Page 1499 – RTO Insider

November 25, 2015

Developer Questions Need for PSEG Projects Without ‘Wheel’

A transmission developer is asking PJM to determine if four projects in the Public Service Electric and Gas territory in North Jersey are still necessary if Consolidated Edison of New York makes good on its threat to terminate the “PSEG wheel” to route power into New York City.

Writing on behalf of Linden VFT, GE Financial Services asked PJM Nov. 16 for a reevaluation of the projects, given the “likely termination” of the wheel in 2017.

“We also request that PJM consider directing PSEG to cease work on the projects until careful reconsideration can be completed,” Linden VFT said.

Con Ed told PJM last month it will end use of the wheel when its current term expires on April 30, 2017, if it doesn’t win relief in a cost allocation dispute. (See Con Ed: Cost Allocation Dispute Could End PSEG Wheel.)

The four projects, part of the Regional Transmission Expansion Plan, include the Sewaren storm-hardening project, two sections of the Bergen-Linden Corridor and the Edison Rebuild.

Linden VFT is the owner of a 315-MW merchant transmission line in northern New Jersey that connects to NYISO on Staten Island. PJM has assigned it $100 million as its share of the project costs. “Linden VFT strongly believes it will not receive benefits from the projects [that] are roughly commensurate with the costs it is being asked to shoulder,” it wrote.

Linden also asked that if PJM determines the projects are still needed without the wheel, it should explore if there are less expensive alternatives.

– William Opalka

November 25, 2015

FERC Questions Fairness of Artificial Island Cost Allocation

By Suzanne Herel

FERC ruled Tuesday that PJM’s cost allocation schemes for the Artificial Island and Bergen-Linden Corridor transmission projects may be unjust and unreasonable, ordering a technical conference to probe the issue.

The technical conference will “explore both whether there is a definable category of reliability projects within PJM for which the solution-based DFAX [distribution factor] cost allocation method may not be just and reasonable, such as projects addressing reliability violations that are not related to flow on the planned transmission facility, and whether an alternative just and reasonable ex ante cost allocation method could be established for any such category of projects,” FERC said in its order (EL15-95).

Those wishing to participate may submit their requests by Dec. 18.

FERC accepted PJM’s Tariff changes involving the cost allocations but suspended them pending the outcome of the technical conference.

Under PJM’s rules, the cost of lower voltage facilities such as the Artificial Island and Bergen-Linden projects is computed up using the solution-based DFAX method. For regional facilities or “necessary lower voltage facilities,” only half of the cost is allocated by DFAX, with the remaining expense distributed on a region-wide, postage-stamp basis.

In the case of the Bergen-Linden project, Consolidated Edison of New York and Linden VFT had complained to FERC that the DFAX method was inappropriate and assigned a disproportionate percentage of the cost to Linden, which would receive “negligible benefits.” (See Con Ed Rebuffed Again on NJ Cost Allocation Dispute.)

Similarly, state agencies representing consumers in Maryland and Delaware, along with Easton Utilities Commission, Old Dominion Electric Cooperative and Linden VFT, argued that it was unfair to bill those states’ customers for virtually all of the $146 million price tag of the Artificial Island project, designed to fix a stability issue at the Salem and Hope Creek nuclear plants in New Jersey.

In response to the complaint, PJM conceded that the cost allocation may “appear disproportionate” but said its hands were tied by rules proposed by transmission owners and approved by FERC. (See PJM: Artificial Island Cost Allocation Appears ‘Disproportionate.’)

The DFAX methodology generally identifies reasonable beneficiaries of reliability projects based on power flows, it said. The Artificial Island project, however, is a stability fix, in which power flow is not the derived benefit.

The $1.2 billion Bergen-Linden project intends to upgrade a short-circuit problem in the Public Service Electric and Gas transmission zone outside New York City. PJM assigned $629 million of the cost to Con Ed and $52 million to PSE&G.

Responding to the ruling, PJM said, “FERC has determined that overall, the current method of allocating the costs of transmission projects is just and reasonable. However, in certain instances, the allocations led to complaints that individual results were unjust and unreasonable.

“Therefore, PJM will be pleased to support the FERC’s process to explore alternative cost allocation methods for projects that may not fit into the current process.”

FERC’s order was welcomed by Delaware Gov. Jack Markell.

