Page 1142 – RTO Insider

July 16, 2018

MISO, SPP Loosen Interregional Project Requirements

By Amanda Durish Cook

MISO and SPP announced Friday they plan to relax barriers that have prevented them from agreeing to develop interregional projects.

The two RTOs will remove their $5 million cost threshold and joint modeling requirement for the projects, staff revealed during a July 13 conference call of the Interregional Planning Stakeholder Advisory Committee.

Removal of the $5 million cost standard will not affect other criteria, such as the 5% or higher benefit threshold for each RTO and the requirement that projects be in service within 10 years of approval, the RTOs said.

miso interregional projects reserve requirements — Lopez | © *RTO Insider*

Instead of creating a joint model, MISO and SPP will now leverage their existing regional planning models to evaluate interregional projects. Eliminating the joint model requirement will shorten a lengthy study process and allow the RTOs to examine more potential projects, they said. MISO and PJM removed a similar requirement almost two years ago in response to a FERC complaint filed by Northern Indiana Public Service Co. (See FERC Orders Changes to MISO-PJM Interregional Planning.)

MISO Planning Adviser Davey Lopez said removing the joint model will eliminate inconsistencies between the joint model and the RTOs’ respective regional models.

“We’re both doing very robust regional reviews,” SPP Interregional Coordinator Adam Bell added.

Concerns over Cost Allocation

Bell said stakeholders were split over removal of the joint model; while some wanted the triple hurdle eliminated, others were concerned about equitable cost allocation absent a joint model. Had MISO and SPP approved an interregional project, the joint model would have determined each RTO’s share of the cost.

The RTOs said they will calculate adjusted production costs and avoided costs for all interregional projects using their regional calculations of benefits. They have pledged to provide interregional cost allocation examples to address stakeholders’ concerns about inequities and explore the possibility of adding a market-to-market benefit metric.

The Wind Coalition’s Steve Gaw stressed the need for the RTOs to develop an objective cost allocation plan rather than promising negotiations.

“For me, this isn’t sweeping things under the rug. This is sweeping things into a different room,” Gaw said. “If you’ve got two RTOs determining what their benefits are. … I think you have to have something that avoids you arguing over how the benefits are calculated in each of your regions.”

Other stakeholders also asked for a more specifics on cost allocation, and Lopez promised more discussion on the issue during the August IPSAC meeting.

“This is a difficult conversation to have without examples in front of us,” Bell acknowledged. He assured stakeholders the RTOs only arrived at the decision to remove the joint model after substantial discussion about how it would affect project cost allocation.

The two RTOs agreed in February not to pursue a 2018 coordinated system plan, which could have resulted in an interregional project, instead promising to examine their joint planning process and seek ways to improve interregional coordination.

The two have completed two coordinated system plan studies to date, but neither has resulted in a viable interregional project. During their 2016/17 study, the RTOs identified three possible projects, but all were disqualified by the $5 million cost requirement, Lopez said.

“I think the studies have shown us that there are some barriers,” Lopez said.

Bell said MISO and SPP will likely return to the IPSAC next month to seek approval to revise their joint operating agreement, which will be filed by the end of the year.

Bell said the RTOs hope to produce another coordinated system plan study in 2019, although filing timelines could interfere with the goal.

No Dent in MISO 345-kV Threshold

The JOA revisions will not include a provision to lower MISO’s requirement that market efficiency interregional projects be at least 345 kV.

“SPP continues to encourage MISO to pursue lowering its current 345-kV voltage threshold for SPP-MISO interregional projects,” SPP said. However, MISO said it continues to view the voltage threshold as a strictly regional issue, not up for discussion in the IPSAC because there is no voltage threshold criteria in the JOA. Lopez said MISO’s Regional Expansion Criteria and Benefits Working Group will continue to explore the effects of lowering the threshold.

MISO last month said it will revise its regional — not interregional — cost-sharing practices for market efficiency interregional projects with SPP in order to match its process for PJM seams projects, lowering the voltage threshold to 100 kV over some stakeholders’ objections. (See MISO to Lower SPP Interregional Project Thresholds.) MISO lowered its 345-kV threshold for MISO-PJM projects to 100 kV in 2016 under FERC’s orders.

The MISO-SPP plan also excludes a requirement that prospective interregional projects that were evaluated but didn’t pass a cost-benefit ratio be reviewed and voted on by both boards of directors. MISO said requiring such a move was unnecessary: Interregional projects that pass all criteria would still need to be approved by the boards.

July 15, 2018

FERC Advances Mystic Cost-of-Service Agreement

By Michael Kuser

FERC on Friday tentatively accepted a cost-of-service agreement between Exelon and ISO-NE for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues (ER18-1639).

The order drew sharp rebukes from Commissioners Robert Powelson and Richard Glick, both of whom called it “yet another rush to judgment.”

The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. But the commission found the information Exelon provided to support those figures insufficient, setting for hearing the company’s proposed capital expenditures, fuel costs, and operations and maintenance expenses.

Notably, FERC did not hold the hearing in abeyance and appoint a settlement judge, as it often does when it suspends an accepted filing. Instead, it ordered an expedited hearing schedule, citing Exelon’s Jan. 4, 2019, deadline for deciding whether to retire the units and the beginning of Forward Capacity Auction 13 on Feb. 4. The agreement goes into effect June 1, 2022, subject to the outcome of the hearing.

The commission ordered the presiding judge to certify the record by Oct. 12, with initial briefs due Nov. 2 and reply briefs Nov. 16.

ISO-NE’s Tariff does not allow for reliability-must-run agreements, and only allows cost-of-service agreements to respond to local transmission security issues. FERC on July 2 denied the RTO’s request for a Tariff waiver to allow for the Mystic agreement. Exelon said in March that it would retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022 (ER18-1509). (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

Cost-of-service agreement Mystic ISO-NE FERC — Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.

