

“We think there is something we could be doing differently, and we’d like to have a discussion about what those could be,” Haas said.

While stakeholders appeared supportive of discussing some of the Monitor’s concerns, many — including PJM itself — pushed back against questioning the RTO’s 15-year planning horizon for measuring benefits.

“That was literally just approved by FERC two months ago,” PJM’s Tim Horger said. “Let’s get some experience with using this.”

In a Feb. 19 ruling, PJM won its bid to revise the benefit-cost ratio to ensure projects with delayed in-service dates only receive analysis within the existing 15-year planning horizon. Under previous rules, PJM said it spent considerable time developing ad hoc projections for years beyond the current cycle, resulting in “risky” and “unreliable” modeling.

The Monitor protested PJM’s reasoning, proposing instead a longer horizon exceeding 20 years. FERC rejected the Monitor’s arguments. (See PJM Extends Planning Window After FERC Approvals.)

“To the extent that we just had the paint dry on one filing … if we had filed our proposal, we do believe it would have been approved,” Haas said on Thursday.

Pauline Foley, PJM’s legal counsel, questioned the Monitor’s insistence on bringing the issue up now instead of during the earlier phases of the Market Efficiency Process Enhancement Task Force.

“There’s a little bit of frustration. … I think the task force is the appropriate place to bring this, and I think we need a new problem statement, frankly,” she said. “My suggestion is that this be a whole new initiative because it looks like you’re trying to revamp the market efficiency process as a whole.”

LS Power Will Seek 2nd Deferral on Transmission Replacement Language

LS Power’s Sharon Segner told the PC on Thursday she will seek another 60-day vote deferral on her company’s proposed revisions to the Regional Transmission Expansion Plan process.

Segner’s amendment to Manual 14B was slated for stakeholder endorsement at the April 25 MRC meeting. The proposal specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria.

Aaron Berner, PJM manager of transmission planning, said stakeholders agreed to another deferral after conducting two educational sessions last month to discuss how projects are removed from the RTEP. (See “RTEP Removal Discussions Scheduled,” PJM PC/TEAC Briefs: March 7, 2019.)

“There is still some work to be done and some technical discussions to be had,” he said. “It’s a good step to keep moving forward. We are finding some resolution and some common ground on some of the language.”

PJM will schedule as many as five additional meetings on the subject over the coming months, Berner said.

TMI Deactivation Costs Rise $1.5 Million

Three Mile Island’s scheduled deactivation just got $1.5 million more expensive, PJM’s Phil Yum said Thursday.

The plant requested new station service to a control building with a new 230-kV bus ahead of its planned closing in September. Yum said the work is necessary in order to fulfill the deactivation request.

JCP&L Needs Transmission Line Upgrades

Jersey Central Power & Light requested a dozen transmission line upgrades, citing outdated and faulty equipment with few experts left to fix it.

FirstEnergy identified protection schemes using a certain vintage of relays and communication equipment with a history of misoperation, the utility said in a problem statement submitted to the Transmission Expansion Advisory Committee on Thursday.

Affected 230-kV lines include: Atlantic-Red Bank, Atlantic-Eaton Crest-Red Bank, Pohatcong-West Wharton, Gillette-Traynor, Greystone-West Wharton, Raritan River-Werner, Greystone-Portland, Atlantic-Smithburg, Chester-Glen Gardner, Gilbert-Glen Gardner and Chester-West Wharton.

Dominion Supplementals

Dominion Energy said customers requested two new transformers in Northampton County, N.C., and Charles City County, Va. The new units will support commercial load growth and contingency loading for the loss of an existing transformer.

Dominion also proposed a $2.5 million project to satisfy requests for a new substation in Chesterfield County, Va. The plan involves cutting into line No. 2066, installing three switches and a 230-kV circuit switcher on the high side of a new transformer.

In addition to building a third transformer at the Winterpock substation, Dominion suggests installing a four-breaker ring and a circuit switcher on the high side of the new transformer for $8.5 million. The utility also wants to spend $750,000 to install a new 230-kV circuit switcher at the Rockville substation and $4.5 million to replace an old transformer along the Chesterfield line. Transformer replacements near the Peninsula substation are estimated to cost $16.1 million.

