MISO Sees Nov. 1 Filing on Forward Auction; Simulation Shows Price Disparities

By Amanda Durish Cook

MISO officials said last week they are still finalizing their forward auction proposal for competitive areas, but the changes won’t be significant and won’t affect a late fall FERC filing. Meanwhile, simulations including the new proposal suggested it could result in large price disparities.

Bladen © <em>RTO Insider</em> — Bladen © RTO Insider

Jeff Bladen, executive director of market services, said MISO is now targeting a Nov. 1 filing, with implementation in the 2018/19 planning year. The RTO plans to release another version of draft Tariff language at a Sept. 19 Resource Adequacy Subcommittee meeting and collect stakeholder feedback by the Oct. 6 RASC meeting. The Brattle Group will also present more forward auction findings at the September meeting. (See MISO Delays Forward Auction Filing; Issues Draft Tariff and Business Rules.)

“At this point, we’re not anticipating any meaningful changes,” Bladen said at a two-day RASC meeting last week.

Bladen said MISO is still working on a materiality clause to determine which retail choice load participates in the forward auction in Michigan and Wisconsin, where the zonal boundaries straddle state lines.

The RTO also is considering changes to its cap on the safe harbor provision that excuses supply from having to offer capacity.

The current cap is based on historical planning reserve margin requirements (PRMR) and an “open-ended” exception process. MISO is considering a cap based on projected PRMR and a “prescriptive” exception process, and one based on projected PRMR plus additional prescriptive adjustments with no exception process.

Based on stakeholder feedback, MISO is reworking transmission modeling compatibility between the forward and prompt Planning Resource Auction and a simultaneous feasibility test, which judges the system’s ability to handle all megawatts of capacity dispatched during a maximum generation event. Bladen said MISO is still refining a possible congestion charge to remedy infeasible capacity delivery through cost allocation.

“We want to make sure that anything that clears in the FRA [Forward Resource Auction] will be feasible with the rest of the footprint,” Bladen said.

Finally, the RTO is mulling over which demand curve shape to pursue. (See MISO Backs Forward Auction Plan, Rejects Prompt Proposal.)

Split with Market Monitor

Mark Volpe, senior director of regulatory affairs for Dynegy, asked if MISO is still working with Independent Market Monitor David Patton on his concerns over price formation.

“We speak with the Market Monitor on a regular basis. While we continue to have a difference of view, we are open to his advice and feedback on how and when to improve the FRA, [but] the price formation concerns that he’s raised are not what we’re seeing,” Bladen said. “I think the nature of his role as an adviser is not in question. But at this point, we have a difference of view in what the data shows, and that’s not uncommon with topics like this.”

When pressed by stakeholders on how much of the Monitor’s advice would be incorporated, Bladen became less conciliatory, suggesting the RTO would rely on Brattle’s suggestions. “There’s nothing [in the Tariff] to suggest that Potomac Economics is the sole [adviser] for MISO,” he said. “And FERC is the ultimate arbiter.”

RASC Chair Gary Mathis asked if MISO could leave certain details out of the filing to work out later. Bladen said he expected the filing to include all relevant details.

“Like most FERC filings, everything is up for grabs once FERC gets its hands on it,” Bladen added.

Michael Chiasson of Potomac Economics asked if MISO would leave any details out of the filing in favor of providing a reference to the accompanying Business Practices Manual. Bladen said MISO would not.

MISO-IPL Analysis Produces Disparities

MISO also collaborated with Indianapolis Power and Light on a forward auction pricing analysis, which used results from last year’s Planning Resource Auction in a forward auction and PRA simulation.

The two simulations yielded disparate results. A first simulation that used a sloped demand curve produced clearing prices of $1.99/MW-day for MISO South, $1/MW-day for Zone 1 and $222/MW-day for the remainder of MISO North in the prompt auction, and $110/MW-day in the forward auction, which will be limited to retail choice areas. IPL said the PRA demand curve moved to the right during its simulation, noting “cleared FRA resources offered at zero … in the PRA are not a direct offset to the shift in demand curve.”

On a second simulation using a demand curve shaped closer to what Brattle used in its analysis, IPL results produced $210.10/MW-day in the forward auction, and a $2.99/MW-day clearing price in MISO South and a $5/MW-day clearing price in MISO North. (See chart.)

IPL analyst Ted Leffler said the outcomes of the auction are “in line with expectations” even though the forward clearing prices were disproportionately higher than PRA prices.

“Should we be concerned that we’re going to be introducing more volatility? I don’t know. It’s something we need to think about,” Leffler said.

Leffler said IPL used the Zone 4 PRMR as a representation for all competitive zones and didn’t change any offers or capacity import or export limits. The analyses only used the most expensive offers in Zones 1, 2, 8 and 10. For the second analysis, he said, IPL assumed just 78% of Zone 4’s resources were offered in the forward auction, as that was the percentage considered competitive.

Leffler also said the simulations’ use of 2015 PRA results was “imperfect” because it was a “sold-out” auction, with all supply megawatts clearing except for some in Zones 4 and 7.

Count External Resources Toward Clearing Requirement?

While a seasonal and locational auction filing is also on hold until the 2018/19 planning year, MISO said it could consider implementing pieces of the locational construct in the 2017/18 planning year. Namely, said Executive Director of Resource Adequacy Renuka Chatterjee, MISO could apply external resources toward local clearing requirements in next year’s auction if the RTO can file with FERC and get approval in time.

South-North Limit

Meanwhile, MISO continues to solicit stakeholder opinion on whether the 876-MW South-North transfer limit should be adjusted in planning for next year’s auction. (See “South-North Transfer Limit in 17/18: Higher or Lower? Firm or Non-Firm?” MISO Resource Adequacy Subcommittee Briefs.)

The RTO brought six days’ worth of 2016 summer data to the RASC to illustrate peak usage on the sub-regional transfer. The data showed North-South flow averaging 2,446 MW on June 17 (with a peak of 2,840 MW) when a maximum generation alert was issued in MISO South, and an average 1,618-MW South-North flow (peak 2,225 MW) on July 22 when Midwest load peaked at 88 GW.

Volpe said the results show that MISO should continue to be “somewhat conservative” for constraints on real-time flows between the regions. Dynegy, which independently examined flows during two peak summer days this year, concluded MISO should continue to subtract firm reservations from the 2,500-MW South-North limit.

Other stakeholders agreed, saying MISO should account for all firm reservations across the interface, as only non-firm reservations could be guaranteed after all firm flows were granted, even if the firm flows weren’t in use.