“This FERC decision is an important first step to protect Delawareans from a significant electric rate increase,” he said in a statement. “I want to thank the FERC for its review and very sensible conclusion that the costs of a project designed to maximize power production and improve reliability in New Jersey should not fall entirely on Delaware and Maryland consumers.”

November 25, 2015

Connecticut Regulators Poised to OK Iberdrola Acquisition of UIL

By William Opalka

Connecticut regulators released a draft decision Tuesday approving Iberdrola USA’s $3 billion acquisition of UIL Holdings, adding a requirement that UIL’s headquarters remain in the state indefinitely.

With its “proposed final decision,” the Connecticut Public Utilities Regulatory Authority appears poised to give final approval next month to the Spain-based conglomerate’s second try to acquire UIL. The companies withdrew their initial application in June when PURA indicated it was likely to deny it.

“The authority concludes that the applicants have met their burden of proof that the proposed transaction, as presently structured, is in the public interest,” PURA wrote in the draft. UIL is comprised of The United Illuminating electric distribution company and two natural gas distribution companies in Connecticut, and two natural gas distribution companies in Massachusetts.

The regulators required Iberdrola to amend its settlement agreement with the state Office of the Consumer Counsel to include a promise to keep UIL’s headquarters in Connecticut for as long as it owns it. The companies had committed to a minimum of seven years.

“The authority sees the applicants’ commitment to maintaining its headquarters in Connecticut as meaningful and an integral aspect of this approval. Having a physical presence in the state enables more effective local management of the day-to-day operations of Connecticut-based utilities,” PURA said.

Otherwise, the draft largely mirrors the settlement agreement, which was filed in September. The companies agreed to “ring-fencing” to protect the Connecticut operations from any financial risks from Iberdrola’s other domestic or international operations — addressing a concern that helped doom the initial filing. (See Iberdrola Refiles Acquisition Bid for UIL Holdings.)

PURA also required the companies to provide a more detailed post-merger plan on their commitment to hire 150 people in Connecticut, saying “the details of the hiring plan are weak at this time.”

The settlement provides $40 million in ratepayer credits to existing electric and gas customers; approximately $45.4 million in rate freezes and avoided costs related to pipeline upgrades and system hardening; and approximately $39 million in public benefits from environmental remediation, charitable contributions and customer disaster relief, the draft says.

The companies previously agreed to a consent order with the state’s Department of Energy and Environmental Protection that would allow the contaminated English Station site in New Haven to be cleaned up for reuse. (See Iberdrola, UIL Would Clean Up Site if Connecticut Acquisition Approved.) The draft reiterates that the estimated $30 million in cleanup costs will come from shareholders and not ratepayers.

Parties to the PURA proceeding have until Dec. 1 to submit written comments on the proposed decision. The PURA commissioners are scheduled to hear oral arguments on the case on Dec. 3 and plan to render a final ruling on Dec. 9.

Iberdrola said last week it plans to change its U.S. holding company’s name to Avangrid following the UIL merger, but the names of the local distribution companies, including New Haven-based United Illuminating, would not change.

November 24, 2015

Ontario: Clean — and Expensive

Ontario’s Independent Electricity System Operator serves a population of 13.8 million, almost 40% of Canada’s total population, making it nearly equivalent in population and peak demand to ISO-NE.

After peaking about a decade ago at almost 160 TWh, Ontario’s annual electricity use has dropped to 140 TWh — equivalent to that in 1990 — as growth has been offset by conservation, distributed generation and a decline in the pulp and paper industry. Loads are not expected to rise until 2028.

Nuclear power, now 60% of the province’s generation output, is expected to drop to 40% by 2025 following the retirement of the 3,252-MW Pickering plant. Two other nuclear plants with a combined 8,400 MW of capacity, Bruce and Darlington, are scheduled to be refurbished from 2016 to 2032.

Because of the lost nuclear output, the province will need to add as much as 3,000 MW of capacity between 2021 and 2032.

Prices

As in New England, prices are relatively high, and that has prompted frequent interventions from government.

Sergio Marchi, president of the Canadian Electricity Association, lamented that Canada’s electric rates are much more politicized than in Europe. “Electric rates, rightly or wrongly, have become a go-to tool to clobber the incumbent government.”

