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November 18, 2024

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7 Sites Eyed for MISO-PJM Targeted Market Efficiency Projects

By Amanda Durish Cook

MISO and PJM have nearly completed their work on joint operating agreement and tariff language to create the new targeted market efficiency project (TMEP) type, and the RTOs have singled out seven congestion-relieving candidate projects.

Four of the possible TMEPs are located at flowgates in Indiana, while one is in northern Illinois, one is on the southeastern Michigan-Ohio border and another is in central Ohio. The projects, produced from a joint RTO analysis that originally studied 12 candidates, range from 138 kV to 345 kV with total costs of $19 million and benefits of $117 million:

  • The Burnham-Munster 345-kV project on the northern Illinois-Indiana border:
    • Benefit-cost ratio: $32 million/$6.5 million
    • Cost allocation: PJM 88%/MISO 12%
  • The Bayshore-Monroe 345-kV project on the southeastern Michigan-Ohio border:
    • $17 million/$1 million
    • PJM 89%/MISO 11%
  • The Michigan City–Bosserman 138-kV project in northern Indiana:
    • $29.6 million/$2.3 million
    • PJM 90%/MISO 10%
  • The Reynolds-Magnetation 138-kV project in north-central Indiana:
    • $14.5 million/$150,000
    • PJM 41%/MISO 59%
  • The Roxana-Praxair 138-kV project in northeastern Indiana:
    • $6.5 million/$4.5 million
    • PJM 24%/MISO 76%
  • The Klondike-Purdue 138-kV project in north-central Indiana:
    • $6 million/$4.2 million
    • PJM 4%/MISO 96%
  • The Marysville-Tangy 345-kV project in central Ohio:
    • $12 million/“minimal” cost
    • PJM 98%/MISO 2%

“We’re pretty excited about this. This is exactly what we were hoping for,” PJM engineer Alex Worcester said during a Sept. 30 meeting of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC). “These aren’t projects that are just squeaking by; these are very significant cost-benefits.”

miso, pjm, targeted market efficiency projects
Twelve flowgate projects were initially considered in MISO and PJM’s TMEP analysis.

Worcester also said both RTOs were surprised with how evenly the cost allocation was shared among the total projects.

The RTOs used a joint survey to decide on some details of the TMEP process.

For example, the RTOs will not subtract congestion hedges in calculating project benefits. PJM said not excluding the hedge is “consistent with TMEP goal of simple, efficient metrics easily reproduced by stakeholders.” A majority of 27 survey respondents preferred not to include congestion hedges in the benefit calculation.

Worcester said there’s nothing to prevent congestion hedges being counted in the regional cost allocation, however.

A majority of 22 respondents supported using the last three years of historical congestion data in benefit calculations. Other stakeholders wanted the highest historical congestion data from two of the past three years used, while others wanted the past two years of congestion data used.

Exelon’s Sharon Midgley said the number of respondents seemed “incredibly low.” Worcester said there was “a reasonable cross-section of stakeholders” even though more MISO stakeholders responded than PJM stakeholders.

“This is what we’re going forward with now. In a couple of years from now, we’re open to revisiting this and improving it,” Worcester said.

PJM Manager of Interregional Planning Chuck Liebold said that there are internal RTO cost allocation details that need to be fleshed out in the draft JOA and respective tariff language. “But we have everything we need to know for the interregional benefit calculation and cost allocation,” Liebold said.

PJM and MISO staff said intra-RTO cost allocation rules are being worked out in PJM’s Transmission Owners Agreement-Administrative Committee and MISO’s Regional Expansion Criteria and Benefits Working Group.

MISO’s Adam Solomon said MISO and PJM will file JOA and tariff changes at the same time. In spite of unfinished cost allocation details, the RTOs plan to file the JOA changes sometime in October and recommend project candidates to their boards by December.

A first draft of the JOA language was released at the July IPSAC. (See MISO, PJM Unveil JOA Process for ‘Targeted’ Market Efficiency Projects.)

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ERCOT Asks for Conservation Measures in Rio Grande Valley

ERCOT is asking consumers in the Lower Rio Grande Valley region to limit or reduce their electricity use where possible through Tuesday, especially during the 3-7 p.m. peak demand hours.

ERCOT control room Source: ERCOT Rio Grande Valley
ERCOT control room Source: ERCOT

“With some unplanned electric generation outages, combined with high temperatures in the region, we expect tight conditions during peak demand hours over the next few days,” Dan Woodfin, ERCOT’s director of system operations, said in a statement released Monday.

Woodfin said the 524-MW Frontera combined cycle plant’s recent withdrawal from the ERCOT system has complicated the task of meeting demand along the U.S.-Mexico border during tight conditions. Frontera’s owners, Viva Alamo, a subsidiary of The Blackstone Group, is dispatching energy into the Mexican market.

ERCOT said the conservation request is limited to the Lower Rio Grande Valley, and that it is not experiencing any systemwide issues at this time.

ERCOT has asked consumers to reduce demand during peak hours by:

  • Turning thermostats up 2-3 degrees during the peak hours;
  • Setting programmable thermostats to higher temperatures when no one is home;
  • Using fans inside homes;
  • Scheduling pool pumps to run in early morning or overnight hours, and shutting them off from 4-6 p.m;
  • Limiting the use of large appliances (dishwashers, washers, dryers, etc.) to morning hours or after 7 p.m.;
  • Use a microwave or slow cooker; and
  • Closing blinds and drapes during the late afternoon.

