Page 1451 – RTO Insider

May 9, 2016

Atlantic Bridge Environmental Assessment Released

By William Opalka

FERC last week released an environmental assessment of the Atlantic Bridge natural gas pipeline expansion project, finding “no significant impact” (CP16-9).

Atlantic Bridge Project Map Source: Spectra Energy (environmental assessment, ferc) — Atlantic Bridge Project Map *Source: Spectra Energy*

Spectra Energy has proposed expanding its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems’ capacity by 132,700 dekatherms/day to serve the New England and Canadian natural gas markets.

Six miles of existing pipeline in New York and Connecticut would be widened from 26 inches to 42 inches. A 7,700-horsepower compressor station would be built in Massachusetts, along with numerous infrastructure improvements.

The project has a proposed in-service date of November 2017. Public comment on the project is open until June 1.

While only a fraction of the size of other natural gas projects seeking to tap into abundant shale gas from Pennsylvania, the project has provoked opposition from climate change activists and landowners fearing encroachments on their properties. (See Hearing on Algonquin Pipeline Expansion Highlights Local, National Issues.)

The developers have commitments from New England gas distribution companies and manufacturers for 40% of the additional capacity, with the other 60% committed to commercial and industrial customers in the Canadian Maritime provinces. The developers say none of the gas is destined for the LNG export terminals proposed in Maine or the Maritimes, a major source of controversy for any infrastructure expansions in New England.

“The additional supply from Atlantic Bridge will help enhance the reliability of energy throughout the region and generate savings for homeowners, businesses and manufacturers,” according to Spectra.

FERC said its review did not find significant issues that rise to the level of requiring a more extensive environmental impact statement.

May 9, 2016

PJM Study Defends Markets, Warns State Policies can Harm Competition

By Suzanne Herel

A PJM analysis released last week concludes that the RTO’s markets are efficiently managing the entry and exit of capacity resources but warns their efforts could be hamstrung by policies to protect social, economic or political interests.

“Realizing the ‘investment efficiency’ advantages of PJM’s markets can require policymakers to accept tough choices because efficient market outcomes may inflict harm to other policy objectives,” said the 45-page report, titled “Resource Investment in Competitive Markets.”

“Policymakers must weigh these trade-offs, but understand that pursuing individual actions that ‘defeat’ efficient market outcomes will aggregate to a point they will altogether thwart effective operation of the market to the point it can no longer be relied upon to govern resource exit and entry and attract capital investment when needed,” it said.

Informed Decisions

Presenting the study in a conference call with the news media Friday, PJM General Counsel Vince Duane said, “It’s important to ensure that policymakers are making informed decisions when they decide to go with one approach at perhaps the expense of another.”

The report was commissioned by the Board of Managers last summer, following efforts by money-losing coal-fired generators in Ohio and nuclear generators in Illinois to win state-backed subsidies.

The Public Utilities Commission of Ohio is grappling with how to respond to a recent FERC order requiring federal review of power purchase agreements it granted to American Electric Power and FirstEnergy. (See related story, AEP, FirstEnergy Revise PPA Requests to Avoid FERC Review.)

Meanwhile, Exelon CEO Christopher Crane said in an earnings call on Friday that if Illinois legislators don’t step in and provide aid, it will decommission its money-losing Clinton and Quad Cities nuclear plants beginning next year. (See related story, Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)

Local Consequences

“There’s no question that the retirements of legacy generation can create disruptive effects to local economies, job loss, loss of tax revenues for local communities,” Duane said. “Our markets are not designed — and really shouldn’t be designed — to account for those kinds of policy interests. But nonetheless they have to work alongside programs that are intended to advance social and political, environmental issues.

“The message is … let’s acknowledge there are trade-offs from time to time. Those trade-offs could be minimized perhaps if externalities can be priced and then the market can more readily digest those policy choices. … But that’s not always possible.”

The analysis is composed of two parts. The first “examines how markets drive resource investment decisions and compares generation entry and exit outcomes under both market and traditionally regulated constructs.”