“I’m really surprised that Ontario ratepayers aren’t up in arms with pitchforks and the like,” said Jason Chee-Aloy, a consultant and former director of generation procurement at the Ontario Power Authority. “I think that is going to be an issue in the next election because we’ve baked in a lot of these costs.”

Jasmine Bertovic, vice president and general manager for eastern energy at TransCanada, said opening the market to more imports would provide price discipline.

The province is a net exporter with Michigan (46%) and New York (39%) its biggest export markets. About 85% of its imported power comes from Quebec.

“When you tie yourself to another jurisdiction and now you’re competing beyond Ontario … it is another check on your market. … It can’t be a check valve. It has to be open seams, open import-exports.”

Cap and Trade

Canada’s electricity system is among the cleanest in the world, says Marchi, noting that 80% of its generation does not emit greenhouse gases. That compares, he said, with Germany (41%), the U.S. (31%) and Japan (15%).

In 2017, Ontario plans to begin trading emissions through cap-and-trade auctions. The first auction will be for the province only, but Ontario plans to link its prices to those of California and Quebec, which already trade allowances. The province’s goal is to reduce CO₂to 15% below 1990 levels by 2020.

— Rich Heidorn Jr.

November 24, 2015January 30, 2024

Ontario Grid Looks Like the Past — and the Future — of the US

By Rich Heidorn Jr.

TORONTO — On April 8, 2014, the Thunder Bay Generating Station belched out the last kilowatt of coal-fired electricity in Ontario, a signature achievement for Canada’s most populous province. “The single largest climate change initiative in North America,” the Ontario Power Authority boasted.

Ontario’s carbon emissions have dropped by almost 90% over the last decade as it eliminated coal. Ontario Power Generation added silos to convert its Atikokan Generating Station (background image) from coal to wood pellets. The company, Ontario’s largest power producer, produced a quarter of its electricity from coal as recently as 2003.

While the province is far ahead of its U.S. counterparts in reducing its CO₂emissions, it is in other ways trying to catch up to the U.S. Provincial and local governments own most of the generation, and most of the non-government generation is under long-term contracts. Hourly prices are set province-wide with no locational pricing. It began regional planning in 2013 and is only now considering a capacity market.

It was against this backdrop that about 650 industry participants gathered here last week for the Association of Power Producers of Ontario’s (APPrO) 27th Annual Canadian Power Conference & Networking Centre.

Many of the discussions would be familiar to those in the U.S.: flat load growth; the threat and promise of distributed generation and storage; the need to improve coordination between generators and gas pipelines; and concern over the future of an aging nuclear fleet.

Speakers at the conference included Dan Dolan, president of the New England Power Generators Association, and Gavin Donohue, president of the Independent Power Producers of New York, who commiserated with their Canadian counterparts over what they view as government interference in the markets.

But “New York and New England don’t have as much political intervention in picking winners and losers” as Ontario, said Jason Chee-Aloy, former director of generation procurement at the Ontario Power Authority.

Like Moths to Light

Evan Bahry, executive director of the Independent Power Producers Society of Alberta, said the result has been “cross-threaded policies.” Government has “this reflexive instinct to jump in and solve it for us,” he said. “They can’t help themselves. They’re attracted like moths to light.”

Several speakers lamented the fact that Canada lacks FERC and the Federal Power Act to clearly establish independent regulatory control over the sector and limit tinkering by elected officials.

APPrO Executive Director Jake Brooks says Canada’s electric industry is operating under a fragmented governance structure, with each province and territory, as well as the federal government, having its own energy legislation, its own energy ministry and its own energy regulator. As a result, he said in an editorial, “many viable projects never get financed because benefits are viewed myopically by each level of government without considering the gains being delivered to other levels of government.”

Capacity Market

The shortcomings are evident, speakers said, in policymakers’ consideration of a capacity market.

The Independent Electric System Operator (IESO), which has managed the grid since 1999, merged in January with the Ontario Power Authority, combining short-term and long-term resource planning for the province, whose electric market is about the size of ISO-NE. (See related story, Ontario: Clean — and Expensive.)

IESO inherited from the OPA fixed term contracts for about 19 GW of operating capacity for a region whose peak is less than 22 GW.

“Ontario is in an awkward spot,” said Linda Bertoldi, chair of the National Electricity Markets Group for law firm Borden Ladner Gervais. “[It’s] so heavily contracted [that] there’s little liquidity for a capacity market.”