“We believe these voluntary actions by consumers can help limit the need for further action, such as rotating outages, to maintain overall reliability in the valley,” Woodfin said.

ERCOT in June unanimously approved two transmission projects to improve reliability concerns in South Texas. (See ERCOT Board OKs Rio Grande Valley Fixes.)

– Tom Kleckner

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PJM Markets and Reliability and Members Committees Briefs

The Members Committee approved by acclamation a rate-increase proposal that struck a balance between allowing for cost increases and providing long-term certainty.

Members endorsed the Finance Committee’s unanimous recommendation for a composite rate of $0.36/MWh for two years and then a 2.5% annual increase that will result in a rate of $0.41/MWh in 2024. The approved rate schedule creates the lowest projected refunds, explained PJM’s Suzanne Daugherty, and allows for future revisions. The ability to install fee escalators later was built in, along with a five-year review.

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PJM touted Moody’s Investors Service’s recent upgrade in the RTO’s credit rating, which praised its structure for recovering administrative costs.

“Under stated rates, PJM uses fixed, long-term capped rates for the administrative costs of managing the grid and wholesale electricity markets. Costs are managed within the rates,” PJM explained. “Other grid operators automatically pass through their administrative costs to members through formula rates that vary from month-to-month or year-to-year.”

PJM noted it has taken on additional responsibilities since the rates were first implemented in 2006, including enhanced physical and cybersecurity, increased planning and analysis related to changing governmental policies and implementation of new technologies.

Assuming timely approval by the PJM Board of Managers and FERC, the rate would take effect on Jan. 1. (See “PJM Eyes Fee Hike,” PJM Markets and Reliability and Members Committees Briefs.)

Transmission Task Force Halts Most Action in Response to FERC Order

Calling it a “unique situation,” PJM’s Fran Barrett won approval from the Markets and Reliability Committee to suspend most of the activities of the Transmission Replacement Processes Senior Task Force in response to a recent FERC order.

The Aug. 26 Order to Show Cause calls into question whether PJM transmission owners, per FERC’s Order 890, are complying with their local transmission planning obligations, specifically with respect to supplemental projects (EL16-71). (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)

All but the task force’s forward-looking work on transmission project costs — which isn’t affected by the order — has been suspended.

PJM and the TOs have until Oct. 25 to respond to the FERC order, which opened a Section 206 proceeding. An addendum was also approved that allowed the task force to reconvene in March if FERC, which has no deadline for responding, hasn’t acted.

Susan Bruce, who represents the PJM Industrial Customer Coalition, commended the parties involved for maintaining communication during resolution of the issue.

Proposal Chosen for Capacity Release

After months of consideration, the MRC approved the straight-line offer curve PJM proposed for selling back excess capacity in February’s third incremental auction for the 2017/18 delivery year. The curve had to compete against several member proposals, but it was ultimately recommended by the Market Implementation Committee on Sept. 14. (See “PJM’s Straight-Line Offer Curve Recommended for Capacity Sellback,” PJM Market Implementation Committee Briefs.)

Members voted over the objections of Market Monitor Joe Bowring, who reiterated his concerns that the RTO is undervaluing the capacity and shouldn’t publicly broadcast its asking price. “PJM bought this capacity for a fairly high price. We believe, with reliability and the benefits associated with it, the minimum price should be much higher than you’re proposing,” he said.

No Objections to Metering Revisions

The MRC approved revisions to Manual 1 to close gaps in understanding between staff and members on metering rules. The proposal had minor edits from previous presentations, but it maintained its basis on solutions recommended by the Metering Task Force. (See “Metering Standards Ready for Stakeholder Vote,” PJM Markets and Reliability Committee Briefs.)

Flexibility for Vendors Approved for Competitive Bidding Rules

A PJM request to revise  the Operating Agreement’s requirement to use open and competitive bidding when procuring goods or services from a member breezed through both the MRC and MC without objection.

There was some minor concern that the revisions — which exclude certain vendors from PJM’s competitive bidding requirements — might eventually allow for awkward conflicts of interest, but PJM assured that the screenings it devised would eliminate the potential.

PJM’s solution cribs off an existing provision in the OA that addresses a similar issue in allowing PJM personnel to invest in member companies with a de minimis PJM relationship based on a three-part test. To avoid the competitive bidding rules, a company must not:

  • be considered an electric sector company under the North American Industry Classification System;
  • receive more than 0.5% of its gross revenue from PJM; and
  • be involved in more than 3% of PJM’s total market transactions.

“What we found is that over the years, increasing numbers of nontraditional companies … engaged in activities at PJM as a member, but their focus was on other areas” than participating in the energy markets, explained PJM’s Steve Pincus. As examples, he cited office suppliers, such as Target and Walmart, and software companies, such as Microsoft and Siemens.

Responding to stakeholder requests, PJM said it would consider providing a list of the vendors it uses for operations and services as long as it doesn’t run afoul of any confidentiality or disclosure rules.