The second section looked at “subsidies, regulations, policies and other requirements that may either reward or disadvantage generating resources and how such actions affect the performance of markets.”

On the first subject, researchers concluded that competitive markets are efficient when left alone to manage resource entry and exit, and that they do this on a more cost-effective basis for consumers than under a regulated model.

Bearing the Risk

At the same time that PJM is encouraging cost-effective new generation, it is avoiding investment in risky, capital-intense, experimental utility-scale projects such as Southern Co.’s Kemper integrated gasification combined cycle project and the Vogtle nuclear plant’s Units 3 and 4. The projects, backed by state and federal subsidies in traditional, rate-regulated states, are years behind schedule and billions over budget.

“Over the long term, markets can misallocate capital — we’re not saying it’s just a problem with regulators,” Duane said. “But markets also move very quickly” to correct their mistakes.

“We are operating … in very uncertain times in this industry right now,” he continued. “There’s a lot of concern about the disruption of the business model. Risk has a price, has a cost. In market environments like PJM’s, that risk is owned by the merchant investor. … Regulated entry is underwritten by the consumer/ratepayer.”

On a risk-adjusted basis, he said, “it seemed that new combined cycle entry was coming in to PJM on highly favorable terms relative to regulated models. Consumers of merchant generation in PJM were getting a pretty good deal.”

That, he said, raised two questions: Were regulated markets allowing returns on equity that were too high compared with what an investor would require? And on the other hand, was PJM providing sufficient revenues to support investments?

Given that 140,000 MW of natural gas capacity has entered the project queue since 2010, he said, “It’s hard to imagine that sophisticated investors are deploying their capital in PJM in that manner if they’re not expecting adequate returns.”

Resources Not Retiring Prematurely

The study also helps PJM rebut allegations that it is prematurely retiring resources that still have a useful life, Duane said.

“We were able to conclude with a high degree of confidence that both regulated models and PJM are doing a pretty good job in exiting coal resources that are really no longer competitive. But we were unable to see any meaningful statistical distinction that we were more aggressive or unduly aggressive or starving resources that still had an economic life but were unable, based on the market design, to earn the revenues that they should to support their operations,” he said.

PJM’s Tom Zadlo, who joined Duane on the media call, said PJM’s markets could accommodate a cap-and-trade system that would improve the finances of nuclear plants. “At a very simple level, if it’s something you can put a price on, it’s something that the market can then optimize for,” he said.

But the study did not make recommendations for how policy objectives can be designed in ways that don’t thwart market economics. “We leave that for another day,” Duane said.

May 9, 2016

NRC: Staff Must Reanalyze Indian Point Accident Impacts

By William Opalka

The Nuclear Regulatory Commission last week ordered its staff to redo an accident analysis for the Indian Point nuclear power plant in New York, ruling the original study used incorrect parameters and underestimated the economic impacts of a severe accident (50-247-LR, 50-286-LR).

In early 2014, state Attorney General Eric T. Schneiderman protested a ruling by the commission’s Atomic Safety and Licensing Board approving Entergy’s severe accident mitigation alternatives (SAMA) analysis as part of the company’s application for a 20-year license renewal of Indian Point Units 2 and 3. Both units have been operating under extensions granted by the commission after their licenses expired.

Schneiderman challenged the analysis on several key findings, with the commission siding with his contention that cleanup costs and other economic impacts were underestimated.

Indian Point Source NRC — Indian Point Nuclear Plant *Source: NRC*

“While typically we decline to second-guess the board on its fact-specific conclusions, here the decision contains obvious material factual errors and could be misleading, warranting clarification,” the commission wrote.

In his challenge, Schneiderman said Entergy had relied on generic cost estimates for site cleanup and not a site-specific analysis, as required by the commission. Indian Point is about 40 miles from midtown Manhattan.