“It’s really hard to be half pregnant on markets,” agreed Dolan. “If you do go down the path of capacity markets, you pretty much have to be all in. I don’t think you can say we’re only going to do it for this portion and not that portion.”

APPrO President David Butters said the province must address its governance issues if it is to adopt a capacity market. “How do we limit the ability of government to interfere in markets and to undermine the value of investments and contracts?” he asked. “That is the really big issue to me.”

Jasmine Bertovic, vice president and general manager for eastern energy at TransCanada, said the market’s current price signals are muted. And he’s not sure the changes being contemplated will be improvements.

“I’m worried that we may be introducing new signals that just add complexity without changing behavior, or have some purpose or some cost-benefit.”

He likened “bolt-ons” to the market to the “Whac-a-Mole” arcade game, with unintended consequences popping up. “These things have to be part of an overall framework,” he said.

Regarding a move to LMPs, he said: “Every little piece that’s connected to the grid has a separate price. It’s all nice to know that information, but if it’s not leading to improved transmission infrastructure or transmission does not participate in locational pricing, then why have that signal?”

Going to War Without a Target

Adam White, president of the Association of Major Power Consumers, also expressed reservations.

“Planning without a vision is like going to war without a target. What are we planning for? Market evolution is inexorable. It’s inevitable. Evolution is all the [stuff] that happens over time. But that’s not a plan. That’s not a vision for the future we want,” he said. “The Ontario market’s evolved quite a lot in the years since it’s been opened … but it’s still sort of a 1.0 version of the market.”

Version 2.0, he said, needs to acknowledge the shift to distributed energy systems.

JoAnne Butler, IESO vice president for market development, also cited the growth of distributed generation, along with solar power and storage, as drivers for the future. “The change we’re going to see in the next 10 years — going off coal pales in comparison,” she said.

The Ontario Electric Board, which regulates prices for small consumers, last week issued a Regulated Price Plan Roadmap that seeks to address those changes, calling for phasing in fixed distribution rates and decoupling for commercial and industrial customers.

“I’m confident that regulation won’t disappear, at least not in the short term,” said Rosemarie Leclair, chairman of the board. “But what we regulate and how we regulate will change. It has to.”

Bill 135

Some worry, however, that the OEB’s efforts to pursue its plan will be undermined by a bill the provincial legislature is considering.

George Vegh, former general counsel of the OEB, said Bill 135 would effectively give the province’s minister of energy IESO’s responsibility for electricity planning and procurement and the OEB’s authority for approving transmission. It also would extend the government’s procurement authority to energy storage and transmission.

“The net result of Bill 135 is therefore to ensure that the main energy institutions — the IESO and the OEB — are focused almost exclusively on implementing government plans and directives,” Vegh, now head of the Toronto energy regulation practice for law firm McCarthy Tétrault, wrote in a commentary. “The government has always been steering the direction of energy policy. It is now rowing as well: It is in direct control of every policy instrument available.”

Chee-Aloy, now a consultant with energy management firm Power Advisory, said the government is “doubling down” on its “command and control” oversight.

“Of course the government could say: ‘IESO, use a capacity market to procure those resources.’ But it’s kind of hard for a market to work as a market when you don’t have a lot of participants competing to build or to upgrade those resources,” he said.

IESO CEO Bruce Campbell said he disagreed with those who think the bill will constrain the ISO. “I’d like to argue the exact opposite — that with the directing authority being taken away from the minister and going up to the cabinet level, it will inevitably be a much more policy-oriented framework. I view us as having a great future within that framework in implementing policy in the best possible way.”

Jack Burkom, senior vice president of commercial development for Brookfield Energy Marketing, said that while he hopes for “more significant market price signals … we’ll also continue to use contracting mechanisms.”

He urged IESO to act more quickly.

“The IESO shouldn’t wait for a trigger. The trigger is here. There’s existing infrastructure in the province that should be given the opportunity to compete to provide services when they come off of contact,” he said. “As JoAnne [Butler] said, ‘it’s not either/or.’ We’re not going to turn into PJM overnight.”

November 24, 2015

FirstEnergy Ordered to Report ODEC Load Data

FERC upheld an administrative law judge decision that FirstEnergy is responsible for reporting data related to Old Dominion Electric Cooperative load in Virginia (ER12-2399).