FE’s MAIT Receives Needed OA Revisions

FirstEnergy received approval for several Operating Agreement changes that will allow Mid-Atlantic Interstate Transmission, its newly formed transmission subsidiary, to assume the rights and obligations of Metropolitan Edison and Pennsylvania Electric in PJM’s Consolidated Transmission Owners Agreement. (See NJ Opposition Derails FirstEnergy’s Tx Reorganization — but not Projects.)

FE plans to make necessary FERC filings in October with a targeted effective date of Jan. 1. Several “legacy” contracts won’t have their interconnection service agreements finalized until later that month.

MRC Endorses Manual Changes

Members unanimously approved the following manual changes:

— Rory D. Sweeney

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ERCOT Technical Advisory Committee Briefs

AUSTIN, Texas — ERCOT’s Technical Advisory Committee passed three nodal protocol revision requests (NPRRs) Thursday to improve the ISO’s reliability-must-run procedures following its decision earlier this summer to extend an RMR contract for an aging natural-gas unit in the Houston area.

The three revisions, previously endorsed by the Protocol Revision Subcommittee, would modify the Texas grid operator’s RMR planning studies, create a clawback mechanism for ERCOT-funded capital expenditures and clarify the reliability unit commitment process. The Board of Directors is scheduled to consider all three revision requests at its Oct. 11 meeting. The NPRRs were classified as urgent requests following this summer’s extension of an RMR contract through 2018 for NRG Texas’ Greens Bayou Unit 5. (See ERCOT Finds No Alternatives to Greens Bayou; RMR Rule Changes Advance.)

The TAC approved NPRR788, which modifies the system’s RMR planning studies, after accepting revisions from the Independent Market Monitor. The revision request will require that future studies include forecasted peak loads, and it says a potential RMR unit must have “a meaningful impact on the expected transmission overload” to be considered for an agreement.

“ERCOT filed comments [after the subcommittee vote] that I feel effectively rebutted the comments made by [stakeholders] that they were concerned ERCOT was not being compliant with NERC standards,” said Beth Garza, the IMM’s director.

The Monitor’s revisions would allow ERCOT, “in its sole discretion,” to deviate from the planning criteria “in order to maintain … reliability. However, ERCOT shall present its reasons for deviating from the above criteria at the next regularly scheduled [TAC] and [board] meetings.”

Transmission Providers Opposed

The measure was opposed by transmission providers American Electric Power, CenterPoint Energy, Sharyland Utilities and Luminant, Texas’ largest generating company.

Valentine Emesih, CenterPoint’s vice president of grid and market operations, said the ISO’s approach could create problems in a year or two. “If you force me to operate the line at 110% of [rated capacity], you’re essentially using a policy that forces you to use load shed to upgrade the system,” he said. “The real solution to mitigate the issue is to build appropriate infrastructure to inoculate yourself from that situation, and that’s where the planning comes in.”

ERCOT staff assured stakeholders there were no plans to shed load and there were no reliability issues.

“It’s more about what is the risk this market is comfortable with when deciding whether or not to get an RMR unit,” said Jeff Billo, senior transmission planning manager. “We are going to plan transmission projects to address those issues.”

The transmission providers also lost a bid to revise the planning criteria’s threshold for overloaded transmission facilities to 100% of the emergency rating under normal system conditions following a contingency loss of a generating unit, transmission unit or other facilities. The threshold will instead remain at 110%.

Stakeholders unanimously approved NPRR795, which creates a mechanism to refund capital expenditures funded by ERCOT under an RMR agreement, but not before adding amended language from Texas Industrial Energy Consumers and the ISO.

Coleman © RTO Insider
Coleman © RTO Insider

Attorney Katie Coleman, representing industrial customers, said she wanted to “tighten the parameters around the depreciation assumptions” and compensate customers for the value of accelerated tax depreciation, “which can provide a significant tax write-off for a resource owner.”

Coleman proposed requiring 10% of this value to be repaid along with the capital expenditure before a resource re-enters the market.

“This approach compensates loads for funding a tax write-off for the resource entity in excess of what straight-line depreciation would provide during the RMR contract period,” Coleman said, “but then transfers the value of any accelerated depreciation back to the asset owner after the asset is returned to service.”

ERCOT added language that would only require a signed attestation from a company’s officer or executive, rather than having the ISO audit tax forms.

The TAC also quickly passed the final revision request, NPRR793, by a unanimous vote. It adds several responsibilities for RMR unit owners, revises RMR formulas and makes other clarifications to ensure RMR units are not accidentally committed as a reliability unit before other resources.

Two Transmission Projects Sent to Board

ERCOT stakeholders endorsed staff recommendations for a pair of West Texas reliability projects that address the region’s Permian Basin oilfield load growth without opposition. Reliant Energy Retail Services abstained from both votes.

The first project, estimated at $50.6 million and belonging to Texas-New Mexico Power, will rebuild 39 miles of 69-kV line and three substations to 138-kV standards, and add a new 138-kV ring substation and 6 miles of 138-kV line.

ERCOT, Technical Advisory Committee

According to ERCOT’s analysis, that portion of the TNMP system will see coincident peak loads of 254 MW by 2022, resulting in reliability violations. The project, expected to go into service in the fall of 2019, would reduce loading on other transmission lines in the utility’s system.

