Nuclear power plant owners are welcoming reports that Gov. Andrew Cuomo wants state regulators to mandate that half of the state’s energy come from renewable energy sources by 2030 while creating incentives for nuclear to remain viable in the interim.
Governor Andrew Cuomo
Getting 50% of its energy from wind, solar and other renewable resources by 2030 is currently a state goal, but it lacks the force of an order from the New York Public Service Commission. The governor is also seeking a way to keep the R.E. Ginna and James A. Fitzpatrick nuclear plants on Lake Ontario in the state’s fleet to help New York meet the federal Clean Power Plan. The hope for those in the nuclear industry is that these combined efforts will mean their plants will serve as the primary source for low-carbon power in the near term.
The New York Times first reported the proposed mandate on Sunday. A source told RTO Insider the details could be released in the governor’s annual State of the State address in January, with final action by the PSC hoped for about six months later.
“If true, this new policy would be a welcome and constructive step that promotes the transition to clean energy,” said David Tillman, a spokesman for Ginna’s owner, Exelon. “We believe that with the governor’s leadership, a state clean energy standard can be implemented that would recognize the zero-carbon, economic and reliability attributes of nuclear energy while maintaining New York’s focus on renewable energy and efficiency.”
Advocates from different sectors of the power industry were generally pleased by the news.
“The clean energy standard as proposed by the governor is an important and forward-looking approach that will help attract investment in renewables and address market problems that need fixing,” Gavin Donohue, president of the Independent Power Producers of New York said in a statement. “The alternative is the potential loss of nuclear power in New York due to currently low natural gas prices — a scenario that would be catastrophic for both ratepayers and the environment.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, supported the plan but is less sanguine about the nuclear component. “Gov. Cuomo’s reported directive to the Public Service Commission to mandate the 50% renewables by 2030 goal is great, encouraging news for the renewable energy industry,” she said. “Nuclear power, while emitting less carbon than coal or oil, nevertheless does not meet the definition of renewable technologies. Supporting uneconomic and aging power plants should not be the long-term solution, but should be a transition to a renewable energy future.”
Iberdrola USA, whose Rochester Gas & Electric unit negotiated the RSSA with Exelon, would not comment on the purported extension of Ginna’s operation. “We’re working to complete the Ginna Reliability Transmission Alternative to meet our requirement, anticipating it will be completed in mid-2017 when the plant is supposed to be retired,” spokesman John Carroll said.
GRTA is intended to provide access to other generation sources to supply the Rochester area and render Ginna unnecessary.
In contrast to the lifeline Cuomo is offering to the upstate nuclear units, the governor has repeatedly called for the closure of Entergy’s Indian Point plant, citing concerns over the safety of New York City, 30 miles south.
The PSC was supposed to take action on several clean energy orders at its meeting on Thursday, including one on a retail renewable portfolio standard, but the items were pulled from its agenda at the last minute.
“Because these programs are so important, we wanted to make sure we are examining all the issues. It is absolutely our intent to pursue these programs. Nobody should read anything into this, other than they are complex matters for our state energy policy and it’s important that we get it right,” commission chair Audrey Zibelman said to open the meeting.
FERC last week reaffirmed its rejection of MISO’s proposal to institute a mandatory capacity market, denying rehearing of its 2012 order on the issue.
In June 2012, FERC conditionally approved revisions to improve deliverability of capacity resources in the MISO footprint, but the commission rejected MISO’s request that the Planning Resource Auction become obligatory and subject to a minimum offer price rule. More than 15 entities, including MISO’s Independent Market Monitor, requested a rehearing.
Critics say vertical demand curve like that in MISO results in excessive price volatility. Dynegy included this chart in a presentation to investors last year, saying that when resources fall short of requirements, prices spike to the cost of new entry (CONE).
Capacity suppliers complained that MISO’s capacity construct is discriminatory because it requires sellers, but not buyers, to participate. Others took issue with MISO’s use of a vertical demand curve and two-month forward period before the auction.
In its order last week, FERC again rejected MISO’s proposed mandatory auction for resource deficiencies and upheld the use of a vertical demand curve (ER11-4081-001).
