The union representing workers at a Massachusetts power plant slated for closure is again asking federal regulators to reconsider its protest of capacity auction results in New England (ER15-1137).
Utility Workers Union of America Local 464 last week asked the Federal Energy Regulatory Commission to rehear its order accepting results from the ninth Forward Capacity Auction from February, citing “errors” in a June order affirming the results.
The union has tried three times without success to persuade FERC that recent capacity auctions in New England have been tainted by generators illegally withholding the Brayton Point generating station from the last two FCAs to boost prices paid to other assets. (See FERC Accepts ISO-NE Capacity Auction Results.)
“The June 18 order errs by failing to place the burden of proving just and reasonableness and compliance with the Tariff with respect to the FCA 9 results on ISO-NE, as required by Federal Power Act … and the ISO-NE Tariff, and by failing to expressly find that ISO-NE failed to meet that burden in reaching its finding approving the FCA 9 results, and particularly by failing to require the submission of substantial evidence affirmatively demonstrating that the attempted withdrawal or ‘retirement’ of Brayton Point by its owner announced in early 2014 was economic, and therefore in conformity with the ISO-NE Tariff provisions,” the filing says.
Iberdrola reported net income of 1.5 billion euros in the first six months of 2015, up 7.4% on the same period last year, as increased revenue in its U.S. and other overseas operations offset declines in Spain.
Gross operating profit increased by 5.7% in the first half to 3.8 billion euros, thanks to the strong performance of its international business, which grew by 20%, compared to a 6.5% drop in Spain, the company said in a statement.
The company also reiterated plans to refile with regulators in Connecticut and Massachusetts its proposed acquisition of UIL Holdings, which was derailed earlier this month. (See Iberdrola Withdraws UIL Acquisition; Plans to Refile.)
The company only briefly mentioned its proposed acquisition of Connecticut-based UIL, which has gas and electric operations in New England. Iberdrola expects to close the deal in the fourth quarter of the year.
The company said it has received approvals from all four federal agencies required and expects to close the transaction in the fourth quarter.
The Federal Energy Regulatory Commission has conditionally granted a request by MISO to create a 10th local resource zone, in Mississippi (ER15-1771).
The state currently is part of MISO Zone 9, which also consists of Louisiana and part of Texas.
MISO’s Tariff requires that the RTO must develop new zones by Sept. 1 of each year if necessary to ensure adequate planning resources to meet demand and loss-of-load-expectation requirements.
MISO said its analysis showed the need for a separate, stand-alone zone for Mississippi.
MISO will use the zone to allocate costs of new market efficiency projects. It will not affect the cost allocation transition period for the MISO South region, the order stated.
The RTO defines zones by several criteria, including state and local balancing authority boundaries and the strength of transmission interconnections between BAs.
FERC said MISO’s re-evaluation was consistent with such criteria and that no parties opposed creating the new zone. “MISO states that with the new Mississippi zone, MISO will continue to appropriately balance the granularity in the calculation of benefits from market efficiency projects and the uncertainty of these calculations at a more granular level,” FERC wrote.
New Zone Rests on Resolving Another Dispute
But FERC said its approval would be conditional on resolution of a pending case involving proposed revisions to MISO’s resource adequacy construct. The RTO filed the changes to comply with FERC orders addressing concerns about deliverability of capacity resources throughout MISO’s footprint (ER11-4081).
MISO won commission approval to impose a zonal deliverability charge on load-serving entities that meet their resource adequacy requirements through resources located outside of the zone where their loads are located.
MISO proposed two types of hedges against deliverability charges, including a “grandmother agreement” for market participants that secured firm transmission rights prior to July 20, 2011.
But FERC ordered MISO to terminate the grandmother agreements after a two-year period, saying it would unreasonably allow LSEs to avoid using deliverability as part of their resource planning analysis — negating the purpose and reliability benefits of the proposed locational market mechanisms.
Parts of that 2011 FERC order are still being slugged out at the commission. Among those trying to convince FERC to rehear the elimination of the grandmother clause is Great River Energy, which said it has been exposed to significant pancaked costs for capacity since the two-year phase out of the waiver.
Dynegy Case Indicative of Broader Zone Problem?
In a filing last month, Great River referred to a dispute involving zonal boundaries: the complaint filed in May by Public Citizen and the Illinois Attorney General about the nine-fold increase in Zone 4 prices in MISO’s Planning Resource Auction last April (EL15-70).
Great River said that case illustrates “that commission action is needed to address problems in the implementation” of zones.
Great River said the Zone 4 complaints also demonstrate significant price separation that can occur between zones. “Some of this price separation could have been hedged from grandmother agreement treatment if firm transmission service existing from non-Zone 4 generation to Zone 4 load.”