The commission agreed. “We find that the SAMA analysis and the board’s decision insufficiently address uncertainty in the Indian Point … inputs — uncertainty shown by New York to have a potential to affect the SAMA analysis cost-benefit conclusions,” it wrote. “We conclude … that the analysis should be buttressed by additional sensitivity analysis.”

“I am heartened that the NRC commissioners agreed with my office that Entergy and NRC staff have systematically undercounted the costs and impacts associated with severe reactor accidents at the Indian Point plant,” Schneiderman said in a statement.

“As part of the standard process for relicensing nuclear power plants, the NRC tasked Indian Point with assessing the economic consequences of the unlikely event of a serious accident,” plant spokesman Jerry Nappi said in a statement. “In our application to renew the plant’s license, we used a model the NRC established for the entire nuclear power industry.”

The ruling comes as New York investigates the plants for several incidents, including a leak of radioactive water. (See NRC: No Further Leakage at Indian Point.)

The “decision by the NRC commissioners to reverse an earlier administrative ruling, and to require a re-examination of the impacts caused by severe accidents at Indian Point and potential upgrades, reaffirms our long-standing position that the aging nuclear power plant needs to be retired,” Gov. Andrew Cuomo, who has frequently criticized the plant, said in a statement.

May 9, 2016

Federal Briefs

The Nuclear Regulatory Commission has determined that the Yucca Mountain nuclear waste repository project in Nevada, if it were built, would have a small environmental impact. The commission continued working on the environmental impact statement even after the Obama administration shelved the project, following a ruling by the D.C. Circuit Court of Appeals that said NRC must consider the project in accordance with a 1987 law.

“The NRC staff concludes that the estimated radiological doses are small because they are a small fraction of the background radiation dose … and much less than the NRC annual dose standards for a Yucca Mountain repository,” the commission’s report said.

Yucca Mountain advocates hope the final environmental report could help fuel a resurgence of support for the moribund project. “The big-picture take on this is that it is yet another independent expert study that has found the proposed repository to be safe and environmentally sound,” the Nuclear Energy Institute’s nuclear expert Rod McCullum said.

More: POWER Magazine

Kemper ‘Accounting Matters’ Spur Probe by SEC

The Securities and Exchange Commission has opened an investigation into the cost and disclosure timeline of Southern Co.’s $6.7 billion Kemper coal-gasification plant in Mississippi.

The commission is focusing on “accounting matters, disclosure controls and procedures, and internal controls over financial reporting,” Southern reported in regulatory filing late last week. Though stock prices dipped the day after the filing’s release, Southern does not “expect the investigation to have a material impact on the financial statements of either Southern Co. or Mississippi Power,” stated Tim Leljedal, a Southern spokesman.

The company still plans to move ahead in the third quarter with switching the plant from natural gas, which it’s currently burning, to coal. The six-year project, which has come under fire for delays and cost overruns, would convert coal to gas to fuel electrical generators.

More: Bloomberg

Enviro Groups Sue EPA Over Fracking Waste Disposal

An alliance of environmental groups sued EPA last week to force stricter controls over the disposal of oil and natural gas drilling wastes.

The Environmental Integrity Project, which filed the suit with other groups, says the underground disposal of wastewater from fracking operations has been linked to an increase in earthquakes in Oklahoma and other states. The group said federal regulations covering disposal of liquid and solid wastes are 30 years old and need updating.

The groups also want EPA to ban dumping wastewater on fields and roads, where they say it could pollute drinking water.

More: The Washington Post

NARUC Names New Committee Chairs

National Association of Regulatory Utility Commissioners President Travis Kavulla appointed Nancy Lange as chair of the Energy Resources and Environment Committee and Richard S. Mroz as chair of the Critical Infrastructure Committee.

Lange is the vice chair of the Minnesota Public Utilities Commission, having been appointed in 2013. She is also on NARUC’s Washington Action Committee. Before being appointed to the PUC, she was manager of policy and engagement at the Center for Energy and Environment.