Load-serving entities, “as buyers of resources, must obtain sufficient resources to meet their planning resource margin requirement or pay a significant penalty of 2.748 times [the cost of new entry]. We do not consider this requirement and its associated penalty to be a ‘free pass,’ as characterized by capacity suppliers, or that buyers have no incentive to purchase capacity, as NRG [Energy] claims,” FERC ruled.
It also said MISO had not met its burden of proving its proposal was just and reasonable.
The commission also denied rehearing of the decision to reject MISO’s proposed minimum offer price rule, again concluding that customers “lacked the incentive to suppress auction prices in the MISO capacity market.” On the other hand, FERC reiterated its defense of MISO’s fixed resource adequacy plan, saying LSEs do not “have an incentive to exercise market power in the MISO region” and market manipulation is “unlikely.”
Daily Peak Load
The rehearing request by the Coalition of MISO Transmission Customers, a group of industrial customers, challenged MISO’s use of daily peak load, a method FERC directed the RTO to use three years ago, replacing the grid operator’s proposed daily pro rata method.
“We find that the use of the daily peak load contribution methodology until sufficient data exists to use the peak load contribution methodology does not represent undue discrimination against LSEs in retail choice states. … Requiring MISO to use available historical information, as Coalition of MISO Customers recommend, does nothing to resolve this data gap because MISO cannot force electric distribution companies to provide the necessary data,” FERC decided.
To comply with the commission’s June 2012 ruling, MISO revised its Tariff language. FERC accepted the edits, conditionally approving MISO’s map of zonal boundaries that pinpoint major transmission constraints and local balancing authorities and instructing the RTO to remove a reference to a minimum offer price rule (ER11-4081-002).
In the same order, FERC responded to Illinois Commerce Commission’s concern that the Tariff could hinder state commissions’ responsibility for enforcing resource adequacy, saying it was beyond the scope of the compliance proceeding.
LaFleur: Room for Improvement
At FERC’s open meeting Thursday, Commissioner Cheryl LaFleur said she supported the order “because I believe, based on this record and in the context of the primarily vertically integrated MISO region, the resource adequacy construct that we have approved is just and reasonable.”
“I’ve often noted that we need to take account of legitimate regional differences and I think we’ve tried to do so in this order. But I do want to comment to say that a determination that a market construct is just and reasonable does not mean that it cannot be improved. I want to recognize that there are a lot of efforts underway in the MISO region to consider reforms to the adequacy construct and I very much encourage parties to stay engaged in those processes, and I’ll be continuing to follow them closely.”
Amid increasing concern over threats to the nation’s power grid, the North American Electric Reliability Corp. last week ran a rigorous, two-day drill that simulated terrorist attacks.
“There were cyberattacks on corporate computers, infiltration of transmission systems and substations, explosives and shootings,” NERC CEO Gerry Cauley said in a press briefing Thursday, the final day of GridEx III. The exact scenarios were kept secret.
Cauley said that about 10,000 people at 315 organizations — electric generators, transmission companies, law enforcement, and local, state and federal government agencies — participated in or monitored the drill.
GridEx II, in 2013, drew 234 organizations and an estimated 3,000 participants. The first sector-wide grid security exercise was held in November 2011.
While details on the drills are kept close to the vest by NERC and the participants, a public report, expected out in January, will detail what the grid operators faced and how they fared.
The GridEx II report noted that the drill included simultaneous physical and cyberattacks. It laid out the “lessons learned” and recommendations, including efforts to enhance information sharing.
It also recommended expanding the capabilities and role of the industry group that coordinates with federal agencies on grid threats, the Electricity Sub-sector Coordinating Council.
Southern Co. CEO Tom Fanning, the head of ES-CC, said planning for the exercise began more than a year and a half ago and was essentially complete before the terrorist attacks in Paris on Nov. 13. So, although Fanning and his colleagues were in constant contact with federal counterparts after the attacks, they did not have an effect on this year’s drill.
That, he said, is an example of how grid operators must use current events to keep up with evolving threats. “The threat is ever changing,” Fanning said. “We know we have to continually anticipate the threat and adapt our own strategy. Being perfect here is an aspiration. We know we are always going to have to get better.”
