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November 14, 2024

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Transmission, REV Dominate NYISO’s Landscape

By William Opalka

Bradley Jones, who stepped in as CEO of NYISO late last year, recently told RTO Insider that his three top initiatives “have always been transmission, transmission, transmission.”

He came to the right place. Transmission upgrades dominated activity in the NYISO footprint in 2015 and promise to occupy headlines in 2016.

The improvements are occurring amid a changing energy landscape. State officials and regulators are deciding how to handle aging and unprofitable power plants in western New York. Meanwhile, the Reforming the Energy Vision initiative seeks to encourage the growth of distributed and renewable resources throughout the state.

The New York Public Service Commission last month declared a public policy need for an expected $1.2 billion in upgrades to move 1,000 MW of power from upstate generation sites to load centers in and around New York City. The project has been discussed for more than three years; now, NYISO will seek bids on the projects. The PSC hopes to evaluate siting proposals by the end of the year, with approvals anticipated in 2017. The upgrades are expected to be in service in 2019. (See NYPSC Declares Public Policy Need; Directs NYISO to Seek Tx Bids.)

Future of Nuclear Uncertain

Will the transmission projects come too late to save aging and unprofitable nuclear and coal-fired power plants in the western part of the state? Or, as environmental and consumer advocates might ask: Are those plants even worth saving?

In his State of the State address on Jan. 13, Gov. Andrew Cuomo is expected to announce details of a plan to shift the state to 50% renewable energy by 2030, along with a strategy to keep the nuclear plants open until then by offering some financial recognition of their carbon-free emissions. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

Nevertheless, Entergy is standing by its decision to close the James A. FitzPatrick nuclear plant on Lake Ontario in late 2016 or 2017.

Exelon and stakeholders are finalizing a reliability support service agreement for the R.E. Ginna nuclear plant that would run through March 2017 — after which, the company says, the plant is likely to retire. The PSC has extended the negotiating window for that deal to Feb. 29. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)

At the same time, the state’s REV proceeding is continuing with development of demonstration projects, including microgrids and energy efficiency programs.

Much attention will be paid to the anticipated Track 2 Order that addresses rate design for the new business models. (See NYPSC Outlines Reforming the Energy Vision Changes.)

RMRs Winding Down

In the meantime, several reliability-must-run agreements that pay unprofitable plants above-market rates are starting to wind down. Some of the facilities hope to repower with natural gas, proposals that will be addressed by regulators this year.

One of these, the coal-fired Dunkirk station outside of Buffalo, was mothballed Dec. 31, when its RSSA expired. Owner NRG Energy has suspended the repowering plan pending resolution of a lawsuit filed by Entergy. (See NRG Plant Closures Could Impact Reliability in NY.)

The 312-MW Cayuga coal-fired plant outside of Ithaca is operating under an RSSA through mid-2017. Although its owner has proposed converting it to natural gas, a transmission project proposed by a distribution utility and endorsed by environmentalists could make the plant unnecessary.

Plans to convert the idled Greenidge power plant on Seneca Lake to gas are on hold as EPA has said it must undergo a “new source” review.

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SPP, ERCOT Set New Wind Peaks

SPP, which has already set six wind peaks this fall, established another on Dec. 19 with 9,948 MW, the second time it has eclipsed 9,000 MW. The RTO said wind’s penetration level was 33.5%, off the record 38.3% set Nov. 4.

ERCOT closed out 2015 with its eighth wind peak of the year, a record 13,883 MW on Dec. 20, representing more than 93% of its installed wind capacity and 44.7% of load served.

The wind generation easily topped the previous peak set Dec. 19, when the ISO exceeded 13,000 MW for the first time with 13,029 MW.

ERCOT generated almost 4.4 million MWh of wind energy in November, accounting for 18.4% of energy used.

— Tom Kleckner

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A Few Growing Pains for SPP as it Celebrates 75 Years

By Tom Kleckner

During the past two years, SPP has added new markets for its members, some 5,000 MW of peak demand and 7,600 MW of generating capacity in the Upper Great Plains, extending its footprint to the Canadian border in the process.