The commission instead ordered the RTO to revise its rules to allow cost-of-service agreements for facilities needed to address fuel security issues, or show cause as to why it shouldn’t have to (EL18-182). ISO-NE’s response is due Aug. 31.

Powelson and Glick also dissented in that order, and both cited it in their dissents last week.

“The commission is not even waiting for stakeholders’ responses to the show cause order it issued last week before plunging ahead with its plans to bail out Mystic and Distrigas,” Glick said. Exelon included in the agreement the costs of purchasing fuel from and operating the nearby Distrigas LNG import terminal, which it is buying from ENGIE North America.

“By setting the agreement for modified settlement and hearing procedures, the majority is expressing a preference for a short-term cost-of-service mechanism to address fuel security,” Powelson said. “That message may have been implied in the waiver order, but after today’s order there is no question as to the majority’s direction. …

“Over the next few months, interested participants will focus time and energy on the agreement in an attempt to reach consensus on a host of challenging issues. Because the commission has failed to narrow the issues to be addressed in this proceeding, today’s order has opened a proverbial can of worms. Thus, instead of working collaboratively to respond to the commission’s Section 206 inquiry or consider more cost-effective alternatives, stakeholders will be working on the Mystic agreement.”

Distrigas, Cost Allocation

While FERC said it could not determine whether the agreement was just and reasonable, it did comment on several issues raised by protesters in the proceeding.

Several protesters questioned whether including an entire LNG facility in a cost-of-service rate violated the Federal Power Act.

The commission said it would set the matter for hearing, but “in advance of the hearing, we find unpersuasive arguments that the FPA prohibits any recovery of the fuel supply charge for the Distrigas facility.”

“This finding as to jurisdiction does not mean that Mystic is entitled to recover all costs that it claims in connection with the Distrigas facility,” the commission said. “Whether individual components of a cost-of-service rate, including fuel-related costs, are recoverable turns on whether they are just and reasonable, not whether the commission has regulatory authority over all aspects of those rate components.”

Other protesters were concerned that there was no cost allocation mechanism in the agreement. FERC noted that in its show cause order, it directed ISO-NE to include such a mechanism in any Tariff revisions the RTO proposes.

The commission also said that while capital expenditures would be subject to hearing, the Mystic units should be allowed to collect actual prudently incurred costs, subject to true-up.

“We find that given the inherent difficulty in projecting costs in advance of the agreement’s effective date, and the concerns raised as to whether certain expenditures will be necessary to keep the Mystic units operational during the proposed service period, a true-up mechanism is necessary to ensure that the rates established reflect actual costs incurred,” the commission said.

The order directed the participants to present evidence regarding the appropriate design of the true-up mechanism in the agreement, noting that ISO-NE may also address the related clawback provision in EL18-182.

July 15, 2018

FERC Rejects PJM Exemption for Incumbent TOs

By Rich Heidorn Jr.

FERC on Friday rejected PJM’s proposal to exempt incumbent transmission owners from signing designated entity agreements (DEAs), saying it gave them an undue advantage over non-incumbents (ER18-1647).

In May, PJM proposed two changes to the competitive proposal window process mandated by Order 1000.

The commission approved PJM’s request to allow transmission developers 60 days to accept a DEA after receiving it as the winner of a project. The agreement includes a development schedule and a requirement to provide a letter of credit equal to 3% of the estimated project cost.

But the commission rejected the RTO’s proposal to exempt incumbent TOs from the requirement to execute a DEA for Regional Expansion Transmission Plan projects that the Operating Agreement requires PJM to designate to an incumbent. Such projects include TO upgrades; projects that would alter the TO’s use of its right of way; and those located solely within a TO’s zone that are not allocated outside.

PJM argued that the terms of the Consolidated Transmission Owners Agreement (CTOA) governing incumbents are comparable to the DEA. It said the security requirement — to protect ratepayers from additional costs if the original developer abandons a project and it must be reassigned — was unnecessary for incumbents because they cannot abandon projects and that requiring it would only increase costs.

designated entity agreements PJM FERC — | *Asplundh Construction*

The commission said PJM’s proposal would provide an advantage to incumbent TOs in the RTO’s evaluation of transmission proposals. FERC noted that it had rejected similar exemptions in Order 1000 filings by FERC Accepts Order 1000 Compliance Filing.)

“The less stringent requirements in the Consolidated Transmission Owners Agreement also could spare an incumbent transmission owner from a breach (and the associated remedies) that would otherwise be triggered if it executed the designated entity agreement. Although PJM argues that the proposal to exempt incumbent transmission owners from the requirement to execute a designated entity agreement in certain cases will further administrative efficiency, any such benefits do not overcome undue discrimination concerns,” the commission said.

“Under PJM’s proposal, an incumbent transmission owner proposing a transmission owner designated project in PJM’s competitive proposal window process could reflect the cost savings associated with not having a security requirement in its proposal,” FERC added.

The commission also said the CTOA’s milestone requirements are less stringent than that in the DEA, which includes “several interim milestone obligations and consequently, more potential events for breach.”

FERC said the DEA could prevent a transmission developer from assigning its rights to an affiliated limited liability company or C-corporation as financing vehicles, or from meeting legal requirements for state public utility status. “Such prohibition could inhibit the developer’s ability to seek siting approval from that state, particularly if the state requires that the developer be incorporated as a public utility under state law,” FERC said.

The commission approved PJM’s proposal to change the time period for a transmission developer to accept its designation.

Rather than having 60 days from receiving notification of its designation to accept, PJM proposed that the developer have 60 days after receiving the DEA.

“We agree that this proposal will provide PJM with more time to develop and issue the designated entity agreement, as well as for the transmission developer to respond to the initial designation with a development schedule with milestones and relevant project information,” FERC said.

July 15, 2018

EIM OKs ‘Simple’ GHG Compliance Plan

By Robert Mullin

Energy Imbalance Market officials on Thursday approved a proposal to prevent market participants outside California from skirting the state’s greenhouse gas compliance obligations by “shuffling” low-emissions resources into CAISO while ramping polluting resources to serve load closer to home.