The dispute stems from ODEC’s purchase of the distribution facilities and service territory of Potomac Edison, a FirstEnergy subsidiary, in Virginia. FirstEnergy argued that it was no longer responsible for calculating and reporting data for Potomac Edison, such as total hourly energy obligation, peak load contribution and network service peak load, to PJM.

FERC, however, affirmed the judge’s finding that because ODEC did not purchase the transmission facilities of Potomac Edison, FirstEnergy was still responsible for reporting the data in the entire Allegheny Power System zone, which encompasses parts of Pennsylvania, Maryland, West Virginia and Virginia. “As the initial decision found, requiring ODEC to perform the metrics would result in unduly discriminatory treatment of ODEC when compared to other wholesale LSEs in the APS zone,” the commission said.

–Michael Brooks

November 24, 2015

Mass. Attorney General’s Study: Pipelines Unneeded

By William Opalka

Massachusetts Attorney General Maura Healey on Wednesday released a study that said additional interstate natural gas pipelines are not needed to guarantee the reliability of New England’s electric grid over the next 15 years.

Instead, reliance on demand response and energy efficiency would protect consumers and also help the region reach its greenhouse gas emissions goals, according to the study.

“This study demonstrates that we do not need increased gas capacity to meet electric reliability needs, and that electric ratepayers shouldn’t foot the bill for additional pipelines. This study demonstrates that a much more cost-effective solution is to embrace energy efficiency and demand response programs that protect ratepayers and significantly reduce greenhouse gas emissions,” Healey said in a statement.

The study by the Analysis Group runs counter to the view of many regional officials that massive pipeline construction is needed as New England becomes more reliant on natural gas for power generation. In October, the Massachusetts Department of Public Utilities ruled that electric distribution companies can sign contracts for natural gas capacity and pass the costs on to electric ratepayers if the companies can prove that they will save ratepayers money. (See Massachusetts Regulators Endorse Pipeline Contracts.)

The authors said the study used “extremely conservative assumptions,” including applying winter conditions from 2004, one of the coldest years in two decades.

“Under the base case analysis, power system reliability can and will be maintained over time, with or without additional new interstate natural gas pipeline capacity,” the report said.

The study concedes additional natural gas infrastructure would lower electricity prices, but with a steep cost. “Investment in new interstate pipeline capacity generates significant wholesale electricity price benefits but would require up-front and long-term ratepayer commitments,” it said.

Analysts also considered the impact of new transmission needed to import Canadian hydropower, the most expensive option for ratepayers, it indicated.

The study accounted for the recent announcement that the Pilgrim nuclear power plant would close no later than June 2019, resulting in the loss of 680 MW of non-GHG emitting power.

November 24, 2015

FERC Briefs – MISO

Northern States Power’s Wisconsin ratepayers will be billed for 15% of the nearly $79 million spent on the now-abandoned Prairie Island nuclear project under an agreement approved by FERC last week. The 15% share, totaling $12 million, reflects the most recent coincident peak demand ratios approved for the Wisconsin utility’s interchange agreement with Northern States Power Minnesota, FERC said (ER15-698).

Northern States had planned to expand the capacity of two existing units at the Prairie Island site. Northern States said the shrinking cost of alternative energy and delays in obtaining Nuclear Regulatory Commission approvals “reduced [the project’s expected benefits] to an extent that the project was no longer economical.”

The Minnesota Public Service Commission, which granted a certificate of need for the project in 2009, approved its cancellation in February 2013. In late August, the commission found that Northern States acted in good faith in the development and cancellation of the project.

No Rehearing in MISO Wind Interconnection Study Matter

FERC denied MISO’s request for rehearing of an order that found that the RTO violated its obligations to an interconnection customer regarding network upgrade studies. The commission said that MISO had not alleged any specific errors in a 2013 order that found the RTO had improperly concluded that the Jeffers South wind generation facility was obligated to fund construction of a $43 million 161-kV line from Dotson to New Ulm, Minn. (EL10-86-004).

Jeffers South said MISO neglected its duty to identify the least expensive network upgrade option. In its rehearing request, MISO argued that the study process was valid because Summit Wind, Jeffers South’s predecessor, had agreed to it.