MISO said of the 10 respondents that provided feedback on the regional transfer limit, seven supported using the maximum 2,500-MW limit as a starting point. Two others opted for a 1,000-MW starting limit. The final stakeholder to provide comment asked for a study of firm-flow reservations before a decision is made.

The RTO is expected to present a draft proposal on the 2017/18 sub-regional limit at the Oct. 5 RASC meeting.

September 5, 2016

Federal Briefs

The Omaha Public Power District has notified the Nuclear Regulatory Commission that it will permanently shut down its Fort Calhoun reactor on Oct. 24. The OPPD board unanimously approved a recommended shutdown in June, but officials had not provided a date for when the plant would stop operating, only saying it would by the end of the year.

With the shutdown date set, the plant’s decommissioning will kick into gear. That includes the removal and transfer of nuclear fuel from the reactor into the spent fuel pool, where fuel rods will be placed for about 18 months while they cool to a level that permits transfer into longer-term storage.

The decommissioning process could take up to 60 years and will cost OPPD as much as $1.5 billion. The 43-year-old, 478-MW Fort Calhoun is the smallest nuclear plant in the country, which made it financially untenable to continue operating.

More: Omaha World-Herald

Firm Lands DOE Grant for Flameless Combustion Plant

Southwest Research Institute has received a $3.28 million grant from the Energy Department to develop a project that could eliminate smokestacks and reduce emissions from coal-fired power plants.

The project is described as a “flameless pressurized oxy-combustion plant” by Rep. Joaquin Castro (D-Texas), who announced the grant. The organization also received nearly $900,000 in private industry support for the research.

SwRI, a research and development nonprofit, said the smoke produced from burning coal will be purified in a process that captures carbon dioxide and results in zero emissions. The captured CO₂ will be kept out of the atmosphere by injecting it underground.

More: San Antonio Business Journal

DOE Estimates $1.2B to Retrofit Colstrip Plant

Energy Department representatives said that retrofitting the Colstrip coal-fired power plant in Montana to reduce greenhouse gas emissions would cost at least $1.2 billion, but that price tag could be partially offset by selling captured carbon dioxide for use in oil fields. Colstrip emitted about 16.5 million tons of CO₂ in 2014, two-thirds of the state’s total, according to EPA.

The department presented its analysis of reducing emissions from the Colstrip plant at the request of Montana Gov. Steve Bullock. A Democrat up for re-election in November, Bullock has faced a barrage of Republican criticism for not doing enough to protect the aging plant.

“We need to be saying, what can we do to find solutions?” Bullock said to utility and mining executives gathered at the governor’s office in Helena to hear the Energy Department’s findings. “Those discussions only become more urgent given recent developments at Colstrip.”

More: The Associated Press

FERC Approves Dominion Pipeline Expansion in Md., Va.

FERC has approved an expansion of one of Dominion Transmission’s natural gas pipelines necessary to serve new generating stations in Maryland and in Virginia. Dominion filed to expand the Leidy South Project in May 2015.

The project involves adding compressor stations and other equipment to the pipeline, which crosses Pennsylvania, Maryland and Virginia. Ultimately, it will allow natural gas to be carried to the Panda Stonewall generating station planned for Loudoun County, Va., and the Mattawoman Energy project in Prince George’s County, Md.

Dominion estimates the expansion will cost $209 million.

More: GenerationHub

NRC Cites FirstEnergy for Inaccurate Medical Info

The Nuclear Regulatory Commission cited FirstEnergy for failing to provide accurate medical information after a nuclear operator at the company’s Davis-Besse plant lied about taking his prescribed medication.

The commission found that the operator, who resigned before the investigation began, failed to notify the plant when he stopped taking medicine for diabetes and high blood pressure. As a result, the commission said, the company unknowingly provided it with inaccurate information.

A FirstEnergy spokesperson said the operator’s failure to take his medication did not impact the plant’s operations. The company has agreed to modify its fitness-for-duty procedures as a result of the incident.

More: The Blade

TVA’s Watts Bar 2 Offline After Transformer Fire

A main transformer fault at the Tennessee Valley Authority’s new Watts Bar 2 nuclear station caused a transformer oil fire and tripped the reactor last week. The incident occurred during testing of the unit before it goes into commercial operation.

TVA had achieved 99% of maximum output during the test before the fire broke out. It completed construction of the plant this year.

The fire was extinguished and there were no injuries. TVA said it is completing a full examination of the incident and the plant before resuming the testing. It said it didn’t know when it would go back online.

More: POWER Magazine

September 5, 2016

PJM: Regional Plan Cuts Costs, but Gas Prices are Wild Card for CPP Compliance

By Rory D. Sweeney

The Clean Power Plan poses no threat to PJM’s reliability, but compliance costs are highly sensitive to gas prices and whether states go it alone or combine efforts with a regional approach, according to a study released by the RTO last week.

If gas prices remain low, states within PJM’s footprint are likely to meet EPA-mandated emissions reductions simply through the replacement of coal plants with new combined cycle generators. However, compliance costs could more than triple if states decide to meet their CPP targets individually while also regulating emissions from new sources, the RTO’s analysis concludes.

Issued by EPA in August 2015, the CPP requires PJM’s states to reduce carbon dioxide emissions by 36% from 2005 levels by the year 2030. The analysis, requested by the Organization of PJM States Inc., compared seven compliance “pathways” employing mass- and rate-based trading at regional or state levels. Rate-based plans would mandate that generators meet a pounds-per-megawatt-hour target, while mass-based plans cap state emissions in tons per year.

PJM also looked at several sensitivities, including the impact of retirements on resource owners’ exit decisions based on five- and 20-year horizons. Also modeled were the impact of lower natural gas prices, a multistate split of rate- and mass-based compliance within the PJM region and state renewable portfolio standards.

Regardless of the pathway used, the CPP would not have a substantial impact on resource adequacy as “the capacity and energy markets [will be] able to attract sufficient new investment to satisfy PJM’s reliability requirements,” the RTO said.

Regional Compliance Reduces Costs

The analysis found that levelized compliance costs would range from $0.61/MWh (1.1% of the average total wholesale cost) for regional plans and $1.93/MWh (3.3%) for individual state plans that include regulation of both new and existing sources.

“The cost of compliance for the entire PJM region differs according to the compliance pathway chosen, but regional compliance leads to lower costs than does individual state compliance under both mass-based and rate-based compliance pathways,” the report said.