The EIM Governing Body’s decision nearly completes a two-year effort to reach agreement on the issue among a broad swath of stakeholders, including the California Air Resources Board, environmentalists, and power producers and utility regulators in the inland West.

CAISO EIM GHG Compliance — CAISO developed the EIM GHG proposal to help ensure that California accounts for emissions from resources dispatched secondarily to cover for zero-emissions power transferred into CAISO. | *Fort Churchill Generating Station, NVEnergy*

“This has been a long effort,” Governing Body Chair Valerie Fong said during the group’s July 12 meeting. “It has required active engagement by market participants. It has required active listening and rethinking by ISO staff and management. So, I do think we’re in a better place today than we were a year ago.”

Under CAISO rules, the proposal falls under the Governing Body’s “primary” decisional authority, meaning it will now advance to the consent agenda of the ISO’s Board of Governors before submission for FERC approval.

Secondary Dispatch

The reason for “resource shuffling” is that under the EIM’s rules, California load-serving entities are subject to GHG emissions caps and compliance obligations, while LSEs elsewhere in the West are not.

The EIM Greenhouse Gas Attribution Enhancements proposal was designed to prevent what CAISO refers to as the “secondary dispatch” of higher-emitting resources in the EIM to replace lower-emitting generation transferred into CAISO. Under current EIM practice, the ISO’s least-cost dispatch process typically selects the lowest-emitting resources to serve load in CAISO’s balancing authority area because those resources tend to submit the lowest GHG bid adders into the market.

“Because all resources in an EIM balancing area are generally equally effective in supporting energy transfers to another balancing area, the market minimizes costs by designating the resources with the lowest GHG costs as supporting transfers to the ISO balancing area,” CAISO management explained in a memo to the Governing Body.

The problem: The market currently designates all of a resource’s output with a corresponding GHG adder as supporting a real-time transfer into CAISO, even if that output was already submitted to the EIM as part of a base schedule — indicating the supply was already slated to support load outside ISO.

“The market may designate a resource as supporting a transfer into the ISO even though that resource would have operated at the same output to serve load outside of the ISO without an energy transfer,” CAISO said. “The market will dispatch another resource or resources to ‘backfill’ this dispatch to serve the load outside of the ISO that would have been served by the resource designated as supporting the transfer.”

If the backfilling resource has higher emissions than the one supporting the transfer, this “secondary dispatch” results in the market undercounting the actual GHG emissions attributable to California, the outcome ARB was trying to prevent when it prompted CAISO to develop the proposal. (See CAISO, ARB to Address Imbalance Market Carbon Leakage.)

Headroom

CAISO’s proposal seeks to address ARB’s concerns by limiting a resource’s energy transfers into the ISO to “an amount no greater than the headroom” above the resource’s base schedule.

Under the plan, the EIM would calculate that headroom by subtracting the base schedule from the megawatt quantity for which a resource has submitted an energy bid and corresponding GHG bid adder. CAISO expects the changes will reduce the GHG emissions from secondary dispatch and more appropriately account for emissions produced by units dispatched to serve California.

“Unfortunately, this approach doesn’t fully eliminate the potential for secondary dispatch. It only minimizes it,” Don Tretheway, the ISO’s senior adviser for market design policy, told Governing Body members.

Tretheway also noted that some EIM stakeholders have expressed concerns the new rules could incentivize suppliers to hold the base schedules for their non-emitting resources such as hydro to zero, while simultaneously base scheduling an emitting resource. That would leave the non-emitting resource with all the headroom in the EIM, possibly positioning it to capture a GHG premium if an emitting resource with a GHG adder sets the marginal price for transfers into CAISO — an opportunity for gaming the market.

“But this concern doesn’t recognize that there’s consequences for having suboptimal base schedules. Because we will redispatch, and this leads to additional costs,” Tretheway said. “So, at a minimum, you’re going to have imbalance energy costs as you decrement down that gas resource and increment up the non-emitting resource.”

Tretheway also pointed out that an EIM participant would face additional costs for creating real-time congestion if it didn’t resolve congestion ahead of an operating hour — resulting in uplift costs for the BAA — before submitting its suboptimal base schedule.

‘Simple is Always Better’

CAISO’s final GHG plan won out over a more complicated proposal that would have developed a “two-pass” market mechanism to address secondary dispatch. Under that proposal, a first pass in the market would have determined the optimal schedule across the EIM footprint while restricting net transfers into the ISO. A second pass would allow transfers into the ISO but limit each EIM resource’s GHG bid quantity to the difference between the resource’s upper economic limit and the optimal schedule determined in the first pass. (See EIM Members Seek More Details on GHG Accounting Plan.)

“We were, as [were] other stakeholders, concerned about the two-pass approach that was considered, so the final approach we think is very reasonable,” said Eric Hildebrandt, director of CAISO’s Department of Market Monitoring. “There is the issue of monitoring the base schedules and looking for that potential gaming opportunity. We think that is something the ISO is committed to doing.”

Speaking ahead of the vote, Governing Body member Kristine Schmidt applauded ISO staff for developing a proposal that “has resolved a really strong, outstanding issue … very important to the state of California.”

Body member John Prescott congratulated staff for a solution “that seems to be workable.”

“I can understand it, which means its fairly simple,” Prescott joked. “But simple is always better.”

Prescott said the proposal allows California to meet its environmental goals with “minimal impact to the external EIM participants — that’s very important.” He added that he hoped EIM participants would monitor the proposal after it becomes policy.

“If those out there that are actually implementing this find that it is a problem for them, that it causes unanticipated results, I’d sure like to hear that, so I just put that request out there,” Prescott said.

While Governing Body Vice Chair Carl Linvill added his praise, he reminded his fellow members they will likely have to deal with the issue again after CAISO deploys its day-ahead market to the EIM.