In last week’s order, FERC told MISO to permit Jeffers South to name a new point of interconnection at Heron Lake. “We expect all of the parties to endeavor to perform their obligations pursuant to the Tariff and in a cooperative manner going forward,” FERC said.

No Time Value Refunds in Michigan Contract Dispute

FERC reversed an administrative law judge ruling requiring the payment of time value refunds in a dispute between the 1,633-MW Midland Cogeneration plant and Consumers Energy (ER10-2156). The dispute concerned the plant’s interconnection agreement with Consumers and a second agreement in which Consumers bought most of the output of the plant. Consumers later sold its transmission to Michigan Electric Transmission. “If Consumers Energy and Michigan Electric were required to refund the time value of payments received, or to be received, from Midland for services performed prior to acceptance of the facilities agreement, they would necessarily have operated at a loss, contrary to long established commission policy,” the commission said.

FERC Rejects Louisiana Rehearing Bids on Entergy Depreciation

FERC rejected two rehearing requests by the Louisiana Public Service Commission in cases involving Entergy’s depreciation rates:

FERC denied the Louisiana PSC’s request to reconsider a previous order that affirmed an administrative law judge’s initial determinations approving depreciation rates for Entergy Arkansas (ER10-2001). The Louisiana regulators had challenged the judge’s decisions regarding the admissibility of witness testimony.
FERC also denied rehearing of the Louisiana PSC’s complaint that the state could not use state-determined depreciation inputs in the bandwidth formula used to equalize production costs among Entergy’s operating companies (EL10-55). The order affirmed FERC’s finding that the PSC had not shown the commission’s use of the depreciation rates was unjust or unreasonable.

– Amanda Durish Cook and Tom Kleckner

November 24, 2015

Cuomo: 50% Renewables by 2030, Keep Nukes Going

By William Opalka

Nuclear power plant owners are welcoming reports that Gov. Andrew Cuomo wants state regulators to mandate that half of the state’s energy come from renewable energy sources by 2030 while creating incentives for nuclear to remain viable in the interim.

Getting 50% of its energy from wind, solar and other renewable resources by 2030 is currently a state goal, but it lacks the force of an order from the New York Public Service Commission. The governor is also seeking a way to keep the R.E. Ginna and James A. Fitzpatrick nuclear plants on Lake Ontario in the state’s fleet to help New York meet the federal Clean Power Plan. The hope for those in the nuclear industry is that these combined efforts will mean their plants will serve as the primary source for low-carbon power in the near term.

The New York Times first reported the proposed mandate on Sunday. A source told RTO Insider the details could be released in the governor’s annual State of the State address in January, with final action by the PSC hoped for about six months later.

“If true, this new policy would be a welcome and constructive step that promotes the transition to clean energy,” said David Tillman, a spokesman for Ginna’s owner, Exelon. “We believe that with the governor’s leadership, a state clean energy standard can be implemented that would recognize the zero-carbon, economic and reliability attributes of nuclear energy while maintaining New York’s focus on renewable energy and efficiency.”

Ginna is scheduled to close in 2017 at the conclusion of a reliability support services agreement that is now pending before FERC and the PSC. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)

A spokesman for FitzPatrick could not be reached for comment. (See Entergy Closing FitzPatrick Nuclear Plant in New York.)

Advocates from different sectors of the power industry were generally pleased by the news.

“The clean energy standard as proposed by the governor is an important and forward-looking approach that will help attract investment in renewables and address market problems that need fixing,” Gavin Donohue, president of the Independent Power Producers of New York said in a statement. “The alternative is the potential loss of nuclear power in New York due to currently low natural gas prices — a scenario that would be catastrophic for both ratepayers and the environment.”

Anne Reynolds, executive director of the Alliance for Clean Energy New York, supported the plan but is less sanguine about the nuclear component. “Gov. Cuomo’s reported directive to the Public Service Commission to mandate the 50% renewables by 2030 goal is great, encouraging news for the renewable energy industry,” she said. “Nuclear power, while emitting less carbon than coal or oil, nevertheless does not meet the definition of renewable technologies. Supporting uneconomic and aging power plants should not be the long-term solution, but should be a transition to a renewable energy future.”

Iberdrola USA, whose Rochester Gas & Electric unit negotiated the RSSA with Exelon, would not comment on the purported extension of Ginna’s operation. “We’re working to complete the Ginna Reliability Transmission Alternative to meet our requirement, anticipating it will be completed in mid-2017 when the plant is supposed to be retired,” spokesman John Carroll said.