In Great River’s case, it told FERC it is likely to incur even more capacity costs through the islanding of its load in Zone 3. Great River said MISO’s “improper” application of the zone criteria had the effect of islanding its load in southern Minnesota by carving it out of Zone 1, where all of its generation is located.
The Federal Energy Regulatory Commission has accepted revisions to the ISO-NE Tariff that make wind and hydropower resources more readily dispatchable (ER15-1509).
The changes “will minimize the need to use manual curtailment processes and thus, provide for a more economically efficient use of these resources,” FERC wrote.
The recent increase in the integration of variable renewable resources in relatively remote areas of the transmission system has caused increased congestion, ISO-NE said. These resources do not have direct control over their net power output, are not currently electronically dispatchable and must be manually curtailed to manage congestion, which is inefficient.
ISO-NE said the new method would manage localized congestion through Do Not Exceed (DNE) Dispatch Points — the lesser of the maximum output level at which the resource would operate in economic dispatch, or a reliability limit representing the maximum output consistent with reliability constraints.
FERC said the changes are particularly important as these resources are increasing in New England. While there are 878 MW of wind and 321 MW of hydro generation operating in the region, there are more than 4,000 MW of these renewables in the RTO’s interconnection queue.
“We agree with ISO-NE that these changes will improve price formation, particularly in areas that have a high penetration of renewable resources and limited transmission capacity, and system reliability because of the reduced reliance on manual curtailments,” the commission said.
FERC, however, rejected Tariff language that would have excluded wind resources from participating in regulation and reserves markets, agreeing with renewable energy developers that a “blanket exclusion” was not justified. “Eligibility for providing these services should be based on capability and performance characteristics rather than categorical exclusions,” according to the order. Rules should be developed through a stakeholder process, the commission said.
FERC also gave hydro resources that do not currently have remote terminal units an additional year to comply because they have to undertake additional steps to become DNE Dispatchable Generators, compared with resources that already have the equipment.
ISO-NE’s proposed Tariff revisions are conditionally accepted effective April 10, 2016, with a compliance filing due in 30 days.
Delaware Gov. Jack Markell has joined regulators, consumer advocates and industrial customers representing the Delmarva Peninsula in lobbying the PJM Board of Managers to reject planners’ recommended reliability fix for Artificial Island, barring a new look at why virtually all of the project’s $275 million price tag will be charged to Delaware and Maryland customers.
Markell
“As the project is currently structured, Delaware consumers would bear over $100 million of costs associated with the project in exchange for a very small portion of the value it would create,” Markell wrote in a July 13 letter to board Chairman Howard Schneider.
According to the Delaware Public Service Commission, that could translate to a 25% increase in transmission costs in the state. Some of the state’s heaviest users could see their monthly bills surge by hundreds of thousands of dollars, Markell said.
‘Neither Reasonable nor Equitable’
“It seems patently unfair that electricity users in the Delmarva Peninsula would bear almost the entirety of the costs of a project for which the principal benefit is not expanded energy transmission in Delaware, but maximizing power from generating units in New Jersey that serve customers throughout the PJM region,” Markell said.
“Allocating to Delaware and Maryland consumers the bulk of those costs for a project not necessitated by demand in this area is neither reasonable nor equitable.”
Paul McGlynn, PJM’s general manager of system planning, said in an interview that cost allocations for Order 1000 projects are formulaic and governed by PJM’s Tariff as approved by the Federal Energy Regulatory Commission.
When the 10-member board meets Wednesday in closed session, it could take a position anywhere on a wide spectrum, from approving the project as-is, to directing staff to develop Tariff changes regarding cost allocation, he said.
Previous Board Action
A number of those dissatisfied with the cost allocation recalled the board’s rejection last summer of a Public Service Electric & Gas proposal to upgrade Artificial Island following outcry from losing bidders, environmentalists and New Jersey officials. (See PJM Board Puts the Brakes on Artificial Island Selection.)
“The board displayed leadership and courage in July 2014 to defer decision on the Artificial Island proposal selected,” a group of end-use businesses said a July 17 letter.
“We respectfully submit that similar leadership and courage is necessary again now with respect to Artificial Island to ensure that the project selected by PJM staff and the cost allocation produced by PJM’s solution-based DFAX [distribution factor] do not undercut PJM’s important efforts to implement Order No. 1000 in a just and reasonable manner,” said the group, which includes Linde, E.I. du Pont de Nemours and Co., Delaware Racing Association, Kuehne Chemical Co., Delaware City Refining Co. and Christiana Care Health System.
LS Power Plan
PJM staff announced at a special April 28 meeting of the Transmission Expansion Advisory Committee that they would recommend LS Power’s plan to use horizontal directional drilling under the Delaware River to build a new 230-kV circuit from Salem, N.J., to a new substation near the 230-kV corridor in Delaware, tapping the existing Red Lion-Cartanza and Red Lion-Cedar Creek 230-kV lines. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.) LS Power’s proposal also includes the option of an overhead crossing.