Mroz, president of the New Jersey Board of Public Utilities, is also on NARUC’s Nuclear Issues – Waste Disposal subcommittee. He is New Jersey’s representative to the Organization of PJM States Inc.

More: NARUC

DOE Puts up $25M For Solar Integration

The Energy Department announced it will distribute $25 million for projects designed to speed up the integration of solar power to the grid.

The department expects the funding, part of an existing program called Enabling Extreme Real-Time Integration of Solar Energy (ENERGISE), to result in 10 to 15 projects by software developers, utilities and solar companies.

“Our ongoing grid modernization work will help accelerate the widespread adoption of the clean energy resources that will define our low-carbon future,” said Lynne Orr, undersecretary for science and energy. “In doing so, we hope to drive down costs and encourage even more American homeowners and businesses to install solar systems.”

More: Department of Energy

TVA Set to Start New Reactor at Watts Bar

The Tennessee Valley Authority is ready to start Unit 2 at Watts Bar, the first new reactor to come online in the U.S. in two decades.

The reactor, which first went under construction in 1972, will add 1,411 MW to the TVA fleet. After repeated delays and construction suspensions, the unit is projected to achieve initial criticality later this month. It should be synchronized to the grid by this summer after more tests, according to TVA Chief Nuclear Officer Joe Grimes.

TVA says the final price tag for the unit is $4.7 billion.

More: Chattanooga Times Free Press

Plant Operators Plead Guilty to Emissions Tampering

The operators of an Agawam, Mass., power plant pleaded guilty in federal court to tampering with emissions equipment and submitting false information to regulators.

The Berkshire Power Plant and Power Plant Management Services agreed to pay $8.5 million in fines. The companies will be sentenced in August. The plant’s operations and maintenance manager, Frederick Baker, also pleaded guilty to charges of conspiracy to violate the Clean Air Act and tampering.

The case marks the first criminal prosecution for false statements made to FERC. The companies admitted they instructed employees to adjust an oxygen monitor to hide the amount of pollutants released.

More: The Boston Globe

Group Asks FERC to Dismiss Pipeline Application

The Pipeline Awareness Network for the Northeast filed a motion with FERC to dismiss Kinder Morgan’s application for the 412-mile Northeast Energy Direct pipeline that would run through Massachusetts and New Hampshire.

The company recently said it was suspending development work on the $3.3 billion project, citing a lack of commitments from utility customers and low natural gas prices. But the group asked FERC to dismiss the project “with prejudice” to ensure the project cannot be revived.

More: The Berkshire Eagle

May 9, 2016

New Transmission ROE Challenge Filed in ISO-NE

By William Opalka

Thirteen municipally owned electric systems in Massachusetts have asked FERC to reduce the return on equity earned by New England transmission owners (EL16-64), the fourth such challenge in ISO-NE since 2011.

The Eastern Massachusetts Consumer-Owned Systems, a group of municipal distribution companies that surround Boston, want the base ROE lowered from 10.57% to 8.67%. They also called for reducing the upper end of the zone of reasonableness, which serves as a cap on incentive adders, to no more than 11.24%, from the current 11.74%.

EMCOS said it brought the new complaint for several reasons, including the continuing decline in the cost of equity capital since FERC adopted a two-step discounted cash flow (DCF) model in Opinion 531, the 2014 ruling that resulted from the first of the four recent challenges (EL11-66-001). (See FERC Splits over ROE.)

They also cited “divergent commission rulings” since Opinion 531, noting administrative law judge findings of “anomalous” capital market conditions in cases involving MISO (EL14-12-002) and ISO-NE (EL14-86, EL13-33-002) and a finding that such conditions did not exist in one concerning Entergy Arkansas (ER13-1508, et. al). “This complaint offers an opportunity to reconcile these decisions,” the group said.

It also said it is unclear “the extent to which the commission’s anomalous-conditions rationale in Opinion No. 531 is intended to reflect changes in its long-standing reliance on the DCF methodology, and particularly the DCF midpoint, for determining ROE.”