“We are acutely aware of the recent events [in Paris] and the heightened urgency,” Cauley said. However, he said, “we have intentionally not built that into the exercises.”
This year’s drill was intentionally challenging, if not overwhelming, Cauley said. “It is a national exercise, and includes Canada and observers from Mexico,” he said. “The cyber vectors that we used started early [Wednesday] with attacks on public Internet and customer sites. We want to make sure this is not day-to-day stuff; it is rare,” he said. “We wanted to test the system.”
“There are cyberattacks in coordination with physical attacks, combined with trucks, and shootings to create some kind of enduring damage,” Cauley said. “This is not to be a simple, easy, one-day or two-day recovery.”
Cauley said cyberattacks have a bigger role in GridEx III than they did in previous exercises. Recently, there have been several public conversations about grid’s vulnerability to such attacks. Broadcaster Ted Koppel has been on a tour promoting his controversial book, “Lights Out,” about the grid’s vulnerability. Earlier this fall, a British think tank released a report asserting that U.S. nuclear power plants are at risk from cyberattacks. London-based Chatham House said the “risk of serious cyberattack on civil nuclear infrastructure is growing” because of its reliance on commercial “off-the-shelf” software.
“There are methods and tactics that exist to cause control systems to cause damage to equipment,” Cauley acknowledged. “But as a practical matter, it is very, very difficult to carry out” a successful cyberattack on security-hardened grid facilities.
NERC, grid operators and all other sectors of the industry continue to assess threats and react to them, Fanning said. “I think we are the only industry with mandatory critical infrastructure protection” against cyberattacks, he said. “What we are trying to do here is go beyond the requirement.”
FERC last week released its annual Enforcement Report, noting that it had opened 19 new investigations and closed 22 others with settlements or no action in fiscal year 2015. Settlements resulted in more than $26 million in civil penalties and disgorgement of $1 million in unjust profits. The biggest settlements were over the 2011 Southwest power outage that left more than 5 million people without power for up to 12 hours.
Enforcement staff is currently seeking recovery of more than a $500 million in civil penalties and disgorgement through federal court and administrative litigation.
The commission spent about $316 million during the fiscal year, an increase of almost $9 million over FY 2014. Three-quarters of spending was on salaries and benefits for 1,456 full-time equivalents, according to its annual financial report to Congress, which also was issued last week.
FERC approved two reliability rules proposed by the North American Electric Reliability Corp.:
One order approves reliability standards EOP-011-1 (Emergency Operations) and PRC-010-1 (Undervoltage Load Shedding) (RM15-7, RM15-12, RM15-13). It also includes a revised definition of the term “remedial action scheme” and eliminates use of the term special protection system. NERC said the two had previously been used interchangeably, resulting in ambiguity.
The second approves Transmission Operations (TOP) and Interconnection Reliability Operations and Coordination (IRO) reliability standards (RM15-16). The commission said the revised standards are more precise and clarify the delineation of responsibilities between applicable entities while eliminating gaps and ambiguities. Eight current TOP standards were compressed into three. FERC ordered NERC to revise the standards within 18 months to include transmission operator monitoring of non-Bulk Electric System facilities; specify that data exchange capabilities include redundancy and diverse routing; and require testing of alternate or less frequently used data exchange capabilities.
Rehearing Denied on e-Tag Access
FERC denied rehearing in its 2012 order (Order 771) granting the commission, RTOs, ISOs and their market monitoring units’ access to electronic tags (e-Tags) used to schedule transmission (RM11-12-001). The National Rural Electric Cooperative Association, the Edison Electric Institute and Southern Co. filed rehearing requests, while Open Access Technology International filed a request for clarification. Before the 2012 order, RTOs could only access e-Tags for interchange transactions that flowed into, out of or across their footprints.
WILMINGTON, Del. — A Tariff change endorsed by stakeholders last week will allow PJM to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auction for the 2016/17 delivery year.
PJM procured more than 4,200 MW of new capacity in that auction in August.
The resources would be sold in the third incremental auction for the delivery year, which is set for February. (See “Tariff Change Would Allow PJM to Sell Excess Capacity for 2016/17” in PJM Markets and Reliability & Members Committee Briefs.)