So what does it plan for an encore in 2016?

Celebrating its 75th anniversary, for one. SPP will mark the occasion this fall with several ceremonies and a commemorative publication chronicling the RTO’s history, which began in the days after the attack on Pearl Harbor.

That’s when 11 regional power companies in the Southwest — including predecessors of today’s SPP member companies — signed an agreement to pool their energy resources and ensure Central Arkansas’ aluminum production could maintain 24/7 operations. When World War II ended, an executive committee decided to continue the organization to maintain reliability and coordination.

From those modest beginnings, SPP has grown into a sprawling member-driven organization, coordinating electricity flows over 56,000 miles of high-voltage transmission lines across 575,000 square miles in all or parts of 14 states, from the Deep South to the Dakotas and westward. It counts 97 members representing cooperatives, power producers, marketers and independent transmission companies along with the usual transmission owners, and has 170 registered participants in its markets.

A ‘Success Metric’

SPP’s growth has been good news for its members.

The RTO projects the addition of the Integrated System (IS) last October will yield $334 million in member benefits over a 10-year period. It also has said the Integrated Marketplace — comprising day-ahead, real-time balancing and congestion-hedging markets — generated approximately $210 million in total regional net savings in its first year, in addition to $170 million in savings from SPP’s previous energy imbalance service market. SPP plans to release a study quantifying the transmission benefits its members receive in January.

“It’s been another interesting year for the corporation and our members,” SPP CEO Nick Brown said during October’s board meeting. “If ever there’s a success metric, it’s the members who have decreased costs or rates.”

SPP will focus much of this year on improving its rapidly maturing markets with three projects: enhanced combined cycle (ECC) logic, gas-electric “harmonization” and the Z2 crediting tool.

Improved Economic Dispatch

The ECC project is designed to provide more sophisticated modeling that captures the flexibility of combined cycle plants. Each combined cycle configuration will be modeled in the market-clearing engine as a separate resource.

SPP expects the increased flexibility to allow “optimization of the combined cycle resource configuration throughout the unit commitment processes,” projecting in its 2016 budget a $3 million to $5 million reduction in generation costs. The savings are expected to grow as new combined cycle plants join SPP in the future.

SPP has targeted March 2017 for completion of the $1.5 million project. (See “Enhanced Combined-Cycle Project Moves Forward” in SPP Board of Directors/Members Committee Briefs.)

The ECC work will be done in conjunction with system changes needed to close the Integrated Marketplace’s day-ahead market earlier and shorten the solution time for posting results by 30 minutes. Both have significant impacts on the market operating system’s solution time.

SPP said the gas-electric harmonization work will be completed by the fall, at a projected cost of $6.2 million.

The initiative is a result of FERC Order 809, which moved the timely nomination cycle deadline for gas from 11:30 a.m. CT to 1 p.m. (See “Board Approves Gas-Electric Timeline Change” in SPP BoD/Members Committee Briefs.)

SPP says the schedule changes are “an incremental improvement over the existing timeline.”

Years of Incorrect Credits

The Z2 crediting project dates back to the last decade as a result of years of incorrect credits for transmission upgrades. (See “Z2 Crediting Task Force Remains on Track” in SPP Markets and Operations Policy Committee Briefs.)

A project team is developing software that will properly credit and bill transmission customers for system upgrades under SPP’s Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.

The task force has estimated creditable upgrades of $750 million, with up to $90 million in transmission customer improvements and the remainder from sponsored upgrades.

The task force hopes to present a better estimate during the Markets and Operations Policy Committee and Board of Directors/Members Committee quarterly meetings in January.

SPP says the new system should reduce errors, disputes and resettlements.

Eyes on Expanded Footprint

SPP’s day-to-day business in 2016 will remain focused on maximizing the addition of the IS to its footprint.

The IS tripled SPP’s hydroelectric capacity, which represented only 1.1% of the RTO’s capacity in 2014. It also added winter-peaking regions, increased seams coordination issues and greatly expanded the geographic area for SPP’s reliability monitoring function.