Commission action is pending on the two other New England dockets cited by the group, following a proposed decision by an administrative law judge in March. The ALJ recommended an ROE for two time periods that was lower than what transmission owners sought but higher than what states and commission trial staff advocated. (See New England ROEs Set in Initial Decision.)

May 9, 2016

Atlantic Sunrise Gets Preliminary Approval

By Suzanne Herel

FERC staff last week released a draft environmental impact statement on Atlantic Sunrise Project, finding that the natural gas pipeline expansion would result in “some adverse environmental impacts” but that they would be “less than significant” following mitigation measures (CP15-138).

ferc, atlantic sunrise, williams — Atlantic Sunrise Project Map *Source: Williams*

Williams has proposed expanding its existing Transcontinental Gas Pipe Line (Transco) from the Marcellus Shale area in northern Pennsylvania to its southeastern market. The 198 miles of additional pipeline would deliver an incremental 1.7 million dekatherms/day of year-round firm transportation capacity.

In making its determination, staff considered that about 28%, or 55 miles, of the project would be within or next to existing infrastructure rights of way. Proposed mitigation measures by Williams, along with recommendations by FERC staff, would minimize impacts on natural and cultural resources during construction and beyond, staff said.

The Atlantic Sunrise Project consists of 184 miles of greenfield pipeline and 11.5 miles of looping pipeline in Pennsylvania. Williams would also replace 2.5 miles of pipeline in Virginia.

The project also involves two new compressor stations, two new meter stations and three new regulator stations in Pennsylvania, along with infrastructure improvements that also would affect Maryland, North Carolina and South Carolina.

Williams expects the project to be in service in the second half of 2017. Comments on the draft EIS are due by June 27.

May 9, 2016

MISO Considering Changes to Proposed Auction Design

By Amanda Durish Cook

MISO is considering changes to its proposed forward capacity auction for Southern Illinois in the face of opposition from stakeholders and Independent Market Monitor David Patton.

John Harmon - MISO IMM auction design — MISO Manager of Resource Adequacy John Harmon discusses MISO 2016/17 PRA results. *© RTO Insider*

In addition, MISO staff have again postponed a FERC filing seeking approval for seasonal and locational capacity constructs in order to gain more buy-in from market participants.

Patton last week told the Resource Adequacy Subcommittee (RASC) that the auction plan — which would procure Zone 4’s local capacity requirement three years in advance and all other capacity in the prompt-year auction — will fail to optimize procurement or provide accurate pricing and efficient transfers between zones.

“You can’t bifurcate this market and have any hope of establishing an efficient price,” Patton said.

Patton said the plan will result in underprocurement and depressed forward prices in competitive retail areas because the “optimal procurement level in the competitive retail area is likely higher than the minimum requirement.” While Patton thinks the residual prompt auction could be optimized, he said that still would fail to correct prices and procurement volume in the forward auction.

The Monitor had other general criticisms of forward procurement, saying units can’t “intelligently” decide to retire or suspend four years in advance. New resources, meanwhile, are unlikely to enter the auction at competitive prices close to the cost of new entry because clearing guarantees only one year of revenue. As a result, those investing based on expectations of future revenue will offer as price takers, close to zero, and those seeking to maximize the one year will offer much higher than CONE. (See PJM-Type Capacity Auction for MISO Zone 4 Proposed.)

The Monitor recommended that MISO instead introduce a sloped demand curve for the local requirement in the competitive retail areas and jointly optimize the amounts procured inside and outside of the competitive retail areas on a prompt-year basis.

MISO: Auction a ‘Continued Evolution’

Jeff Bladen, MISO executive director of market services, offered possible adjustments to the proposal, telling the RASC that auction design is “a continued evolution.”

MISO staff could alter the plan so that the full forward procurement occurs in a separate auction — or altogether eliminate the forward auction and revert to prompt-only procurement. Under the former scenario, MISO would consider enacting a minimum offer price rule to combat price distortion for competitive retail areas.

