The Environmental Protection Agency said it will miss by a month its own deadline to issue a regulation to minimize the impact of industrial and power plant water cooling structures on fish populations. “In spite of its best efforts, EPA will not meet the April 17 deadline, but will require an additional 29 days, i.e., until May 16, 2014, to complete inter-agency consultation with the services,” the agency told a federal court.
As proposed in 2011, the rule would require plants to slow the velocity of their intakes or find some other way to stop fish from being trapped or killed. Environmental groups had sued the EPA for not issuing the rule — required by section 316(b) of the Clean Water Act — but settled when the agency agreed to finalize it. The most recent court-approved agreement had required the agency to issue the rule by last Thursday. The EPA said the delay was caused by its consultations with the federal Fish and Wildlife Service and the National Marine Fisheries Services, who are tasked with Endangered Species Act enforcement.
Riverkeeper Inc., an alliance of environmental groups that brought the lawsuit against the EPA to force it to issue the regulation, blasted the EPA’s delay. “EPA’s breach of the legal commitment it made to issue a final 316(b) rule by April 17 is yet the latest in a long string of failures by this agency to meet its own deadlines, leaving us no choice but to return to federal court where we can seek an order compelling the rule’s issuance,” Reed Super, an attorney for the group, said last week.
The Obama administration again extended the review period on the Keystone XL pipeline, and its final decision may not come until after the Nov. 4 congressional elections. The State Department said officials need more time to review some of the 2.5 million public comments on the project and investigate the impact of a pending Nebraska lawsuit that could change the route of the pipeline. Officials there did not say when those reviews would be completed.
Supporters of the pipeline denounced the delay. “Here’s the single greatest shovel-ready project in America, one that could create thousands of jobs right away,” Senate Minority Leader Mitch McConnell (R-Ky.) said. “But the president simply isn’t interested. Apparently radical activists carry more weight than Americans desperate to get back on the job.”
Environmentalists called it a sign that the project will be rejected. The latest postponement “confirms, yet again, that this project is not permit-able,” said Rachel Wolf, a spokesperson for a group called the All Risk, No Reward Coalition. “This export pipeline fails the climate test, fails the jobs test, and doesn’t even have a legal route.”
The Nuclear Regulatory Commission will increase its oversight of the Ginna nuclear power plant in Wayne County, N.Y., east of Rochester. The NRC had issued what is called a “white” safety finding — of low to moderate significance — having to do with flood protection at the plant and the threat to backup batteries and other emergency power sources.
Ginna owners made modifications late last year, but the NRC was unhappy with the time it took to make the fixes. “This was one of the primary areas of focus for the NRC after Fukushima back in March 2011, and basically we wanted to make sure that all of the plants were protected to the greatest degree possible, and a lot of that analysis work is still going on,” said NRC spokesman Neil Sheehan.
Exelon said it has faith in the actions taken. “Ginna is a robust, fortified facility designed to withstand the most severe weather related events, including the highest recorded flood levels in the area,” the company said in a statement. “This potential issue was corrected, [and] it did not affect the safe, reliable operation of the plant.”
The U.S. Court of Appeals for the District of Columbia Circuit last week upheld a regulation that limits emissions of mercury and other hazardous pollutants, in a decision that affects mainly coal-fired power plants. The EPA’s Mercury and Air Toxics Standards (MATS) applies to 1,400 of the country’s largest power plants and begin taking effect in 2015.
The regulations are expected to cause a wave of coal plant retirements. U.S. companies have shut or converted more than 22,000 MW of coal-fired power plants since 2009 and have plans to shut or convert more than 42,000 MW in the next decade.
Exelon Corp. owns 1,300 MW of wind generation, a portfolio dwarfed by its 22,000-MW nuclear fleet.
So when company executives decided in 2012 that the interests of wind and nuclear power had diverged over the renewal of wind’s Production Tax Credit, Exelon called on Congress to let the subsidy expire.
The American Wind Energy Association, which spends much of its time lobbying for continuation of the PTC, responded by kicking Exelon out of the trade group. The wounds haven’t healed since.
Last month, AWEA released a study in response to Exelon’s claims that wind farms subsidized by the PTC are responsible for negative prices that are hurting the revenues of the company’s nuclear plants.
At last week’s Federal Energy Regulatory Commission meeting, Commissioner John Norris said the AWEA study provided “very compelling evidence” that “the PTC and negative pricing … are having none or negligible impact on nuclear facilities.”
“If that’s not a factor [in nuclear’s woes], as the AWEA study would seem to indicate, let’s get it out of our rhetoric,” Norris said, calling on Exelon to respond to the analysis.
AWEA’s report is intended to bolster its case for renewal of the PTC, which expired Dec. 31. On April 3, the Senate Finance Committee approved a two-year PTC extension, retroactive to Jan. 1, sending it on to the full Senate.
Exelon has been lobbying Illinois state legislators, warning that the company may shutter as many as three of its six nuclear plants in the state. The company has cited low natural gas prices and flaws in PJM’s capacity market as causes of its plants’ declining revenue. (See Exelon in Lobbying Push to Save Ill. Nukes.)
It also blamed the PTC, which pays wind generators $23/MWh of output, the equivalent of $37/MWh before taxes.
With no fuel cost and with revenue from the PTC and renewable energy credits (RECs), wind farms can profitably generate even when prices are negative.
On that, AWEA and Exelon agree. AWEA, however, takes issue with being blamed for causing negative prices.
The AWEA report, authored by analyst Michael Goggin, says that wind projects have the same impact on real-time and day-ahead prices with or without the PTC.
A generator receiving the PTC and selling RECs would offer at -$20 to -$40 per MWh, says Goggin.
“A wind project that does not receive the PTC will offer into power markets at just above $0/MWh, based on wind’s zero fuel cost and very low variable O&M [operation and maintenance] costs,” the study says. “This offer will always be lower than almost all other offers.”
Northbridge Group analyst Aaron Patterson, co-author of a 2012 Exelon-sponsored report critical of the PTC, does not question AWEA’s data but does disagree with the conclusions.
Wind “may set the price in certain hours. It has a much broader effect in all hours of pushing the dispatch curve out,” Patterson said in an interview. “That manifests itself in some hours in negative prices but in other hours in positive prices that are lower than what they would otherwise be.”