SPP says the addition of the IS has “opened opportunities to expand SPP’s services to affiliated entities in the Western Interconnect” through membership or contracted services. SPP has an ongoing market-consulting contract with the Northwest Power Pool, which has been exploring the possibility of opening an energy market for several years.

Because of the surge in wind production, the RTO will refresh its 2009 wind-penetration study in February.

Navigating the Clean Power Plan

SPP will continue its work helping states comply with EPA’s Clean Power Plan. The RTO expects “significant impacts in the near term and well into the future.”

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone. Several SPP states have joined litigation to block the rule.

“The lawsuits will muddy the water in terms of how SPP interacts with its stakeholders as they work to comply with the standards,” it said.

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone.

The RTO will include CPP compliance in the 2017 Integrated Transmission Planning 10-year assessment. A near-term transmission study also will be conducted this year, with the results presented to MOPC and the board in April.

At that time, MOPC and the board should be taking up for consideration SPP’s first Order 1000 project, the 21-mile, Walkemeyer-North Liberal 115-kV project in Kansas. An industry expert panel is currently evaluating responses to SPP’s request for proposals.

SPP expects to receive 3,200 proposals for competitive projects in 2016, double the number it saw in 2014.

It also expects a “significant increase” in generation interconnection studies. SPP projects a 12% bump in transmission volume to more than 407 MWh in 2016.

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FERC Again Rebuffs Brayton Point Union

FERC on Wednesday denied rehearing of its June decision certifying the ninth Forward Capacity Auction results in ISO-NE, dealing another blow to a utility union’s claim that supply of the Brayton Point plant was illegally withheld to raise prices (EL15-1137).

The Utility Workers Union of America, which represents workers at the Massachusetts plant, in July asked FERC to void the auction results. (See Fourth Time the Charm? Brayton Point Union Again Challenges ISO-NE Auction.)

Energy Capital Partners, former owner of the 1,517-MW plant, did not offer it in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.

FERC previously rejected the union’s challenge to results of FCA 8 on similar grounds. FERC said a non-public investigation by its Office of Enforcement failed to uncover any evidence of wrongdoing.

“This conclusion remains valid for FCA 9,” FERC wrote.

The commission also reiterated its acceptance of the conclusion of ISO-NE’s Internal Market Monitor that no anti-competitive behavior existed before the auction.

FERC also rejected the union’s contention that the ISO-NE Tariff requires a determination that a unit is uneconomic before it is allowed to retire.

“The Tariff contains no provision requiring a resource to demonstrate that it is uneconomic before it is allowed to retire, and UWUA does not point to any such provision. There is no test as to whether the unit can economically provide capacity, nor is there a mechanism by which ISO-NE can compel the resource to continue operating under any circumstances,” the commission wrote.

— William Opalka

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FERC Accepts Order 1000 Compliance Filing

FERC has accepted NYISO’s fourth Order 1000 compliance filing, turning aside the protests of transmission developers that claimed it unfairly favored incumbent transmission owners (ER13-102-007).

LS Power and NextEra had protested the ISO’s right to terminate development agreements if a force majeure event prevents a non-incumbent developer from completing its project by the in-service date. (See Tx Developers Challenge NYISO, SPP, ISO-NE Order 1000 Filings.)

NYISO and the New York Transmission Owners submitted their fourth Order 1000 compliance filing in May. It included a pro forma development agreement for NYISO’s reliability transmission planning process.

“NYISO argues that it must have the option to terminate the development agreement and identify alternative means of satisfying an identified reliability need if a developer cannot complete its project by the required project in-service date,” FERC wrote on Dec. 23.

The commission cited a similar provision at PJM, ordering NYISO to add comparable language in its development agreements with incumbent transmission owners to prevent discrimination.

In a second order Dec. 23, FERC rejected a NYISO filing that the commission said was unfair to competitive transmission developers (ER15-2059).

