Page 1496 – RTO Insider

December 8, 2015

MISO Proposes Two-Season Capacity Market

By Amanda Durish Cook

CARMEL, Ind. — Signaling a newfound sense of urgency, MISO officials last week proposed a switch to a two-season capacity market procurement and appointed a team to consider ways to retain merchant generators in Illinois.

Under a draft proposal outlined to stakeholders last week, MISO would obtain capacity based on a four-month summer season (June-September) and eight-month winter (October-May), with separate seasonal resource accreditations, reserve margins and capacity import/export limits.

“We do see the value in two seasons and providing resource adequacy in both summer and winter. This felt like a place that is justifiable,” Laura Rauch, ‎manager of resource adequacy coordination, told stakeholders at a two-day joint meeting of the Supply Adequacy Working Group and the Loss of Load Expectation Working Group.

Officials said the proposal was driven by concerns over the year-round availability of resources such as demand response and generation imports. The RTO, which sets its reserve margins based on a summer loss-of-load probability of one day in 10 years, was awakened to its winter reliability risk in the 2013–2014 season, when forced generation outages peaked at 22 GW, almost 50% above the expected 15 GW.

The two-season proposal, which retains the current June 1-May 31 planning year, appeared to be a compromise between those who favored a four-season procurement, including the Organization of MISO States and the Independent Market Monitor, others who wanted monthly auctions and those who favored the status quo. (See MISO Seasonal Procurement, Site Auctioning Proposals Face Opposition.)

Task Team

The two-day stakeholder meeting also resulted in the announcement of a SAWG “task team” to recommend ways to accommodate merchant generators in MISO Zone 4 in Illinois, which unlike most of the RTO, allows retail choice.

The move followed an Oct. 20 FERC technical conference and a Nov. 19 policy session of the Illinois Commerce Commission on the problems in Zone 4. (See MISO Stakeholder Process Under Scrutiny.)

The formation of the team came over the opposition of some stakeholders who said the RTO should delay action until after the ICC’s second session on the subject, scheduled for this Thursday.

But Jeff Bladen, MISO’s executive director of market design, told stakeholders Wednesday, “These issues are ripe whether we like it or not.

“If there was agreement on anything [at the Nov. 19 session], it was that Illinois is depending on MISO’s markets as the primary mechanism to ensure resource adequacy,” he said. “The process of asking for a task team was a dynamic one. It was a result of Illinois moving forward and describing that MISO needed to more proactively address the issue.”

Bill Booth, of the Mississippi Public Service Commission, asked if MISO will develop rules that would work for both retail choice states and traditionally regulated states.

“Our goal would be to find solutions that are tailored and meet the needs of the states like Illinois with retail choice, but at the same time, we need to ensure that we … meet the needs of non-retail states,” Bladen said.

He said MISO is not looking to change states’ planning processes. “I think what’s been identified in Illinois is a gap,” he said. “It is a very targeted, surgical matter that needs to be tackled.”

Illinois Senior Assistant Attorney General Susan Satter told stakeholders that the creation of a team could be “somewhat premature.”

“It sounds like Illinois has directed MISO to address this … I think there were several avenues that were being discussed and explored. So I think it needs to be kept within that perspective,” Satter said.

Kevin Murray, chair of MISO’s Advisory Committee, objected to the creation of a task team, arguing that stakeholders should have been given advance notice of a vote to create a group.

Supporters cited SAWG rules, which they said do not require a vote to form a task team. “This is a topic that pretty well suits the business for what a task team does,” said SAWG Chairman Brian Glover, markets compliance and policy analyst for Great River Energy.

Urgency Needed

Glover said he favored “reaching a productive end” instead of inaction and delays.

Marka Shaw, director of wholesale market development for Exelon, also called for urgency. “There are retirements occurring in southern Illinois,” she said. Dynegy cited a poorly designed capacity market in Illinois when it announced last month that it would close its 465-MW Wood River Power Station in 2016.

The task team is expected to have an approximate six-month lifespan and convene in time to deliver preliminary recommendations at the next SAWG meeting in January.

Shoulders Ignored?

Shaw was among several stakeholders who complained that the proposed two-season capacity structure ignores the spring and fall shoulder periods, when peaks are much lower.

Shaw said a planning auction modeled after two seasons isn’t feasible in states with deregulated markets. “What MISO’s doing here just won’t work for what we’re doing in Illinois. We’re going to be requesting something different,” she said.

The draft plan says MISO’s current structure does “not explicitly ensure transparency or sufficiency of resource adequacy throughout the year. In addition, stakeholders expressed an interest in a less-than-annual requirement to account for the seasonal diversity, thus providing additional flexibility to meet load and reserve obligations.”

MISO noted that several other regions also have addressed concern about winter reliability, citing ISO-NE’s Pay-for-Performance and PJM’s Capacity Performance programs.

Only New York currently uses separate summer and winter capacity periods, although Ontario is considering such a move, the report says. (See Ontario Grid Looks Like the Past — and the Future — of the US.)

MISO’s recommendation calls for retaining the system-wide summer reserve margin (0.1 day/year LOLE risk) while setting the winter requirement based on a “negligible” one day in 100 years or 0.01 day/year LOLE.

The same targets would apply for local resource zones “if the zone’s base model indicates zero LOLE risk in the winter season. If a zone’s base model annual LOLE risk results in winter LOLE risk, then the annual LOLE will be driven to 0.1 day/year LOLE risk without deterministically dictating where the LOLE risk is distributed.” The analysis would include seasonal capacity import and export limits.