“We can work with AWEA on a clean energy future but we can’t deny the truth,” said Joe Dominguez, Exelon’s senior vice president for governmental and regulatory affairs and public policy, in an interview. “We didn’t pick a fight with the wind industry for the fun of it. We’re trying to save plants and jobs.”
Below is a summary of the major points of the AWEA report and Exelon/Northbridge’s response.
PTC Corrects for “Market Distortion”
AWEA: “The PTC is correcting for market externalities that are not currently accounted for, such as the cost of carbon emissions and the other major environmental and human health costs of fossil fuel consumption. As a result, the PTC is actually countering the market distortion that occurs on an ongoing basis because market pricing does not account for these factors.”
Exelon has complained that zero-emission nuclear power also gets no credit for its contribution to meeting climate change goals.
But Patterson notes that the PTC subsidy typically represents more than half of the per-MWh revenue of wind plants.
“I think it’s fair to say that to the extent that carbon reduction is a goal that it’s more efficient to price carbon rather than selectively subsidizing some sources and not others,” he said.
Pretax carbon prices in California and the Regional Greenhouse Gas Initiative range from $4 to $12 per ton, equivalent to $2 to $6/MWh, Patterson said. “$37 [per MWh] doesn’t strike me as an appropriate level of compensation given the carbon markets we have today,” he said.
As wind’s growth has depended on the PTC, nuclear power has benefited from the Price Anderson Act, which limits nuclear plant liability in an accident.
But that’s different, Patterson said. “It’s not production-based. It doesn’t affect how nuclear units operate in the market,” he said. “In my view, it’s not a distortionary subsidy.”
Negative Prices Overstated
AWEA: “Exelon has grossly overstated the frequency of negative prices at its nuclear plants, by a factor of at least 10 in most cases, and in some by a factor of 20 or more.”
AWEA cites a February 2013 statement by Exelon CEO Christopher Crane that the company’s Byron nuclear plant sees negative prices 16% of the time. In May 2013, Crane was quoted as saying that the Clinton nuclear power plant and the rest of the company’s nuclear plants face negative prices about 14% of the time.
Between 2009 and 2013, Exelon says real-time and day-ahead prices at its Quad Cities nuclear plant were about $6/MWh less than at the Northern Illinois hub because of competition from subsidized wind. In 2012, the differential totaled $130 million. “That’s huge,” said Exelon’s Joe Dominguez.
AWEA says real-time prices at the Byron and Clinton plants were below zero only 2 to 5.5% of the hours between 2011 and 2013. In the day-ahead market, negative prices occurred in only 0.8 to 2.4% of hours over the same period, AWEA says.
Dominguez said Crane’s comments referred to only off-peak hours.
“In the off-peak hours wind tends to produce most of its output and it is also coincident with when our consumers use the least amount of electricity. And the combination of those two factors and transmission congestion leads to negative prices,” Dominguez said. “It’s an upside-down argument to criticize nuclear plants because they can’t ramp when windmills unpredictably run.”
Real-Time vs. Day-Ahead Prices
AWEA: “Merchant nuclear plants almost exclusively sell their energy into day-ahead markets, so day-ahead data captures the true impact of negative prices on Exelon’s nuclear plants.”
Patterson responded: “To say that negative prices don’t matter because Exelon or any other nuclear generator sells their output in [forward markets] is not correct. Those prices are lower than they would otherwise be because of negative prices in the real-time market.”
Wind’s Blame for Negative Prices
AWEA: “Market price data and wind plant output data show that most instances of negative prices occurred when wind plant output was very low. … If Exelon were correct, and wind plants were the factor causing these negative prices, one would expect to only see negative prices during hours when wind plants were producing at nearly full capacity.”
Three incidents that appear to have involved localized transmission outages were responsible for most of the negative prices affecting the LaSalle, Braidwood, Byron, Quad Cities and Clinton plants in 2013, Goggin said.
Patterson agrees with AWEA that transmission outages play a role in negative prices — along with, he says, unexpectedly low load or unexpectedly high wind production. “Disentangling the specific cause for a specific negative price is very hard,” he said.
But he said the frequency of negative prices has grown since 2008, “which coincides with the expansion of wind capacity in Iowa and Illinois and surrounding regions. The nuclear plants were there [before]. The transmission was what it was. The load is what is was. What changed? The wind.”
Tx Upgrades Reducing Negative Prices
AWEA: “Instances of negative prices have rapidly dropped to near zero in all regions of the country. … Negative prices are being eliminated as long-needed transmission upgrades are completed and grid operating procedures are modernized.”
AWEA cites data showing the frequency of negative prices peaking in Illinois in 2009 and 2010 and falling since, consistent with the Northbridge report.
“It’s too early to tell whether we’re going to see a trend of reduced negative pricing,” responded Exelon’s Dominguez. “Transmission [expansions are] always trying play catch-up to the introduction of subsidized generation. The reality is we have seen many years of negative pricing. We can’t claim victory simply because one season it didn’t show up.”
PTC Discourages Investment in Conventional Generation
AWEA has noted the boom-and-bust cycle of wind capacity additions in response to cancellation and resumption of the PTC.
Northbridge says the PTC also discourages investments in conventional generation needed to maintain reliability. “In recent years, about 85% of total wind capacity has not operated during the peak hours on the highest demand days of the year, on average,” the Northbridge report says. “Controllable conventional generation is thus needed to backstop wind and ensure the lights stay on.”
Goggin said wind also contributes to reliability, noting it provided PJM more than 3,000 MW of generation during the polar vortex, when many coal- and gas-fired generators suffered forced outages.
“No resource is 100% reliable. This past winter was a very good example of that,” he said. “Every resource is backed up by all other resources.”
PJM’s newest hydropower project will be barely large enough to power nine homes. But if some visionaries have their way, it will be the start of a trend that could add up to a substantial new power source.
The North Wales Water Authority in suburban Philadelphia won Federal Energy Regulatory Commission approval last month for an 11-kW turbine and generator to capture the energy from a 12-inch water line.
North Wales’ project is among 19 projects approved by FERC since September under legislation enacted last year that a Department of Energy study says could unlock 12 GW of capacity at existing non-powered dams and manmade water conduits, including about 1.5 GW in PJM.
The Hydropower Regulatory Efficiency Act (H.R. 267) amends the Public Utility Regulatory Policies Act of 1978 (PURPA) to exempt dams up to 10 MW from FERC licensing requirements (up from 5 MW).