FERC said the proposal “subject[s] nonincumbent transmission developers to an interconnection process with different requirements than the interconnection process that applies to incumbent transmission owners.” While all interconnection customers are required to obtain system impact and facility studies, the nonincumbents were required under the proposal to additionally submit a feasibility study and deposits for all three studies.

NYISO had argued the incumbent would have already conducted a feasibility study in its normal planning process, but FERC said that would create two different processes that are not comparable.

— William Opalka

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FERC Orders Tech Conference on PJM FTR Rule Changes

By Rich Heidorn Jr.

FERC on Monday ordered a technical conference to sort out conflicting claims over PJM’s proposed rule changes to reduce underfunding of financial transmission rights.

PJM’s proposed changes, filed in October, were challenged by the Financial Marketers Coalition and others, who said they would be ineffective and discriminatory. The commission said the conference was needed to develop more evidence before it rules (EL16-6-001, ER16-121).

The conference will explore PJM’s claim that its existing rules on FTRs and auction revenue rights are unjust and unreasonable and that the problems would be remedied by its proposed changes. Specifically, the conference will look at ARR modeling and allocation processes; treatment of portfolio positions in allocating underfunding or surplus among FTR holders; and the potential for market manipulation.

pjm
Crews install towers as part of Commonwealth Edison’s Grand Prairie Gateway project, which is expected to go into service in 2017. PJM said the need for the project might have been approved earlier under its proposed FTR rule changes.

An FTR entitles its holder to credits based on LMP differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.

PJM improved funding under current rules by modeling more transmission outages, clearing more counterflow FTRs and improving its modeling of loop flow, the alignment of the FTR, day-ahead and real-time energy markets, and market-to-market coordination with MISO.

PJM said the changes raised FTR revenue adequacy from as low as 69% during planning years 2010/11 through 2013/14 to at least 110% since the 2014/15 planning period.

However, PJM said the changes resulted in an unfair shift of revenues from ARR holders to FTR holders. It said the load-serving entities receiving reduced Stage 1B ARRs are largely different from the LSEs receiving the over-allocation of infeasible Stage 1A (10-year) ARRs.

To correct the cost shift, PJM proposed eliminating the netting of negatively valued FTRs against positively valued FTRs within portfolios. It also proposed increasing current ARR results by 1.5% annually — equal to the average ARR 10-year growth rate since 2007 — in the Stage 1A 10-year simultaneous feasibility process. (See PJM to File FTR, ARR Rule Changes with FERC.)

PJM said the changes will increase the likelihood of infeasible ARRs, potentially identifying needed transmission upgrades such as Commonwealth Edison’s Grand Prairie Gateway project sooner. The 60-mile 345-kV line through four counties in northern Illinois began construction in the second quarter of 2015 and is expected to begin service in 2017. The company says it will allow the import of cheaper wind power from the west, saving customers about $250 million net of all costs within the first 15 years.

Commenters including utilities and the Independent Market Monitor told FERC they generally supported the proposed changes. But the Financial Marketers Coalition (representing DC Energy, Inertia Power, Saracen Energy East and Vitol), Shell Energy N.A. and others protested the elimination of netting, saying PJM failed to show the current rules are unjust and unreasonable and that the change would cure underfunding.

Without netting, the coalition argued, underfunding risks would shift to those that take on counterflow FTR obligations and could encourage market manipulation.

Opponents also questioned whether the proposed 1.5% escalation would be as effective in preventing ARR infeasibilities as claimed by PJM.

[Editor’s Note: An earlier version of this article mistakenly reported that J. Aron & Co. is a member of the Financial Marketers Coalition.]

 

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PJM Seeks Changes to AEP, FirstEnergy PPAs

By Suzanne Herel

Power purchase agreements proposed by American Electric Power and FirstEnergy need changes to preserve competition and Ohio’s ability to attract merchant generation, PJM said this week.

The RTO made the recommendations in testimony to the Public Utilities Commission of Ohio (14-1693-EL-RDR, 14-1694-EL-AAM, 14-1297-EL-SSO).