AEP and Oncor proposed the second project, a 138-kV line between Barrilla Junction and the Permian Basin. The 54-mile line’s load is expected to grow from 95 MW to 150 MW by 2020.

cexycfztrgeson6mectp_full_aep-oncor-transmission-line-study-area-ercot-content

Staff recommended a rebuild of the existing line and installing a new 100/-50-MVAR static VAR compensator at an estimated cost of $77 million. The project will not require new rights of way, which will help keep the costs down. It is expected to go into service in June 2019.

Committee Deactivates 4 Groups

The TAC’s annual structural review resulted in the deactivation of four stakeholder groups, agreements to improve the revision-request process and the incorporation of additional binding documents into ERCOT’s protocols and guides.

The committee’s leadership agreed to move the Competitive Renewable Energy Zone Task Force, the Future Ancillary Services Team, the Scenario Development Working Group and the Long-Term Study Task Force to ERCOT’s inactive groups list.

Stakeholders agreed NPRRs and any accompanying guide revisions will now both require board approval, eliminating the discrepancy in the timing of the approval process. NPRRs have normally been approved at the board level, but guide changes are only endorsed by the TAC.

The committee also agreed to incorporate some of ERCOT’s 49 other binding documents — 24 of which have not required frequent changes — into the appropriate guides or protocols, either as new language within existing sections or as appendices.

Additional TAC Endorsements

TAC unanimously approved five NPRRs and one revision to the nodal operating guide (NOGRR) after first agreeing on several refinements to ERCOT’s approval process following the committee’s annual structural review.

  • NPRR755: Allows an entity to register as a data-agent-only qualified scheduling entity (QSE) to connect to ERCOT’s wide area network (WAN) as an agent for another QSE without meeting applicable collateral and capitalization requirements.
  • NPRR769: Clarifies the alternative-dispute resolution process to note the proceeding is the next level of appeal following ERCOT’s denial of verifiable costs. Also clarifies the confidentiality of data submitted in connection with a verifiable-cost appeal.
  • NPRR775: Strengthens the limits on fast responding regulation service (FRRS) to address future operational issues. A previous revision (NPRR581) added limits of 65 MW to FRRS up and 35 MW to FRRS down, but it lacked implementation details regarding self-arrangements in the day-ahead market and restrictions on providing the service in real time without a day-ahead award.
  • NPRR781: Addresses the market’s growing use of advanced metering systems (AMS) by updating protocol language to clarify purpose and definitions, update processes and methodologies and remove outdated ones.
  • NPRR789: Requires ERCOT to publish all of its mid-term load forecasts for market participants and note which one is currently being used by operations. The ISO currently publishes several forecasts per weather zone, but it only makes one at a time available to the market.
  • NOGRR154: Clarifies the WAN’s installation requirements, allows a QSE to designate an agent in order to connect to the WAN and requires ERCOT and its market participants to use the network to exchange resource-specific XML data.

– Tom Kleckner

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MISO Ponders Changes to Behind-the-Meter Generation Rules

By Amanda Durish Cook

CARMEL, Ind. — MISO began working with stakeholders to refine its behind-the-meter generation procedures last week with a special meeting at which it dropped hints on changes it might seek.

miso behind the meter generation
Shah © RTO Insider

“We have a few ideas, but we want to hear from you,” System Support Resource Planning Manager Neil Shah said in opening the meeting.

“We do realize that [behind-the-meter generation] does span across several MISO processes,” MISO Director of Market Engineering Kim Sperry told stakeholders. “Our goal is to work with you on what the next steps should be.”

MISO staff said BTM generation could be incorporated into transmission planning, modeling and retirement notifications and questioned whether interconnection requirements need updating.

The RTO currently defines BTM generation as load-serving resources located behind a commercial pricing node.

Shah said some — but not all — BTM generation load data is captured when load-serving entities or transmission owners submit load information for planning models.

MISO’s Transmission Expansion Plan (MTEP) studies model generators with interconnection agreements, designated legacy network resources of MISO member utilities and all generators with long-term firm point-to-point service.

Eric Swanson, MISO modeling adviser, said all BTM generators greater than 5 MW and directly connected to MISO transmission are modeled. He said the effort to model all BTM generation could “exceed the benefit.” Swanson said if BTM generation is modeled, it would need to be registered as either a Type II demand response resource (DRR) or under a pricing node of a load zone or a DRR Type I.

Director of Planning Jeff Webb asked if BTM generation should be subjected to retirement studies. Webb said the RTO has about 6,000 MW of BTM generation and said it would be a problem only if it all retired simultaneously. “Perhaps we ought to treat it like a load addition,” he said of the retirement study process. “If generation can go off-grid and we don’t look at the impacts, is that okay?”

MISO also wants to know if changes are needed in how it registers BTM generation.

miso, behind the meter generation
Sperry © RTO Insider

Currently, if BTM generation wishes to register as a load-modifying resource, it must submit to an annual generator test and registration and get assigned to a commercial pricing node. It must be able to respond in emergencies with a minimum 12-hour notice, be available five times during the summer and run for at least four hours. It also must submit its status daily to MISO.