AEP Takes over Dayton Line

Dayton Power and Light will retire its Killen substation in June and transfer use of the 345-kV Don Marquis-Stuart line to American Electric Power. AEP said it will need to bypass Killen taps in order to complete the line circuit.

– Christen Smith

April 15, 2019November 5, 2023

OSW Industry Urges Cooperation as States Covet Jobs

By Rich Heidorn Jr.

NEW YORK — Looking for a place to assemble offshore wind farms on the East Coast?

New York officials say their 63 acres at the South Brooklyn Marine Terminal could be just the place. For about $300 million, a report for the New York State Energy Research and Development Authority says, it could demolish existing warehouses, dredge the dock area and fortify the ground to withstand loads of 6,000 pounds/square foot to dedicate the port to OSW staging and deployment.

Massachusetts officials, meanwhile, are touting New Bedford, insisting the new industry can coexist with fishermen in the most productive fishing port in the country. In October, developers signed a lease to use the New Bedford Marine Commerce Terminal to stage and construct turbines for the 800-MW Vineyard Wind project 15 miles south of Martha’s Vineyard.

And Boston office buildings are renting space to members of the European OSW industry looking to create a headquarters for their U.S. operations.

East Coast states are now promising to fund the construction of nearly 18,000 MW of offshore wind, almost equal to Europe’s current capacity. While state officials say the procurements are long-term investments intended to address climate change, they acknowledge the immediate lure is economic development. The European OSW industry employs 40,000 people.

At the Business Network for Offshore Wind’s 2019 International Partnering Forum at the Grand Hyatt New York last week, the talk was all about the jobs and contracts the industry would bring. In the forum’s exhibit area, state economic development agencies and labor unions manned booths alongside engineering firms and providers of everything from cranes to helicopters to drones.

Liz Burdock, CEO of the Business Network, said that while building a local supply chain will lower the cost of U.S. OSW, it is the economic development that the industry should promote in talking with other stakeholders.

“As we talk about public acceptance and getting more people willing to support our industry, I don’t think it is really about what is the lowest cost of energy. It has to be about what is the job creation. And maybe we are going to have to pay a little bit more,” she said. “I think that’s something that we need to start saying.”

“We have every intention to be here locally,” said Jason Folsom, director of U.S. sales for MHI Vestas Offshore Wind, a joint venture between Mitsubishi Heavy Industries and turbine maker Vestas Wind Systems based in Denmark. “We do not want to run our new market businesses from Europe. We’re here to build stuff.”

Cooperation vs. Competition

Numerous speakers at the conference questioned whether states can cooperate to nurture the fledgling industry even as they compete to promote their ports as potential manufacturing hubs. Several urged states to stagger their procurements to create steady, predictable demand.

“The supply chain in the U.K. was really dependent on having consistent procurements happening,” said Eric Thumma, director of policy and regulatory affairs for Avangrid Renewables. “When they had an on-again, off-again nature of the procurements, that made it very difficult to get supply chain folks to be confident enough to invest. So, one of the challenges in the U.S. is how do you get the states to collaborate on sort of a comprehensive offshore policy?”

NYSERDA Chairman Richard Kauffman said the states are cooperating through the National Offshore Wind Research & Development Consortium, which the agency started last year with funding from the U.S. Department of Energy. Other participants include the National Renewable Energy Laboratory, Brookhaven National Laboratory, developers, and the states of Maryland, Massachusetts and Virginia.

“We frankly never realized the power of friendly competition that we started through this collaboration,” Kauffman said. “All Eastern states with water can benefit from scale.”

NYSERDA CEO Alicia Barton was asked by an audience member during one panel discussion at the IPF whether New York would invest in assets outside the state if it can’t build a manufacturing hub in any of its ports.

“We get that question a lot,” she acknowledged, without definitively answering it. “I work for the people of New York, and I am, along with Gov. [Andrew] Cuomo, committed to making New York the center for the U.S. offshore wind industry. We’re not shy about that.

“On the other hand, we are quite realistic. … We want 9,000 MW of offshore wind. That makes us a very large buyer of offshore wind, locally speaking. … It is without a doubt in our interests to see the U.S. supply chain mature [and] develop as fast as possible to see the U.S. industry scale as fast as possible so that as a large buyer, we will get the best deal possible.”

