Commenters Laud, Blast New York’s Nuclear Subsidy Plan

By William Opalka

New York’s proposal to subsidize upstate nuclear power plants was blasted as a corporate giveaway and embraced as an economic lifeline and necessity to reduce carbon emissions in comments filed last week with regulators (15-E-0302).

The state Public Service Commission closed the comment period Friday on the cost of the plan’s zero-emission credits. (See NYPSC Extends Comment Period on Nuclear Subsidy.)

Although it was the first time commenters had the opportunity to respond to the projected price tag of the subsidy, the arguments were familiar.

The subsidy was proposed earlier this year as part of the larger Clean Energy Standard. The original proposal pegged the nuclear subsidy as the difference between the average wholesale price of electricity and the operating cost of the nuclear plant. (See New York Would Require Nuclear Power Mandate, Subsidy.)

On July 8, the PSC staff released what it called a “responsive proposal” that calculated ZECs based on estimates of the social cost of carbon. The PSC said that would be $17.48/MWh for qualifying nuclear power generators in the first two years of the 12-year program, or about $965 million.

Staff also modeled the eligibility determination to take into account the costs and benefits of other clean energy alternatives. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)

A coalition of environmental groups — including the Alliance for a Green Economy, the Council on Intelligent Energy & Conservation Policy, the Nuclear Information and Resource Service and the Sierra Club’s Atlantic Chapter — continued its opposition.

“After claiming the nuclear tier would cost only $270 million over 12 years, the new ‘responsive proposal’ outlined a plan that will cost nearly $1 billion in just the first two years, with costs escalating to total approximately $7.6 billion. The program will likely cost more than $10 billion if Indian Point gets included,” they wrote.

The Brattle Group, which had done a study last year for New York labor groups, said the subsidy is cost-effective, estimating that electricity costs would rise by an average of $1.7 billion a year between 2015 and 2024 without the nuclear plants. “Although customers would pay for ZECs, they would avoid a power price increase that is larger than the ZEC cost. This means that customers actually pay less overall for power than if the upstate nuclear plants were to shut down.”

Upstate Energy Jobs, a coalition of municipal, business, labor, education and economic development leaders, said it supports the ZECs to keep the plants operating during the transition to clean sources. “Furthermore, renewable energy sources are not being constructed at a pace that makes replacing nuclear power with renewable power a realistic approach at this time.”

Towns and legislative members from western New York also focused on the plants’ economic impact. Comments from the Town of Scriba, which is the site of three nuclear plants, Nine Mile Point 1 and 2 and James A. FitzPatrick, were typical.

“More than any other community in New York state, we are most affected by the potential closure of these facilities should a reasonable and workable solution to the current financial difficulties facing our upstate nuclear-powered electric generators not be realized in a timely manner.”

fitzpatrick reliability - new york nuclear subsidy plan nypsc entergy exelon — Fitzpatrick Nuclear Plant *Source Entergy*

Exelon is the owner of three nuclear power plants on Lake Ontario, with two in Scriba, and is in negotiations to acquire a fourth. (See Entergy in Talks to Sell FitzPatrick to Exelon.) FitzPatrick has been scheduled to close early next year by its current owner, Entergy. Exelon said it would close Nine Mile Point 1 and R.E. Ginna early next year if a contract is not in place by the end of September.

“Time is of the essence,” Entergy reiterated in its comments.

A group representing large commercial and industrial customers complained that the July 8 proposal is an entirely new formula that is considerably more expensive than what was discussed in earlier proceedings. “In New York’s apparent haste to appease the owners of selected nuclear generation facilities to ensure the continued operation of those facilities, customers are being exposed to potentially 12 years of artificially inflated and excessive subsidy obligations,” it wrote.

Likewise, the National Energy Marketers Association said the proposal interferes with the development of the retail market. “The proposed purchasing and pricing mechanism under which [load-serving entities] will be required to purchase ZECs will have an adverse impact” on energy service companies, it said.

NYISO emphasized the environmental and reliability attributes of the plants. “The state’s nuclear power stations are non-emitting resources that already contribute significantly to the state’s production of clean energy and supply 30% of New York’s energy requirements.”

The Pace Energy and Climate Center supports the ZEC program by emphasizing it as a temporary bridge until renewable energy is built at scale, a point also emphasized by Exelon’s Constellation Energy Nuclear Group.

“While the long-term goal for New York should be to replace the state’s existing nuclear fleet with renewables that are additional to the CES target, over the next 12 years, the governor’s plan to support the state’s nuclear fleet will ensure that New York is able to achieve its carbon emissions targets while making rapid progress towards the CES goal,” Pace wrote.

The American Petroleum Institute proposed an expansive definition of credits for carbon reduction. “The NYPSC must create a level playing field by making emissions credits available to all technologies and energy sources that can reduce net GHG emissions from the electricity sector, including … energy efficiency measures, and other forms of electricity generation that can help achieve compliance with state emission reduction goals, such as natural gas, [combined heat and power], biomass, and waste heat power,” it said.

The PSC could act on the CES at its next regular meeting on Aug. 1.

July 25, 2016

CAISO: Forecasting Challenges Drove Increased Regulation Requirements

By Robert Mullin

CAISO last week provided an explanation of its decision to increase regulation requirements in response to the growing variability on its system.