PSE&G and Transource Energy, two other finalists, were tapped to build necessary connection facilities.
Home to the Salem and Hope Creek nuclear reactors, Artificial Island is the second largest nuclear complex in the country. Special operating procedures that historically have been used to maintain stability in the area have become increasingly difficult to implement while respecting the system’s other operational limits.
ODEC noted that the cost of PSE&G’s alternative 500-kV project would have been divided among all PJM zones on a load-ratio share basis, with 50% allocated using the solution-based DFAX method.
“In other words, two transmission upgrades designed to address the same operational performance issues and both costing approximately the same would be allocated to widely varying groups of customers,” it said.
“ODEC believes that, in this specific situation, the cost allocation of the proposed Artificial Island solutions is highly relevant to the determination of whether the proposal is ‘the more efficient and cost-effective solution.’”
It noted that FERC is considering a number of similar challenges to certain DFAX cost allocations.
Environmental Challenge
The board received another letter opposing the Artificial Island project, but on environmental grounds, from the Delaware Riverkeeper Network. It urged the board to seek out an alternative with fewer environmental impacts that does not include crossing the Delaware River.
Riverkeeper Maya K. van Rossum noted that the project’s route will traverse the Augustine Wildlife Area and the Appoquinimink River, which include large expanses of wetlands that are part of the largest preserved coastal marshland on the East Coast.
Several endangered bald eagles breed in the area, which also supports the similarly endangered northern harriers, she said.
“Furthermore, species such as the federally endangered Atlantic Sturgeon — of which there are less than 300 spawning adults each year of the river’s genetically unique population — can ill afford additional harm to their population, spawning capabilities or juvenile survival.”
If PJM proceeds with the LS Power proposal, she said, the group will request federal agencies to prepare a full environmental impact statement.
“In addition to potential time delays, any environmental impacts will raise the cost of the project through the need for mitigation projects,” she said.
The price tag on the proposed Northern Pass transmission line in New Hampshire appears likely to rise after a draft environmental impact statement released last week showed the cheapest route would also have the greatest environmental impact.
The draft EIS by the U.S. Department of Energy evaluates various alternatives for the 187-mile route that would connect Canadian hydropower with the wholesale energy markets in New England.
The developers’ preferred route would require the creation of a new, 40-mile right of way measuring 150 feet wide. Identified as Alternative 2, the route “would impose the greatest environmental impacts as compared to the other action alternatives primarily because of visual impacts, vegetation removal and ground disturbance required,” according to the department.
It “would also have the least cost of construction (approximately $1.06 billion).” The department also said it would cost an additional $564.1 million in “economic impacts from construction.”
Only 8 miles of the northernmost section would be buried under the cheapest scenario, but the developer appeared to leave open the possibility that more of the route could be laid underground, saying it is reviewing the reaction to the document and giving “further consideration” of the “potential view impacts related to overhead lines.”
“These and other conclusions in the DEIS will help inform our forthcoming proposal to the state of New Hampshire’s Site Evaluation Committee,” Northern Pass Transmission, an Eversource Energy subsidiary, said in a statement. “As we’ve stated, we plan to propose a new, balanced plan in the near future that incorporates the feedback we’ve heard in discussions across the state and will address those concerns while providing substantial economic benefits to New Hampshire.”
William Hinkle, a spokesperson for Gov. Maggie Hassan, reiterated her opposition to Alternative 2, saying “the project must fully investigate burying more sections of the lines.”
“She will continue to encourage the company to listen to the concerns of Granite Staters, and if it is going to move forward, propose something that ensures lower costs for New Hampshire ratepayers and that protects our scenic views and beautiful natural resources, which are critical to our economy,” Hinkle said.
Environmental advocates, outdoorsmen and elements of the tourism industry have lobbied for burial of the entire route — the most expensive alternative.
“The Department of Energy’s alternatives analysis provides strong evidence that the overhead transmission line proposed by Northern Pass or just partial burial in the vicinity of the White Mountain National Forest would cause considerable environmental and scenic damage compared to total burial of the project,” Kenneth Kimball, director of research for the Appalachian Mountain Club, said in a statement.
The department said its draft EIS concluded that “the alternatives that would be constructed underground along existing roadways … would impose the fewest environmental impacts due to the lack of visual impacts and use of already disturbed roadway corridors. However, all of the underground alternatives … would have the highest construction costs (between approximately $1.83 billion and approximately $2.11 billion).”
The 1,200-MW project is a joint venture of Eversource Energy and Hydro Quebec. It was proposed in 2010 and, if the current schedule holds, would be completed in 2019. (See Eversource: Northern Pass Delayed Until ’19; Earnings Up.)