Tim Sullivan, CEO of the New Jersey Economic Development Authority, said he’s realistic. “We’d love to have those 40,000 [jobs] in New Jersey, but it’s going to be a regional thing,” he said.

Sullivan said states will need to work with community colleges and labor unions to develop the workforce needed to ensure the supply chain is developed locally. “Cobbling together wind, offshore wind and oil and gas [resources] from the European supply chain … would be a really unfortunate outcome,” he said. “That would be a terrible outcome for New Jersey … for the Northeast, because this is a once-in-a-generation opportunity.”

Sullivan said officials overseeing port development for OSW also need to balance short- and long-term considerations.

“There will be an impulse to overly design the infrastructure and the supply chain to [accommodate] the first set of projects that are moving forward as opposed to designing for an industry,” he said. “We want a network of ports that is somewhat project-agnostic, that is somewhat developer-agnostic, so it can have multiple users over the next 45 to 50 years.”

Walter Cruickshank, acting director of the U.S. Bureau of Ocean Energy Management, which awards leases and oversees OSW projects in federal waters, said his agency is doing its part to ensure the industry’s growth by developing “an efficient and predictable regulatory process.”

BOEM has issued 15 leases totaling more than 1.7 million acres at a cost of almost $477 million since 2012. The lease price per acre — which had been as low as $39 in 2013 — topped $1,000 in three auctions off Massachusetts last year.

Cruickshank said OSW projects will be subject to President Trump’s “one federal decision” executive order, which requires all federal agencies to coordinate their reviews of major infrastructure projects in a single proceeding and to issue rulings within two years.

BOEM also is taking a regional approach to its evaluation of some potential new wind energy areas (WEAs), he said.

Rather than focus on the small section of the ocean off New Hampshire’s narrow 18.5-mile coast, he said, “We see value in looking at the Gulf of Maine as a whole, and pulling in the states of Maine and Massachusetts to look … at the effect of sharing natural, socioeconomic and cultural resources to plan how we might proceed in that area.”

BOEM also is combining the planning processes for the Carolinas, with plans to identify a WEA there later this year.

Giles Dickson, CEO of WindEurope, a trade group representing the European wind industry, said success for the U.S. OSW industry will require “happy coexistence” with the military as well as the fishing and shipping industries.

NYSERDA was cognizant of those stakeholders when it issued a solicitation for the state’s first, 800-MW OSW procurement, Barton said. The agency is expected to announce the winners next month. (See Four Bidders Vie for NY Offshore Wind Project.)

“We made clear … that we wanted to see great projects,” Barton said. “That we wanted to see strong economic development commitments, that we wanted to see commitments to labor … we wanted to see fishery mitigation plans.”

100% Clean

The Atlantic states’ OSW targets are central to their efforts to reduce carbon emissions and address climate change.

In January, for example, Cuomo announced New York was nearly quadrupling its offshore wind energy goal to 9 GW as part of its plan to reach “100% clean power” by 2040. (See New York Boosts Zero-carbon, Renewable Goals.)

New Jersey, California, Hawaii, New Mexico, Puerto Rico and more than 100 cities across the country have also pledged to move to 100% renewable or “clean” energy, as have more than 150 companies, from Adobe to Walmart.

While the 100% goal has no shortage of critics who question its feasibility, those who support it say OSW will be a big part of the resulting generation mix. A recent Stanford study projected a 19% share for offshore wind, with onshore wind and utility-scale PV at 31% each.

“It’s very ambitious, but we do believe it’s actually achievable,” Barton said of Cuomo’s goal. “To achieve that target, offshore wind has to be a huge piece of the puzzle,” she added, noting that the 9,000 MW of OSW would represent 30% of the state’s load.

Barton said the 100% pledges by Cuomo and other governors reset “the conversation about what’s possible. Even a year or two, three years ago, we would not be talking about California, New York [and] New Jersey — major economies in the U.S. — committing to a 100% clean electricity. It’s been a radical mind shift. It’s clear we don’t have a lot of time … to do what we know needs to be done to combat climate [change].”