Speaking during his first meeting as a Governing Body member, Montana Public Service Commission Vice Chair Travis Kavulla said he would support the proposal “with a little bit of reluctance.”

“I wouldn’t want the opportunity to pass by without at least questioning a little bit of the premise of what we’re trying to do here,” Kavulla said. “I do think we have to realize that resource shuffling is a natural and economically rational consequence of having a local carbon dioxide price that doesn’t persist across the entire footprint of the market.”

Kavulla said that by assigning a “local” emissions price to backfill generation, CAISO was doing what it has admitted is impermissible, “which is to subject generation outside of California to a California air regulation even when the generation is not being used to serve California load.”

July 15, 2018December 13, 2023

UPDATED: Texas Regulators Fear Customer Risk from Wind Catcher

By Tom Kleckner

AUSTIN, Texas — Regulators threw a wrench in American Electric Power’s massive Wind Catcher Energy Connection on Thursday, expressing concerns over whether the company will protect ratepayers from the project’s risks.

Public Utility Commission Chair DeAnn Walker made that clear following oral arguments in the contested proceeding involving AEP subsidiary Southwestern Electric Power Co. and several consumer groups (Docket No. 47461).

“I’m going to be upfront with you,” Walker said, addressing AEP CEO Nick Akins, her fellow commissioners and others in the PUC’s hearing room. “At this point, I can’t approve the [project].”

Walker said she would need additional consumer protections from SWEPCO, which would own 70% of the $4.5 billion project. It includes a 2-GW wind farm being built by Invenergy in the Oklahoma Panhandle and a 360-mile, 765-kV line from the facility to Tulsa. Sister company Public Service Company of Oklahoma would own the other 30%.

The two utilities would purchase the wind facility upon its completion, scheduled for the fourth quarter of 2020.

“I have issues and concerns … on the financial impacts to the company,” Walker said, alluding to a recent court decision remanding a SWEPCO rate case back the PUC.

The Texas Court of Appeals for the Third District on July 10 granted a rehearing request by the Texas Office of Public Utility Counsel (OPUC), Texas Industrial Energy Consumers (TIEC), and Cities Advocating Reasonable Deregulation (CARD), reversing a district court’s ruling that the utility’s John W. Turk, Jr. Power Plant should be included in cost recovery (No. 03-17-00490-CV).

Commissioner Arthur D’Andrea said he too would like to see the parties develop additional consumer protections. “But it doesn’t do us any good to protect the consumers, and then have the company fail,” he said.

Moody’s Investors Service’s also recently issued a downgrade watch for Sempra Energy following its $9.45 billion acquisition of Texas utility Oncor earlier this year. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)

As is their normal practice following oral arguments, the commissioners will review the arguments and the financial data submitted before issuing a decision. The PUC’s next scheduled open meeting is July 26.

“I’d like some time to look at the transcript,” D’Andrea said.

“I am really struggling with where I am on this,” Walker said. “I was hoping to get more solid on where I am.”

The commission was unmoved by the AEP delegation’s reminder that it faces a time crunch to take advantage of expiring federal production tax credits. Paul Chodak, AEP’s executive vice president of utilities, said the company must give contractors a notice to proceed by Aug. 6 to qualify. He said the company is already moving dirt, securing rights of way and spending “tens of millions of dollars” in legal fees.

“We are on a critical path. Whatever the answer is, we would like it as quickly as possible,” Akins said. “If it’s a bad answer, we can deal with that. If it’s a good answer, we can certainly deal with that too.”

“We’re very aware of the timing implications,” Walker responded.

She encouraged AEP and the other parties to try and “address the customer benefits or protections” before the next open meeting. “Right now, I think there’s more that can be done for the consumers,” Walker said.

“We’re hopeful we can have additional settlement discussions with the intervenors, especially given the PUCT’s encouragement,” said SWEPCO spokesperson Carey Sullivan.

PUC staff, which oppose Wind Catcher, met after the hearing with OPUC, TIEC, CARD and fellow intervenor Golden Spread Electric Cooperative. The group did not commit to further settlement discussions.

SWEPCO operates in East Texas, Louisiana and Arkansas. AEP says Wind Catcher will save SWEPCO’s Texas customers $1.7 billion over 25 years. Company representatives pointed to settlement agreements in Arkansas and Louisiana that insulate customers from the project’s risks, including a cap on construction costs, minimum production levels and qualification for 100% of the federal PTCs. They also noted components of Wind Catcher’s 800 turbines will be built in Texas and Houston-based Quanta Services will build the transmission line.

Representatives of TIEC and CARD argued Wind Catcher would saddle Texas consumers with hundreds of millions of dollars in future rates, saying it would be more expensive and less efficient than the recently approved Xcel Energy wind facility. (See Texas PUC Issues Final Order for SPS Wind Farm.)

“This project is not needed in any traditional sense,” said TIEC’s Rex VanMiddlesworth, pointing to AEP’s argument that Wind Catcher will provide a hedge against higher natural gas prices. “All these parties that have dug into that — staff, the cities and OPUC — have disagreed with that and have presented [countering] evidence. If [SWEPCO’s estimate] was the case, we’d all be saying we want it, like we did for the [Xcel] wind facility.”

“Our concern is not the accuracy of SWEPCO’s forecasts. … Our concern is that the risk of those projections being accurate is on the ratepayer,” said CARD’s Alfred Herrera. “Our concern is that when this project goes into the rate base, the customer will pay.

“SWEPCO is asking you to approve a multibillion project and guarantee its returns,” Herrera said. “That’s the effect of what will happen if this plant comes into the rate base. That’s not how competitive markets work. If this deal is such a good deal, then let the competitive market build it.”

PUC staff oppose an administrative law judge’s preliminary decision approving AEP’s application, saying “the evidence presented does not support a sufficient probability of improvement of service or lowering of costs to ratepayers.”

Staff are recommending that the commission condition its approval on a requirement that SWEPCO guarantee tax credits in the amounts represented by the utility, and some level of net benefits to customers.