The filings were virtually identical and offered two amendments to the eight-year agreements. The first would define a “reasonable bidding practice” as offering the output of units covered by the deals into PJM’s markets at no lower than their actual cost, with no consideration of offsetting revenue being provided by Ohio retail customers.

“Bidding at actual cost, consistent with the definition of acceptable costs included in the PJM Tariff and manuals, ensures that the PPA does not have the effect of artificially suppressing prices in any of PJM’s markets,” Stu Bresler, senior vice president of markets, said in the AEP case. The phrasing for the FirstEnergy case was changed only to reflect the term that company is using for its request, a retail rate stability rider (RRS).

Bresler also recommended that if the commission accepts the agreements, it should make clear in its order whether generation owners or their customers would bear the risk of non-performance under the new Capacity Performance model, which aims to ensure reliability by rewarding over-performing units and penalizing under-performing generators.

Bresler said PJM takes no position on the proposed stipulations but felt it necessary to weigh in on aspects that could affect its wholesale markets.

The consequences of “unreasonable” actions when selling AEP’s and FirstEnergy’s output would be “severe,” yet the agreements do not clarify “reasonable” or “unreasonable” actions, Bresler said.

“This provision, more than any other in the stipulation, has the potential to impact the PJM marketplace as a whole and the marketplace in Ohio for new investment, depending on how the provision is implemented,” he said.

PJM’s recommendations are in Ohio’s interest because the output of units covered by the agreements falls substantially short of the companies’ peak loads — 10,500 MW in AEP Ohio’s case and 11,900 MW for FirstEnergy, Bresler said. New generation resources are critical to Ohio’s future, he said, but they would be discouraged from investing in the state if others were allowed to bid below their costs.

Bowring: PPAs Inconsistent with Competition

PJM Market Monitor Joe Bowring also filed testimony, saying that the retail rate stability rider requested by FirstEnergy and AEP’s proposed power purchase agreement both “constitute a subsidy which is inconsistent with competition in the PJM wholesale power market.” He urged the commission to reject them.

The purpose of the AEP agreement, he said, “is to shift costs and risks from shareholders to customers, to remove the incentives to make competitive offers in the PJM capacity market and to provide incentives to make offers below the competitive level in the PJM capacity market.”

The agreement also does not explicitly address how AEP plans to operate within PJM’s new capacity market design.

However, Bowring said, “I would expect that the proposed PPA rider would require ratepayers to pay any performance penalties associated with the assets included in the PPA rider. I would also expect that AEP would retain any performance payments at other AEP units not included in the PPA rider, even if paid for in part by these ratepayer penalties.”

That removes the risk from shareholders, along with the incentive to manage the performance of the units, he said.

Like Bresler, Bowring expressed concern about the agreements enabling the companies to offer output into the market at artificially low prices, edging out competition.

AEP’s request, he said, indicates that PJM should expand its minimum offer price rule to include any new units with subsidies, requiring them to bid into the market at a level no lower than the cost of new entry.

Bowring also testified that the rider requested by FirstEnergy would transfer all “historic and future costs” for certain plants to ratepayers and set up the same paradigm involving its participation in PJM’s capacity market.

Together, the agreements essentially would re-regulate about 6,300 MW of generation. AEP announced its PPA on Dec. 14. FirstEnergy released its proposal Dec. 1. PUCO is expected to rule on the cases in early 2016.

In addition to its testimony, PJM plans to issue a market analysis of both deals this spring. (See PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces.)

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FERC Allows CAISO EIM to Identify Adjacent Capacity

By Michael Brooks

FERC last week approved Tariff revisions that will allow CAISO’s Energy Imbalance Market to automatically recognize the capacity that participants outside of the ISO’s footprint use to maintain reliability in their own territories (ER15-861-006).

In its filing proposing the change, CAISO told the commission that its software’s inability to recognize this “available balancing capacity” was creating false scarcity in the market, resulting in price spikes. The changes will ensure prices reflect the true nature of the deployed capacity, the ISO said.

caiso eimUnder the revisions, each EIM participant will be required to identify the available balancing capacity of all its resources, even if it does not bid those resources into the market.