The law also amends the Federal Power Act to relax regulations on conduit hydropower facilities — tunnels, canals, pipelines or other “manmade water conveyance” used in distributing water for agricultural, municipal or industrial consumption — of up to 40 MW.
A second law, the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act (H.R. 678), authorizes the U.S. Bureau of Reclamation to develop small hydropower projects at existing canals, pipelines and other man-made waterways.
Only 3% of the 80,000 dams in the United States generate electricity. An addition of 12 GW would boost U.S. hydropower resources — 2,500 dams generating 78 GW — by 15%. (See PJM Small Hydro Potential: 1.5 GW.)
Three Projects in PJM
The North Wales project is one of three approved thus far in PJM.
Ellwood City, a town 40 miles north of Pittsburgh, won approval for a 10-kW turbine on a 24-inch wastewater pipe that discharges 1.7 million gallons of water daily. The Pelton wheel turbine would use the momentum of the 50-foot “head” — or drop in elevation — in the 340-foot pipe.
Another project that won approval is a 250-kW project by Oak Lawn, Ill., a Chicago suburb, which will install a turbine in a drinking water pumping station.
Oak Lawn buys water from Chicago’s purification plant, storing it in eight reinforced concrete reservoirs. Water must be delivered to the reservoirs through an air gap to prevent backflow into the Chicago delivery system.
Oak Lawn had been using butterfly valves to create the air gap and reduce the 45 pounds per square inch pressure. When the town began planning a major overhaul of the water system, engineers decided to replace the valves with a turbine. “Why not recapture what [energy] they can?” explained Randy Rogers, an engineer with CDM Smith Inc., which is designing the project.
The turbine and generator, about the size of a side-by-side washer and dryer, will save the town more than $160,000 annually in electricity, about 15% of what it spends powering the pumps that deliver water to its customers.
Village Manager Larry Deetjen said the hydro project was an easy sell in the environmentally conscious town, which runs an electronic waste center and was an early adopter of the switch to more efficient LED street lights.
The cost of the turbine, generator and related electrical equipment will be about $1 million, with a payback period of 10 to 12 years, Rogers said.
“I can see this being used wherever you burn head” (move from high pressure to low pressure water flow), he said. “I expect there to be a lot of interest in this.”
$10 Billion Market?
The North Wales hydropower project will install a “reverse pump” on a 12-inch water pipe to replace a pressure-reducing valve at a water transfer station. The station serves a role akin to an electrical substation that steps down voltage from transmission lines to the distribution system.
North Wales is using the valve to reduce the water pressure by about 30 psi. “In doing so, it becomes wasted energy,” said Frank Zammataro, CEO of Rentricity Inc., a New York City-based startup that won a $300,000 grant from the New York State Energy Research and Development Authority to build the project. Pending regulatory approvals, the company hopes to begin construction within two months and have the generator running by summer.
There are about 23,000 locations in the U.S. with such pressure-reducing valves, said Zammataro, a former Merrill Lynch banker. That represents a $2.4 billion market for potable water systems in the U.S.
Industrial uses — food processors, mines, chemical and pharmaceutical manufacturers, and the pulp and paper industry — boost the market size by another $1 billion in the U.S., he said, with worldwide potential of more than $17 billion.
Improving Cost Effectiveness
Current hydropower technology is only cost-effective at scale of 30 kW or more, Zammataro said. But for every 30-kW opportunity there are 10 to 20 opportunities of 5 kW to 30 kW.
Thus Rentricity set out to find cheaper technology that could make the small projects viable. The turbine in the North Wales project will be a modified version of a pump by Xylem Inc., the second-largest pump maker in the world. Rentricity also has a distribution deal with manufacturer Cornell Pump Co.
“The equipment is getting very cookie-cutter, very plug-and-play,” which is essential to reducing cost, Zammataro said.
Workers install Rentricity’s turbine and generator at a pump station for the Municipal Authority of Westmoreland County near Pittsburgh. The “behind-the-meter” 21-kW installation powers two of four large horsepower pumps that send water up hill to a treatment plant 2,500 feet away. (Source: Rentricity Inc.)
Reducing regulatory costs and delays are also key to making small projects viable. Zammataro said it formerly took six months or longer to win a Federal Power Act licensing exemption from FERC. Under the new legislation, the agency is now approving exemptions in about 50 days. “This is, in my opinion, a big breakthrough at FERC,” Zammataro said.
He said state regulators in New England also are on board and allow such projects to qualify for renewable energy credits under state renewable portfolio standards. Not so in Pennsylvania, which he complains is “behind the curve.”
Earlier this month, he was informed that the Pennsylvania Public Utility Commission had rejected “in-pipe micro hydro generation” from being qualified as an “Alternative Energy” resource under state law. The PUC said the technology is not listed among the sources identified by the state’s Alternative Energy Portfolio Standards law and doesn’t qualify as “low-impact hydropower.”
Without such certification, the project cannot qualify for net metering, which provides a higher value for the power than it would be able to obtain though a purchase power agreement. Zammataro said he plans to file a challenge.
Because of its topology, Pennsylvania is “a prime target within the PJM region,” he said. “There’s a lot of hills and mountains they’re moving water over.”
Smaller Footprint than Wind, Solar
To date, Rentricity has completed about a half-dozen projects.
Two turbines at Keene, N.H. water treatment plant, the first energy-neutral water treatment plant powered by its own in flow of water in the U.S. (Source: Rentricity Inc.)
In Keene, N.H., the company installed a 62-kW generator, creating what he says is the “first energy-neutral water treatment plant in the country.”
The company’s largest project is a 325-kW generator installed at the California Water Services Co. The generator is in a 20-foot by 20-foot vault, a much smaller footprint than wind or solar for an equivalent output. “This form of hydropower is very efficient and very compact,” he said.
Zammataro says all new water pipeline projects should be required to investigate the opportunities for energy recovery. In addition to offsetting water utilities’ electric bills — typically 30 to 35% of utilities’ budgets — it can provide remote power sources to run sensors to monitor flow and pressure data and identify the leaks that waste an estimated 20% of water.
“We have a relatively dumb electric grid. We have an even dumber water grid,” he said. “When you replace it you ought to replace it with smart technology.”
PJM’s scheduling rules aren’t flexible enough to meet the needs of wind and other variable energy resources, the Federal Energy Regulatory Commission ruled last week.
The commission said PJM’s rules failed to meet the requirements of Order 764, which requires transmission providers to offer scheduling at 15-minute intervals. FERC ordered PJM to submit a new compliance filing within 30 days.