PUC Grants Utilities’ SMT Rehearing Request

The PUC granted a motion for rehearing and issued a final order for Smart Meter Texas (SMT), a website that provides customers and authorized market participants access to electric usage data (Docket No. 47472).

The utilities involved in SMT (AEP Texas, CenterPoint Energy Houston Electric, Oncor and Texas-New Mexico Power) filed the request in June “to address limited clarifications.”

The utilities agreed to provide on-demand meter readings as a substitute for home area network (HAN) functionality. Walker filed a memo clarifying that the utilities can’t discontinue support of a customer’s existing HAN device unless the customer requests that the device be disconnected.

SMT allows customers to download and view their energy data or share them with competitive service providers, companies that market energy efficiency, demand response, distributed generation and other services. (See “Commission Streamlines Smart Meter Texas Portal,” Texas PUC Issues Final Order for SPS Wind Farm.)

July 15, 2018

NYPSC: Offshore Wind ‘Ready for Prime Time’

By Michael Kuser

ALBANY, N.Y. — The New York Public Service Commission on Thursday voted unanimously to authorize state agencies to procure 800 MW of offshore wind energy by next year, the first phase of a plan to develop 2,400 MW by 2030.

offshore wind nypsc — Rhodes | © *RTO Insider*

Offshore wind is “viable, valuable and ready for prime time,” PSC Chair John B. Rhodes said.

Under the commission’s July 12 order (18-E-0071), the New York State Energy Research and Development Authority will issue a solicitation for 800 MW of offshore wind in the fourth quarter, in consultation with the New York Power Authority and the Long Island Power Authority.

NYSERDA will announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal. The agency will hold a technical conference on the solicitation process from July 23 1-3 p.m. at the Department of Public Service’s office at 90 Church Street in New York City; it will also be available via webinar.

High-Stakes Race

Gov. Andrew Cuomo’s office said that offshore wind will not only help achieve the state’s Clean Energy Standard goal of obtaining 50% of electricity from renewables by 2030 but also will support nearly 5,000 new jobs, nearly 2,000 of them long-term career opportunities in operations and maintenance.

“We’re in a race right now with our fellow states along the Eastern seaboard to get these staging and fabrication facilities for this new industry built in our state, and of course they want it in their states,” Commissioner Gregg C. Sayre said. “I think it would be appropriate for us to get moving quickly and win this one for New York.” (See Competition, Cooperation and Costs the Talk at OSW Conference.)

The U.S. Department of Energy in June awarded a $18.5 million grant to NYSERDA to lead a nationwide research and development consortium for the offshore wind industry, with the state to match the federal funds.

In May, Massachusetts awarded a contract for 800 MW of offshore wind and Rhode Island agreed to procure 400 MW. (See Gov. Signs NJ Nuke Subsidy, Renewables Bills.)

Massachusetts officials hope to develop supply chains for the nascent industry in the Port of New Bedford but will have to avoid interfering with fishing operations there, the No. 1 fishing port in the U.S. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)

According to the environmental impact statement issued by NYSERDA in June, the New York offshore wind projects will affect only 3% of the state’s fishing grounds.

Bidding Details

David G. Drexler, DPS managing attorney, told the commission that NYSERDA will solicit two separate bids from each participating bidder. One would be for a fixed-price offshore wind renewable energy certificate (OREC), while the other would be based on a variable OREC tied to an index.

To contain costs, NYSERDA will reject bids higher than a confidential “upset price,” like the method used in Renewable Energy Standard Tier 1 procurements, Drexler said.

“NYSERDA … would at all times have the authority to reject any and all bids, taking into account not only the benchmark upset price but also recent auctions and market conditions,” Drexler said.

NYSERDA will rank bids based on the following weights price (70%); economic benefits (20%); and project viability (10%). The agency will have discretion in fixing the specific terms of the contract, which will run for 20 to 25 years.

Transmission Component

The Phase 1 order for the initial 800 MW makes the generation developer responsible for its own radial transmission to shore, calling it “the most easily implementable and feasible option for jump-starting offshore wind development in New York.”

NYSERDA recommended that backbone transmission and independent ownership be reserved for consideration in Phase 2, to procure the remainder of the 2,400 MW total. It noted that the Bureau of Ocean Energy Management has sold only one wind energy lease directly off New York — Equinor’s site, which is capable of hosting approximately 1,000 MW. The agency said a shared radial system would create unnecessary risks of stranded assets and provide limited cost advantages.

Equinor and Vineyard Wind supported the direct generator lead approach in the early stages of development, arguing in joint comments that “requiring a separate transmission provider would increase project uncertainty and the risk of delay.”

The Green Building Council, the Sustainability Institute and transmission developer Anbaric argued that the first phase should include soliciting bids to develop an “Open Access Offshore Transmission” system, with Anbaric saying it would provide more information about the best options and potentially reduce the costs of the procurement.

Anbaric said that requiring direct generator leads would lead to a piecemeal approach and would not optimize the interconnection, potentially increasing costs for later stages of development. The Green Building Council and the Sustainability Institute concurred with Anbaric’s argument, saying that the generator lead approach would result in a highly inefficient array of separate transmission cables.

Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange and Rockland Utilities, and Rochester Gas & Electric, filing as “Joint Utilities,” also argued that the state should immediately consider developing a transmission backbone and optimizing onshore interconnection locations. They said utility ownership of the transmission portion could produce substantial ratepayer savings. NYPA and New York City also urged that “a coordinated approach to transmission should be initiated immediately,” with NYPA adding it was prepared to assist in the effort.

“Anbaric remains eager to deliver offshore wind to the New York onshore grid quickly and economically,” Anbaric CEO Edward Krapels said in a statement Friday. “We will intensify our development of our New York OceanGrid and look forward to working with generation companies to link the first 800 MW of offshore wind to the New York state grid.”