Shah said if BTM generation wants to become a capacity resource, it needs an energy resource interconnection service (ERIS) or network resource interconnection service (NRIS) with firm transmission service. If the resource isn’t already connected to the MISO transmission system, it must enter the interconnection queue to obtain NRIS.

Indianapolis Power and Light’s Lin Franks said requiring BTM generation to enter the interconnection queue does not make sense when the generation will only serve nearby load. “If it’s going to serve load in your own territory, then there is absolutely no need for it to qualify for transmission service because it’s not going anywhere,” Franks said.

“Things might be unclear in the Tariff right now,” Shah told stakeholders. “In this meeting and meetings going forward, we’d like to clarify what’s required to make changes to the Business Practice Manuals if necessary. We want to work with you all to be if there needs to be any change.”

Justin Stewart of MISO’s stakeholder relations unit asked for stakeholder feedback on how definitions and requirements should evolve. He said responses would influence a yet-unannounced follow-up meeting.

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Maxim Power to Pay $8M to Settle Fuel-Switching Case

By William Opalka

Maxim Power will pay $8 million to settle a FERC complaint that it manipulated the New England power market in a fuel-switching scheme (IN15-4).

FERC alleged that in July and August 2010, the Canadian company submitted offers for its 181-MW dual-fuel generating station in Pittsfield, Mass., based on fuel oil prices when it actually burned less expensive natural gas. The plant provides voltage support to the ISO-NE market.

maxim power, ferc

Pittsfield Plant Source: Maxim Power

Under the consent agreement approved last week with FERC’s Office of Enforcement, Maxim agreed to pay a $4 million fine and disgorge another $4 million in earnings to ISO-NE but did not admit guilt.

FERC issued Maxim a $5 million fine in May 2015 and sued the company in U.S. District Court two months later to collect the money. On July 21, 2016, the court rejected Maxim’s motion to dismiss the case.

The settlement also closes FERC investigations into allegations that the company gamed ISO-NE market mitigation rules in 2012 and 2013 and that it improperly boosted its generators’ outputs during testing in order to collect inflated capacity payments from 2010 to 2013. (See Maxim to FERC: Prosecute or Drop Probe.)

FERC Chairman Norman Bay, the former head of the Office of Enforcement, did not participate in the decision approving the settlement.

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N.E. Roundtable Considers Carbon Pricing, State PPAs

By William Opalka

BOSTON — New England stakeholders are considering a future market design that could include a price on carbon and a two-tiered capacity market to accommodate state clean energy procurement.

Gordon © RTO Insider

Gordon © RTO Insider

Raab Associates’ 151st New England Electricity Restructuring Roundtable on Friday discussed the New England Power Pool’s effort to reimagine the market, dubbed Integrating Markets and Public Policy (IMAPP).

The initiative comes out of a recognition that the six New England states’ aggressive climate goals don’t align with competitive market structures, said NEPOOL Chairman Joel Gordon.

“The intent is to use the most efficient set of resources using the discipline of competition,” Gordon said. “If it’s successful, it’s going to fundamentally change how power markets work.” (See Q&A: NEPOOL Chair on Redesigning Market Rules for Low-Carbon Future.)

In a series of ongoing meetings, NEPOOL hopes to develop a framework document by the end of the year that could lead to further discussions in 2017 and eventual changes to the ISO-NE Tariff.

“A concern we have is the scale and scope of what [the states] are doing [with procuring carbon-free energy] that the scale is so large that there’s a fundamental risk to the markets that we have,” he added.

The first challenge is defining the policies — economic development, fuel independence and fuel diversity — and then deciding how much clean energy would be needed to achieve them, given the preferences of the individual states. Next comes market rules that promote the overall policy objectives. Finally, cost allocation among the various constituencies must be decided.

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© RTO Insider

Gordon said 15 proposals have been made in the IMAPP process, which can generally be categorized in “three buckets.”

  • A carbon adder would be technology-neutral and provide market signals to both supply and demand while also creating a revenue stream for the states.
  • States’ long-term power purchase agreements for clean energy would support the development of new resources but also support existing generation. “It would be up to the states to decide what they want to procure,” Gordon said.
  • A second tier to the capacity market would enable states to procure resources while protecting price formation in the Forward Capacity Market. “This is a mechanism that could help to incorporate those solicitations into the current market design without undermining the existing market,” Gordon said.
Ethier © RTO Insider
Ethier © RTO Insider

Robert Ethier, vice president of market operations for ISO-NE, said he could see a hybrid design eventually occurring.

“They’re not mutually exclusive. Conceptually, you could do all three, and some think that’s where we’ll end up,” he said.

Ethier said economists agree that a carbon price is the most efficient means to send market signals and achieve climate goals. “I’ve also been around long enough to know this is probably the least likely of the three to happen,” he added.

But there are other circumstances that will create challenges in the shorter term as the rules evolve.

Low energy prices, even during the recently concluded hot summer, were more than a function of cheap natural gas, he said. The addition of wind and behind-the-meter solar can depress energy prices, which has implications for the capacity market.

“What that means is the resources that we need when the wind isn’t blowing or sun isn’t shining are earning hardly anything to meet their capital costs, operating costs, so they’re just breaking even,” Ethier said. “So that puts more pressure on the capacity market to provide the revenue so they’re able to stay around when we need them.”