The ISO’s Department of Market Monitoring last month called attention to the sharp rise in costs from the requirements, prompting the California Energy Commission to ask the ISO to justify the move. (See CAISO Regulation Costs Quadruple as Price, Procurement Jump.)

During a Market Performance and Planning Forum last week, CAISO said it doubled its frequency regulation service requirement from late February to mid-June in response to recurring short-term generation forecasting errors stemming from variable wind and solar resources during late winter and spring.

Regulation-Requirements---February-through-June-2016-(Source-CAISO)---content — CAISO’s regulation procurement ramped up sharply ahead of spring, but was backed down with the more predictable summer weather patterns.

The forecasting problem is mostly isolated to spring, when high renewable output often coincides with periods of low loads in California. At the same time, weather patterns tend to be more erratic, often making it especially difficult to predict renewable output on a moment-to-moment basis.

Regulation prices more than doubled shortly after the ISO increased its daily regulation procurement from 400 MW or less to as much as 800 MW in late February. Daily payments to regulation service providers surged from $100,000 to more than $400,000, the ISO’s Monitor found last month.

The ISO rolled back regulation requirements to previous levels for summer because of more predictable weather patterns.

Further compounding the spring forecasting issue is the increasing adoption of residential rooftop solar, which is subject to the same variability as utility-scale projects. The ISO estimates it has nearly 5,000 MW in rooftop solar in its balancing area, with new installations added daily. Variability in behind-the-meter rooftop output complicates matters by causing loads to skew from forecasts depending on whether the sun is shining.

The problem “happens more in the off-season — with more of the clouds coming in,” said Amber Motley, CAISO short-term forecasting manager. “Timing and forecasting of [generation] ramps are very difficult. Forecasting cloud coverage is difficult.”

Variable wind production can also be a factor, with cold fronts making it difficult to predict the timing of wind ramps and changes in wind direction causing intermittency.

Clyde Loutan, ISO senior advisor for renewable energy integration, said weather changes can occur too quickly to incorporate revised forecasts into the real-time market run. He also pointed out that forecasting errors are not covered under the ISO’s real-time contingency dispatch process, which sets aside generation to allow the system to recover from major disturbances.

“So you have to rely on regulation,” Loutan said.

“Seems like it’s more a failure of the forecast,” said Dan Williams, CAISO markets analyst at Portland General Electric. “And that should be changed by changing the market rather than rolling it into regulation.”

Loutan countered that he didn’t know of any forecaster that could reflect the intermittency in the five-minute market.

“When you think about how these markets were designed, they were really designed for conventional units,” he said.

Loutan also pointed to a clear financial incentive driving the ISO’s increased requirement.

“Back in January we had some pretty bad days when we didn’t control the frequency well enough,” he said. “For 11 hours, we had a hard time controlling the system. We found out that we were running out of regulation.”

If the condition had persisted longer than 30 consecutive minutes, the ISO would have been subject to as much as $1 million in NERC penalties, he said.

Carolyn Kehrein, principal consultant for the Energy Users Forum, suggested that increased regulation costs should be allocated to intermittent resources if the forecasting problem continued and the ISO didn’t develop new tools to deal with it. She said increased costs for intermittency should encourage the “right kind” of renewable development, such as geothermal.

Wei Zhou, senior project manager with Southern California Edison, agreed with applying the cost-causation principle to the problem.

“This is something that we’re looking at long-term,” said Loutan, referring to the forecasting issue at large. “But for now we just wanted to explain why we increased our regulation procurement.”

July 25, 2016

PUCT Asks ERCOT, SPP to Coordinate on Lubbock PL Move

By Tom Kleckner

Staff from ERCOT and SPP began discussions last week to determine how to work together on Lubbock Power & Light’s planned move to the ERCOT grid.

The grid operators conducted a staff-only call July 21 at the behest of the Public Utility Commission of Texas, which has bifurcated LP&L’s application to join ERCOT into two cases: one involving the move itself and the other involving a cost-benefit analysis of on ratepayers. (See Texas PUC Takes Slow Approach with LP&L Integration.)

PUC Chair Donna Nelson last week filed a memo describing the information the commission will be looking for from the grid operators’ studies on LP&L’s migration (Docket No. 45633).

“A joint study between ERCOT and SPP on the tangible costs and benefits could mitigate the issues that arise when studies are conducted by different parties,” Nelson wrote.

Commissioner Ken Anderson agreed with Nelson during the PUC’s July 20 open meeting, saying it is important the two entities know how they’re going to proceed.

“The question I will have for SPP and ERCOT … if they can agree on the same method to analyze not just the options of how to, but the more important one of the costs and benefits,” he said. “Then, finally, the costs that stranded ratepayers in SPP would have as a result, if any. I’m not conceding there are [some] now, but how do you think about the impact on Texas ratepayers outside of Lubbock?”

“In my mind, the key component here is so you can interpret the information, and not having a situation where you’re comparing apples to oranges,” Warren Lasher, ERCOT’s director of system planning, told Nelson. “I don’t feel at this time we have to do a joint study, but what we can do is ensure you have the information you can translate between the two studies.”

SPP’s principal regulatory analyst, Sam Loudenslager, told the PUC the RTO staffs would file a preliminary draft study scope before the commission’s next open meeting on Aug. 18.