PJM Assistant General Counsel Jen Tribulski said PJM would seek a waiver from releasing capacity if FERC ordered the removal of demand response from the capacity market before the third incremental auction as a result of a Supreme Court ruling upholding the Electric Power Supply Association’s challenge to FERC’s jurisdiction over DR.
Although the lower court ruling specifically addressed DR in the energy market, some legal experts believe a ruling against FERC would also apply to capacity.
If it ruled in such a manner after the auction but before the start of the 2016/17 delivery year in June, or after the delivery year started but with a retroactive clause, PJM would need to repurchase at least 4,000 MW. This could result in a net cost increase.
If FERC removed DR from the capacity market after the delivery year and did not make the order retroactive, no further action would be necessary. The same holds true if FERC removed DR only from the energy market.
Market Monitor Joe Bowring questioned why PJM would release the capacity at all, given the contingencies and the potential of incurring additional cost.
“It’s not prudent to hold on to those megawatts when we can give value back to the load with megawatts we don’t need,” Tribulski said.
Higher IRM for Next Three Delivery Years Endorsed
With one “no” vote and 27 abstentions, the Members Committee approved an increase in PJM’s Installed Reserve Margin.
The IRM is used in the Reliability Pricing Model capacity auctions. The Reserve Requirement Study increased the IRM for the 2016/17 delivery year to 16.4% from 15.5%. IRMs also rose for the following two delivery years.
In previous discussions at lower committees, stakeholders had expressed confusion over why the IRM was increasing at the same time the Capacity Performance model is being implemented. (See “IRM, FPR Rising; PJM Methodology Challenged” in PJM Planning Committee Briefs.)
On Thursday, PJM’s Tom Falin said that Capacity Performance on its own does not result in a lower IRM because the Reserve Requirement Study always has been conducted under the assumption that generators will perform at the CP level.
“CP is changing the market rules to match the assumption we’ve always made in the study,” he said.
Finance Committee, Sector Whips, Members Committee Vice Chair Elected
Members elected the following:
Finance Committee (three-year terms)
End Use Customers: David Evrard, Pennsylvania Office of the Consumer Advocate
Generation Owners: Michelle Greening, Talen Energy
Other Suppliers: Marguerite Miller, Credit Suisse
Transmission Owners: Jim Benchek, FirstEnergy
Sector Whips (one-year term)
Electric Distributors: Steve Lieberman, Old Dominion Electric Cooperative
End Use Customers: Susan Bruce, PJM Industrial Customer Coalition
Generation Owners: Joe Kerecman, Calpine
Other Suppliers: Katie Guerry, EnerNOC
Transmission Owners: Jodi Moskowitz, Public Service Enterprise Group
FERC last week rejected a request by consumer advocates that it force PJM to update its 2015 peak load forecast using recent modeling enhancements to prevent over-procurement of resources in this year’s capacity auctions.
“While there will inevitably be some difference between PJM’s load forecast and the amount of capacity that PJM ultimately needs in a given delivery year, the record indicates that PJM has taken steps to ensure the reasonableness of the 2015 load forecast, including making a statistical adjustment based on a percentage of error it had seen in the load forecast over recent years, to account for the effects of energy efficiency programs,” the commission said (EL15-83). “The mere fact that PJM is working on a revised forecast methodology does not render the prior one unjust and unreasonable.”
(Click to zoom.)
The complaint was filed in June by a group that included industrial customers, environmental organizations, state regulators and consumer advocates. It said that using updated methodology released by PJM in December would reduce the peak load forecast for 2016/17, 2017/18 and 2018/19 by at least 7,000 MW, potentially saving consumers more than $600 million. (See Model Change Results in Lower Load Forecast for PJM.)
PJM responded that the revised forecasting model would not be complete and ready for use until November, after the Base Residual Auction and transition auctions had been held. It was approved by PJM’s Markets and Reliability Committee last week. (See related story, MRC Briefs.)
Last week’s order denied the consumers’ request that the auctions be delayed — a moot point since they have already occurred.
The commission also rejected the complainants’ request that PJM be compelled to reinstate a 2.5% “holdback” that was eliminated in FERC’s approval of the new Capacity Performance product.