Cryptocurrency Tariff Change

The PSC also approved new electricity rates for an upstate utility, Massena Electric Department, that will allow high-density load customers, such as cryptocurrency companies, to qualify for service under an individual service agreement.

“As part of our continuing effort to balance the needs of existing customers with the need to attract new companies, we must ensure that business customers pay a fair price for the electricity that they consume,” Rhodes said. “However, given the abundance of low-cost electricity in upstate New York, there is an opportunity to serve the needs of existing customers and to encourage economic development in the region.”

The commission’s order (18-E-0211) said that the individual service agreement tariff includes provisions to protect customers from increased supply costs resulting from the new service.

The program will apply to customers who have a maximum demand of at least 300 kW.

The new rates become effective July 17.

Low-income CDG Initiatives

The commission also adopted three measures to enhance the ability of low-income residents to participate in community distributed generation (CDG) programs: a bill discount pledge program; an income verification service; and a loss reserve fund (15-E-0082).

CDG projects are generating facilities located behind a nonresidential host meter coupled with a group of off-takers who receive bill credits based on the generation of that facility. New York defines low income as at or below 60% of the state median income.

Public funds will be held in reserve to cover losses that CDG project owners or their lenders may incur if low-income subscribers default on or terminate their subscriptions at a higher rate than other customers. DPS staff reported that “a relatively modest amount could provide surety for hundreds or even thousands of subscriptions” but did not define the amount.

Con Ed Smart Solutions Program

The commission approved, with modification, Con Ed’s request for a Smart Solutions Program, which included an enhanced gas energy efficiency program, a new gas demand response program, a new “Gas Innovation” program to encourage renewable alternatives to natural gas heating technologies, and a new market solicitation for non-pipeline solutions.

The order (17-G-0606) established criteria for continued development of the gas innovation program and denied the company’s request “to recover costs associated with parallel pipeline development efforts, thereby maintaining customer protections associated with unsuccessful pipeline development projects.”

The commission said Con Ed’s proposed gas DR program and non-pipeline proposal both “require further information from the company, input from stakeholders, and review from staff, and therefore, these components of the petition will not be considered in this order.”

July 15, 2018

NYISO Business Issues Committee Briefs: July 11, 2018

RENSSELAER, N.Y. — The NYISO Business Issues Committee voted Wednesday in favor of changing how the ISO reports on historic congestion, agreeing with management that the current process is resource-intensive and the resulting data underutilitized.

The BIC’s vote recommends that the Management Committee endorse the new process, which will require Tariff changes, to the Board of Directors.

Some of the congestion metrics required by the Tariff can be extracted from production security-constrained unit commitment (SCUC) runs but other data require rerunning SCUC to calculate the difference between the actual constrained grid and an unconstrained system.

“In our review of the site traffic, we realized there was not much use of the historic congestion data, so it’s of limited value in finding where congestion is on the system,” said Timothy Duffy, manager of economic planning. “We don’t believe there are any stakeholders using that data meaningfully.”

The proposed changes would eliminate the requirement to compare historic data to an unconstrained system.

The ISO will continue providing the historic metrics generated by SCUC: the value of demand congestion by constrained element or contingency; load and generator payments; and total load and generation scheduled.

It will add a new set of metrics: actual congestion rents by constraint, based on modeled flows and shadow prices.

Consolidated Edison’s Jane Quin representative abstained, saying it was premature to change the current reporting before the ISO has moved ahead with an economic transmission project to address congestion. Quin also said NYISO had not shown that the current Tariff requirement was unduly burdensome.

“Data we are pulling is not used in any settlement proceeding at all … and the data we are presently required to produce [that we would no longer produce] would not be of any value in planning an economic transmission project,” Duffy responded.

By the fourth quarter, the ISO will provide a report of historic congestion information relating to 2018 data utilizing the new metrics, broken into quarterly figures to mesh with quarterly reports beginning with 2019 data.

The data will continue to include actual demand ($) congestion by constrained element/contingency; load and generator payments ($); and total load and generation scheduled (MWh).

The reporting of historic congestion will incorporate actual congestion rents by constraint based on modeled flows and shadow prices.

Supplemental Resource Evaluation Improvements

NYISO has made progress in clarifying the minimum deliverability requirements for capacity from PJM, Rana Mukerji, ISO senior vice president for market structures, told the BIC.

ISO officials made presentations on the current Supplemental Resource Evaluation process and potential changes at joint meetings of the Installed Capacity Working Group and Market Issues Working Group in April and May. The ISO will present the market design proposal for process improvements at a joint ICAPWG/MIWG meeting July 26.

In his Broader Regional Markets Report, Mukerji also discussed NYISO’s efforts since 2016 to find an alternative approach for calculating locality exchange factors, which measure the capability of import-constrained regions relative to neighboring control areas.

NYISO has concluded the stability and transparency of the current approach is preferable to a probabilistic approach. The ISO has told stakeholders that further work on this effort is unlikely to yield an implementable methodology and continued investigation of a probabilistic approach is not warranted.

Mukerji also discussed Public Service Electric and Gas’ May 3 complaint against Consolidated Edison concerning two transmission lines, B3402 Hudson-to-Farragut (B line) and C3403 Marion-to-Farragut (C line). PSE&G alleged that underwater portions of the lines may have been permanently damaged and should be removed; however, the complaint acknowledged that a prior leak in the B line has been repaired.

NYISO filed a protest with FERC on June 6 indicating that removal of the lines would undermine resilience in both New Jersey and New York. The lines support grid resilience by providing opportunities for operational flexibility and emergency service in both the New York Control Area and PJM. The ISO’s protest noted that PSE&G’s complaint did not demonstrate that another leak from either of the lines was imminent and requested that the complaint be denied.

Public Website Redesign Update

NYISO Business Issues Committee Transmission Congestion — Draft Web Page | *NYISO*

Dave O’Brien, NYISO project manager, provided an update on the project to redesign the ISO’s public website.

The main objectives of the redesign are to improve the site navigation and search engine capability and implement a document library. The project will recategorize the most frequently accessed documents to make them easier to find.