Prior to Order 764, the pro forma Open Access Transmission Tariff — developed for generation that could be scheduled with relative precision — included no option for adjusting transmission schedules within the hour.
As a result, variable energy resources could not avoid generator imbalance charges when they knew their generation was likely to change within the hour. Generator imbalance charges pay for energy the transmission provider must purchase when a generator’s output falls short of the amount scheduled.
The revised pro forma OATT requires that transmission providers allow scheduling changes be made within 20 minutes “or a reasonable time that is generally accepted in the region … before the start of the next scheduling interval.” The commission said it wanted to allow generators to adjust their schedules in 15-minute intervals.
PJM proposed amending the firm and non-firm point-to-point transmission service provisions of its Tariff to allow 15-minute schedules. But the commission said it was not compliant with Order 764 because the proposed Tariff required that the changes be made 20 minutes “before the next clock hour,” rather than before each 15-minute interval.
(As a practical matter, PJM said it does not assess imbalance penalties on any generators, because virtually no market participants use point-to-point transmission to serve load.)
Interchange Transactions
FERC also took issue with PJM’s practice of requiring that interchange transactions have a minimum duration of 45 minutes, which the commission said “is inconsistent with Order No. 764 because it does not allow a generator to schedule for less than three consecutive 15-minute intervals.”
PJM said it implemented the 45-minute rule on interchange transactions in 2008 to prevent “market abuses.”
In 2007, MISO and its Independent Market Monitor determined that nearly 60% of intra-hour schedules between MISO and PJM occurred in the final 15 minutes of the hour. PJM said the trading was the result of “market participants’ ability to see price differences between the two RTO markets for the first third of the hour and thereby predict with relative certainty the direction of the price separation between the two RTOs when the hourly integrated prices were calculated.”
PJM said this resulted in interchange spikes of up to 1,000 MW — increasing uplift charges because of the need to call on combustion turbines to balance the generation swings.
“A return to a 15-minute duration rule would cause an increase in imbalance charges [and balancing operating reserve] costs because it is entirely reasonable to expect that market participants would return to the [prior] practices,” PJM said.
Last year, the commission rejected MISO’s proposal to retain an existing requirement that schedules starting at the 30- and 45-minute marks of the hour be made by the beginning of the hour, which MISO said was intended to prevent the problems identified in 2007.
The commission last week granted MISO an extension until June 30, 2015 to fully implement Order 764.
Data Requirements
Order 764 also requires variable resources to provide meteorological and forced outage data to help transmission providers more accurately forecast generation. The commission accepted PJM’s addition of these requirements to its Tariff.
Calpine Corp. is selling six power plants in the Southeast and Midwest to LS Power for $1.57 billion in cash as part of a plan to focus on its electricity sales businesses in the Mid-Atlantic, Texas and California. The plants — representing a combined 3,498 MW — are in Alabama, Oklahoma, Louisiana, Florida and South Carolina.
Calpine spokesman Brett Kerr said the company planned to sell the six power plants for some time. It wanted to sell additional plants in Alabama, Arkansas and Florida but wasn’t able to get the price it needed for those assets. The LS Power deal is expected to close in the second quarter, and Calpine said it plans to use proceeds to pay down debt, buy back shares and possibly buy new generation.
The company operates 77 natural gas-fired power plants across the U.S., including 24 in California, 20 in Mid-Atlantic states and 14 in Texas. Calpine also has geothermal power plants in California.
PSEG’s Izzo Frustrated Over Opposition to “Energy Strong”
Ralph Izzo (Source: PSEG)
A frustrated Public Service Enterprise Group chief executive Ralph Izzo last week renewed his call for the state to approve a multibillion-dollar infrastructure-hardening project the company proposed shortly after Hurricane Sandy. In comments following PSEG’s annual shareholder meeting in Newark, Izzo questioned how the project’s opponents could maintain what he believes are two competing objections: that it costs too much and that it won’t help enough customers.
“The only way to reconcile those two is by saying, OK, we’re not proposing to spend the money in an optimal way,” Izzo said in an interview. “In which case, I say, we’re an open book. Tell us a better way to do it. And the reality is, there isn’t a better way to do it.”
Izzo said part of the planned 10-year, $3.9 billion “Energy Strong” project calls for strengthening facilities that were damaged by Sandy and Tropical Storm Irene. Newark-based Public Service Electric & Gas — PSEG’s largest subsidiary — filed Energy Strong with the state Board of Public Utilities in February 2013, four months after Sandy. While the utility maintains the project would improve reliability and help prevent the kind of massive power outages Irene and Sandy caused, opponents have pushed back against its price tag. The state Division of Rate Counsel, AARP New Jersey and a coalition of large energy users have also questioned the project’s stated effectiveness and the utility’s insistence on receiving approval for the money before starting construction.
As Stock Slides, Exelon’s Crane Gets 70% Raise in 2013
Christopher Crane (Source: Exelon)
Even as the company’s stock slid nearly 8% last year, Exelon Corp. CEO Christopher Crane was rewarded with a 70% raise, making more than $17 million in 2013. Crane’s total compensation in cash, stock and benefits topped out at $17.2 million, up from $10.2 million the year before. Crane’s compensation moved to a new performance-pay system that ties rewards over a three-year period rather than year-by-year. The company also eliminated stock options and moved its stock-based compensation to restricted shares and performance shares.
Exelon said it raised Crane’s pay to make it comparable to the median for peer CEOs. Before 2013, his pay was targeted at 20% less than the median. Exelon has suffered from falling wholesale power prices as its nuclear plants have grown less profitable. Increases at its regulated utilities — particularly ComEd, which is collecting annual delivery rate hikes per a state law authorizing $2.6 billion in local grid upgrades — have partially offset the declines at the power plants. But the 8% stock slide last year followed a 31% drop in 2012.
Duke Shareholders Urged To Oust Board Members Over Ash
Two of Duke Energy’s major institutional investors are urging fellow shareholders to vote out four directors at the May 1 shareholders meeting over the company’s ongoing coal ash problems. The California Public Employees’ Retirement System (CalPERS) and the New York City Pension Funds wrote shareholders last week, asking that they not reelect four board members responsible for environmental safety and health compliance.