“The commission specifically found in the Capacity Performance order that the holdback was not necessary to address load forecast errors,” FERC said. “The issue of whether it is appropriate to remove the 2.5% holdback is currently pending on rehearing of the Capacity Performance order and will be addressed in that proceeding.”
The commission required RTOs to revise their day-ahead market schedules in coordination with the new pipeline schedules or show why changes were unnecessary.
The commission approved PJM’s schedule change effective March 31 (ER15-2260 and EL14-24).
FERC also accepted compliance filings by NYISO (EL14-26) and ISO-NE (EL14-23), saying they had justified retaining their existing schedules, with day-ahead deadlines of 5 a.m. and 10 a.m., respectively.
FERC on Thursday issued orders that seek to increase the supply of regulation service and reactive power.
Wind generators would no longer be exempt from responsibility for providing reactive power under a FERC Notice of Proposed Rulemaking (RM16-1).
The commission also issued a final rule to allow generators to sell primary frequency response service at market-based rates (RM15-2).
The wind order would require that pro forma large and small generator interconnection agreements eliminate the reactive power exemption for wind. The requirement also would apply to generators making upgrades that require new interconnection requests.
Reactive power is essential for controlling system voltage.
Comments on the proposal will be due 60 days after publication in the Federal Register.
The frequency response order is intended to promote competition to meet increased demand for the service due to the Frequency Response and Frequency Bias Setting Reliability Standard (BAL-003-1), which will require balancing authorities to meet a minimum frequency response obligation effective April 1, 2016. (See FERC to OK 3rd Party Sales of Frequency Response.)
The order defines primary frequency response service as a resource standing by to provide autonomous, pre-programmed changes in output to counter large changes in frequency until dispatched resources can take over to return the system to 60 hertz.
Although most balancing authorities will be able to use their own resources to meet the standard, FERC said some may choose to purchase the service.
Generators selling the service under market- or cost-based rates must report their sales in their Electric Quarterly Reports. The rule will take effect 90 days after publication in the Federal Register.
FERC last week reversed an administrative law judge’s 2013 finding preventing Entergy from including the costs from an abandoned repowering project in the company’s allocation of costs to its operating companies.
Judge Philip Baten in June 2013 rejected efforts by Entergy Services and the Louisiana Public Service Commission (LPSC) to pass on to ratepayers through its “bandwidth formula” $200 million in canceled costs from the $1.8 billion Little Gypsy repowering project (ER12-1384-001, et al).
FERC’s Nov. 20 ruling said Baten’s reading of a provision in Entergy’s system agreement was “unreasonably narrow.” It said adopting his interpretation would negate the inclusion in the bandwidth formula of other production-related costs that were just and reasonable, and found Entergy’s proposal to include Little Gypsy cancellation costs in the bandwidth formula consistent with the system agreement.
Entergy uses its bandwidth formula to allocate production costs among its half dozen operating companies under its system agreement. Payments are made annually by low-cost operating companies to the highest-cost company in the system, using a bandwidth remedy that ensures no operating company has production costs more than 11% above or below the Entergy system average.
FERC also reversed Baten in including the project’s cancellation costs in the bandwidth formula as being “consistent with the purpose of the bandwidth remedy.” It disagreed that the inclusion of the costs “would constitute a landmark policy shift for the Entergy system,” as Baten had said, noting that the commission had already determined the propriety then-current version of the system agreement.
The commission disagreed with the initial ruling and interventions by the Arkansas and Mississippi regulatory commissions, which argued the cancellation costs should be considered “construction work in progress” and excluded from the bandwidth formula. Noting that Entergy had securitized the cancellation costs, FERC found them to be production costs “and, therefore, “the kinds of costs that are appropriate for inclusion in the bandwidth formula.”
At the same time, FERC affirmed Baten’s decision that the repowering project met the needs of the Entergy System “as a whole,” and not just regional needs. It rejected the Mississippi Public Service Commission’s allegation that the LPSC “avoided cost responsibility for its ratepayers” by approving the project’s cancellation, rather than require it be completed.
The commission also sided with the judge in ruling that the LPSC had failed to provide sufficient evidence backing its complaint that his ruling was discriminatory.