Regional compliance would result in fewer coal generator retirements and less new combined cycle gas plants than individual state compliance “due to the greater flexibility and options for emissions reductions offered across the entire PJM region,” the study said.

As a reference case, PJM also ran a simulation in which the CPP, which has been stayed by the U.S. Supreme Court pending legal challenges by numerous states, is not implemented. The simulations begin in 2018, thelatest that compliance plans can be submitted if the rule survives.

Impact of Gas Prices

The study found that continued low natural gas prices — assuming they remain in the $3 to $4/MMBtu range (in 2018 dollars) over the 20-year study period — “has a greater effect on emissions levels, the retirement of fossil steam resources and new entry of natural gas combined cycle resources than even the most stringent of the studied compliance pathways that also regulate the CO₂ emissions of new natural gas combined cycle resources.”

“Because of accelerated [coal] retirements, there would be no cost to achieve compliance, and the resulting emissions would be below the final Clean Power Plan targets, even without the Clean Power Plan,” PJM said.

Challenges for Nuclear, Boon for Renewables

Compared to the reference and mass-based options, PJM found that rate-based compliance would create lower energy market prices because subsidies for renewable resources would allow them to submit offers below production costs. This would increase capacity prices, however, as resources seek to replace lost energy revenue.

This would drive growth in renewables — which would earn more revenue from emissions rate credits than from the increase in energy market revenues under mass-based compliance — but “results in increased economic challenges for existing nuclear resources,” PJM said.

Mass-based plans, on the other hand, would increase energy market prices by adding costs for allowances. They would allow low-emission resources to depend less on non-market revenue and provide no incentive to price generation below cost. They would also make nuclear facilities more viable by pricing their low-emissions status.

The analysis also evaluated the impact of different time horizons on the nuclear and coal fleets.

If generation owners make retirement decisions based on a five-year horizon from 2018 through 2022 before initial compliance targets take effect, the study predicted up to 6 GW of nuclear retirements (in addition to the already-announced decommissioning of the Oyster Creek nuclear plant) and less than 1 GW of incremental coal-fired retirements. Gas prices would drive the reductions in the short run, but the study found nuclear plants become viable again in 2026 under CPP.

pjm clean power plan — Steam Turbine and Nuclear Units Age 40+, Combined Cycle Units 30+ (As of 2018)

“What the analysis shows is that over a 20-year horizon, the existing nuclear fleet can become economic, but in this near term, they face a lot of stress given the low gas prices and current market prices,” PJM’s Muhsin Abdur-Rahman said during a media briefing on the report Thursday.

The analysis found congestion will decline by 2025 under every compliance pathway compared to the reference scenario. Congestion related to historical west-to-east flows drops because of coal retirements in western PJM, although it is accompanied by more localized congestion.

Energy Efficiency

Rate-based plans would also require precise measurement and verification of energy efficiency to earn emission rate credits. A sensitivity that assumed states can convert only 50% of energy efficiency included in load forecasts into credits resulted in cost increases that were more than double the cost of trade-ready mass-based compliance, although still less than $1.50/MWh.

September 5, 2016

CAISO Board OKs Grid Services Requirements for Renewables

By Robert Mullin

CAISO’s Board of Governors last week approved proposed Tariff revisions that will require new renewable resources be capable of providing grid-stability services as a condition for interconnecting with the ISO’s system.

San Gorgonio Pass Wind Farm (Wikipedia) - renewables grid-stability services caiso — CAISO’s Tariff changes will require new and upgraded renewable resources to be capable of providing reactive power and voltage control. *Photo of San Gorgonio Pass Wind Farm source: Wikipedia*

While stakeholders largely support the amendments, some market participants contend they don’t go far enough in guaranteeing adequate compensation for what has become an increasingly important service as more intermittent resources link up with the grid.

The proposed revisions follow FERC’s June issuance of Order 827, which requires that all newly interconnecting non-synchronous generators have reactive power capability. Resources undergoing upgrades would also be subject to the new rules.

“We are pleased to now take this next step, in which clean power resources can contribute to the reliability of the grid,” CAISO CEO Steve Berberich said in a statement. “By providing reactive power, these resources are better suited to help us integrate increasing numbers of renewable resources.”

“It’s really good utility practice to require all resources in the fleet to have reactive power,” Keith Johnson, CAISO manager of infrastructure policy and contracts, told board members during an Aug. 31 meeting.

The ISO’s Tariff changes go beyond FERC’s mandate for reactive power capability by adding a provision requiring that non-synchronous resources also provide voltage regulation.

“Maintaining voltage is very important for how we operate in the West,” Johnson said, explaining the ISO’s rationale for the additional requirement. “The incremental cost of [automatic voltage regulation] equipment is very, very minimal.”

Thermal Generators Seek Raise

Although the new requirements had broad support among stakeholders, a disagreement arose over CAISO’s decision not to use this FERC filing to alter its compensation for reactive power — a move that would especially benefit thermal generators that are steadily losing market share to renewables.

Under current ISO practice, any generator that is dispatched down to provide reactive power is paid its opportunity cost for lost energy revenues. Generators want the ISO to implement a new market provision that would compensate them for the capital cost of installing reactive power equipment — effectively creating a capacity payment for providing reactive power service.

CAISO contends that generators can recover those costs through their power purchase agreements, given the West’s continued reliance on bilateral contracts for the provision of capacity. Any additional market mechanism would run the risk of creating double payments for the service, Johnson said.

“Providing reactive power is a service essential to the operation of the grid,” said Brian Theaker, director of market affairs at NRG Energy. “Today’s disappointing decision doesn’t advance that.”

Theaker said that the current compensation structure does not provide “reliable signals” for generating units that require longer-term guarantees to remain financially viable.

“We feel like there’s been an opportunity missed here,” said Carrie Bentley, a consultant representing the Western Power Trading Forum. “The ability to provide reactive power is not free,” she continued, adding that five other organized markets offer compensation for the service.

“It’s not a secret that renewable power is disrupting the [capacity] and energy market — a lot of thermal generation will not be able to remain in the market,” Bentley continued. “How do you provide a market signal strong enough to keep the thermal generation we need.”

“The ISO did talk about compensation and looked at some of the other ISOs and RTOs across the country,” Johnson responded. “When PJM or MISO was formed, there were legacy arrangements for capacity payments for reactive power. We have no such system of capacity payments — we have bilateral contracts.”

Keith Casey, CAISO vice president for market and infrastructure development, said Bentley’s concerns about the ISO’s thermal fleet were “spot on.” He pointed out that the ISO’s new flexible ramping product — which compensates generators for the ability to rapidly respond to intermittent output from renewables — is one effort to reward “needed” generators.