Bladen said MISO is “seriously considering” assigning risk of congestion to the buyer, in scenarios in which retail areas are subject to a full forward procurement.

“If you run a forward auction, you need to think about access to the transmission system and congestion costs,” Bladen said.

MISO must also prevent “infeasible procurement” because of high congestion, Bladen said, pointing out that market participants that self-schedule already face risk that congestion will render their procurements unusable. “This is not a new design element to think about,” he added.

Bladen said MISO could either constrain transmission availability through forward-looking modeling or keep the current modeling based on local clearing requirements.

Patton countered that MISO’s option to procure the full planning requirement for the competitive retail area in the forward auction cannot be reasonable because it would “divorce the procurements and prices from MISO’s true reliability needs.”

The Monitor also cautioned against MISO’s ambitious timeline for rolling out the proposal and the resources that will be required: “It took New England years to set up their forward procurement. They virtually worked on nothing else.”

Bladen also said MISO is considering instituting a fixed resource adequacy plan requirement preventing market participants from “opportunistically toggling in and out” of the auction and causing price volatility.

Patton said “it would be best” if auction opt-in and opt-out provisions did not exist so that prices will reflect the true supply and demand in the area.

Mark Volpe, Dynegy senior director of regulatory affairs, said it was “encouraging” to see MISO and the Monitor move away from dependence on a local clearing requirement.

“Dynegy has preferred a forward auction, but that preference has always been predicated on if price formation is right,” Volpe said. “It would be preferable to have a prompt auction where the price is correct, rather than a forward auction where the price is wrong. You have to have that price formation correct before you get into the timing.”

Exelon’s Marka Shaw echoed the Monitor’s timeline concerns, saying more time was needed for discussion. “We’re facing very real and serious decisions … and it’s clear it’s not serious to others,” she said, referring to MISO staff’s insistence that a July filing is still feasible.

Seasonal, Locational Filings Delayed

MISO RASC liaison Renuka Chatterjee said the RTO is willing to postpone its planned May Tariff filing on seasonal and locational capacity constructs and use June to further explore the filings.

“What do you need to get comfortable with the proposal, and what language do you think the proposal lacks?” Chatterjee asked stakeholders.

“We’re looking for time to discuss alternatives to the proposal,” said David Sapper of Customized Energy Solutions. “Frankly, if MISO isn’t willing to discuss material changes, we don’t need that time. I don’t think that you’re offering anything that we’re seeking.”

Chatterjee said MISO has already provided justification for concepts such as using two seasons instead of four. “You might not like our answers, but to the extent that we didn’t answer anything, please let us know,” she said.

Stakeholders also denied a motion from East Texas Electric Cooperative urging MISO to move ahead with a seasonal filing.

May 9, 2016

ERCOT Briefs: Ample Capacity; Outage Procedures

ERCOT said last week continued growth in natural gas and renewable energy capacity will help it meet its projected summer peak this year — and demand well into the next decade.

According to its final summer Seasonal Assessment of Resource Adequacy (SARA) released last week, ERCOT has 78,434 MW of generation capacity, more than enough to meet a projected peak demand of 70,588 MW. If reached, the projected peak would break last year’s record peak of 69,877 MW. While last year’s summer was only the 17th hottest on record, Texas’ economic growth has helped boost demand.

The available capacity includes 680 MW of new gas generation expected to begin operating before the peak, which generally occurs in August. Also available will be 410 MW of planned wind and 7 MW of planned grid-level solar capacity. The new capacity more than makes up for the loss of a 371-MW gas unit near Houston. ERCOT said Friday that NRG Texas Power had announced it would mothball the unit indefinitely effective June 27.

“Gas is one of our more efficient and economical generation sources at this time,” said Pete Warnken, ERCOT’s manager of resource adequacy.

ERCOT bases its summer forecast on weather patterns in June to September from the past 13 years. Senior meteorologist Chris Coleman said that while the region is transitioning away from El Niño weather patterns, “we could see some temporary, localized hot periods” in the Rio Grande Valley and West Texas.