LP&L announced last September it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT study completed in June indicated it will cost $364 million and take 141 miles of new 345-kV right of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy, ERCOT Board of Directors Briefs.)

Nelson and her fellow commissioners are also concerned about other companies that may be looking to join ERCOT. Rayburn Country Electric Cooperative, an ERCOT-turned-SPP member with 85% of its load in the Texas grid, has asked the ISO to conduct an integration study as it considers rejoining.

“I’m inclined to think we deal with Lubbock as a one-off,” Anderson said. “It’s a much smaller deal for Rayburn. The question becomes the precedent” it sets.

The commissioners agreed to discuss a rulemaking for new ERCOT members at its next meeting.

“I favor initiating the production of pertinent studies now while concurrently determining whether we need a rule for a clear framework for similar requests in the future,” Nelson said in her memo.

Nelson also stressed the importance of maintaining ERCOT’s independence from federal oversight. “Of import to us all, we need to ensure that Lubbock’s move into ERCOT will not invoke federal jurisdiction over ERCOT,” she said.

In her memo, Nelson provided additional issues she felt were “specific to the matter at issue:”

The impact to the ERCOT and SPP systems’ reliability and operational costs;
The costs of any facilities that would be required or that could be avoided on the ERCOT and SPP systems;
The benefits or challenges that the subject loads would provide or impose on each system;
The impact on wholesale and retail customers, markets and market participants;
Whether LP&L’s status as a municipal utility should be considered in the cost-benefit analysis; and
The length of time the no-harm standard — making LP&L liable for added costs passed on to customers — should be applied to the utility for its admission to ERCOT.

Nelson said she would also like to see analysis of alternative or gradual paths for entry into ERCOT “that are prudent for us to consider” under the cost-benefit analysis.

July 25, 2016June 15, 2023

Federal Briefs

A federal judge in Massachusetts on Thursday ordered a full civil proceeding, including a jury trial if necessary, in FERC’s enforcement of a $5 million fine for alleged market manipulation by a power generator (IN15-4).

U.S. District Judge Mark G. Mastroianni said the proceeding is necessary to preserve the due process rights of Maxim Power, which the commission said billed ISO-NE for oil-fired generation when the company was actually burning cheaper natural gas at one of its plants. (See Maxim to FERC: Prosecute or Drop Probe.)

Mastroianni said Maxim is entitled to a full de novo review, allowing it the full range of discovery, rather than be limited to reviewing FERC’s evidence.

“While respondents were free to submit evidence and responsive arguments, they were unable to seek discovery, depose witnesses interviewed by FERC, gain any insight into the presentation of the case made by FERC’s enforcement staff to the commissioners during the investigative phase or present their own witnesses,” Mastroianni wrote.

More: Law360

Court Stays EPA Haze Plan for Texas

The U.S. 5th Circuit Court of Appeals has stayed implementation of an EPA-imposed regional haze plan for Texas and rejected the agency’s motion to move the case to the D.C. Circuit Court of Appeals, agreeing with petitioners who said they “could suffer irreparable injury in the absence of a stay.”

The court was unconvinced by EPA, which said a lack of a haze plan would harm the public and visibility at national parks. The agency itself acknowledged that the federal implementation plan would not reduce emissions for at least three years, the court noted. ERCOT also expressed reliability concerns over the plan.

EPA rejected Texas’ regional haze plan as insufficient. The federal plan sets sulfur dioxide emission limits on eight coal-fired plants in the state.

More: Bloomberg BNA

BOEM to Hold Online Drilling Rights Auction

The Bureau of Ocean Energy Management will auction drilling rights for nearly 24 million acres in the Gulf of Mexico via live streaming on Aug. 24, the first time the agency has conducted a lease sale online.

“Making government data immediately available is a valuable resource for taxpayers, both in terms of dollars and cents but also in efficiency,” BOEM Director Abigail Ross Hopper said. “Through the use of technology, we can deliver our lease sale information in a much more effective and accessible way to a much wider audience.”

It will be the final lease sale in the Western Planning Area under the Obama administration.

More: Morning Consult

US Improves Ranking In Energy Efficiency

The U.S. moved up to 8th from 13th in a study of energy efficiency among nations. The country still lags behind Germany, Italy and Japan (tied for second), France, the U.K., China, Spain and South Korea, according to a report issued by the American Council for an Energy Efficient Economy.

According to the report, 23 countries account for 75% of the energy consumed on Earth. The U.S. was able to boost its ranking because of improvements in energy use per dollar of gross domestic product, as well as a change in the way energy policies are weighted in the study.

“Despite its leadership on a number of policies, the United States falls behind most of the [European Union] countries on our list in addition to China and Japan,” according to the report. “The United States still has no binding energy savings goals, unlike Germany, France, Japan and other countries, which have a national energy conservation plan in place.”

More: ACEEE

Former Employee: SoCalEd to Blame for San Onofre Leak

A report by a former engineer employed by Southern California Edison concluded that workers ran the San Onofre nuclear station near San Diego at higher temperatures and pressures than allowed, eventually causing a radiation leak that forced the plant to be permanently shut down.

Vinod Arora based his report on Nuclear Regulatory Commission documents obtained through a Freedom of Information Act request. Arora is still seeking daily control room logs from the company. “If those logs have not been destroyed, they will show immediately whether or not Edison risked the lives of 8.5 million Southern Californians by redlining the Unit 3 generators,” he said.