O’Brien indicated that existing webpage and document links on www.nyiso.com would be changing because of the project, but he emphasized there would be no changes to existing mis.nyiso.com (OASIS) links. The project is targeting a launch by year-end.

BIC Elects Aaron Breidenbaugh Vice Chair

The BIC elected Aaron Breidenbaugh of energy management consulting firm Luthin Associates as its vice chair.

In addition to helping clients in procuring electricity and natural gas, Luthin also represents an unincorporated group of nonprofit institutional customers known as Consumer Power Advocates before the ISO, Public Service Commission and FERC.

“I’m happy to be able now to pay back into the NYISO governance structure,” Breidenbaugh said.

Energy Prices up 32% YoY

NYISO prices averaged $32.53/MWh in June, up from $28.78 in May and higher than $31.76 in the same month a year ago, Mukerji said.

Year-to-date monthly energy prices averaged $47.70/MWh through June, a 32% increase from $36.01 a year earlier. June’s average sendout was 445 GWh/day, higher than 397 GWh/day in May but down from 454 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $2.45/MMBtu, down 4% from May but up 4.5% year-over-year.

Distillate prices dropped slightly compared to the previous month but were up 56.3% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $15.47/MMBtu and $15.32/MMBtu, respectively.

Total uplift costs and uplift per megawatt-hour rose from May, with the ISO’s local reliability share at 18 cents/MWh in June, lower than 22 cents the previous month, while the statewide share climbed from -17 cents/MWh to 12 cents.

Thunderstorm Alerts in New York City, which cause more conservative operations with reduced transmission transfer limits, cost 39 cents/MWh, up nearly fivefold from 8 cents in May.

— Michael Kuser

July 15, 2018

MISO Resource Adequacy Subcommittee Briefs: July 11, 2018

Responding to a stakeholder query, MISO staff have determined that it’s appropriate and possible for capacity import limits between local resource zones to bind in the RTO’s annual Planning Resource Auction.

MISO says that while, historically, the local clearing requirement has always bound before the CIL, it is “mathematically possible and reasonable” for CILs to be more restrictive than LCRs.

In this year’s capacity auction, MISO Local Resource Zone 3 in Iowa and Zone 6 in Indiana and Kentucky came closest to binding on their CIL, with Zone 3 coming within 938 MW and Zone 6 within 1,290 MW. MISO said the two zones could have bound if either the LCR or amount of exports varied.

capacity import limit resource adequacy — Sutton | © *RTO Insider*

During a July 11 Resource Adequacy Subcommittee meeting, MISO engineer Matt Sutton said it remains “highly unlikely that the capacity import limit” will bind in future capacity auctions, although that could be subject to multiple variables, such as transmission transfer capability.

“Though we’ve not seen a capacity import limit bind, it is a necessary parameter in the auction,” Sutton said.

Some stakeholders said they could not understand how CILs could bind before LCRs. WPPI Energy’s Steve Leovy said MISO staff have previously told him that CILs should not be enforced. Sutton said he thought MISO staff responsible for resource adequacy would disagree with that viewpoint.

Other stakeholders pointed out that market participants can replace capacity from other resources at midyear and that MISO must still ensure that import limits are not violated.

RTO staff committed to more discussion on the topic at future RASC meetings.

Stakeholders Quiet on Uncertain OMS-MISO Survey Results

Stakeholders offered muted reaction to this year’s annual resource adequacy survey by MISO and the Organization of MISO States, which predicts adequate reserves through 2019 but is less certain about thereafter.

“It’s important to keep in mind that this is a point-in-time forecast,” Ryan Westphal, MISO resource studies manager, told stakeholders.

Over the next five years, MISO’s footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall. The results were less optimistic than last year’s survey, which showed MISO would have anywhere from 0.7 to 7.3 GW of excess resources in 2018-2022.

Westphal said the forecast is even more uncertain as MISO continues its conversion from coal generation to a mixture of gas, wind, solar and load-modifying resources.

Stakeholders asked why Zone 4 in Illinois experienced such a large dip in forecasted reserves year over year. Westphal attributed the decline to a combination of retirements, potential retirements and changes in generator performance.

Coalition of Midwest Power Producers’ Mark Volpe asked if MISO adjusts survey responses to reflect interzonal transactions that may go unreported. Westphal said MISO staff reach out to load-serving entities for clarification on some survey responses.

— Amanda Durish Cook

July 15, 2018

MISO Delays Combined Cycle Model Update

MISO will not implement improved combined cycle modeling until it has a new market platform in place, stakeholders learned last week.

The RTO plans to initially offer seven different modeling options, including combinations of combustion and steam turbines, but operators of combined cycle generators must now wait until 2022 for the improved model.

MISO last month completed a conceptual design for the more sophisticated modeling that can accommodate different combinations of combined cycle units and their dependencies. And while the RTO originally hoped to have software in place by 2020 to offer new modeling options, its outdated market platform is limiting what improvements it can undertake. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)

MISO combined cycle units market platform — Hansen | © *RTO Insider*

Speaking at a July 12 Market Subcommittee meeting, MISO market analyst Chuck Hansen said the conceptual design will still be turned over to a third-party vendor for more in-depth work during the 18-month pause on the project. He said most of that work is not dependent on having the new market platform operational and can be advanced without delay. He also said MISO’s legal team will begin drafting Tariff language during the hold.

MISO Market Design Engineer Congcong Wang said the proposal will represent one of the most complex participation models in the RTO’s energy and ancillary service markets to date. The RTO has predicted the new model could save an annual $14 million to $34 million in production costs.

MISO currently has 44 combined cycle gas turbine resources, with more predicted to come online. Since its markets began, MISO has been modeling combined cycle units as either a single aggregate resource or as individual units.