The ISO also released its biannual Capacity, Demand and Reserves (CDR) report, a “snapshot” of existing and planned generation and load forecasts for the next 10 years. The report shows planning reserve margins ranging between 15.9% and 25.4%. The ISO has added almost 1,000 MW of new generation since September, but because much of it is renewable energy, it has a peak capacity contribution of about 250 MW.

The CDR report reveals a 1,700-MW drop in generation capacity since December, but based on current planning criteria, ERCOT projects nearly 6,200 MW of new gas-fired generation by summer 2018 and 7,400 MW in new capacity by 2020. Additional unit retirements are not reflected in the planning horizon.

The report also projects about 11,000 MW of planned wind generation by 2019, adding nearly 1,800 MW in expected capacity during summer-peak conditions.

Warren Lasher, ERCOT’s director of system planning, added a note of caution into the otherwise rosy predictions.

“This report also includes generation resources that could be affected by environmental regulations, and future decisions by resource owners may impact these projected planning reserve margins,” he said.

The report does not take into account the proposed 2019 integration of Lubbock Power & Light into the ERCOT system “due to uncertainty regarding the regulatory outcome.”

The Texas grid operator also released its preliminary fall SARA, covering October and November. That assessment foresees 82,737 MW available to meet a normal fall demand of 54,437 MW.

Staff, Stakeholders Discuss Market Outage Procedures

Resmi Surendran ERCOT - briefs — Surendran

ERCOT staff conducted a market continuity workshop last week as a first step in addressing a “lack of market restart procedures.”

The ISO has black start, business continuity and crisis communication plans in place, but it lacks clear protocols or operating guide language to recover from a market outage, according to ERCOT. Staff has developed draft procedures to address gaps but has been tasked by the Technical Advisory Committee to gather stakeholder input.

The workshop focused primarily on how to best restart the real-time and day-ahead markets following an outage. Stakeholders also discussed how to handle credit policies, financial transactions and retail-transaction processing during interruptions and subsequent restoration periods.

Resmi Surendran, senior manager for wholesale market operations, said ERCOT has protocol language covering security constrained economic dispatch (SCED) or brief market failures. But staff wanted to provide more clarity to language governing more significant market downtime, she said.

“If we go for a month without a market, which is possible, what happens?” Surendran asked. “Will people be able to get their money? How do we pay the generators that must still run?”

ERCOT is proposing to start the real-time market first and then the day-ahead market. “Once we see the real-time market is stable … and we can model the topology and credit correctly, then we can start the day-ahead market,” Surendran said.

Staff will update the TAC in the near future and request guidance on next steps. Feedback and questions can be sent to Karen Farley.

ERCOT Moving to Internet Explorer 11

ERCOT is upgrading its browser to Microsoft’s Internet Explorer 11. Staff says projects that use browser services will be updated to be compatible with IE 11. At the same time, ERCOT is ending its support for older versions of Internet Explorer and will no longer build projects that are backwards compatible to IE 8.

– Tom Kleckner

May 9, 2016

NYISO Proposes ‘Class Year’ Tx Study Extensions

By William Opalka

NYISO asked FERC Thursday to approve Tariff revisions that would make it easier for generators to get a place in the transmission queue “class year” (ER16-1627).

The ISO’s large facility interconnection procedures require generators to complete a three-step study process, starting with a high level feasibility study, which evaluates the configuration and local system impacts, followed by a system reliability impact study (SRIS), which evaluates the project’s impact on transfer capability and system reliability.

Finally, the class year study evaluates the cumulative impact of a group of projects that has completed similar milestones. This study identifies the upgrades needed to interconnect the project and maintain reliability.

In order to preserve its place in the transmission queue and enter the class year study, the project must acquire necessary permits from the state within two years of the NYISO Operating Committee deeming its application complete following an SRIS.