The company blames Mitsubishi Heavy Industries, which designed the steam generators at the plant for the problems.

More: The San Diego Union-Tribune

Nations Working on Rule to Limit HFCs

EPA Administrator Gina McCarthy said she is confident the U.S. and other countries will be able to reach an agreement on a rule limiting the release of hydrofluorocarbons (HFCs) before the end of the year. McCarthy, who is leading a U.S. delegation that includes Secretary of State John Kerry, said she has seen clear signs of progress.

Negotiators from about 200 countries are in the midst of meetings in Vienna under the Montreal Protocol, a 1987 treaty that limited the emission of hydrochlorofluorocarbons (HCFCs), which severely damage the ozone layer.

HFCs, potent greenhouse gases used as refrigerants that were developed as alternatives to HCFCs, do not fall under the original agreement, as they do not affect the ozone layer. A rule resulting from the meetings taking place would amend the Montreal treaty to include the gases. A final deal is expected to be reached in October at a meeting in Rwanda.

More: Bloomberg BNA; Reuters

White House Pledges $4.5B For EV Charging Stations

The Obama administration announced it is freeing up $4.5 billion in Energy Department loan guarantees for commercial electric vehicle charging stations.

The funds are part of the administration’s broader initiative to accelerate the use of EVs. It will also designate and develop “charging corridors” to form of a national network of stations by 2020.

The initiative to provide more stations “serves the goal of providing consumers with more comfort that they will be able to move across regions and across the country in their electric vehicles,” a White House official said.

More: The Washington Post

Navy, Dominion to Partner On 21-MW Solar Facility

The U.S. Navy and Dominion Virginia Power plan to build a 21-MW solar facility at the Navy’s Oceana Naval Air Station near Norfolk, according to the Solar Energy Industry Association.

Dominion expects the plant to be operational by the end of next year. Under the agreement, Dominion will own and operate the facility for 37 years in exchange for electrical upgrades at the base.

More: The Virginian-Pilot

July 25, 2016

State Briefs

Electricity Price Plunge Continues in ISO-NE

ISO-NE said that prices and consumption remained low throughout New England in June.

The six-state region’s average real-time, monthly wholesale power price during June was $21.24/MWh, up 8.3% from June 2015’s average price of $19.61/MWh, but lower than May’s $21.29, which held the record for the third-lowest price since 2003 for only a month.

Total energy consumption during June was at the second-lowest level of any June since 2000, likely because of continued mild weather, the RTO said. The lowest average monthly price ever is $17.20/MWh, set in March.

More: ISO-NE

CALIFORNIA

Regulator to Probe SCE Long Beach Outages

The Public Utilities Commission has opened a penalty case against Southern California Edison over a series of underground electrical fires that caused explosions and cut power to thousands of customers in Long Beach last July.

The proceeding will determine whether the utility violated any regulations and provided an adequate emergency response to the events, which left some customers without service for as many as five days and caused explosions strong enough to blow manhole covers into the air.

More: KPCC

INDIANA

NIPSCO Electric Rate Increase Approved

The Utility Regulatory Commission sanctioned a 6% electric base rate hike for Northern Indiana Public Service Co. last week, the first change to base rates since 2011.

NIPSCO said it needs the money to pay for higher expenses and service upgrades. The utility said a typical residential customer will pay $5.70 more per month.

The base rate agreement was previously struck by the Office of Utility Consumer Counselor, NIPSCO’s industrial customers, a coalition of eight municipalities and the United Steelworkers in February. Consumer Counselor David Stippler called the agreement “a fair resolution for NIPSCO’s residential and commercial customers.”

More: NiSource

KENTUCKY

Court Nixes Utility’s Plan to Buy Power from Biomass-Burning Facility

A state Court of Appeals panel has struck down ecoPower Generation’s contract to sell electricity to Kentucky Power.

The court said there was no evidence that ecoPower’s biomass-burning plant would result in an economic benefit to customers or the region. The court cited testimony that the agreement would result in an increase of up to 7% in the average monthly residential bill in the first year and a jump of up to 13% in later years.

The ruling puts the future of the plant, which would burn wood and sawdust to generate enough electricity for 30,000 homes, into doubt. Kentucky Power is reviewing the ruling before it decides whether to appeal, a spokesperson said.

More: Lexington Herald Leader

MARYLAND

Delmarva Power Requests $66.2M Rate Increase

Delmarva Power, now under Exelon ownership, is asking regulators to approve a $66.2 million electric rate base increase to pay for reliability improvements and smart grid upgrades conducted over the past four years. The increase would boost a typical monthly bill by 14.5%.

If approved by the Public Service Commission, the rate adjustment would translate to a $21.42 increase on the monthly bill of residential customers using 1 MWh, to $168.64 a month.

Delmarva said it has spent more than $330 million on improvements in the state since 2012. Its last rate-increase request was in 2013.

More: Delmarva Power

MASSACHUSETTS

Pipeline Loop Opponents Head to State Court

Opponents of a proposed natural gas pipeline loop through a state forest want to block a water-quality approval certificate issued June 30.

A coalition of environmentalists and landowners appealed the state Department of Environmental Protection’s approval of Kinder Morgan’s 4-mile Connecticut Expansion Project with the agency. The final decision would come from DEP Commissioner Martin Suuberg.