Ash Spill (Source: Duke Energy)
The letter cites the Feb. 2 ash spill into the Dan River, saying Duke had “forewarning of the public risk” from environmental groups that had intended to sue Duke over ash contamination. None of the committee members named — Alex Bernhardt, James Hyler, James Rhodes and Carlos Saladrigas — has coal industry or other relevant experience, CalPERS and New York City comptroller Scott Stringer wrote. “In light of the serious failures of oversight, scale of impact on the company’s risk profile and the poor response to shareowner enquiry thus far, we urge our fellow investors to hold the relevant board members accountable.”
Duke said last week it has spent $15 million so far cleaning up the spill but said the costs would not be “material” to the company. Duke CEO Lynn Good has said Duke will pay for cleaning up the 70-mile trail of ash in the Dan River, but that it will ask the North Carolina regulators to approve ratepayer funding of costs associated with closing 33 ash basins at Duke sites across the state.
Duke had no immediate comment on the stakeholders’ action. CalPERS owned $140 million in Duke stock in 2013. The New York City funds have $62 billion in U.S. stocks, although it’s unclear how much of that is Duke stock.
PPL Generation, Trading Sale Rumors Fuel Stock Rise
PPL Corp. stock is trading near the top of its 52-week range amid continued speculation that the company may spin off its generation and energy marketing business. PPL shares closed Friday at $33.14, close to its 52-week high of $33.55. The rise came after the International Strategy and Investment Group raised its target price for PPL, citing the strength of its regulated utilities and the potential benefit if it spun off its generation. The report also cited the potential upside for PPL if it merged its power plants with another company’s.
A trade publication earlier this year published a report saying PPL hired Morgan Stanley and Citibank to conduct an internal review of PPL Energy Supply, the business arm that includes PPL’s generation and energy trading and marketing businesses. That report pointed at Dynegy as a possible buyer. PPL declined comment on any sale or spinoff rumors.
Dominion Virginia Power will conduct an earthquake risk assessment for its North Anna nuclear generating station but doesn’t expect the study to point to any significant modifications. The plant’s two 980-MW reactors were knocked offline by a 5.8-magnitude earthquake that shook central Virginia in August 2011. Although the temblor caused no significant damage, the station remained out of service for three months while the company and the Nuclear Regulatory Commission conducted a thorough safety check.
“These plants have so much design margin on the seismic side, I have no concerns about this whatsoever,” said David A. Heacock, president and chief nuclear officer of the parent company’s Dominion Nuclear operating group, said last week. “We verified our plant can withstand a stronger earthquake” than it was designed for.
In 2012, the U.S. Department of Energy, the Electric Power Research Institute and the NRC updated the seismic model for the central and eastern U.S., reflecting a greater seismic hazard at some nuclear plants than previously thought. Forty-seven plants will have to conduct additional studies to determine whether their designs protect them from earthquake hazards. Once the assessments are complete, the NRC will decide if plants require upgrades.
A judge allowed a competitor of a Delaware fuel cell company to challenge a state-sanctioned surcharge added on the bills of Delmarva Power customers last Thursday. U.S. District Court Magistrate Christopher Burke decided that FuelCell Energy, of Connecticut, can go forward with its suit against Delaware Gov. Jack Markell and the state Public Service Commission, saying it violated the Constitutional prohibition against state interference with interstate commerce.
The subsidy was created and approved by the commission in 2011 in a successful attempt to get Bloom Energy to move its fuel cell operation from California’s Silicon Valley to Delaware. The subsidy is funded by a surcharge on Delmarva’s residential customers averaging $4 to $6 a month. Burke wrote in his ruling that the tariffs help Bloom, but not FuelCell, and put FuelCell at a competitive disadvantage. There was no public solicitation for bids from out-of-state fuel cell companies.
ComEd Asking For Rate Hike; Says Improvements Paying Off
Commonwealth Edison Co. is asking for a rate hike, marking the fourth time since 2011 that the company has gone to regulators for permission to boost rates for modernization programs. The company said this increase request would add about $3 to the average electric bill. ComEd says improvements already undertaken have prevented 500,000 power outages, saving consumers about $82 million.
“These improvements, if done right, should pay for themselves in the long run, but the key moving forward is to hold ComEd accountable,” said Jim Chilsen, a spokesman for consumer advocacy group Citizens Utility Board in Chicago.
South Side Petcoke Storage Spurs Residents’ Outrage
(Source: MidWest Energy News)
Southeast Chicago residents vowed to take their fight to the streets over the increasing piles of petroleum coke being stored in their neighborhood. Saying they’ve been let down by elected officials who last year promised to crack down on companies storing the fuel, residents are planning an April 26 march and a boycott of BP, the source of the “petcoke” being stored along the Calumet River.
An expected City Council vote on an ordinance that would have limited petcoke storage morphed into a tamer proposed ordinance that allows more petcoke storage. Opponents are concerned the new ordinance would be the first step in the eventual approval of a contentious proposal for a synthetic gas plant in the area.
The gas plant plan was tabled last year after Gov. Pat Quinn vetoed legislation that would have committed Chicagoans to pay a fixed rate for synthetic gas from the plant for 30 years, even if market natural gas prices were much lower.
Ameren Brags on Upgrades; Critics Remain Unconvinced
Ameren Illinois’ pride in its transmission and distribution upgrades and resultant reliability improvements are being met with a jaded eye by some customers. The company said the $625 million spent on upgrades have shown a 20% improvement in reliability and savings worth $57 million a year since 2012 for residential and small business owners. Ameren Illinois was forced to make the investments, which included smart meter installations and energy-efficiency programs, under the Illinois Energy Infrastructure Modernization Act of 2011.
“This is a long-term process, but we have been able to deliver results to customers while keeping their rates reasonable,” said Ron Pate, senior vice president of operations for the utility.
Critics hope Ameren’s calculations are right but think the company may be jumping the gun. “We haven’t seen the evidence yet, and we think it’s too early to tell,” said David Kolata, executive director of the Citizens Utility Board public watchdog group. “It’s really going to be in the next six months that we’ll really start to get a read on it.”
East Kentucky Power Cooperative plans to shut down all four units at the 196-MW William C. Dale coal-fired power plant in Clark County over the next year, but the company said the two largest units will be held ready for restart if needed. East Kentucky decided that retrofitting the units so they meet 2015 pollution limits would be too expensive. The company said it has often been cheaper to operate other plants or purchase power from the market, particularly since East Kentucky’s 2013 integration into PJM.