Dykes © RTO Insider

Dykes © RTO Insider

The capacity market is also pressured by renewable resources, which benefit from government subsidies like the federal production and investment tax credits, and state renewable portfolio standards, as well as long-term contracts through state-sponsored procurement.

But Katie Dykes, deputy commissioner at the Connecticut Department of Energy and Environmental Protection, said those state policies are needed to encourage clean energy development until market structures are in place.

“Is there a better mousetrap than the states doing procurements?” she asked. “In the near term we have to continue with it, but we’re very open and interested in other ways that we could come up with.”

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Arizona Public Service, Puget Sound Energy Begin Trading in EIM

By Robert Mullin

Arizona Public Service and Puget Sound Energy began transacting in the Western Energy Imbalance Market on Oct. 1, bringing the region’s only real-time market up to five members — including market operator CAISO.

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Arizona Public Service and Puget Sound Energy are the newest members to join the Energy Imbalance Market.

The utilities’ full entry into the EIM follows on two months of testing in which they operated in the market under real conditions without their transactions becoming financially binding. (See Arizona Public Service, Puget Sound Energy Enter EIM Testing Phase.)

The two utilities follow in the footsteps of NV Energy, which entered the market last December, and PacifiCorp, which helped launch the effort in November 2014.

“Participation by Arizona Public Service and Puget Sound Energy in the EIM will strengthen the market and yield substantial benefits in the form of access to low-cost energy for them and for all EIM participants,” CAISO CEO Steve Berberich said in a statement.

The EIM has produced $80 million in economic benefits for its members during the past two years, according to CAISO. Those benefits stem from more efficient inter- and intraregional dispatch in the 15-minute and real-time markets, lower curtailment of renewable energy and reduced need for market participants in all balancing areas to carry flexibility reserves.

Studies commissioned by the utilities indicate that APS could save $7 million to $18 million a year through EIM participation, while PSE could save between $18 million and $30 million.

“Participating in a market that enables APS to buy and sell power closer to when electricity is consumed will result in meaningful economic savings to customers through lower production costs and better integration of renewable resources like solar,” said Tammy McLeod, vice president of resource management at APS, which has transmission connections into both the CAISO and PacifiCorp-East balancing authority areas (BAAs).

PSE’s sole point of connection with the market is via a 300-MW long-term firm transmission reservation on the Bonneville Power Administration system that connects the utility with the PacifiCorp-West balancing authority area.

FERC last week authorized PSE to transact in the EIM at market-based rates, ruling that the company provided sufficient evidence that its limited link would not become constrained frequently enough to create an EIM submarket requiring measures to mitigate market power (ER10-2374).

The commission also directed APS to revise its proposed rules related to how resources external to the EIM can use dynamic scheduling to participate in the market through the utility’s transmission network. (See APS Ordered Again to Revise EIM Dynamic Scheduling Rules.)

Portland General Electric is scheduled to enter the EIM in October 2017, with Idaho Power slated to follow in April 2018.

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NYISO Management Committee Briefs

RENSSELAER, N.Y. — The NYISO Reliability Needs Assessment for 2017-2026 identified two transmission security needs beginning next year.

The assessment, which was approved by the Management Committee on Wednesday, identified the risk of thermal overloads on New York State Electric and Gas’ Oakdale 345/115-kV transformer in the Binghamton area and the Long Island Power Authority’s East Garden City-Valley Stream 138-kV line. Generation resources were deemed adequate in the period.

The Oakdale transformer overload was also mentioned in the 2014 assessment. NYSEG responded with plans for a third Oakdale transformer and reconfiguration of the Oakdale 345-kV substation. However, NYSEG has since updated the in-service date of the improvements from 2018 to the winter of 2021, the report said.

The LIPA 138-kV line has a risk of thermal overloads under N-1-1 conditions. “The power flow on this facility is driven by the combination of LIPA load in western Long Island and the scheduled 300-MW wheel between ConEdison and LIPA,” the report said.

Following the NYISO Board of Directors’ approval of the assessment, NYSEG and LIPA will be asked to develop solutions for the two transmission needs. If they are not addressed in their updated Local Transmission Owner Plans, the ISO will solicit solutions from developers.

The proposed solutions will be evaluated in the 2016 Comprehensive Reliability Plan. The RNA is the foundation for the reliability plan, which will be adopted next year.

Until upgrades can be completed, “the use of demand response and operating procedures, including load shedding under emergency conditions, may be necessary to maintain reliability during peak load periods,” the ISO said.

The biennial RNA process assumed the deactivation of the R.E. Ginna and James A. FitzPatrick nuclear plants. Those potential retirements were announced since the last Comprehensive Reliability Plan in 2014.

The plants, with a combined 1,463 MW, may be saved by the Clean Energy Standard adopted by the state’s Public Service Commission in August, which would pay upstate nuclear plants nearly $1 billion for their carbon-free attributes in the first two years of the program.

Systemwide Demand Response Activated

A summer heat wave prompted the first mandatory systemwide DR event in NYISO in three years.

The Aug. 12 event came on the second day of a two-day heat wave, when the peak load was 31,477 MW. NYISO estimated a peak of 32,415 MW if DR had not been activated.