More: The Berkshire Eagle

MONTANA

Developer: Low Rates Endanger Wind Project

Developer Greycliff Wind Prime’s proposed 25-MW wind farm is unlikely to move forward following the Public Service Commission’s decision to set its wholesale price to NorthWestern Energy at $45.49/MWh, about 16% lower than the price it says it needs to make a profit.

“It’s not a rate that works. It’s also not a rate that’s realistic,” said Steve Tyrell, a Greycliff stakeholder. Developers said they needed a price in the mid-$50s, which would have been similar to the rate for another NorthWestern renewable energy source.

Renewable energy projects are on a two-month losing streak with the PSC. The commission in June pulled the plug on guaranteed rates for small solar projects at the request of NorthWestern.

More: Billings Gazette

NEVADA

Peppermill Casinos Seeks to Sever Ties with NV Energy

Reno-based Peppermill Casinos became the third hotel casino operator in recent months to notify state regulators that it intends to leave NV Energy and acquire electricity from other sources.

The move will entail a costly exit fee. Las Vegas Sands reversed its decision to leave the utility after the Public Utilities Commission determined the company would have to pay $24 million to do so.

Peppermill has invested $9.7 million in onsite geothermal generation. “We are committed to continuing that investment in responsible and renewable energy sources,” a company executive said. Wynn Resorts and MGM Resorts International have also announced their intentions to leave NV Energy.

More: Reno Gazette-Journal

NORTH CAROLINA

Duke Energy on Track To Buy Piedmont Natural Gas

Regulators completed a two-day evidentiary hearing examining Duke Energy’s $4.9 billion acquisition of Piedmont Natural Gas, moving the merger toward a decision by the Utilities Commission as early as October.

The commission’s staff supports the merger, the costs of which will be charged to shareholders, not customers, the companies said.

Under the deal, Duke will give Piedmont’s customers in the state a $10 million break on bills over two years. It also will donate $17.5 million to charity over four years and earmark $7.5 million to help low-income customers and support community job training.

More: Charlotte Business Journal

Duke Asks Fed Judge To Block Ash Testimony

Duke Energy has asked a federal judge to block the testimony of a state toxicologist in a lawsuit, filed against the utility concerning its handling of coal ash, from being made public.

The company argued that the testimony of Dr. Kenneth Rudo, of the epidemiology branch of the state Department of Health and Human Services, about his views on the toxicity of coal ash and its effect on drinking water supplies is “largely hearsay” and would prevent the company from getting a fair hearing. The lawsuit was filed by environmental organizations.

Residents have received mixed messages from state officials about the safety of their drinking water, who were told to avoid using it last month after receiving assurances that it was safe. Testimony transcripts already released by the plaintiffs show disagreement among state scientists about the advice to give residents.

More: WRAL

NORTH DAKOTA

Application for State’s Largest Wind Farm Filed

A Renewable Energy Systems Americas subsidiary filed an application with the Public Service Commission last week for what would be the largest wind farm in the state. Glacier Ridge Wind Farm proposed a 300-MW project with nearly 100 turbines in Barnes County.

Glacier Ridge aims to start construction in November and complete work in 2019.

More: The Bismarck Tribune

OKLAHOMA

Regulators Approve Opt-outFees for PSO Smart Meters

The Corporation Commission approved a plan allowing Public Service Company of Oklahoma to charge a $28 monthly fee to customers who opt out of installing a smart meter. The three-person commission unanimously approved the fee. Customers will also need to pay a one-time fee of $71, which will increase to $110 next year.

PSO originally requested a $28 monthly fee and one-time fees between $183 and $261. Its customers already are paying $3.11 monthly fees for smart meter installation, part of a $133 million rate case settlement the commission approved in April 2015.

Commission Chairman Bob Anthony said estimating costs is tricky because the commission is starting from scratch on the opt-out program. “We haven’t done this before; we don’t know if there’s going to be 200, 500 or 1,000 people [who] sign up for this program,” Anthony said.

More: The Oklahoman

Fire Damage to GRDA Plant Could Reach as Much as $200M

The Grand River Dam Authority says its costs could reach $200 million to recover from a July 1 fire at its main generating facility in Chouteau. Officials from the state-owned utility say the final bill will depend on the cost of rebuilding the larger of the two coal-fired units affected.

The utility believes the fire was started by a lightning strike that knocked out the unit’s cooling pumps, causing it to overheat and creating a friction fire. The fire spread to the roof of the building and caused the other coal-fired generator, Unit 1, to automatically shut down.

Assessing the damage to Unit 2 and the building that houses both units is expected to take about a month. GRDA recently completed an $86 million environmental upgrade to the 30-year-old Unit 2.

More: Tulsa World

PENNSYLVANIA

FE Subsidiary Starts Work on 5-Year Grid Improvement Plan

West Penn Power, a subsidiary of FirstEnergy, is starting work on $17 million of grid improvement projects to enhance reliability for its 720,000 customers.

The projects are part of the company’s five-year infrastructure improvement plan approved earlier this year by the Public Utility Commission.

The long-term plan calls for $88 million to be spent through 2020 on upgrades, including installing protective devices on wires and poles, rebuilding transmission lines and installing automated and remote control devices.