“We agree that the available balancing capacity proposal will reduce the potential for imbalance energy price spikes by providing for greater visibility of the capacity each EIM entity has available to it to resolve power balance violations within its own [balancing area authority], even when that capacity is not being offered into the EIM,” FERC said. The changes also allow EIM participants flexibility to determine what capacity they should retain outside of the market to maintain reliability, the commission said.

Beginning in November 2014, CAISO expanded its EIM to Western Interconnection utilities outside its territory. PacifiCorp — with territory in Oregon, Idaho, Utah and Wyoming — was the first to join, followed recently by Nevada-based NV Energy. Arizona Public Service and Washington-based Puget Sound Energy are projected to join early next year, followed by Portland General Electric in 2017. (See CAISO Expands Reach to 7 States with Imbalance Market.)

NV Energy

In a related order, FERC dismissed requests for rehearing of its approval of certain Tariff revisions by NV Energy to allow its participation in the EIM (ER15-1196-002).

Powerex, a power marketer that operates in the western U.S. and Canada, and Truckee Donner Public Utility District, a municipal utility in California, objected to the commission’s approval of NV Energy’s use of CAISO’s LMPs to settle imbalances for transmission customers who opted out of the EIM. Powerex also asserted that NV Energy’s participation in the EIM would jeopardize resource adequacy in the Nevada utility’s balancing area.

The companies based their complaints in part on price spikes and other problems in the market when PacifiCorp first joined. FERC said, however, that “CAISO has taken tangible steps to resolve the underlying problems that contributed to the price spikes” in PacifiCorp’s territory. The commission pointed to the steps the ISO has taken to resolve those problems — including the recognition of available balancing capacity.

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FERC Briefs

FERC denied MISO’s request for clarification and rehearing of a May 2015 order concerning the RTO’s request for waivers from the requirements of Order 676-H, which incorporated into commission regulations the North American Energy Standards Board’s latest Standards for Business Practices and Communication Protocols (ER15-548-001).

“We disagree with MISO’s argument that the commission’s policy regarding the point at which a redirect customer loses rights to its original path was unclear until the issuance of Order No. 676-H,” the commission said, adding that the policy was announced in 2002.

FERC Directs MISO to Specify SSR Cost Allocations, Interconnection Transfer Rights

FERC denied rehearing but granted clarification of a July 2014 order that conditionally accepted MISO’s Tariff revisions regarding system support resource procedures (ER12-2302).

The commission agreed with MISO that its order was unclear, clarifying that the RTO’s Tariff must “provide specific guidance about the contractual commitments required of generation and demand-side resource alternatives, and general guidance about how MISO will evaluate whether contractual commitments required for additional types of resources are comparable to the commitments that apply to transmission solutions.” The commission said MISO’s September 2014 compliance filing generally met the directive.

“However, we note that MISO’s proposed revisions providing that a ‘generator alternative may be a new generator, or an increase to existing generator capacity’ do not address the situation where an existing generator, which is not available at the time of SSR designation and is subsequently made available, can be selected as an alternative solution,” FERC said. It ordered MISO to submit a compliance filing within 45 days revising its Tariff to allow an existing generator to be considered as a generator alternative.

The commission also granted Wisconsin Electric Power’s request for clarification, ruling that MISO must allocate SSR costs to the load-serving entities that require the operation of the SSR units for reliability. FERC said it agreed with Wisconsin Electric’s concern that MISO’s method for cost allocation “can produce results that are not consistent with MISO’s Tariff or cost-causation principles.”

PATH Ruling on RTO Adder Affirmed

The commission denied Potomac-Appalachian Transmission Highline’s (PATH) request for rehearing of a November 2012 order denying the transmission developer continued application of the 50-basis-point incentive for membership in PJM (ER12-2708-002, ER09-1256-001).