Actual loads were 1,000 MW more than earlier projections for the day and came as neighboring control areas in Ontario and New England were also experiencing high demand. Operating reserves for some time intervals fell below the required 2,620 MW.

The summer’s peak was 32,076 MW on Aug. 11.

“The peak represented the third consecutive year that the NYISO peak fell below the 50/50 forecast,” said Wes Yeomans, NYISO’s operations vice president, who presented the summer 2016 report. The forecasted 50/50 peak was 33,360 MW.

nyiso management committee

Noteworthy over the two days was the performance of the state’s 1,700 MW of wind resources.

On Aug. 11, wind generation was essentially a flat line of about 50 MW from 8 a.m. to 8 p.m. On Aug. 12, as thunderstorm alerts began to move through the state, wind generation topped out at about 600 MW during the afternoon, closely following the rise in demand, which peaked in the 4 p.m. hour.

On July 24, NYISO activated its 21-hour notice for DR for the Lower Hudson Valley, New York City and Long Island, but the ISO did not implement its operation. Rochester Gas & Electric, Con Ed and the New York Power Authority instituted their voluntary DR programs, however.

The last systemwide DR event was during the polar vortex in January 2014 when the voluntary program was activated. The last mandatory DR systemwide event was in July 2013.

– William Opalka

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Overheard at the 8th Annual Transmission Summit West

SAN DIEGO — Transmission industry owners, operators, generators, regulators, financiers and other key players from the Western U.S. attended Infocast’s 8th annual Transmission Summit West last week. They discussed the strategic, regulatory, investment and technology issues facing the industry.

Western Regionalization

CAISO’s Stacy Crowley, vice president of regional and federal affairs, pushed the benefits of ISO participation in her solo presentation, saying, “Utilities and stakeholders have found these ISOs to be valuable, as far as providing cost-effective power.

“We know in the Midwest, states like Iowa could not have reached their renewable standards without an ISO. We’ve seen entities around the Northwest asking if there are efficiencies with a larger market. Clearly, a board appointed by the California governor and approved by the State Senate would not fly in a regional ISO. California clearly has the largest load of any state in the West, but a regional ISO must speak for everyone and their policies.”

ColumbiaGrid CEO Patrick Damiano agreed, but he made the case that coordinating planning doesn’t require a centralized market.

ColumbiaGrid conducts transmission planning and other coordination for its eight members: Avista, Bonneville Power Administration, Chelan County Public Utility District, Grant County PUD, Seattle City Light, Snohomish County PUD, Tacoma Power and Puget Sound Energy, which joined the Western Energy Imbalance Market on Oct. 1.

“The Northwest has always been an active bilateral market,” Damiano said.

“We’ve been very excited about the creation of the EIM,” said Gerald Deaver, manager of regional transmission policy for Xcel Energy. “Our first baby step was FERC’s approval of a joint dispatch area in Colorado [with Platte River Power Authority]. We’ll be the market operator, but we look at it as a way to more efficiently use generation resources in the balancing area. Our ultimate goal is to develop a larger geographic footprint to better integrate renewables. Our hope is that entities will become more comfortable operating in that environment.”

“I can’t imagine all of the West as we know it today would be one RTO. It’s too big. I see two or three RTOs with seams agreements,” SouthWestern Power Group’s Tom Wray said. “For resource management and market efficiency, [RTOs] are clearly a good policy move for the country. One of the motivating factors for expansion of the regional market we know as Cal-ISO is largely coming from regulatory pressure.”

Tanya Bodell, executive director of Energyzt, called for “market-based solutions” to cope with too much generation on the Western system. “West Texas retailers are selling energy for free on nights and weekends. FERC Order 745 has opened up an opportunity for demand to come into the market. I can see 745 creating a mechanism through which system operations encourage people and pay people to use more energy. Generators have a different bid price to operate, versus a bid price to curtail. You may end up getting a curtailment market, where the ISO asks for bids from generators.”

Renewable Integration Remains Sticky Issue

“We’ve done pretty well so far in integrating renewables. We didn’t think 20% would be that easy, but it turned out to be not so much of a challenge,” said Carl Zichella, director of Western transmission for the Natural Resources Defense Council. “We have 38 different balancing authorities in the West. It’s one big grid operating in discrete chunks, rather than an integrated system. While that’s worked so far, we’re going to need to do much better to integrate deeper penetration of wind.

“The worst-case scenario for renewables is what we have now … [balancing authorities] complicating the use of transmission with bilateral contracts and artificial congestion. The biggest hurdle to regionalization is the governmental structure.”

Jay Caspary, SPP’s director of research, development and Tariff studies, said America’s best renewable resources straddle the seam between the Western and Eastern interconnections. While SPP, MISO and ERCOT have built and continue to build transmission to access those resources, the abundance does create a dilemma.

“ERCOT is harvesting thousands of megawatts in SPP’s backyard and pulling them into ERCOT,” he said. “We have two separate independent networks in the Texas Panhandle. At some point, we’ll probably have to integrate those two, but there are a lot of jurisdictional issues.”