More: FirstEnergy

RHODE ISLAND

Community Boos, Lambasts Governor over Gas Plant

Gov. Gina Raimondo offered little comfort to residents opposed to a 1,000-MW natural gas plant in Burrillville, where she said at a community meeting that gas-fired generators are needed to bridge the gap until clean generation is built at a larger scale.

“I’m for green energy and moving as fast as we possibly can from fossil fuels and towards cleaner sources of energy,” she said. “But I’m also for keeping energy prices as low as possible for the people of Rhode Island.” Raimondo has previously said that the $700 million plant proposed by Invenergy would create jobs and moderate electricity prices.

“What I need to do as governor is balance the interests of all the people,” she said. “In the near term, natural gas is a piece of that puzzle.” This final comment drew boos from those in attendance. Raimondo then had to fend off criticism from speakers.

More: Providence Journal

July 25, 2016

SPP Sets New Record for Peak Load — Twice

As expected, SPP’s first summer since the Integrated System joined its system last year has resulted in a new record for peak load, as well as the RTO’s first two peaks above 50,000 MW.

The RTO recorded a peak load of 50,083 MW at 4:35 p.m. July 20, surpassing that record the next day at 4:47 p.m. with 50,622 MW. The previous record of 48,323 MW was set in June.

The record peaks were not a surprise, given the addition of the Integrated System’s 5,000 MW of added peak demand and the oppressive heat wave in the Great Plains. Bruce Rew, SPP’s vice president of operations, told the Regional State Committee last week the RTO will “likely continue to see increases in peak numbers, primarily driven by the addition of new members.”

– Tom Kleckner

July 25, 2016

Company Briefs

Great River Energy will retire its Stanton Station power plant by May 2017, saying the central North Dakota plant is no longer economic given current low prices. The 189-MW coal-fired plant began generating power in 1966 and has a staff of 65 people.

“It became clear that retiring the plant was in the best interest of our member cooperatives,” CEO David Saggau said. The company will develop plans over the next nine months to decommission the plant, he said.

Stanton has been generating electricity on a limited basis since March, firing up only 65 to 75% of the time when market prices made it economical.

More: The Bismarck Tribune

Empire Launches EV Initiative With Joplin Charging Station

Empire District Electric unveiled an on-campus charging station for electric vehicles at Missouri Southern State University. The station is open to the public at no charge.

The station is part of Empire’s “Evolve” campaign, in which the company has committed to spending 5% of its annual vehicle fleet budget on EVs. The company is also offering rebates ranging from $750 to $2,000 to customers who purchase an EV.

Promoting EV use makes sense as the energy industry transitions to renewable resources, Empire CEO Brad Beecher said. He noted that SPP gets 15% of its electricity annually from renewables, particularly wind. “Any time that you’re driving an electric car and it’s been charged, at least partially, with renewable resources, it is not just less emissions, it is no emissions,” Beecher said.

More: The Joplin Globe

Lawsuit Seeks $30M from Chesapeake, SandRidge

Chisholm Partners and 16 oil and gas investors filed a lawsuit in U.S. District Court in Kansas seeking $30 million in damages from Chesapeake Energy and SandRidge Energy under the Sherman Antitrust Act.

Chisholm says it sold oil and gas leasehold interests to Chesapeake at prices that were “artificially depressed” because of a conspiracy alleged in a federal criminal indictment of Chesapeake CEO Aubrey McClendon. The sale of the leases produced $10 million less than they would have absent a conspiracy, the suit said.

McClendon was indicted March 1 on charges he led a scheme to coordinate bidding for oil and gas interests with another active bidder, which the lawsuit claims was SandRidge. He died a day later when the vehicle he was driving smashed into a bridge embankment in northeast Oklahoma City.

More: The Kansas City Star

Enel Expanding Wind Farm in Oklahoma

Enel Green Power North America began construction last week on the 64-MW Chisholm View Wind Project II wind farm in north-central Oklahoma.

The project is expected to be completed late this year at a cost of $90 million. Construction on the 235-MW Chisholm View I was completed in 2013.

More: Enid News & Eagle

Entergy Puts 22 Guards on Leave to Probe Fire Records

Entergy, operator of the Palisades nuclear station in Michigan, has placed 22 security guards at the plant on leave while it investigates allegations that fire inspection records were falsified.

“The bottom line is that we cannot tolerate employees stating they completed a task when they didn’t, and we are obligated to fully investigate any such instances,” Palisades spokeswoman Val Gent said.

Palisades has had other workforce problems in the past, when the Nuclear Regulatory Commission determined that workers were laboring under a “chilled work environment” after some guards claimed they were fired for pointing out safety issues.

More: The Herald-Palladium

NM Company Seeks to Extend Pipeline into Mexico

New Mexico Gas said last week it will seek a presidential permit to extend a natural gas pipeline into Mexico, New Mexico’s first such connection across the border. Construction on the $5 million project is expected to be completed within a year.

The project involves extending the company’s existing pipeline in Santa Teresa about 5 miles to the border, as well as widening it to allow more capacity. Additional facilities in Mexico will also need to be built. The project will be funded at shareholder expense, according to a company spokesperson.

More: Albuquerque Journal

ISO-NE Approves Northern Pass Tx Line

ISO-NE has determined that the Northern Pass transmission project can reliably interconnect with the regional electric grid.