“Dale Station was East Kentucky Power Cooperative’s first power plant,” Tony Campbell, the co-op’s president and CEO, said in a statement. “This plant has been a reliable workhorse, generating the electricity that powered many thousands of Kentucky homes and businesses over the past 60 years.”
East Kentucky also owns and operates the 341-MW Cooper baseload coal plant in Pulaski County and the 1,279-MW Spurlock baseload coal plant in Mason County. The co-op has installed pollution controls on both plants and intends to continue operating them.
The Public Service Commission is giving utility customers a gift after a brutal winter: a two-month extension to the period when certain utility companies can cut off service to non-paying customers. The new deadline is May 31, instead of March 31, and applies to Baltimore Gas & Electric Co., Potomac Electric Power Co. and Delmarva Power Co.
The utilities themselves had proposed the extension during a meeting with the commission. The commission is calling for all Maryland utilities to adopt the extension and wants utilities to move faster in switching customers with smart meters to competing retail suppliers when asked.
Southern Maryland Electric Cooperative signed a 20-year power purchase agreement last week with the developers of a proposed 10-MW solar facility in Charles County. Under the PPA with Juwi Solar Inc., SMECO will purchase all energy, capacity and renewable energy credits from the Rockfish Solar farm. If approved by the Public Service Commission, the $40 million project is scheduled to be completed by the end of the year.
SMECO has a 5.5-MW solar farm in Hughesville and purchases energy from two wind projects in Pennsylvania.
Attorney General Roy Cooper is returning to the state Supreme Court to try to block Duke Energy’s recent rate increase. Cooper argues that the state Utilities Commission failed to weigh the rate hike’s economic impact on Duke’s electricity customers.
The Utilities Commission originally approved Duke’s 7.2% rate increase in 2012 and upheld its decision in 2013. The state Supreme Court agreed with Cooper the first time around, setting up the current challenge. Now Cooper says the Supreme Court needs to send a clearer message to get the point across.
“The commission’s position is deeply unfair to consumers,” according to the attorney general’s legal challenge, which was filed Thursday.
Duke said the commission did everything correctly. “We believe the commission’s order satisfies all of the requirements set out by the N.C. Supreme Court and that the commission properly weighed the evidence,” the company said in a statement.
Thomas W. Johnson was sworn in last week as the new chair of the Public Utilities Commission, bringing with him experience in finance and budget issues from 22 years in the Ohio House. Johnson takes the helm of the 330-person agency for a five-year term.
(Source: PUCO)
Gov. John R. Kasich swore in Johnson Wednesday, after expressing misgivings over the state’s move to retail choice.
“The ideological effort to deregulate, I’m not so sure it’s the smartest thing we’ve done in the state of Ohio,” Kasich said, speaking to the audience in the PUCO chamber before the swearing-in. “But we are where we are, and we can’t go backwards now. So it’s onward in a deregulated environment, and we’ve got to figure it out.”
Poll Shows Ohio Voters Back Renewables, Efficiency
Ohio residents overwhelmingly favor using renewable power to replace coal-fired generators and want utilities to help customers increase energy efficiency, according to a poll commissioned by a green energy advocacy group. The telephone survey of Ohio voters found that 72% favor renewable energy over traditional power plants and 86% favor mandated utility energy efficiency programs. Two-thirds of those polled said they would back legislative candidates who promote renewable power over those who continue to support coal and nuclear power plants.
The poll was commissioned by Ohio Advanced Energy Economy, which opposes a Republican-backed bill that would freeze energy-efficiency efforts at the current level pending a study.
AEP Consolidating TX Ops To New Building in New Albany
American Electric Power plans to build offices in New Albany for its division that manages the interstate flow of electricity, bringing together about 500 workers who are now based at several central Ohio locations.
AEP Transmission Executive Vice President Lisa Barton said the company expects “significant cultural, operational and efficiency benefits” from having all transmission operations employees in one spot. The new headquarters will be completed in about two years.
PPL Electric Utilities wants to update its price to compare for default electricity customers twice a year, rather than quarterly, according to a proposal filed with the Public Utility Commission. PPL said twice-yearly prices “will provide customers more certainty around shopping and provide retail suppliers with more time and flexibility in creating pricing programs to encourage customers to shop.”
The price to compare is the price customers pay for generation and transmission if they don’t choose a competitive electricity supplier. PPL’s plan would cover the period from June 1, 2015 to May 31, 2017. The PUC is expected to rule on the request in early 2015.
Appalachian Power will ask the State Corporation Commission to let it increase the monthly residential customer charge from $8.35 to $16, but offset that by decreasing the base rate for each kilowatt-hour used. The SCC has set a Sept. 16 hearing date in Richmond to review the electric provider’s rates.
The SCC will review Appalachian Power’s generation, transmission and distribution rates, with any changes approved to take effect early next year. Appalachian Power also is seeking to establish two residential energy-efficiency programs. Appalachian Power serves about 500,000 customers in Virginia.
After several months of evaluation, PJMis close to naming a developer to fix the Artificial Island transmission stability problem, with LS Power’s proposal for an overhead crossing of the Delaware River holding on as the lowest-cost choice.
PJM’s Paul McGlynn told the Transmission Expansion Advisory Committee last week that the RTO will schedule a special meeting shortly — preferably before the next TEAC meeting May 8 — to discuss its evaluations of the proposals in detail. PJM expects to recommend a winner to the Board of Managers in July.
The presentation to the TEAC listed 10 apparent finalists among the 26 proposals submitted in July, including five that would add a 17-mile 500-kV line that parallels an existing 500-kV line from Red Lion to Hope Creek.
Five other proposals would cross the Delaware River to the Delmarva Peninsula south of Artificial Island with a 230-kV line and run to a new or expanded substation. Three of the proposals would run a submerged line in the river bed and two others would run the line above the water.
McGlynn said PJM planners and the RTO’s engineering consultant concluded that they needed to add options that increased the proposals’ price tags by as much as $192 million. The additional costs included an additional cable for the submarine crossings and an auto-transformer to proposals that included only one bank.
LS Power’s overhead proposal, the lowest cost proposal by its own estimate, remained the cheapest in PJM’s recalculation.
Dominion’s overhead proposal tumbled from second to fifth as PJM added $125 million in costs, nearly doubling its price tag. The Pepco Holdings/Exelon proposal received the biggest boost in the relative rankings, rising from sixth to second even as PJM added $59 million in costs.
PSEG’s cost estimate was the only one reduced by PJM’s calculations, though its ranking rose only from 10th to seventh.