In California, rooftop solar is the oncoming train. Jack Moore, director of market analysis for Energy + Environmental Economics, said his company is projecting the state will enjoy 17 to 23 GW of the sunshine resource by 2025. “The big driver we see is in certain hours, California has more solar than it can use. That does set up a reason for [increased] transmission to be able to bring more flexibility to the system.”

“Our experience in Texas is that you build these [interconnection] ties and they get oversubscribed,” said Bill Bojorquez, vice president for Hunt Power. “There are great stranded resources in New Mexico. Sharyland Utilities has over 11 [GW] of generator-interconnection requests. We are literally over-subscribed. It’s one of those stories where if you build it, they’ll be oversubscribed.”

Getting Utilities to Embrace Alternative Technologies

Several speakers complained about the industry’s conservatism.

William White, director of public affairs for CTC Global, said his company has found it difficult winning acceptance of its high-temperature, low-sag, composite core conductors. “We’re in the odd position of having a proven product that works,” he said. “We know it works, our customers know it works, but old habits die hard. Most of [today’s] conductors are literally 100-year-old technology.”

“Some of the biggest resistance to regionalization is the cost,” said Gregg Rotenberg, president of Smart Wires, which provides “grid optimization solutions.”

“If we’re having a conversation about regionalization and we’re only using existing infrastructure, that means we’re using the grid inefficiently,” Rotenberg said. “The hardest group to get involved is the transmission groups at these utilities. When we get them on an equal playing field and we’re spending less on new technologies, we’ll have a new grid.”

Byron Woertz Jr., the Western Electricity Coordinating Council’s manager of system adequacy planning, preferred to see his glass half full. “This a country that put a man on the moon with 20th century technology, so I think we can improve the grid,” he said.

Battery Storage Ready for Prime Time

Asked whether battery storage needs tax credits similar to wind and solar resources, Kiran Kumaraswamy, market development director for AES Energy Storage, said storage is “absolutely ready for prime time.”

“What we really need is a framework to value this class of resources. Four to five years ago, we started talking about the value of solar in a way in which you could bring all those benefits to the table and compare them with all the other options. The gap right now is being able to evaluate [storage] resources on an apples-to-apples basis.”

“I think energy storage works best when paired with other grid assets, to increase the value of the electricity being generated,” said John Jung, CEO of Greensmith Energy Management Systems. “You can do a lot more with electricity when you have the ability to shape the nature of it and the quality of it.”

John Fernandes, RES Americas’ director of policy and market development, said he is not worried about customer migration from the grid. “I’ve been announcing the death spiral of the utility death spiral for years now.”

Non-utilities “are not dealing with NERC violations worth millions of dollars a day,” he said. “When you’re talking about megawatts, [reliability] matters. We’re so highly dependent on this super-reliable service.”

Making FERC Order 1000 Work

A panel sharing their experiences with FERC Order 1000’s directive on competitive transmission projects agreed that CAISO continues to put space between itself and other RTOs with its implementation of the order.

“The evaluation process is certainly evolving. Cal-ISO maybe puts more emphasis on costs and less emphasis on [operations and maintenance], but it’s gotten much better,” said Charlie Adamson, principal manager of major transmission and distribution projects for Southern California Edison. “Every evaluation, they’ve gotten better at it. Things like the EIM or the ultimate experience of an ISO … opens up market availabilities for that energy transfer to make sense. Over time, that could enable long-haul lines that bring in energy from where it’s cheap to where it’s necessary.”

Josh Burkholder, director of transmission asset strategy and grid development for AEP Transmission and Transource Energy, relayed his experiences in SPP’s first competitive process, which resulted in one project being awarded — and then canceled as unneeded. “There were some real head scratchers [in how an industry expert panel graded the projects]. A notch difference in your parent company’s credit rating was a five-point difference [in the scoring]. In a $10 million project, [the credit rating is] pretty irrelevant. Be careful what you wish for a little bit, when it comes to clarity and understanding with how the decision is made.”

“From my standpoint, a lot of things that may not be apparent may become a reliability issues when it’s too late to solve the issue with transmission,” said Bob Smith, vice president of transmission development for TransCanyon, a joint venture of Pinnacle West Capital and Berkshire Hathaway Energy. “This is the second year we’ve had laws in California that are going to require a 50% [renewable portfolio standard], maybe higher, to comply with greenhouse gas laws. Yet, Cal-ISO is relying on a 20% portfolio? It doesn’t make sense for Cal-ISO to be planning when you don’t know where the resources are. By the time Cal-ISO gets clarity on where resources are, we’re coming pretty close to 12 years from the 2030 policy deadline, and you don’t develop transmission in three or four years.”

Speaking of transmission projects in general, Chris Jones, a vice president with Duke-American Transmission Co., said delays in the permitting process “that can happen over the decades-long process” remains “the biggest risk in each of our projects.”

“One of the things that’s changed since I started doing this work is the sensationalism of these projects and the media coverage you get and the protests that come with that. It’s usually local groups, but we’re seeing more and more groups outside the [non-governmental organizations] get media coverage. You’re seeing that now with the North Dakota pipeline project.”

Ali Amirali, a senior vice president with the Starwood Energy Group, called transmission development “a giant game of economic chicken.” He said, “The generation developers are waiting for the transmission to be built. The transmission developers want the generation to be built before getting into the heavy capitalization of transmission.”

– Tom Kleckner