The grid operator approved the project’s application, saying Northern Pass will not have a significant adverse effect on the reliability or operating characteristics of the regional grid and its participants.

Northern Pass, a proposed HVDC line that would carry 1,090 MW of Canadian hydroelectric power to New Hampshire, is still under review by the state’s Site Evaluation Committee.

More: ISO-NE

July 25, 2016

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

PJM Manuals (9:10-9:40)

Members will be asked to endorse the following manual changes:

A. Manual 11: Energy & Ancillary Services Market Operations for the Day-Ahead Scheduling Reserve. Adds language excluding resources from the day-ahead scheduling reserve process that cannot reliably fulfill obligations in real time.

B. Manual 14C: Generation and Transmission Interconnection Facility Construction. Changes are to support the inclusion of Order 1000 processes. Since the first reading, the new tie line section has been removed.

C. Manual 20: PJM Resource Adequacy Analysis. Updates are the result of a periodic review.

D. Manual 29: Billing. Clarifications and updates are the result of a regular review.

3. Underperformance Risk Management Sr. Task Force (URMSTF) Charter (9:40-9:55)

The charter reflects two issue charges: The group will seek to develop ways that Capacity Performance resources can manage their risk during performance assessment hours. It also will look to better align the requirements for internal and external resources. (See “Charter for Underperformance Risk Management Senior Task Force Presented,” PJM Markets and Reliability and Members Committees Briefs.)

4. Auction-specific Bilateral Transactions (9:55-10:10)

Proposed changes ensure the physicality of an auction-specific bilateral transaction. (See “Members OK Clarifications to Preserve ‘Physicality’ of Auction-specific Bilateral Transactions,” PJM Market Implementation Committee Briefs.)

5. FERC Order 825 (10:10-10:40)

Members will be asked to approve a problem statement and issue charge related to the recent FERC Order 825, which requires RTOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period. (See “Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing,” PJM Markets and Reliability and Members Committee Briefs.)

6. Non-Performance Assessment Charge Rate

David “Scarp” Scarpignato, on behalf of Calpine and the Independent Market Monitor, will present a problem statement and issue charge related to the calculation of the CP nonperformance charge rate. The problem statement maintains that the performance assessment hour number used in the charge rate does not reflect the expected number of PAHs as intended. The issue would be worked in special Market Implementation Committee sessions with the aim of bringing proposals to the MRC for implementation in the 2017 Base Residual Auction for delivery year 2020/21.

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to approve operating agreement and Tariff language giving more flexibility to the parameter-limited schedule exception process. (See “More Flexible PLS Process Approved,” PJM Markets and Reliability and Members Committees Briefs.)

July 25, 2016

FERC Rejects Enforcement Action in Connecticut PURPA Dispute

By William Opalka

For the second time in seven months, FERC declined on Thursday to intervene in a renewable energy developer’s claims against Connecticut regulators (EL16-69).

The commission declined to begin an enforcement action under the Public Utility Regulatory Policies Act on behalf of Allco Finance and its unit Windham Solar. The petitioners said the Connecticut Public Utilities Regulatory Authority and state law violated PURPA’s mandatory purchase obligation.

The company owns 26 small solar generating facilities whose energy and capacity it offered to sell to Eversource Energy for 30 years at the utility’s forecasted avoided costs. The developer sold the renewable energy credits separately to Eversource, in a one-year agreement approved by PURA, its petition states.

However, Allco and Windham allege that they are being required by Connecticut to either offer a bundled product that includes the RECs or sell energy under short-term contracts, in violation of PURPA.

“The commission has stated that the states have the authority to determine who owns RECs in the initial instance and how they are transferred and has explained that the automatic transfer of RECs within a sale of power at wholesale must find its authority in state law, not PURPA,” FERC wrote.

FERC rejected a similar petition for PURPA enforcement in January that involved the state’s procurement of wind energy from a proposed project in Maine. (See Court Next Stop for Developer, FERC Says.)

July 25, 2016

MISO Planning Advisory Committee Briefs

MISO has settled on a probability weighting for the futures analysis in its 2017 Transmission Expansion Plan, with existing trends given 31% consideration, policy regulations given 43% and accelerated alternative technologies receiving 26%.

The RTO relied on stakeholder feedback to tweak the weighting and used an average of weighting that each sector recommended. MISO had originally proposed using a 30% weighting for existing trends, 40% for policy regulations and 30% for accelerated alternative technologies. (See “MTEP 17 Futures Process Enters Stakeholder Inspection,” MISO Planning Advisory Committee Briefs.)

MISO’s J.T. Smith said stakeholder feedback played a major role in developing the final weightings, and stakeholders said the process has gone well.

The RTO also released its refinements to the MTEP 17 futures siting methodology, vowing to represent zonal resource adequacy requirements and solar and expanded wind zones and develop distributed generation siting methodology. It will consider National Ambient Air Quality Standards nonattainment areas in the siting process.

miso planning advisory committee — MISO’s Tiers 1-3 would allow the RTO to add 50 GW of wind beyond that already enabled by multi-value transmission projects. Tier 4 would allow for an additional 30 GW. *Map Source: MISO*

MISO will share final MTEP 17 capacity forecasts and siting locations at the September Planning Advisory Committee meeting and is urging participants to submit comments in early August.