Marie Hindhede, deputy permanent secretary for the Danish Ministry of Energy, Utilities and Climate, said higher penetration by renewables doesn’t mean less reliability, noting her country had 99.99% “security of supply” despite getting three-quarters of its power from wind, solar and biomass.

To reach the 100% goal, she said, Denmark needs an active demand-side response and more transmission to sell power across national boundaries. Hindhede said power trading with other countries has been key to balancing intermittent generation thus far but that electric storage will likely be part of the solution in the future.

Steve Dayney, head of North American offshore operations for Siemens Gamesa Renewable Energy, said reaching 100% is “not really an issue of technology. It’s an issue of, do we have the will to do it? It’s an issue of how fast new technologies can emerge and how quickly can we industrialize it to make it cost-competitive.”

Ditlev Engel, CEO of DNV GL, which provides risk management and quality assurance services to OSW and other maritime energy industries, said one key to winning political support for 100% policies is to include the health-related costs of climate change and air pollution in the discussion.

“Everybody talks about the cost of electricity per megawatt or per kilowatt-hour. But what about the costs to society? Are we using the right rulers for how we set the systems up?” he asked.

April 15, 2019November 5, 2023

Longer Tx Planning Horizon Seen for OSW

By Rich Heidorn Jr.

NEW YORK — U.S. grid operators may have to consider a different way of transmission planning for offshore wind, panelists told the Business Network for Offshore Wind’s 2019 International Partnering Forum last week.

Speakers said interconnections to the land-based grid should be shared “social” resources and that queue positions shouldn’t be a deciding factor in states’ OSW solicitations.

Christer af Geijerstam, president of Equinor Wind US, said locating offshore cables is not a concern. “But if you are targeting substations that are 20 miles inland, how many times do you want to go dig up that same road for future projects? Should we pre-invest in capacity?”

Sven Utermöhlen, board member for E.ON Climate & Renewables, agreed that a long time horizon is essential to OSW transmission planning.

“If you think about 15 to 20 individual projects in the next decade or so to be constructed, you may find that there is only a handful of really suitable, sensible grid connection points … you better have a plan in place because you don’t want to dig up the same onshore connection route five times over the next 15 years.”

Repeated construction could undermine public support and complicate permitting, he said. “So, you better start thinking about a real network development plan.”

Clarke Bruno, lead partner for Anbaric Development Partners, said New York will have to expand its onshore grid to move its planned 9,000 MW of offshore wind from delivery points on Long Island and in New York City.

“Long Island [is] about a 2,400-MW load. Taking half of that 9,000 MW and trying to drop 4,500 MW into a 2,400-MW system is going to be a challenge. The same is true in New York City [with] a much larger average load of 6,400 [MW].

“There are very few interconnection points in Long Island and New York that have the degree of robustness that you would like to have. And … getting from offshore to those interconnection points, you have very few good routes, given the congestion on Long Island and the wetlands and, in New York City, the bottleneck of the Verrazano Narrows. So, with those challenges in mind, it strikes me that a planned transmission system is essential.”

The state must “plan and permit the offshore wind so that we are able to … seize the optimal interconnection points and allow equal access to all developers to those very scarce social resources.”

Gil Quiniones, CEO of the New York Power Authority, agreed with Bruno’s description of the challenges.

“Long Island, especially on the East End … we [say] ‘the wires are thinner.’ And New York City is very dense and [does not have] a lot of very easily accessible connection points. … Logic tells you that there is maybe an opportunity to have a collector system … and bring it to the optimal interconnection point. It does require planning. It requires all the regulatory bodies — state and federal — to be aligned in making that happen.”

State officials and grid operators have only begun to consider the transmission challenges of offshore wind.

The New York State Energy Research and Development Authority’s OSW Master Plan, published in January 2018, said an expandable “backbone” transmission system would offer economies of scale and reduced barriers to entry but could also lead to overbuilding and stranded asset costs. A transmission system custom-built for a single offshore facility — the “direct radial” model — would be less efficient and is limited in scope, the report said. (See NY Offshore Wind Plan Faces Tx Challenge.)

Proposed offshore wind projects in Connecticut (1,760 MW), Rhode Island (1,056 MW) and Massachusetts (6,064 MW) represent almost half of the 18,600 MW in ISO-NE’s transmission queue, Alan McBride, the RTO’s director of transmission and strategy services, told the IPF conference in a presentation.