GRTA is intended to provide access to other generation sources to supply the Rochester area and render Ginna unnecessary.

In contrast to the lifeline Cuomo is offering to the upstate nuclear units, the governor has repeatedly called for the closure of Entergy’s Indian Point plant, citing concerns over the safety of New York City, 30 miles south.

The PSC was supposed to take action on several clean energy orders at its meeting on Thursday, including one on a retail renewable portfolio standard, but the items were pulled from its agenda at the last minute.

“Because these programs are so important, we wanted to make sure we are examining all the issues. It is absolutely our intent to pursue these programs. Nobody should read anything into this, other than they are complex matters for our state energy policy and it’s important that we get it right,” commission chair Audrey Zibelman said to open the meeting.

November 24, 2015

FERC Rebuffs MISO’s Push for Mandatory Capacity Auction

By Amanda Durish Cook

FERC last week reaffirmed its rejection of MISO’s proposal to institute a mandatory capacity market, denying rehearing of its 2012 order on the issue.

In June 2012, FERC conditionally approved revisions to improve deliverability of capacity resources in the MISO footprint, but the commission rejected MISO’s request that the Planning Resource Auction become obligatory and subject to a minimum offer price rule. More than 15 entities, including MISO’s Independent Market Monitor, requested a rehearing.

Capacity suppliers complained that MISO’s capacity construct is discriminatory because it requires sellers, but not buyers, to participate. Others took issue with MISO’s use of a vertical demand curve and two-month forward period before the auction.

In its order last week, FERC again rejected MISO’s proposed mandatory auction for resource deficiencies and upheld the use of a vertical demand curve (ER11-4081-001).

Load-serving entities, “as buyers of resources, must obtain sufficient resources to meet their planning resource margin requirement or pay a significant penalty of 2.748 times [the cost of new entry]. We do not consider this requirement and its associated penalty to be a ‘free pass,’ as characterized by capacity suppliers, or that buyers have no incentive to purchase capacity, as NRG [Energy] claims,” FERC ruled.

It also said MISO had not met its burden of proving its proposal was just and reasonable.

The commission also denied rehearing of the decision to reject MISO’s proposed minimum offer price rule, again concluding that customers “lacked the incentive to suppress auction prices in the MISO capacity market.” On the other hand, FERC reiterated its defense of MISO’s fixed resource adequacy plan, saying LSEs do not “have an incentive to exercise market power in the MISO region” and market manipulation is “unlikely.”

Daily Peak Load

The rehearing request by the Coalition of MISO Transmission Customers, a group of industrial customers, challenged MISO’s use of daily peak load, a method FERC directed the RTO to use three years ago, replacing the grid operator’s proposed daily pro rata method.

“We find that the use of the daily peak load contribution methodology until sufficient data exists to use the peak load contribution methodology does not represent undue discrimination against LSEs in retail choice states. … Requiring MISO to use available historical information, as Coalition of MISO Customers recommend, does nothing to resolve this data gap because MISO cannot force electric distribution companies to provide the necessary data,” FERC decided.

To comply with the commission’s June 2012 ruling, MISO revised its Tariff language. FERC accepted the edits, conditionally approving MISO’s map of zonal boundaries that pinpoint major transmission constraints and local balancing authorities and instructing the RTO to remove a reference to a minimum offer price rule (ER11-4081-002).

In the same order, FERC responded to Illinois Commerce Commission’s concern that the Tariff could hinder state commissions’ responsibility for enforcing resource adequacy, saying it was beyond the scope of the compliance proceeding.

LaFleur: Room for Improvement

At FERC’s open meeting Thursday, Commissioner Cheryl LaFleur said she supported the order “because I believe, based on this record and in the context of the primarily vertically integrated MISO region, the resource adequacy construct that we have approved is just and reasonable.”

“I’ve often noted that we need to take account of legitimate regional differences and I think we’ve tried to do so in this order. But I do want to comment to say that a determination that a market construct is just and reasonable does not mean that it cannot be improved. I want to recognize that there are a lot of efforts underway in the MISO region to consider reforms to the adequacy construct and I very much encourage parties to stay engaged in those processes, and I’ll be continuing to follow them closely.”