The state permitting process for generators over 25 MW “is a relatively new power plant siting process that ‘front loads’ much of the process,” the ISO explained. “As a result, there are concerns that projects may not be able to reach the ‘completed application’ stage in time to enter a desired class year study, despite having an Operating Committee-approved SRIS.”

NYISO cited a recent example in which a generator needed a FERC waiver to enter the class year study. On April 1, FERC granted the 33-MW Dry Lots Wind project in Herkimer County a waiver allowing it to join the study despite lacking a state siting board permit (ER16-1047). In granting the waiver, the commission cited its expectations of the ISO’s pending Tariff filing.

The proposed Tariff changes would extend the deadline for meeting the regulatory milestone requirement to 90 days after the start of the third class year study following the OC’s SRIS approval.

“This gives additional time for the project to meet the regulatory milestone while not permitting the project to remain in the queue indefinitely,” NYISO said. “This revision will help minimize delays to projects that are close to completing their regulatory milestone when a class year study begins. If a project provisionally enters a class year study, it will be withdrawn from the class if its regulatory milestone is still not met after the 90th day.”

NYISO asked for acceptance of the revision by July 5.

May 9, 2016

CAISO Board Approves Aliso Canyon Market Response

By Robert Mullin

CAISO’s Board of Governors last week approved an ISO plan to temporarily alter market operations in response to natural gas pipeline restrictions stemming from the closure of the Aliso Canyon storage facility.

California Map showing Path 15 & Path 26 (CAISO) - Aliso Canyon Market Response — CAISO is proposing to reserve capacity on the Path 26 transmission line in advance of potential gas restrictions in Southern California. The measure is meant to ensure delivery of energy into the region when constrained fuel supplies threaten to limit output from local gas generators. *Source: CAISO*

The proposal calls for new market rules to help Southern California’s gas-fired generators better manage their burns to avoid system-balancing penalties expected to go into effect June 1 — just ahead of the state’s peak season for electricity consumption.

Under the new requirements, Southern California Gas customers face penalties as high as 150% of daily gas indices when their daily burn deviates from nominated flows by more than 5%. The region’s gas-fired generators say the costs could make them unprofitable when ISO dispatch instructions require their units to burn more — or less — gas than planned for on a given operating day.

“We want to ensure the generation can get” into Southern California, Cathleen Colbert, CAISO senior market design and regulatory policy developer, told a Market Surveillance Committee meeting last month. “That’s why deliverability was the focus.”

Thus, CAISO’s plan takes a systemwide response to gas restrictions, although provisions for recovery of penalty costs are included in the proposal.

When gas flows are restricted the ISO would enforce a gas availability market constraint for generators in a constrained region. The constraint would use the day-ahead or real-time market to cap the gas burn in the affected area below system limitations set out by SoCalGas. Any additional generation needed would only be dispatched through out-of-market operations coordinated with the pipeline operator.

The ISO would also implement a protocol to reserve capacity on the Path 26 transmission line in advance of potential gas shortages, a measure intended to leave enough of a buffer to ensure delivery of energy and contingency reserves into the Los Angeles basin when local resources face curtailment. CAISO decided against implementing a similar procedure along the interties into California because of the current low volume of real-time transfers on those lines.

Additional operational measures proposed by the ISO include:

Reducing the amount of ancillary services procured from Southern California resources based on expected gas and electric system conditions;
Deeming selected internal transmission constraints uncompetitive when the proposed gas availability constraint is in effect, thereby freeing up resources to serve the affected region; and
Clarifying CAISO’s authority to suspend virtual bidding when it identifies potential market inefficiencies.

The ISO is also proposing to allow an affected generator to recover increased gas costs by adjusting the gas component of its day-ahead commitment cost bid cap to up to 175% of the gas index price, compared with 125% today. Gas cost caps included in default energy bids used in the real-time market would be increased from 125% to 200% of the index.

CAISO must now seek FERC approval for the plan. All proposals are set to sunset Nov. 30.