“We just view the reactive power capability as a fundamental requirement,” Casey said. “The capital cost for that capability should be addressed through bilateral contracts.”

September 5, 2016

State Briefs

ARKANSAS

EPA Finalizes State’s Regional Haze Plan

EPA has finalized a federal implementation plan for compliance with its Regional Haze Rule for the state, but regulators and at least one generator say they may appeal the decision.

The final rule calls for increased emissions control at three coal-fired plants and three natural gas-fired plants, in addition to a paper mill. One of the plant owners, Entergy, said compliance measures could cost it up to $2 billion and that the company is exploring its options. State environmental officials may also appeal the rule.

More: KUAR; ArkansasOnline

CALIFORNIA

Imperial Irrigation District Strikes Net Metering Agreement

Imperial Irrigation District, which generated public backlash after it cut off enrollment in its net metering program earlier this year, will allow as many as 1,300 new rooftop solar customers to sign up for the preferential rate.

The district, which provides electrical service to 150,000 customers, reached a deal with the solar industry and state lawmakers to enable any customers who applied for a solar interconnection permit and received a building permit by April 1 to enroll in the program.

IID struck the compromise in the face of possible passage of legislation that would have expanded the eligibility period to July 19.

More: The Desert Sun

Appeals Court Denies Release Of PUC-San Onofre Emails

A state appeals court last week reversed a lower court decision that would have forced the Public Utilities Commission to disclose its communications related to the agency’s settlement with Southern California Edison over the closure of the San Onofre nuclear generating station.

The appellate court sided with the PUC, which argued that the communications involved privileged information regarding a rate case. San Diego attorney Michael Aguirre had sought to release the emails to determine whether Gov. Jerry Brown was party to ex parte, private negotiations between former PUC President Michael Peevey and the utility ahead of the settlement. Peevey, a former SoCalEd executive, stepped down from the commission after the negotiations were revealed.

Though the court denied disclosure, it recommended Aguirre submit his request to the PUC under the state’s Public Records Act and, if denied, take his case directly to the appeals court. Aguirre said he will appeal to the state Supreme Court.

More: The Sacramento Bee

COLORADO

Co-op to Shutter 2 Plants Under Regional Haze Plan

The Tri-State Generation and Transmission Association said it will retire more than 500 MW of coal-fired generation in the next decade in order to comply with the state’s implementation plan for EPA’s Regional Haze Rule.

The electric cooperative said it plans to shutter the 100-MW Nucla Station in Montrose County by 2022, along with the nearby mine that feeds the plant. It also plans to close the 427-MW Unit 1 at the Yampa Project by 2025, although two other units at the site will continue to operate. It said it is more economical to close the units rather than retrofit them to comply with the regulations.

“Tri-State has worked tirelessly to preserve our ability to responsibly use coal to produce reliable and affordable power, which makes the decision to retire a coal-fired generating unit all the more difficult,” the company said. “We are not immune to the challenges that face coal-based electricity across the country.”

More: The Denver Post

MICHIGAN

Agencies Approve $89.5M In Energy Assistance

The Agency for Energy and the Department of Health and Human Services approved $89.5 million in Energy Assistance Program grants last week for 14 nonprofits and utilities.

The grants are meant to help low-income residents pay electric bills. Among the organizations and municipalities that received multi-million dollar grants, DTE Energy received $17 million and Consumers Energy received $13.2 million. The Salvation Army also received $13.7 million, while TrueNorth Community Services received $15 million.

More: WSYM

NEW MEXICO

Regulators Promise Decision On PNM Rate Case by Sept. 28

The Public Regulation Commission said it will issue a decision within a month on Public Service Company of New Mexico’s rate-increase request. The PRC’s announcement came after most parties in the case objected to reopening hearings.

PNM proposed a 15.8% rate hike earlier this year to cover its investments in power and energy-efficiency measures. In early August, a PRC hearing examiner recommended a 6% increase, saying PNM hadn’t justified the higher rate.

PRC acting general counsel Michael Smith said that as a result of the nearly “uniform” opposition to holding more hearings, “We are going to make a decision based on the recommended decision that was issued by Carolyn Glick,” the hearing examiner.

More: Santa Fe New Mexican

Regulator Approves ROW for Southline Transmission Project

Land Commissioner Aubrey Dunn last week gave right-of-way approval to the Southline Transmission Project, a proposed 345-kV double-circuit line that would cross into Arizona. Developers must still submit detailed plans about the exact location of structures and roads associated with the line, along with cultural and biological surveys.

Sponsored by Hunt Power subsidiary Southline Transmission, the line will provide up to 1,000 MW of transmission capacity in both directions and connect with as many as 14 existing substation locations.

More: Albuquerque Journal

OKLAHOMA

OCC Orders Fracking Wells Shut down After Earthquake

A magnitude-5.6 earthquake last week spurred state regulators to order 37 fracking waste disposal wells to shut down over a 725-square-mile area.

The order came from the Corporation Commission’s Oil and Gas Division. Gov. Mary Fallin said the commission is coordinating with well operators around the town of Pawnee and that several buildings in the Pawnee Nation had been rendered uninhabitable by the quake. She also said EPA is assessing the region.

The wells will close within 10 days of the order, according to a schedule the commission says is necessary because scientists have warned that a sudden shutdown could provoke another earthquake. A commission spokesperson said the wells were ordered closed because of the link found by the U.S. Geological Survey between wastewater disposal and the increased number of earthquakes in the region, particularly in the state.

More: CNNMoney; Bloomberg News; The Associated Press

Wind Opponent Seeks to End Tax Credits Next Year

WindWaste, an organization opposed to wind power incentives, estimates that future wind developments could force the state to shell out more than $500 million annually in zero-emissions tax credits by 2019.

The subsidy is set to sunset on Jan. 1, 2021, but WindWaste wants lawmakers to end the credit by July 1, 2017. The next legislative session begins in February.

Representatives of the wind industry say WindWaste’s estimates of $5.2 billion in payouts by 2030 is wildly inflated. It argued that the group based its predictions on the amount of generation in SPP’s interconnection queue, which only has a buildout rate of about 15%, it says.

More: The Oklahoman

SOUTH DAKOTA

Developers of Wind Project Withdraw Request for Permit

Developers of the Prevailing Winds project asked state regulators last week to withdraw their application for a permit. The retreat came one week after a raucous, four-hour community meeting near Pierre.