With a number of plant shutdowns looming in the next five to 15 years, MISO is also looking to improve its generation retirement sensitivities beginning with MTEP 17. The RTO is proposing to consider age-based retirements of coal, oil and gas units in the five-year MTEP reliability assessment. The study will identify necessary projects that will require lead times of more than five years and low-cost upgrades that can be implemented in advance of retirements, said Neil Shah, a seams administration adviser at MISO. The analysis would assume a lifespan of 65 years for coal plants and 55 years for oil- and gas-fired facilities, but would not assume any for nuclear stations.

The proposal received substantial inquiry and criticism from participants, who said it could be redundant and presumptuous. Among the concerns were questions about whether this planning was addressed in existing protocols and how MISO chose specific parameters, such as the plant lifespans. The plan also doesn’t currently address non-transmission alternatives to avoid engaging system support resources.

MISO contends the study could eliminate the need for an SSR agreement for most generation retirements. Staff is requesting stakeholder input on the study enhancements by Aug. 3.

The RTO is also requesting that feedback on the MTEP 17 scope be submitted by September. A summary of the feedback will be presented at the October Planning Advisory Committee meeting and the project’s scope will be adjusted by the end of the year. Beyond core studies to maintain reliability of the system, which are required by FERC and NERC, the MTEP includes targeted studies to optimize market efficiency. Participants may make requests for the targets of those studies; however, not all of them may be able to be accommodated. All feedback should be sent to Adam Solomon.

Meanwhile, a first draft of MTEP 16 is set to be released for external review by MISO on Aug. 8, with stakeholder review and comments expected to roll in by Aug. 22. The draft has been circulating within MISO since July 22. A second draft is slated for release on Sept. 19, with PAC review on Sept. 28 and a vote on Oct. 19. The timeline is aimed for approval at the Dec. 8 Board of Directors meeting.

As of the second quarter of this year, MISO reports there are 633 active MTEP projects totaling $11.1 billion. Another 130 projects valued at $1.9 billion are under construction, while 11 MTEP-approved projects, at $200 million, have been withdrawn. By the end of 2016, MISO expects another $2.5 billion worth of projects to be operational.

Duff-Coleman Selection Moves into the Evaluation Phase

MISO staff is conducting a tariff-required completeness check of developer proposals for the Duff-Coleman transmission project, the RTO’s first Order 1000 competitive solicitation. The identities of the bidders will be released by Aug. 19. Project selection is expected by Dec. 30.

Competitive Transmission Protocol Modifications

MISO is requesting feedback on proposed modifications to Business Practices Manual 20 and 27 and a draft joint functional control agreement.

The BPM 20 modifications would adjust status reporting requirements for market-efficiency and multi-value projects and create variance analysis requirements. MISO Transmission Owners and Wisconsin Electric submitted comments during a previous request for feedback. The BPM 27 modifications would change timing and deadlines for various steps in the RFP process.

The agreement ensures that MISO retains functional control of transmission infrastructure if a portion of the transmission owners decide to leave MISO. All comments or questions are requested by Aug. 3 and should be sent to TDQS@misoenergy.org.

Merchant HVDC Task Team Proposed

The Interconnection Process Task Force is proposing the development of a task team to develop HVDC interconnection procedures. The Merchant HVDC Task Team would meet at least monthly from August through December and report on its activities at PAC meetings.

MISO Tries to Please FERC with Second Attempt at Queue Reform

In another bid to win FERC approval for its interconnection queue reform, MISO plans to cut an initial milestone payment by $1,000/MW of new capacity and assess subsequent milestone payments based on a percentage of upgrade costs.

The revised M2 milestone would become a flat charge of $4,000/MW of new capacity instead of the proposed $5,000/MW. The M3 and M4 milestones will be redefined as 10% and 20% of upgrade cost, respectively.

MISO said it will define the upgrade cost the same way it does in the initial payment section of its generation interconnection agreement, which includes network upgrades, distribution/generator upgrades and TOs’ interconnection facilities and system protection facilities.

MISO said the revised milestone payments will be applied toward the GIA initial payment. It also said it will settle any over- or underpayment after it completes a final facility study.

The RTO plans on posting Tariff redline changes for stakeholder review on July 29 and wants to file the revised queue process at the end of October for a Jan. 1 effective date.

If the new batch of adjustments is accepted by FERC, MISO plans on transitioning completely to the new queue beginning with projects that enter next August.

In March, FERC rejected MISO’s proposed changes, calling the revised milestone payments a barrier to entry and rebuffing the RTO’s explanation that the current project backlog was due to “speculative” projects. (See MISO Queue Changes on Hold Pending Technical Conference.)

So far in 2016, MISO has received 105 new queue requests representing a possible 16.9 GW, and the RTO reports that 12 projects worth 1.9 GW have newly signed interconnection agreements.

MISO is also proposing to move two study deadlines four months ahead under Business Practices Manual 15, which governs generator interconnection. Under the changes, MISO’s annual interim deliverability and energy resource interconnection service studies would be completed by Oct. 31 instead of the current June 15.

“We did not meet [the current deadline] this year, and we did not meet it last year,” said Tim Aliff, MISO’s director of resource interconnection and planning.

— Amanda Durish Cook & Rory D. Sweeney