The commission said that PATH — a joint venture formed by American Electric Power and Allegheny Energy (now FirstEnergy) to build a $1.8 billion transmission line between West Virginia and Maryland — was no longer eligible for the adder after PJM canceled the project in 2012.

The commission said its earlier order was consistent with existing policy, denying PATH’s complaint that it had acted retroactively.

In September, a FERC administrative law judge recommended the developers be denied recovery of more than $10 million of their $121.5 million project recovery claim. The judge recommended the commission deny recovery of lobbying and advertising costs as well as part of their legal costs and losses on the sale of the property they acquired.

The commission, which can accept the recommendations in whole or in part, has not acted on the ruling. (See FERC ALJ Rejects $10 Million in PATH Transmission Project Recovery.)

— Amanda Durish Cook and Rich Heidorn Jr.

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MISO Unveils Queue Rule Transition as Wind Advocates Seek Delay

By Amanda Durish Cook

CARMEL, Ind. — MISO has settled on a transition plan for its new interconnection queue rules and intends to file Tariff changes with FERC by the end of the year, despite wind advocates’ complaints that the process has been rushed.

MISO said it plans to stagger implementation, “processing some projects under the existing rules and transitioning certain projects to a portion of the new process.”

Between Feb. 20 and May 20, MISO plans to finalize existing generation interconnection agreements and facilities studies, with GIAs completed for the latter by late August. These GIAs will be at the top of the queue for all study cycles to follow.

The RTO will also finish all incomplete system impact studies by Aug. 27 and give the owners of those projects an option by early September to either move into phase three of definitive planning under the existing rules, paying an M4 milestone, or enter phase one of definitive planning under the revamped queue without having to pay another M2 milestone fee.

Projects that haven’t yet entered into a system impact study by Feb. 20 will be rolled into the reformed queue.

miso

Vikram Godbole, senior manager of MISO’s generator interconnection planning group, said interconnection customers with pending GIAs as of Feb. 20 will be targeted first to complete negotiations.

“It’s a tall order, I realize that,” Godbole said of the dates outlined in the transition plan.

Throughout the process, staff representing Minnesota-based Wind on the Wires have complained that the adoption of the new queue timeline and rules has been rushed. The wind advocacy group says that costs remain too high under the new rules and wants MISO to eliminate the M4 milestone payment and create a cost cap on network upgrades. It has asked that MISO delay implementation of the rules until it reaches an agreement with the group.

Godbole said that the new queue will be implemented despite any future required Tariff changes to the interconnection process that may arise due to resource adequacy Tariff revisions. He said those will be handled in the future “as necessary.”

He added, “Any aspects from a technical perspective will be done at the [Business Practices Manuals] level. We’ll take those on next year.”

MISO will use the M2, M3 and M4 milestone payments surrendered by owners of non-viable projects to compensate other interconnection projects that were negatively impacted by the withdrawals.

Godbole said the new queue rules are intended to reduce the number of customers who keep non-viable projects in the queue until the “tail-end.”

“We’re doing this for interconnection customers,” Godbole said. “We want to make sure that people who come into the process ready are rewarded.”

In early December, stakeholders said interconnection customers should be able to use their M2, M3 and M4 payments to fund their initial milestone payment in the 30 days following completion of a generator interconnection agreement. Although MISO denied the request, the grid operator offered a willingness to discuss the option with stakeholders and, depending on the outcome, file Tariff revisions sometime in 2016.

During the last round of comments on Dec. 7, stakeholders requested the addition of a third penalty-free withdrawal option if estimated costs increase more than 25% between MISO’s system impact study and facilities study. Godbole said that MISO evaluated the merits of a third off-ramp “intensely” but ultimately determined not to provide it because the proposed queue reform is more economical for interconnection customers than the queue currently in place.

Stakeholders also criticized the M3 and M4 milestone floors of $2,000/MW, arguing that the cost never actually dips to $2,000, so the threshold is “illusory.” MISO declined to raise the floor, saying that the limit was FERC-approved and costs could come down in the future. (See MISO Cuts Queue Admission, Adds ‘Off-Ramps’.)