Public Utilities Commission Chair Chris Nelson said the request was “unexpected.” The request came shortly before the commission’s Aug. 30 meeting and could be considered at its Sept. 13 meeting.

Prevailing Winds would produce about 200 MW of electricity. By asking to have its application dismissed without prejudice, developers could again apply for a permit at a later date.

More: Rapid City Journal

TEXAS

Austin City Council Approves Rate Cut

The Austin City Council last week unanimously approved Austin Energy’s request to redo its residential electric rates, but not before the city-owned utility first dropped a controversial proposal for an increase. Under the revised rate structure, the municipal utility’s 400,000 residential customers would see bills cut by about $62/year.

The council also signed off on $42.5 million in annual cuts that Austin Energy and its major customers agreed to earlier this month. Most of those cuts will go toward reducing electric bills for industrial and commercial customers. Major customers, such as data centers and large hospitals, will see their electric rates cut 24%.

The utility’s original proposal came under attack because of Austin Energy’s tiered residential price structure: Customers pay the base rate for their first 500 kWh of electricity and higher rates for subsequent blocks of 500 kWh.

More: Austin American-Statesman

VIRGINIA

SCC Examiner Affirms Right To Third-Party Solar Financing

A State Corporation Commission hearing examiner rejected an argument by Appalachian Power that third-party solar financing was illegal, paving the way for homeowners to sign up for the popular method of paying for residential solar-system installations.

“Today’s decision is an important win for solar rights in Virginia, which has continued to lag behind neighboring states on solar because of outdated policies and utility opposition like we saw from Appalachian Power in this case,” said Will Cleveland, staff attorney at the Southern Environmental Law Center. “The ruling confirms that Virginians have the right to use common sense financial tools to choose solar power without utilities acting as the middle men.”

The utility argued that third-party financing, in which homeowners paid for solar systems through monthly contracts, was legal only under a Dominion Power pilot project. The ruling now goes before the full commission for public comments and final briefs.

More: The Energy Fix

WISCONSIN

Regulators Approve Enbridge Pipeline Replacement

The Department of Natural Resources has granted a waterway and wetlands permit for Enbridge Energy to replace a section of old oil pipeline.

Ben Callan, a DNR water management specialist, said the permit is for replacing a 14-mile stretch of Line 3, a 1960s-era pipeline. The pipeline had been operating at a diminished capacity after Enbridge recently found issues during integrity tests. The new section will have a 36-inch diameter and be able to carry up to 760,000 barrels per day.

Callan said that the permit requires the hiring of an independent consultant to oversee compliance. Enbridge spokeswoman Shannon Gustafson said the company has not set a timeline for construction.

More: Wisconsin Public Radio

September 5, 2016

ERCOT Expects Adequate Generation for Fall, Winter

By Tom Kleckner

ERCOT’s latest resource adequacy assessments indicate it has 25,000 to 30,000 MW of spare generating capacity for the fall and winter.

ERCOT Control Room (ERCOT) - fall winter ercot generating capacity — ERCOT’s control rom *Source: ERCOT*

The Texas grid operator’s final Seasonal Assessment of Resource Adequacy (SARA) for October and November includes more than 82,000 MW of capacity, more than enough to meet a projected peak demand of about 54,400 MW.

The preliminary winter SARA report is similarly rosy, with more than 81,000 MW of capacity available to meet a forecasted record peak demand just under 59,000 MW. The winter demand record of 57,265 MW was set during February 2011’s record cold.

ERCOT, which operates 90% of the Texas grid, said four gas-fired combustion turbine units and three wind projects have begun operating since its preliminary fall SARA, adding nearly 900 MW of capacity. Three of the gas units are switchable resources and can connect to either ERCOT’s or SPP’s grids. The fall forecast assumes 13,700 to 19,000 MW of planned and unplanned outages.

Another 1,200 MW of new winter-rated capacity is expected to be in service for the winter season (December-February). The final winter SARA report will be released in November.

— Tom Kleckner

September 5, 2016

Monitor OKs PJM Auction; Says Problems Remain Despite CP

By Rich Heidorn Jr.

PJM’s Independent Market Monitor last week gave his blessing to the RTO’s Base Residual Auction for delivery year 2019/20 but called for additional rule changes to build on the tougher standards of Capacity Performance.

The Monitor’s report on the May auction concluded that the results “were competitive, with the caveat that although the Capacity Performance design addressed the most significant issues with the capacity market design, the Capacity Performance design was not fully implemented in the 2019/2020 BRA and there continue to be issues with the capacity market design which have significant consequences for market outcomes.”

PJM will require all capacity to meet CP standards starting with the 2020/21 delivery year.

pjm market monitor capacity auction capacity performance — Bowring © *RTO Insider*

The Monitor called for additional changes concerning the treatment of pseudo-tied generation, demand response and energy efficiency; the calculation of net revenues; and the application of the minimum offer price rule (MOPR).

The Monitor also acknowledged that its call for using the lower of the cost- or price‐based offer in the calculation of net revenues was rejected by FERC in June (EL14-94-001, ER16-1291). (See “FERC Won’t Revisit Cost-Based Energy Offer Cap Ruling,” PJM News Briefs from FERC Open Meeting.)

But he said the FERC-approved approach used in the May auction, which always uses the cost‐based offer, “resulted in an increase of [$43.4 million], or 0.6%, in the cost of capacity in the 2019/20 BRA.”

In addition, the Monitor recommended:

All costs incurred as a result of a pseudo-tied generator be borne by the unit and included in its capacity market offers.
The “electrical proximity” of pseudo-tied resources be “explicitly accounted for” when defining how external resources should be treated during performance assessment hours.
Enforcing “a consistent definition” of capacity resource as a physical resource at the time of the auctions — with a commitment to be physical in the delivery year and moving all DR to the demand side of the market. The Monitor referenced its 2013 report on replacement capacity, in which it warned that “speculative” DR can suppress prices in the BRA and displace physical generation: “Under the current application of the rules, DR providers may not have identified customers, may not have clear plans for implementing DR measures and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year. This is not consistent with the rules.”
Ensuring the net revenue calculation used to establish the net cost of new entry “reflect the actual flexibility of units in responding to price signals rather than using assumed fixed operating blocks that are not a result of actual unit limitations.” Reflecting actual flexibility will result in higher net revenues, which affect the demand curve and market outcomes, the Monitor said.
Eliminating the rule requiring that small proposed increases in the capability of a generator be treated as planned for purposes of mitigation and exempted from offer capping.
Changing the MOPR review to require all projects use the same modeling assumptions. “That is the only way to ensure that projects compete on the basis of actual costs rather than on the basis of modeling assumptions,” the Monitor said.
Extending the MOPR to existing units in addition to new units.
Re-evaluating the market mitigation exemption granted DR and energy efficiency resources in 2009. “In 2009, there was one product defined for capacity, and there were no resource constraints defined,” the Monitor said. “Particularly in [locational deliverability areas] with few suppliers, there is now the potential for DR and EE providers to exercise market power and affect the clearing price.”
Changing the RPM solution methodology to explicitly incorporate the cost of make-whole payments in the objective function.
Removing energy efficiency resources from the supply side of the capacity market to reflect the change in PJM’s load forecasts. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.) “If EE is not included on the supply side, there is no reason to have an add-back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”