The Little Gypsy project would have converted an old gas-fired generator on the Mississippi River west of New Orleans into a petroleum-coke burner. Entergy cited the shale-gas boom and resultant drop in natural gas prices in suspending the project in 2009. It wasn’t until 2011 that the LPSC officially canceled the project and granted cost recovery.
The first call, which was hampered by poor sound quality, focused on the regulatory framework and the CPP’s impact. Several public speakers indicated they had not yet formed a position.
Future calls will discuss the federal plan’s structure, the mass-based implementation approach and the rate-based implementation approach. A face-to-face meeting will be scheduled in early January.
United Illuminating will start work next spring on a microgrid that will allow municipal buildings in the Town of Woodbridge to operate independently of the grid, powered by a 2.2-MW fuel cell.
The centerpiece of the microgrid is a fuel cell that under normal conditions will generate power for the regional electric market. But if the grid fails, the generator will provide power to town hall, the library, the fire station, the police department, the public works department, a senior center and a high school.
The fuel cell, to be owned by UI, will be manufactured by Danbury-based Fuel Cell Energy and will be located on the grounds of Amity Regional High School. Waste heat from the fuel cell will be captured to produce domestic hot water and to heat the school.
Probe: Did Execs Mislead ICC About Ballooning Project Costs?
Madigan
The Commerce Commission will investigate whether executives involved in the $5.7 billion buyout of Peoples Gas failed to disclose the escalating costs of a massive pipe-replacement program during merger proceedings.
The probe grew out of a Sept. 30 auditor’s report that said Peoples Gas executives knew in January, well before they testified before the commission in May, that the estimated cost of replacing 2,000 miles of aging Chicago gas mains had nearly doubled to more than $8 billion.
While the commission dismissed Attorney General Lisa Madigan’s petition asking for a wide-ranging investigation, it will permit her to present other evidence of suspected misrepresentations. The gas utility’s new owner, WEC Energy Group, is expected to propose cost-cutting measures to the ICC this month.
Rock Island Line Stalls as Landowners Turn down Easement Offers
The proposed Rock Island Clean Line that would transmit 3,500 MW of wind power has hit a roadblock after the developer failed to secure easements from a large number of landowners along its route.
Clean Line Energy Partners told the Utilities Board to halt its technical review of the project while the company considers “whether and how to proceed.” Clean Line has secured easements from just 176 of the 1,540 parcels needed for a route that crosses 16 counties, according to the Preservation of Rural Iowa Alliance, an opposition group.
Landowners say delays in the transmission line’s progress has cast a cloud over potential real estate deals and development along the proposed route. A lawmaker says he intends to introduce a bill to establish a deadline for completing the collection of voluntary easements. The bill will also stipulate that a transmission developer cannot exert eminent domain until at least 80-85% of affected landowners voluntarily grant easements.
Construction to Begin on State’s Largest Solar-Powered Site
Construction is expected to begin this month on the state’s largest solar-powered generating facility, according to Louisville Gas & Electric and Kentucky Utilities.
The 10-MW solar farm will consist of about 45,000 photovoltaic panels erected on 50 acres at the E.W. Brown Generating Station, a Mercer County coal and gas plant owned by the two utilities, which are subsidiaries of PPL.
The $36 million facility is expected to generate 19 GWh of energy, enough to power 1,500 homes, when it starts operating in the late spring.
Toyota Plant Supplements Power with Methane from Dump
A Toyota manufacturing plant in Georgetown is tapping into the energy trapped in a landfill to generate power. Toyota officials said the system that captures and burns landfill methane is capable of producing 1 MW currently but can be upgraded to produce 10 MW.
The automaker has installed a generator at the Central Kentucky Landfill that will send power to its plant via a 6-mile transmission line.
There are 645 landfill methane projects operating across the nation with a capacity to produce 2,066 MW, according to the Environmental Protection Agency’s Landfill Methane Outreach Program.
Kentucky Utilities and Louisville Gas & Electric have filed requests to each install 10 new electric vehicle charging stations. Under the filing with the Public Service Commission, the utilities propose that the full cost of charging stations will be borne by those who request the stations or who use the charging service.
More than 15,000 EVs have been registered in the past five years in Kentucky, where there are about 30 public charging stations. The Electric Power Research Institute recently published a report that indicates interest in EVs is growing.