The review estimated all of the projects would take about two years to build. For the Southern Delaware crossing proposals, it identified obtaining permits for the river crossing and crossing Delaware Route 9, a “Scenic and Historic Highway,” among the chief scheduling risks.
The Red Lion proposals face challenges including coordinating with the Salem and Hope Creek nuclear plants and the need to take out of service line 5015, which has had no more than an eight-day outage in the last 15 years.
Stakeholders have raised several technical questions about the proposals, including directional carrier blocking (DCB) schemes and the performance of static VAR compensators (SVCs).
Esam Khadr of PSE&G questioned the security of using DCB schemes and reliability of using SVCs.
“There are 3,800 MW of generation at Artificial Island. If the SVCs fail to respond to a severe disturbance, it could lead to unit instability [at Artificial Island] and a loss of the electrical system,” he said.
Steve Herling, vice president of planning, said planners will conduct market efficiency studies on the proposals before selecting a winner, but that they are unlikely to have a major impact because there is little congestion in the area.
WASHINGTON — PJM and the Federal Energy Regulatory Commission were summoned to the Capitol last week to defend their actions to ensure reliability — FERC in response to sabotage concerns, and PJM in the wake of an extraordinary winter that featured more near calamities than a James Bond movie.
The early expectation was that last month’s leak of a FERC study revealing the grid’s vulnerabilities would dominate the hearing before the Senate Energy and Natural Resources Committee and new Chair Mary Landrieu (D-La.). The day before the hearing, the Department of Energy’s Inspector General released a report that criticized FERC’s security procedures. (See related story, IG Faults FERC on Leaked Sabotage Report)
But the hearing instead focused largely on how PJM — after resorting to voltage reductions and load shedding in January — will keep the lights on over the next two years, as economics and EPA regulations idle 40,000 MW of coal-fired generation.
Role for Coal
Senator Joe Manchin
It was a stage, and a topic, that Sen. Joe Manchin had been waiting for. Manchin, the West Virginia Democrat who put the final bullet in the FERC nomination of Ron Binz last year, was the most animated person in the hearing room.
Manchin cited a report by AEP that 89% of the coal capacity that it will retire in the next 14 months was dispatched in January.
“I’m not here trying to push a product that you don’t want,” Manchin insisted, referring to coal. “But when we hear from people like you, the professionals, who say we’ve gotta have it. And I’ve got an [Obama] administration that’s fighting me every way they can, to get rid of it,” he said, shaking his head over the contradiction.
Then Manchin concluded with a triplet worthy of Yogi Berra: “You gotta have it, but you don’t want it, but you know you need it.”
Natural Gas Dependency
Thad Hill, Calpine
Several witnesses and senators expressed concern over growing too dependent on natural gas. But Calpine CEO Thad Hill, whose company’s generating fleet is 95% natural gas-fired, had no nostalgia for coal.
Of the 30,000 MW of PJM generation that suffered outages due to mechanical problems in January, Hill said, almost 15,000 MW were coal-fired versus only 1,500 MW of modern combined cycle. (Another 7,500 were older gas units, Hill said.) “The point being: This isn’t about overreliance on any one fuel. It was about operational readiness this winter.”
While PJM will lose 15,000 MW of coal over the next three years, it will get 19,000 MW of new resources, Hill said, including a 309-MW combined-cycle plant Calpine is building in Dover, Del.
He noted that the current retirements, sparked by EPA’s Mercury and Air Toxics (MATS) rule, is thinning the coal fleet of its most aged and inefficient units. The median AEP plant being retired is about 50 years old and less than 200 MW.
Nick Akins, AEP
The coal fleet is certain to be reduced further after the EPA announces its greenhouse gas regulations for existing generation in June. (See related story, Now Comes the Hard Part) In addition, some nuclear generation is at risk due to low energy and capacity prices and pending EPA cooling-water regulations.
AEP CEO Nick Akins complained that PJM’s capacity market was “not functioning as intended.
“Yes, PJM has more than 8,000 MW of planned (mostly gas) generation identified in the last two auctions, but many of those generators are being proposed with some form of state regulatory funding support,” he said in his written testimony. “What this means is that many new builds are the result of state directives rather than a response to market signals.”
Kormos: PJM is Prepared
PJM Executive Vice President for Operations Mike Kormos noted that the RTO’s fuel diversity will actually increase over the next few years as coal is replaced by gas and other resources. Coal will remain one-third of PJM’s capacity, he noted.
PJM generation capacity is expected to drop by almost 3,500 MW through 2017. (See chart.) Nevertheless, Kormos told the senators that PJM’s capacity auction has obtained more than its required energy and reserves “through the MATS [transition] period.”
He acknowledged challenges ahead. For one, Kormos said, there will be more price volatility as a result of the replacement of coal by natural gas and demand response, which he described as “one of highest priced resources.”
After enjoying several years of low-priced shale gas tranquility, natural gas generators were jolted in January when prices briefly spiked to more than $100/mmBtu. Kormos said PJM’s costs also were boosted in January by what he called the gas pipeline industry’s “onerous” contract provisions.
“It would not be realistic for me to stand up here and tell you that there will never be an interruption in service,” he said. “But … we will be able to serve the load in all but the most extreme circumstances.”
Moeller: Not Confident in Retirement Data
Commissioner Philip Moeller said he is troubled by contradictory capacity forecasts.
Commissioner Philip Moeller, FERC (L) and Mike Kormos, PJM (R)
“We have executives who say we can get through this period without any problem,” he said. “We have others who are very concerned. My focus has been to try and get the data: which plants retire when; where they are on the system.
“We’re not exactly confident in a lot of the numbers,” he continued. “And that has me very concerned going into the next two to three years.”
Moeller cited MISO, which recently predicted a 2-GW capacity shortfall in summer 2016 — down from estimates a few months ago of a 6-GW deficit. He noted that the revised projection assumes an annual 0.75% drop in energy consumption. “That’s a pretty big assumption,” he said ruefully.
Moeller’s prediction: “A lot of it’s going to depend on the weather. If we have mild weather for the next couple of years we might make it through. But if we have extreme weather in the summer or … in the winter, the system will be extremely stressed.”
The Federal Energy Regulatory Commission lacks proper controls for identifying and handling classified national security information, the Department of Energy’s Inspector General said last week.
Gregory H. Friedman issued his preliminary findings in a report issued on the eve of FERC’s appearance before the Senate Energy and Natural Resources Committee Thursday.