September 5, 2016

FERC Rejects Capacity Release Exemption for NE Gas Generators

By William Opalka

FERC on Wednesday rejected Algonquin Gas Transmission’s request to exempt gas-fired generators from competitive bidding under capacity release rules, another blow to those seeking to increase New England’s gas infrastructure (RP16-618).

Maine PUC, pipeline contracts, ferc, natural gas, Algonquin Gas Transmission, capacity release exemption — *Photo credit: Steve Oehlenschlager*

The proposal to amend Algonquin’s tariff was an offshoot of the company’s proposed Access Northeast pipeline. Electric distribution companies Eversource Energy and National Grid — which are partnering with Algonquin on the pipeline — sought the exemption to ensure the capacity they purchased would be used to fuel gas-fired generators.

The EDCs hoped to release capacity to gas generators as prearranged “replacement” shippers. FERC rules allow such preferences as long as the replacement shipper matches the highest bid submitted by any other bidder. The proposal would have limited that bidding to gas-fired generators, excluding those who might value the fuel more for winter heating.

FERC held a technical conference on the matter in the spring. (See Utilities Seek OK for Gas Releases to Generators at Technical Conference.)

The proposal was opposed by numerous merchant generators, including NextEra Energy, Exelon and Calpine, which said they had found cheaper alternatives to ensure fuel supplies under ISO-NE’s Pay-for-Performance capacity incentives, including installation of dual-fuel capacity and contracts with natural gas marketers and LNG suppliers.

“Merchant generators are not asking you for this capacity, and you need to ask yourself why,” Calpine told FERC. The company estimated firm capacity would cost it $25 million annually, or half a billion dollars over a 20-year commitment. It said it could guarantee the same level of service by investing $50 million in a fuel oil tank.

Other opponents argued that the proposal was premature because no state had approved a state-regulated electric reliability program.

“Neither Eversource nor National Grid provided a persuasive explanation for why the ability to release capacity to a prearranged replacement shipper under our existing regulations is not sufficient to meet their needs,” FERC ruled. “Moreover, neither party sufficiently explained why a generator that needed the capacity to obtain the natural gas supplies necessary to generate electricity during a period when Algonquin’s capacity is constrained would not match a higher bid.”

However, the commission said its ruling was “without prejudice to Algonquin developing other more targeted, justified proposals for consideration.”

The commission also granted Algonquin’s request to exempt from bidding an EDC’s capacity release to third parties managing capacity on an EDC’s behalf.

“By permitting capacity holders to use third-party experts to manage their natural gas supply arrangements and their pipeline capacity, [asset management arrangements] provide for lower gas supply costs and more efficient use of the pipeline grid,” the commission said. A compliance filing on this proposal is due in 30 days.

Access Northeast suffered a setback in August when the Massachusetts Supreme Judicial Court overruled state regulators’ order to allow construction costs be assessed to electricity ratepayers. Soon after the ruling, the EDCs withdrew their proposed contracts that were pending before the Massachusetts Department of Public Utilities. (See Eversource, National Grid Withdraw Requests to Bill for Pipeline.)

Access Northeast Complaint Dismissed

In a related case, FERC dismissed a complaint filed by electric generators seeking to block EDC contracts with pipeline owners as premature (EL16-93).

Public Service Enterprise Group and NextEra said the contracts would render the power markets discriminatory and suppress power prices. (See Generation Owners Seek to Block EDC-Pipeline Deals.)

“The circumstances giving rise to the complaint are in a state of flux and the commission does not have before it the concrete facts necessary to determine whether the tariff will be unjust and unreasonable. Several critical project elements of the individual states’ electric reliability programs are undetermined at this time,” FERC wrote.

The commission cited the Massachusetts court ruling, its concurrent order on capacity releases and its pending ruling on Access Northeast, which is expected in the fourth quarter.

September 5, 2016

EIM Governing Body Convenes First Meeting, Selects Leadership

By Robert Mullin

The newly established Western Energy Imbalance Market (EIM) governing body kicked off its first meeting last week by electing its leadership.

CAISO’s Board of Governors appointed the five-member body in June, selecting one each from five industry sectors: EIM entities, ISO-participating transmission owners, power suppliers and marketers, publicly owned utilities and state regulators. (See CAISO Board Appoints Western Energy Imbalance Market Governing Body.)

Kristine Schmidt, president of Dallas-based Swan Consulting, was selected to serve as the body’s chair. A former vice president at ITC Holdings and director at Xcel Energy, Schmidt has more than 30 years’ experience in the energy sector. She also worked as an adviser to former FERC Commissioner Nora Brownell.

Howe and Schmidt - Energy imbalance market (eim) leader meeting — The EIM Governing Body selected Kristine Schmidt and Doug Howe as its chair and vice-chair, respectively.

Doug Howe, an independent consultant and Ph.D. in mathematics, was chosen as vice chair. Howe has authored or co-authored more than 30 papers and presentations covering industry topics such as energy efficiency in the European Union and utility regulation in the U.K. He previously held an executive position with GPU Inc., which was acquired by FirstEnergy in 2001.

Carl Linvill, a member of the governing body, praised Schmidt for her “equanimity” and also expressed support for the wider Western regional representation that Howe — a New Mexico resident and former state regulator — will provide.

“We still have a lot to figure out and learn,” Linvill said. “Figuring out how to establish a regional presence really is emboldened and enabled by these two positions.”

“On behalf of the ISO, we want to give you our immense thanks for being willing to serve on this body,” CAISO CEO Steve Berberich said. “We consider the EIM as a critical attribute and will continue to support it for as long as necessary.”

A decade ago, Schmidt noted, nobody in the industry would’ve believed the region would have an EIM.