PJM Begins Talks on OSW Tx Rules

In February, PJM’s Planning Committee approved a problem statement to consider granting merchant transmission developers capacity interconnection rights (CIRs) for offshore wind. (See “PC Moves Forward on Offshore Interconnection Rights,” PC/TEAC Briefs: Feb. 7, 2019.)

Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore.

Offshore transmission developers want to acquire CIRs so PJM can identify the necessary network upgrades.

The key difference from the normal procedure is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses.

The first meeting of the initiative, on April 16, will consist of education about the RTO’s current process. Three months of exploration into alternative options are planned before members will return to the PC in August to consider endorsement of proposed changes.

April 15, 2019

ERCOT Board of Directors Briefs: April 9, 2019

ERCOT staff last week warned that forward energy markets indicate high prices this summer, which could lead to unexpected increases in credit obligations.

Given current forward prices, Mark Ruane, ERCOT director of settlements, retail and credit, told the Board of Directors during its April 9 bimonthly meeting that forward adjustment factors may increase materially as summer draws closer, leading to “substantial increases in collateral requirements for ERCOT counterparties.”

ERCOT’s April Board of Directors meeting

Ruane said the market “seems to be expecting high prices,” pointing to August forwards that approached $185/MWh for ERCOT’s North hub but settled back to $160/MWh in mid-March. July forwards were about $100/MWh, and June forwards $85/MWh.

Forward prices are used to adjust the day-ahead and real-time exposure components of ERCOT’s credit calculation. Counterparty letters-of-credit are capped at $750 million, which has been reached only three times — all during last summer.

Ruane said he wants to ensure counterparties are aware of the risks of increased credit requirements and constraints on letter-of-credit issuers, and that they maintain “appropriate collateral” and sufficient letter-of-credit capacity.

“We’re highlighting this risk because we hit the limit three times” last summer, Ruane said.

The Texas grid operator has a historically low planning reserve margin of 7.4% as it heads into summer. It is projecting a record peak of 74.9 GW this summer, with 78.2 GW of capacity on hand. (See ERCOT Summer Forecast: Record Demand, Alerts.)

Ruane also said ERCOT will be holding a mass transition drill with market participants and Texas regulatory staff during the second quarter. The drill is intended to identify potential issues in transitioning a defaulting competitive retailer’s electric service identifier IDs.

Staff, TAC Promise Updates on Cold Weather Event

ERCOT CEO Bill Magness and ENGIE’s Bob Helton, chair of the Technical Advisory Committee, both promised directors and stakeholders a future update on the grid operator’s actions to address events during an early March cold spell that led to much market consternation. (See ERCOT Generators Upset over Early March Weather Event.)

Magness said ERCOT actions “focused on delaying scheduled outages that had not begun prior to forecast peak day morning loads.” Stakeholders complained about a lack of transparency into market information and confusion over communications.

“Sometimes, it’s very important what words you use. ‘Request’ and ‘instruction’ are different things in our world,” Magness said during his CEO update. “The market has to know exactly what to expect from us when we get into these situations.”

The TAC has created a task force to determine improvements that can be made in future situations. Magness said changes could involve:

Communications and procedures during anticipated emergency conditions;
Market visibility of ERCOT forecasts as conditions change;
A process governing delay or withdrawal of planned outages; and
Consideration of cost recovery related to postponing or canceling outages for reliability reasons.

Helton said the TAC plans to hold one or two workshops on the recommendations that might come out of the work.

“We were using new tools, based on where we are today in unchartered territory,” he said. “Sometimes, when you use those tools, you find concerns. There was a little rust on those tools.”

ERCOT Board Chairman Craven Crowell (left) and CEO Bill Magness (right)

ERCOT Projecting $34M Favorable Budget Variance

Magness told the board that ERCOT is already projecting a favorable budget variance of $34 million this year, after having ended last year with a roughly $29 million favorable variance.

The CEO said the variance is driven by interest income from congestion revenue rights and continued load growth. Interest income is expected to be almost $19 million over budget this year as a result of higher balances and rates, and administrative fees are projected to be $6.1 million over budget, based on current system load actuals and forecasts.