Home and small-business customers of Central Maine Power who buy electricity through the utility’s standard offer will see slightly lower rates in 2016. The Public Utilities Commission has accepted a bid for energy supply that is 3.7% lower than last year’s average, which will translate to savings of $1.35/month on a typical residential bill.
According to the commission, energy supply rates will dip to 6.46 cents/kWh next year from 6.71 cents currently. About 40% of the utility’s customers receive the standard offer rather than buying power from a competitive supplier.
“The standard offer prices set this week reflect the best bids received in a strongly competitive auction process,” said Mark Vannoy, PUC chairman. “We are pleased that prices remain stable or slightly decreasing, allowing retail customers and businesses to benefit from recent downward trends in energy markets that have been reflected in New England wholesale prices.”
The environmental group Food & Water Watch has launched a campaign to force legislators to remove chicken manure as a resource from its renewable portfolio standards.
Poultry farms in the state produce more than 650 million pounds of chicken manure annually. As an incentive to keep the waste out of the Chesapeake Bay, legislators in 2011 added the waste to the RPS, in the same top-tier category as solar and wind.
However, few chicken-manure methane capture projects have materialized, and environmentalists say that burning the manure produces toxic chemicals.
Public Service Commission staff have drafted regulations that would allow residents to subscribe to a community solar energy generation system through a pilot program.
The public may submit comments until Dec. 4. The commission will consider the regulations at its Dec. 14 meeting.
Community solar projects, which may appeal to customers who are unable to install rooftop solar, would be permitted up to 2 MW in size.
House, Senate at Stalemate on Solar Incentives, Caps
Lawmakers failed to complete a deal to update the state’s solar incentives before wrapping up for the year. Leaders appointed a conference committee to hammer out a deal that could delay any agreement at least until formal sessions resume in January.
The sticking point is cost. The House’s proposal would significantly curb the state’s net metering credits once the state hits a target of 1,600 MW, while a Senate bill was considered to be more generous to the solar industry.
The law now caps the amount of net metering credits allowed in a particular utility’s system. Those caps have already been reached in National Grid’s territory for non-residential projects, delaying a number of installations. Both the House and Senate bills would increase the caps.
Clean Line to Appeal for Approval on Grain Belt Express
Clean Line Energy will again try to convince the Public Service Commission to approve the Grain Belt Express transmission line that would carry wind-generated electricity from Kansas through Missouri and Illinois to Indiana.
State regulators, who rejected the a certificate of need for the project in July by a 3-2 vote, are the last remaining hurdle for the $2 billion 780-mile transmission line, which was recently approved by Illinois utility regulators. A certificate of need would allow Clean Line to acquire property through eminent domain.
Landowners who oppose the line are also seeking to block the project.
Group Tries Using Farming Law to Stop Mark Twain Tx Line
Opponents of Ameren’s proposed 100-mile Mark Twain transmission line are challenging the project on the grounds that it would allegedly violate the state’s recently enacted “right-to-farm” amendment. The line would deliver wind power from the Iowa border to the grid, according to Ameren.
The group, called Neighbors United Against Ameren’s Power Line, contends that the project would “permanently remove citizens’ property from production and prevent these citizen farmers and ranchers from engaging in farming and/or ranching practices.”
The Public Service Commission rejected the group’s motion to dismiss Ameren’s application for a certificate of necessity, but it said the amendment could still potentially be used in a court challenge. Ameren told the commission that the argument advanced by the activists is “patently absurd” because it would potentially outlaw “every single new electric line, gas line, water line, sewer line” that would “take any farm land whatsoever out of production.”
New Jersey Natural Gas has asked the Board of Public Utilities to increase rates by $148 million, which it says it needs to upgrade its infrastructure.
The increase would boost a typical customer’s bill by about 24%, or about $236 more a year.
The utility says that wholesale natural gas prices are dropping, so it needs to increase delivery rates to make up the difference in revenue. The rate-increase request is the company’s first since 2007.
Two wind farms being built for $430 million are nearing completion. Construction was delayed because of excessive winds.
Contractor Cielo Wind Power, which manages the projects, said the wind created some problems in the last two months for construction crews, but employees have been able to make up for most of the setbacks by working weekends and other off days.