“We’re now seeing a regional market take shape in the West,” Schmidt said. “We’re hitting the ground running.”

Stakeholder Coordination

The governing body’s inaugural meeting included a set of briefings by EIM stakeholders and ISO staff to acquaint members with key structures affecting the market.

“There’s a lot of interest in what you’ll be doing,” said Tony Braun, an industry consultant who chairs the Regional Issues Forum, a loosely structured stakeholder group created by CAISO to foster broad regional discussion about EIM-related issues.

While the forum’s role “has not been concretely laid out,” the group’s first two meetings have been well attended, indicating a high level of interest in the EIM’s activities, Braun said.

The two most significant issues for forum participants: the bidding of external resources at the EIM’s interties and the impact of California’s greenhouse gas regulations on the market. (See related story, CAISO Kicks off Effort to Track GHGs Under Regionalization.)

Braun proposed that future meetings of the forum be coordinated with those of the EIM’s governing body and its state regulators’ group to improve collaboration and reduce participants’ travel for meetings.

“We’d love to hear how we can shape our processes to help you do your jobs,” Braun said.

Governing body members expressed appreciation for the work of the forum.

“The stakeholder-driven nature of the [forum] is probably something that is both difficult and necessary,” said governing body member Valerie Fong. “I found that the way [the meetings are] being run is very open.”

Schmidt called the meetings “extremely helpful.”

“We’re trying to do everything we can do to mitigate some of the travel issues,” she added.

Regulatory Collaboration

Ann Rendahl, chair of the EIM’s body of state regulators, sketched out the role of her group for the new governing body.

“Our purpose is to ensure that state regulators that aren’t involved in this market understand what is going on in EIM,” said Rendahl, a member of the Washington Utilities and Transportation Commission.

The group provides a forum for regulators to learn about EIM and CAISO developments that might be relevant to their jurisdictional responsibilities. While it can take a common position in CAISO and EIM stakeholder processes, individual regulatory commissions are not restricted from taking any position before FERC or the ISO board on EIM-related matters.

The regulators’ group is also charged with monitoring EIM governing body action items and selecting a voting member for the body’s nominating committee.

Rendahl emphasized the need for her group to closely coordinate its activities with that of the governing body. “We want to not just monitor, but work with the governing body,” she said.

ISO Process Basics

Governing body members received a briefing about CAISO’s stakeholder process from Brad Cooper, ISO manager of market design and regulatory policy.

Cooper explained the stakeholder process the ISO uses each fall to develop a “roadmap” of planned policy developments, including EIM initiatives. The ISO last year drew from a catalog of 49 potential initiatives, selecting only 10 because of staff constraints.

“We can’t develop everything in the catalog,” Cooper said.

A final roadmap is presented to the CAISO board — and, in the future, the EIM governing body — at the beginning of each year. The ISO informs stakeholders of any changes to the roadmap through its Market Performance and Planning Forum.

“The roadmap isn’t set in stone,” Cooper said. “For instance, we had the Aliso Canyon issue come up” earlier this year, forcing a modification of the roadmap. (See CAISO Seeks Rapid Response to SoCal Gas Restrictions.)

When developing the roadmap, ISO staff divide initiatives into four categories, including initiatives already in progress, policy changes mandated by FERC, non-discretionary efforts related to reliability or market efficiency, and discretionary initiatives.

For the last category, ISO staff and stakeholders together prioritize potential initiatives according to benefits and feasibility.

“If something could provide great benefits and is relatively trivial to do, that would get priority,” Cooper said.

Cooper acknowledged that CAISO’s policy process is driven more by staff than by stakeholders — and said the ISO prefers it that way.

“We realize that we made a commitment to look at other [stakeholder] processes [to implement under] regionalization, but we think our stakeholder process really allows us to quickly evolve policies,” Cooper said, adding that he didn’t think a project such as the EIM could’ve been developed under a stakeholder-led model.

“The ISO really tries to take a balanced view of our proposed policy,” Cooper said, contending that the ISO’s process does not factor in specific stakeholder interests, avoids “contentious voting structures,” and prevents bias or brokered policy decisions — allowing the ISO to focus on grid reliability.

Still, Cooper emphasized that “stakeholders are involved every step of the way,” including through “working group” meetings that focus on specific initiatives.

“We have a lot of open interaction that may not be possible with more formal stakeholder processes,” Cooper said. “This allows us to really interact with our stakeholders and get their input.”

September 5, 2016January 3, 2024

Company Briefs

The owner of the 40-MW White Pine coal-fired power plant in Michigan’s Upper Peninsula blasted MISO after receiving a 90-day notice that the grid operator will terminate its $7.3 million annual system support resource agreement with the 60-year-old plant on Nov. 26.

White Pine Electric Power, a subsidiary of Traxys North America, said the decision jeopardizes reliability until 2020, when 170 MW of new natural gas-fired plants will come online. “This is a short-sighted decision by MISO that they claim is about utility rates,” said White Pine board Chairman Brent Zettl.

The utility claims that the study MISO used to make its decision did not properly evaluate emergency scenarios, arguing that the plant provides a failsafe against unplanned outages.

More: White Pine Electric Power

Duke Adds Former Nuke Exec to Board

William E. Webster Jr., former executive vice president for industry strategy at the Institute of Nuclear Power Operations, joined Duke Energy’s board of directors eﬀective Sept. 1.

Webster retired from INPO on June 30, ending a career there that began in 1982. While at INPO, he also served in “on‑loan” leadership positions with FPL Group and Arizona Public Service’s Palo Verde Nuclear Generating Station.

He received his senior reactor operator certiﬁcation at Duke’s Brunswick nuclear plant and has a bachelor’s degree in civil engineering from Villanova University.

More: Duke Energy

Xcel Adds Another Wind Farm to Portfolio

The 200-MW Odell Wind Farm began generating power in southwestern Minnesota last week under a 20-year power purchase agreement with Xcel Energy, its fourth wind facility in the Upper Midwest.

Owned and operated by Canadian company Algonquin Power & Utilities, Odell consists of more than 100 turbines erected in four counties.

Xcel gets 14% of its power from wind sources in the Upper Midwest and predicts the share will rise to 22% in 2020. Xcel’s ultimate goal is 42% from wind.

More: Star Tribune; La Crosse Tribune

Former NYPA CEO Joins NYISO Board

NYISO has named former energy executive Roger B. Kelley to its Board of Directors, effective this month. He replaces Vikki L. Pryor, whose term expired in April.