A reduction in ERCOT project costs could add another $7 million to the variance. The grid operator moved several projects up from 2019 into 2018, accounting for much of the variance, Magness said.

Magness also unveiled ERCOT’s annual State of the Grid report in a redesigned format that features major accomplishments from 2018’s record-breaking year and highlights the grid operator’s effort to facilitate a competitive retail market, incorporate new technologies and improve cybersecurity awareness.

Directors Approve Changes to NPRR916

The board unanimously approved a pair of Nodal Protocol revision requests (NPRRs) previously endorsed by the TAC during its March meeting.

NPRR916, which changes the mitigated floor for natural gas units from a fuel-indexed price to -$20/MWh, was approved as amended by ERCOT comments. Staff recommended the mitigated floor price be reduced from its original level of $0 and also requested the NPRR’s implementation be accelerated from May 1 to April 10 to “correct inconsistencies in pricing outcomes.” (See “ERCOT to Ask Board for NPRR916 Changes,” ERCOT Briefs: Week of April 1, 2019.)

Mark Ruane, ERCOT director of settlements

The amendments were driven by recent negative gas prices at the Waha Hub and to match the mitigated floor for coal and lignite units.

NPRR909 resolves a gap in the protocols by addressing the unplanned unavailability of emergency response service (ERS) loads and generators. Morgan Stanley, in the Independent Power Marketer segment, cast the lone opposing vote at the TAC “as a matter of principle,” Helton said.

Directors also approved the Human Resources and Governance Committee’s recommendation to allow business-continuity emergency purchases by ERCOT of up to $5 million and unanimously approved nine other NPRRs, a change to the Retail Market Guide (RMGRR) and a system change request (SCR) on its consent agenda:

NPRR891: Removes the 50-kW threshold for non-opt-in entities to report unregistered distributed generation to ERCOT for its unregistered DG report.
NPRR900: Addresses inconsistencies in the current Nodal Protocol language that don’t align with current processes, Texas Public Utility Commission rules and system design.
NPRR906: Streamlines the protocol language and removes ambiguity over how ERCOT systems handle the decision-making entity during the security-constrained economic dispatch (SCED) mitigation processes.
NPRR908: Aligns RMG references and updates mass transition notification requirements for emergency qualified scheduling entities (QSEs) to match with RMGRR159’s revisions.
NPRR912: Addresses the settlement of switchable generation resources (SWGRs) that receive a reliability unit commitment instruction to switch from a non-ERCOT control area to the ERCOT control area. The change provides a make-whole payment for an SWGR when its real-time ERCOT revenues are not sufficient to cover certain specified costs the resource may have incurred in complying with the RUC instruction.
NPRR914: Adds data points unique to a controllable load resource available for dispatch service or dispatch with a real-time market bid to the existing 60-day SCED disclosure report.
NPRR8920: Modifies the resource ramp rate logic in the protocols (Section 6.5.7.2, Resource Limit Calculator) to dynamically adjust the amount of ramp rate reserved for regulation service in real time based on the percentage of regulation service being deployed in the opposite direction.
NPRR922: Aligns the DC tie import forecast with forecasts of other resources in ERCOT’s Capacity, Demand and Reserves (CDR) report that are deployed during ERS and other energy emergency alert events. The revision also addresses a reporting gap in the CDR by specifying an approach for forecasting expected capacity imports for planned DC tie projects.
NPRR925: Increases the minimum quantity that can be submitted for point-to-point (PTP) obligation bids from 0.1 MW to 1 MW, matching the minimum quantity for energy-only offers and energy bids.
RMGRR159: Clarifies the mass transition processes and communications by shortening required minimum timelines for initial notification to affected parties from two hours to one hour, and allowing preliminary notification of mass transition to affected transmission and distribution service providers, providers of last resort and PUC staff, as long as protected information is not disclosed. Also clarifies that ERCOT may coordinate periodic testing of mass transition systems and processes with market participants.
SCR798: Introduces a limit on the total number of PTP obligation bids that can be submitted into the day-ahead market per QSE and per counterparty. The limit will apply to the number of bid IDs per operating day.

— Tom Kleckner