The Roosevelt Wind Project’s 125 turbines are already energized. The Milo Wind Project, which includes 25 wind turbines, is not yet operating. Roosevelt’s 250 MW is committed to Xcel Energy and Milo’s 50 MW of energy will be sold on SPP’s open market.
The Cuomo administration is urging the U.S. Nuclear Regulatory Commission to deny Entergy’s applications to extend the licenses of two reactors at the Indian Point Energy Center.
“Allowing Entergy to operate these facilities for another 20 years puts the lives of too many New Yorkers at risk,” wrote Jim Malatras, director of state operations. He said the plant’s location near New York City “makes it absolutely impossible to have an effective safety and evacuation plan.”
The administrative law judges of the Atomic Safety and Licensing Board are currently hearing testimony on the request.
Bald Eagles Given Consideration in Wind Farm Development
The Public Service Commission has approved a 100-MW, 59-turbine wind farm on 15,000 acres near the Canadian border. The $175 million project’s developer, Rolette Power Development, agreed to several concessions to minimize the wind farm’s impact on bald eagles.
The U.S. Fish and Wildlife Service determined that there were no eagle nests in the project area, but it did find nests nearby. Rolette amended its application “to allow for various stipulations to minimize impact on the birds.” The company pledged to remove dead livestock and roadkill from the site so as not to attract eagles.
The University of Pittsburgh has received a $2.5 million grant to research ways to shift the grid from alternating current technology to direct current, reviving the 19th Century “War of Currents” between George Westinghouse and Thomas Edison over which type of power transmission would dominate.
“Very few items today require three-phase alternating current,” said researcher Greg Reed, who founded and runs the university’s Direct Current Architecture for Modern Power Systems program.
“The use and development of today’s evolving energy mix, which includes more DC resources such as solar photovoltaics, as well as electric vehicles and battery storage systems, also makes transition to DC more sensible and viable for future power-delivery needs.”
The Public Utilities Commission does not consider many new wind projects, as a state law exempts wind farms that produce less than 100 MW from having to get a permit.
So the PUC on Nov. 12 had the rare opportunity to approve the 103-MW Willow Creek wind farm. It was the first wind project for the two newest commissioners, Chris Nelson and Kristie Fiegen. They joined the remaining commissioner, long-time member Gary Hanson, in approving the proposal by Colorado-based Wind Quarry.
Wind Quarry intends to erect 45 turbines, each 440-feet tall, across three townships in Butte County. The project would connect with a Western Area Power Administration transmission line.
Old Dominion Electric Cooperative selected Hecate Energy to build two solar projects in Northampton and Clarke counties.
The Cherrydale project, in Northampton, is expected to deliver about 20 MW. The Clarke County project will produce about 10 MW. They are expected to be in service by the end of 2016.
Leesburg entrepreneur Karen Schaufeld is developing what is thought to be the state’s largest privately funded solar array on her 63-acre farm in an effort to create a community-based grid.
She wants to develop a model of solar power that is less expensive and more efficient than the power offered by Dominion.
The practice is called Agriculture Net Metering, and Schaufeld’s project is expected to generate more than 450 kW.
Dominion Resources said last week it plans to invest $11.7 billion over the next six years in capital projects, including new generating plants, transmission lines, a gas pipeline and environmental cleanup.
About half the spending is targeted for the state, where the projects are expected to make an economic impact of $1.68 billion annually.
Only one project on the list, a gas-fired generator in Brunswick County, has been approved. Others are at various stages of development.
PSC Considers WPS Hike Request, Cuts Rates for Electric and Gas Instead
Wisconsin Public Service may regret the day it filed a request with the Public Service Commission to raise electric rates by 9.7% and natural gas rates by 2.7%.
On Thursday the commission voted to cut the utility’s electric rates by 0.7% and to reduce gas prices by almost 2%. An average residential electric bill will decrease from $80.93 to $80.80, and the typical gas bill will drop from $53.93 to $52.84.
The commission did approve a $2 increase in the utility’s fixed monthly charge for electric customers, bringing it to $21 from $19. WPS had asked the customer charge to be set at $25.