Kelley has more than 40 years of experience in the electric generation and transmission business. He previously served as CEO of Peregrine Midstream Partners in Houston. He was also CEO of Midland Cogeneration Venture in Midland, Mich.; CEO of Fortistar Renewables, based in White Plains, N.Y.; and CEO of the New York Power Authority.

“Roger has extensive experience in the energy industry, including as president and CEO of the New York Power Authority,” said Michael Bemis, NYISO’s board chair. “We appreciate his willingness to serve as a director. I’m confident we will benefit from his judgment and counsel.”

More: NYISO

Tesla-SolarCity Filing Reveals Cash-Strapped Companies

Prior to agreeing to a merger with Tesla, SolarCity considered selling its Buffalo solar panel manufacturing plant, which is scheduled for completion next June with $750 million in state assistance, according to a filing with the U.S. Securities and Exchange Commission.

SolarCity eventually decided a sale of the plant, a centerpiece of Gov. Andrew Cuomo’s Buffalo Billion economic development program, would not provide an adequate return for company shareholders. But the filing reveals how strapped for cash SolarCity is, even as it considered being acquired for $2.4 billion. The company’s operations rely heavily on a business model that allows customers to install rooftop solar with no upfront costs, forcing it to constantly raise money from investors.

The filing also reveals at least three other firms declined to acquire SolarCity before it accepted the offer from Tesla, which is facing a cash crunch itself. The company will have to pay $422 million to bond holders in the third quarter. Tesla’s debt-to-equity ratio was 145.5% as of June 30; SolarCity’s was 375.6%.

More: The Buffalo News; The Wall Street Journal

Developer Wants to Double Up Indiana Plant

Development Partners, which is building a $500 million, 700-MW natural gas plant in northern Indiana, has asked MISO to allow it to double the size and the cost of the plant.

The White Plains, N.Y., company wants permission to add two more turbines to the St. Joseph Energy Center near the Michigan border. The first phase of the project is scheduled to be completed in 2018.

After Development Partners gets interconnection approval from MISO, which it hopes to earn by the end of the year, the developer would work with local officials to approve a site plan.

More: South Bend Tribune

Enbridge Puts Minnesota Pipeline Project on Hold

Enbridge Energy Partners, which recently invested $1.5 billion into a rival oil-pipeline project, has put its proposed Sandpiper Pipeline in Minnesota on hold, saying current demand for crude oil no longer supports the need for the project.

Sandpiper, which was initiated three years ago, aimed to carry up to 225,000 barrels of oil from North Dakota through Minnesota and then on to Superior, Wis. The proposal faced heated opposition from Native American tribes and environmental groups who objected to the proposed path, which would have crossed numerous lakes and rivers.

Enbridge stopped short of saying the project was dead, but it did say the five-year projection of production in North Dakota’s Bakken region doesn’t forecast the need for more pipeline capacity. The decision comes just after its recent $1.5 billion investment in the Bakken pipeline system, which includes the Dakota Access project.

More: MPR News

Oregon Coal Plant to Run Full Biomass Test

Portland General Electric is exploring the possibility of converting its coal-fired Boardman power plant in eastern Oregon to biomass.

The utility plans to run the 550-MW facility on woody biomass for one full day this year as an experiment, following a successful test last year using a 10-to-1 mixture of coal and biomass. The process will entail pulverizing wood debris into the substance before feeding it into the plant’s boiler.

Boardman is slated for closure in 2020, but the use of biomass could extend the life of the plant. Success of the project will hinge on plant conversion costs and securing a steady supply of fuel.

More: East Oregonian

Southern Co., Kinder Morgan Close Deal on Pipeline System

Southern Co. has acquired 50% of Kinder Morgan’s Southern Natural Gas pipeline system, the companies announced. The 7,000-mile system runs from wells in Texas, Louisiana, Mississippi and Alabama to markets in the southeast. Terms of the acquisition were not announced. Kinder Morgan will continue to operate the pipeline system.

Southern CEO Thomas A. Fanning hinted at other deals possibly in the works. “With our new ownership stake in Southern Natural Gas, we look forward to working with Kinder Morgan to explore future opportunities to deliver natural gas to customers,” he said.

More: Southern Co. and Kinder Morgan

Talen Notifies NRC it is Canceling Nuclear Plant

Talen Energy withdrew its request for an operating license from the Nuclear Regulatory Commission for the proposed Bell Bend nuclear station in Berwick, Pa., saying that the reactor design company’s decision to suspend its certification process left it no choice.

The Allentown, Pa., company said that it had posted a $122 million loss associated with the project when it released its second-quarter results and that it would stop attempts to get a license for the plant. The reactor design company, Areva, asked NRC in 2015 to stop its design certification process. A Talen spokesman said seeking another design company wasn’t feasible.

Talen said the decision was not related to is pending merger with Riverstone Holdings.

More: The Morning Call

GE Joins MIT Energy Initiative

General Electric is joining an energy research program at the Massachusetts Institute of Technology that aims to cut carbon emissions.

GE is contributing $7.5 million to the MIT Energy Initiative for research, particularly in solar power, energy storage, advanced power grids and carbon sequestration, company officials said.

“This partnership really is about advancing the state of the art in low-carbon technologies,” said Steve Bolze, chief executive of the $29 billion GE Power division.

More: The Boston Globe

EnerNOC Wins BQDM Contract from Con Ed

EnerNOC has been awarded a multi-million-dollar contract by Consolidated Edison for the Brooklyn-Queens Demand Management program, part of New York’s Reforming the Energy Vision initiative. The program’s aim is to reduce demand in certain areas of New York City, delaying or eliminating the need for a $1.2 billion substation.

The BQDM project has been described as the largest modern “non-wires” alternative program in the U.S. relying on the use of energy efficiency and demand-side management in lieu of traditional generation and distribution infrastructure.

More: EnerNOC

Duke, Solar Devs Reach Interconnection Agreement

Duke Energy and 33 solar developers reached an agreement that will allow many solar generation projects to go forward and interconnect with the utility’s grid.

Earlier this summer, Duke announced that so many solar projects are seeking interconnection with their grid that it might cause problems and was going to require each new project to undergo a technical review. The new agreement allows the projects to connect while preserving Duke’s right to disconnect if problems arise. There are 3,300 MW of solar projects in various stages of planning and construction in North Carolina.

“In some areas of our system, we’re reaching a saturation point with solar, and in some places it is ill-placed,” a Duke spokesman said. The intermittent nature of the generation could cause problems with some of the lower-voltage circuits, the company says.

More: The Charlotte Observer