MISO said it was unaware of other regions using season-specific reserve margin requirements.

The RTO would accredit resources based on continued use of the single real power test but using seasonal interconnection service for capacity accreditation, and with seasonal ratings for load modifying resources and intermittent generation. It also would reflect outages through a total capacity availability rate (“seasonal EORp”).

Stakeholder feedback on the draft proposals is due Dec. 17. Design review of the constructs will begin in February with MISO unveiling proposed Tariff language. Tariff filings with FERC are targeted for March.

[Editor’s Note: A prior version of this article contained an incorrect link to the draft document mentioned in paragraph 2.]

December 1, 2015

FirstEnergy, PUCO Staff Reach Settlement on PPA for Ohio Merchant Plants

By Ted Caddell

FirstEnergy said Tuesday it has reached a proposed settlement with Public Utilities Commission of Ohio staff that would provide guaranteed income for eight years for two of the company’s merchant generating stations and for the portion the company owns of two other plants.

FirstEnergy has said that it needs the income guarantees, in the form of power purchase agreements for its Davis-Besse Nuclear Power Station, the W.H. Sammis coal-fired plant and its share of Ohio Valley Electric Corp.’s generation output, to keep them profitable. Without the guarantees, it said, it might have to retire the plants, threatening system reliability.

Sixteen parties, including PUCO staff, a low-income advocacy group, Ohio Partners for Affordable Energy and other civic groups, signed on to the proposed settlement filed with the commission Tuesday (14-1297-EL-SSO).

But several other organizations, including the Office of the Ohio Consumers’ Counsel (OCC), have refused to sign on to what they decried as a “bailout” and joined in a motion to reopen the record.

“PUCO’s staff decision to move forward with a backroom deal to bailout FirstEnergy’s aging power plants is insulting to Ohio utility customers,” said Daniel Sawmiller of the Sierra Club of Ohio, which dropped out of the settlement negotiations in protest last week.

FirstEnergy’s first proposal, which PUCO staff rejected earlier this fall, called for income guarantees for 15 years. This proposal seeks income guarantees for eight years.

According to the proposal, ratepayers would pay FirstEnergy if its generators were not profitable based on their capacity and energy sales in the competitive market. The company contends that in the long run, the plants will be able to produce power more cheaply, and any income over cost would be returned to ratepayers.

It estimates that under its new proposal, residential ratepayers would pay an extra $3.25 to $3.50 a month during the first year. Over the eight years of the plan, the company says, it will produce savings of about $560 million.

“The settlement filed by FirstEnergy’s Ohio utilities — Ohio Edison, The Illuminating Company and Toledo Edison — outlines ambitious steps to safeguard customers against retail price increases in future years, deploy new energy efficiency programs, and provide a clear path to a cleaner energy future by reducing carbon emissions,” the company said in a statement.

The proposal also includes a “goal” to reduce carbon dioxide emissions from FirstEnergy’s generating fleet by at least 90% below 2005 levels by 2045 regardless of whether EPA’s Clean Power Plan survives court challenges.

It also promises $102 million in assistance to low-income customers and energy efficiency programs.

Sawmiller blasted the proposed settlement.

“Over months of public hearings, there was no credible evidence presented that this bailout furthers any public interest. The shortened timeline has an even more negative impact, front-loading the handout to FirstEnergy and its shareholders while saddling customers with a cost that could run into billions. This deal provides no path for transitioning to a cleaner, more affordable clean energy economy and should be flatly denied by the PUCO.”

The Consumers’ Counsel and the Northeast Ohio Public Energy Council (NOPEC) also opposed the agreement.

“OCC and NOPEC’s expert preliminarily projects that the new PPA proposal will cost consumers approximately $3.9 billion,” reads a joint statement from the two groups. “And the settlement’s impact on Ohioans’ electric bills does not end with the PPA charges: the settlement contains a virtual holiday wish list of favorable ratemaking for FirstEnergy.”

Chuck Keiper, NOPEC executive director, noted that some of those that signed on to the agreement would receive payments from FirstEnergy in exchange.

“The use of financial inducements to obtain buy-in of some intervenors for pennies on the dollar compared to the billions we project the utility will collect from other customers is, frankly, a terrible way to develop public policy,” he said. “It is our sincere hope that the PUCO commissioners will do the right thing and reject this settlement,” he said.

Consumers’ Counsel Bruce Weston also was critical of the settlement agreement. “Consumers should not be charged a penny more than the cost of power in the market,” Weston said in a statement. “FirstEnergy’s proposal comes at a time when Ohioans already are paying more for electricity, on average, than consumers in 32 other states,” he said.

The PJM Power Providers Group (P3) and the Electric Power Supply Association also criticized the deal, with P3 President Glen Thomas saying PUCO staff’s “about face” represents “corporate welfare at its worst.”

“If FirstEnergy is so sure this is a good deal for consumers, they should make public the information underlying its claims and provide iron clad corporate guarantees that consumers will actually receive the promised net benefits,” said EPSA President John Shelk.

Although PUCO staff approved the settlement, it still needs approval of the commission. FirstEnergy said it expects the commission to hold hearings on the proposed settlement early next year.

But it may face tough going.

Earlier this year PUCO’s new director, Andre Porter, criticized FirstEnergy and American Electric Power, which has a similar proposal before the commission, for raising the threat that reliability will suffer without income guarantees for their generation. “Let’s stop attempting to scare Ohioans,” Porter said at the time. “We’re going to continue to have reliable power” with or without guarantees, he said.

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