— Amanda Durish Cook

July 13, 2018

CAISO Q1 Prices Surge on Lower Hydro, Higher Gas

By Robert Mullin

CAISO prices surged in the first quarter on falling hydroelectric output and increased costs for natural gas, the ISO’s Department of Market Monitoring told stakeholders Wednesday.

Speaking during a call to discuss the department’s quarterly market issues report, Amelia Blanke, manager of monitoring and reporting, noted that the ISO is accustomed to a pattern of lower prices in the first two quarters followed by rising prices later in the year.

“That was not the case in Q1 of this year,” Blanke said.

Average five-minute prices jumped 50% ($12/MWh) compared with the same period a year earlier, while 15-minute prices rose 20% ($6/MWh), putting prices close to levels seen last fall. Day-ahead prices were also up about $6/MWh during the quarter (See chart).

CAISO gas prices hydropower — Average Monthly Price | *CAISO Department of Market Monitoring*

“One of the factors that influenced this include the availability of hydro generation,” Blanke said, adding that hydro output was just under half the level seen in the first quarter of 2017.

Despite heavy snowfall in March, snowpack in California’s Sierra Nevada mountains ended the winter at just 52% of normal. That was well short of the near-record snowpack many areas reported last year, which required dam operators to release water from reservoirs earlier than usual.

Increased congestion also provided a boost to Southern California day-ahead prices, adding about $2/MWh to average prices in the Southern California Edison area and $5/MWh in the San Diego Gas & Electric area. But the lack of congestion in the north helped reduce Pacific Gas and Electric prices by about $3/MWh.

Tight Gas, High BCR

Tight gas supply was the other key factor driving up power prices, Blanke said. PG&E Citygate gas prices were up 19% over the first quarter of 2017, while SoCal Citygate added 7%, continuing last year’s trend of rising gas prices. (See Gas Costs Drive Sharp Gain in CAISO 2017 Prices.)

“There was a higher frequency of high same-day gas prices and shortage conditions for gas in the southern part of our balancing area,” Blanke said.

Grid operations in Southern California are still hamstrung by limited gas supplies from the Aliso Canyon storage facility north of Los Angeles. As a result of market operations intended to preserve that supply, the ISO paid out $11 million in bid cost recovery (BCR) in February because of a cold snap — the highest BCR expense for any month since 2011, the Monitor said.

Limited gas supply in the SoCalGas system during a period of high gas demand led to both high regional gas prices and the reinstatement of Aliso gas cost scalars, both of which contributed to high real-time bid cost recovery in February, the DMM report said.

CAISO implemented the scalars — or price adders — in 2016 to help ensure that gas-fired generators can recover fuel costs in the face of potential price spikes stemming from the Aliso Canyon limitations. (See FERC Approves CAISO’s Aliso Canyon Response Plan Ahead of Summer.) When activated in the real-time market, the adders boost the commitment proxy gas cost calculation to 175% of the day-ahead gas reference price, while gas prices in the default energy bid calculation are set to 125% of the day-ahead price.

The Monitor has opposed the ISO’s reliance on the scalars, instead recommending the ISO develop the ability to update gas prices in real time.

FERC gas prices hydropower — Hourly System Marginal Energy Prices | *CAISO Department of Market Monitoring*

“DMM believes that each use of the Aliso Canyon gas adders on default energy bids and commitment costs highlights the problems associated with the use of these adders,” the Monitor said.

The first problem, according to the DMM, is the delay in activating and deactivating gas adders in response to actual conditions.

The second problem is the mismatch between the gas price based on the adders and actual volatility over the same day, the Monitor said.

It noted that bid cost recovery payments totaled $5 million over Feb. 20-23, when SoCal Citygate prices were “significantly high.”

“These events also highlight the need for the ISO to develop the capability to update gas prices used in the real-time market based on same-day gas market price information available each morning, as recommended by DMM” in its comments to FERC after CAISO filed to extend its Aliso provisions. The ISO has defended its use of the adders as a needed, if imperfect, tool. (See Gas Adders a Necessary Tool, CAISO Says.)

Less Negativity

Blanke also pointed to the price impact of the “duck curve,” which illustrates the precipitous drop in net load at midday as solar and wind resources displace higher-cost fossil fuel generation. “As we have throughout last year, you see lower prices in the middle of the day — in all markets — than we do in the traditional off-peak hours,” she said.

But declining hydro output helped reduce the frequency of negative prices in the market, as prices slipped below zero in about 2% of 15-minute market intervals and 4% of five-minute market intervals, compared with 10% and 13%, respectively, a year earlier.

natural gas prices hydropower caiso — Frequency of Negative 5-minute Prices | *CAISO Department of Market Monitoring*

“This is highly correlated with a reduction in self-scheduled hydro generation,” Blanke said.

The DMM report noted that a “reduction in self-scheduled generation would result in increased bidding flexibility and reduce the likelihood of negative prices.

The report again called out an issue the DMM has flagged for nearly two years: the continued funding shortfalls stemming from the ISO’s congestion revenue rights auctions. (See Report Shows Continued Losses in CAISO CRR Auctions.) The Monitor pointed out that first-quarter CRR auction revenues came up $43 million short of payments made to the non-load-serving entities that purchased the rights at auction, compared with a $12 million shortfall a year earlier. It was the second largest shortfall for any quarter since 2015.

“Losses in the first quarter represent 38 cents in auction revenues paid to transmission ratepayers for every dollar paid out to auctioned rights holders,” the report said. “Total ratepayer losses from the congestion revenue rights auction since the market began in 2009 surpassed $770 million.”

FERC earlier this month approved the first stage of the ISO’s CRR rule changes, which will limit allowable source and sink pairs for CRR transactions to those that align with typical supply delivery paths. The changes also require annual transmission outage reporting to more closely match day-ahead models. (See FERC OKs Tighter Rules for CAISO CRR Auction.) While the DMM expressed support for the ISO’s rule changes as “an incremental improvement,” the report said it “continues to recommend that the auction process be replaced by a market for financial hedges based on clearing bids from willing buyers and sellers.”