The IG review was initiated in March in response to news reports that included non-public information regarding FERC modeling on grid vulnerabilities and the investigation into the April 2013 attack on Pacific Gas and Electric Co.’s Metcalf substation.
The IG report said DOE’s subject matter experts concluded that at least one presentation created by commission staff should have been classified when it was created.
Article Cited
Although the report did not identify the presentation, Acting FERC Chair Cheryl LaFleur told the Energy Committee Thursday it was modeling created in early 2013 that was the subject of a March 13 Wall Street Journal article.
The article said the modeling indicated that disabling just nine critical substations could blackout the continental United States — a conclusion some experts have questioned.
“Based on preliminary information, we determined that the presentation was accessible to, and in specific instances, was viewed and handled by Commission employees who may not have had personnel security clearances and thus, were not fully aware of their obligation to protect the information,” Friedman said in a management alert. “Similarly, the document was reported to have been maintained on portable electronic equipment and transmitted via unsecured means.”
The document’s contents may “have been provided to both Federal and industry officials in unclassified settings,” the report added.
LaFleur had requested the IG review along with Senate Energy Chair Mary Landrieu, D.-La., and ranking member Lisa Murkowski, R-Alaska. LaFleur told the committee Thursday she had ordered FERC staff to make implementation of the IG’s corrective recommendations a top priority.
Scrubbing Computers
Cheryl LaFleur, acting chair, FERC
LaFleur said that the presentation was created in early 2013 and should have been classified at the secret level or higher, rather than as Critical Energy Infrastructure Information (CEII), a level of information that can be obtained by many FERC employees.
FERC responded to the IG findings by “gathering any paper copies we can find … wiping and scrubbing all databases and computers, and any portable devices across the commission,” LaFleur said.
She said the commission also is “reaching out to former employees including our former chairman [Jon Wellinghoff], and trying to get our arms around any information that may be out there.”
Wellinghoff, who was chairman from 2009 until December 2013, has been widely quoted in news accounts since leaving the commission during his campaign to raise awareness of the threat of sabotage. Each of the current commissioners has criticized Wellinghoff, both for going public with his concerns and for not doing more to address them when he headed the commission. (See FERC Criticism of Ex-Chair Mounts.)
Wellinghoff told Politico last month that he and another FERC official had briefed hundreds of people about the study and that the information in the Journal article was no secret. “There was no classified information,” he said. “There was no secret information and nothing was shared with anybody that was in any way part of some unpublished report.” He did not respond to requests for comment last week.
NERC: Attack was ‘Turning Point’
At least two saboteurs are believed to have taken part in the Metcalf attack, which caused more than $15 million in damage and idled the substation for nearly a month, but caused no power interruptions.
Gerry Cauley, president of the North American Electric Reliability Corp., who also testified before the committee, said the attack was a “turning point” that indicated security measures designed to keep intruders from getting onto substation property were insufficient.
“We’re doing the right things and were doing the right things on a prioritized basis,” he said. “… The Metcalf incident was serious but it’s also a good example of the resiliency of the grid — there were no customer outages.”
American Electric Power expects coal to represent 51% of its generation portfolio in 2020, down from 65% in 2012 but up from an earlier prediction of 46%. Coal’s gain will reduce growth in the company’s natural gas portfolio. Natural gas lost market share to coal last year in PJM due to rising gas prices.
Dominion is buying six California solar development projects with a combined output of 139 MW from Recurrent Energy. The acquisition will greatly raise Dominion’s solar portfolio from its current 41 MW in Georgia, Connecticut and Indiana. The new projects, which already have power purchase agreements and are under construction, are scheduled for commercial operation later this year or early in 2015.
Exelon Absorbs CENG Units, Bringing Fleet to 22,000 MW
Exelon has integrated the operations of Constellation Energy Nuclear Group’s five reactors into its own nuclear group, adding 4,200 MW of capacity to bring its nuclear fleet to more than 22,000 MW in 23 reactors at 14 sites. Exelon thus is the world’s third-largest nuclear operator, behind French state-owned Electricite de France (EDF), with 63,130 MW, and Rosenergoatom in Russia, which has 25,200 MW.
CENG still exists, with 50.1% owned by Exelon and 49.9% by EDF. But last summer the companies made a deal whereby Exelon lent $400 million to CENG to support a special dividend to EDF and granted EDF an option to sell its CENG stake to Exelon between January 2016 and June 2022 at fair market value.
The move was envisioned when Exelon bought CENG’s parent, Constellation Energy, in 2012. At that time the Nuclear Regulatory Commission approved the indirect transfer of the operating licenses, and now the NRC has approved a direct transfer.
Energy market rules have not kept up with “seismic shifts in how energy is produced and consumed,” Exelon Generation President and CEO Kenneth Cornew said. He cited the influx of natural gas, rapid expansion of subsidized renewables, smart grid, low demand growth and behind-the-meter technologies. Focusing on a theme Exelon has used heavily, Cornew told the Platts Global Power Markets Conference that markets need reform. The winter’s polar vortex, with its disruption of gas supply to power plants, highlighted a continuing need for baseload assets like nuclear power, he said, but “flawed market rules” and renewables subsidies result in failure to compensate nuclear for its reliability and zero-emission quality.
FirstEnergy CEO Anthony Alexander believes that “state and federal policymakers are manipulating the supply and demand, and distorting markets for electricity, to further advance the ‘war on coal.’” Speaking at a U.S. Chamber of Commerce event, Alexander lambasted state and federal energy policies that he said were “designed to achieve a social agenda.” He warned that efficiency, renewables, microgrids, rooftop solar and demand reduction are examples of what “sounds good” but are “untested policies” that will threaten reliability and raise power prices.
NRG Closes Deals to Grow Capacity, Retail Presence
NRG Energy closed on its $2.6 billion purchase of Edison Mission Energy generating assets and the $165 million purchase of Dominion Resources’ competitive retail electricity business.
Edison Mission’s nearly 8,000 MW brings NRG’s fleet to more than 53,000 MW, second-largest in the U.S. Dominion’s retail business will add more than 500,000 accounts to NRG’s retail footprint by the end of this year, doubling the company’s Northeast retail presence and expanding its leading retail position in Texas through the Cirro Energy brand.
Completion of the purchases followed on the heels of NRG’s purchase of Roof Diagnostics Solar, a solar sales and installation company.