According to the report, the company’s preferred route, and a similar 1,200-MW alternative, would provide the greatest benefit for the wholesale energy markets. It would decrease wholesale electricity costs by $22 million in New Hampshire and by $149 million across ISO-NE. Other alternatives with a 1,000-MW capacity would only save $18 million and $134 million, respectively.
The department also said that the preferred route is the only alternative inconsistent with the existing White Mountain National Forest Plan. Overhead transmission would be seen from “historic architectural resources and thus could adversely affect the historic context of these sites more than the underground alternatives.”
A 90-day comment period will begin once the study is published in the Federal Register.
The SPP working group responsible for recommending changes to the RTO’s Tariff decided last week to form a task force to consider developing a payment plan for members who face debts as a result of the Z2 credit resettlements.
Westar Energy’s Dennis Reed, the Regional Tariff Working Group’s chair, said a task force’s narrow focus would help determine the best approach for a Z2 resettlement payment plan. The task force will work with SPP staff and report to the RTWG, which will email a request for member participation.
The Z2 project is an effort to design software that would properly credit and bill transmission customers for system upgrades under Tariff attachment Z2. The problem has been trying to avoid over-compensating project sponsors and include a way to “claw back” revenues from members who owe SPP money for other reasons. Accounting for transfers of reservations has also been a challenge. The project is scheduled to be completed in 2016 after years of delay. (See SPP Z2 Project Team Still Grappling with Problem’s Size.)
The RTWG was briefed on the current estimated cost of creditable upgrades involving generator interconnections, transmission service and sponsored upgrades: $721 million for 142 upgrades, with the costs borne by 68 initial upgrade sponsors. A separate member task force will work with SPP staff to review and verify the results.
Canadian Transactions
The RTWG made slight edits to a Tariff revision request involving future transactions with Canadian utilities.
With the Integrated System’s integration into SPP, the RTO will now have interconnections with SaskPower, whose affiliate will become a market participant, and Manitoba Hydro, which has also expressed interest in market participation. Manitoba Hydro requested that SPP develop Tariff language that recognizes the U.S.-Canada border as the point of delivery and point of receipt for transactions involving Canadian entities.
SaskPower assets (click to zoom).
The revision request (TRR 110: Point-of-Delivery and Point-of-Receipt Transactions at the Canadian Border) will provide legal recognition that satisfies federal and provincial requirements and allows Canadian entities to export energy in the U.S. without seeking approval from the U.S. Department of Energy. The revision would set the energy’s border point-of-delivery at an interconnection between a transmission provider’s facility and the Canadian utility’s transmission facility.
Transmission Working Group
Meeting earlier in the week, SPP’s Transmission Working Group discussed three potential SPP-MISO interregional projects and whether their construction will create new reliability needs.
The group approved SPP staff’s review of system constraints for use in the regional review of the three projects. Staff will identify “least-cost” projects to mitigate any thermal needs, reporting study results back to the working group in August.
The projects include construction of a 345-kV line between Nebraska and Kansas, a series reactor on a 115-kV line in northeast Louisiana and the rebuild of a 138-kV line south from Shreveport to Wallace Lake. They have been recommended for approval in the SPP-MISO Coordinated System Plan study.
The group also approved a flowgate assessment report and reviewed revision requests 67 and 71, Firm Service with Redispatch Clean Up and Revisions to Attachment D and Section 19.2, respectively. The group decided to wait until its next meeting to finalize any recommendations of the two RRs.
American Electric Power celebrated increased second-quarter profits last week, but the company said it still needs the Public Utilities Commission of Ohio to approve the so-called “guaranteed rate” plan it and other utilities have asked for to support its generating plants.
Akins
The company reported net income of $430 million, up from $390 million for the same quarter last year. CEO Nicholas Akins credited increased industrial load, partly from the oil and gas industries associated with Utica and Marcellus shale fields.
He also noted the approval by the Federal Energy Regulatory Commission of PJM’s Capacity Performance proposal and said that despite that commission “throwing a wrench in in the plans for at least a supplemental auction being held next week,” the company intends to participate in the delayed Base Residual Auction. (See FERC Orders PJM to Include DR, EE in Transition Auctions.)
The auction, he said, “will ultimately help define the forward view of generation value.”
“The supplemental auction remains important to our risk-adjusted 2016 performance,” he added.
Akins said the pending decision on guaranteed income in Ohio, in which PUCO would set rates for its generating plants to secure the future of those stations, is crucial to the company.
“We would not have presented the [power purchase agreement] option through the commission if we did not think it was important,” he said. “It’s about volatility of electric pricing — particularly in extreme heat or extreme cold — that impacts all customers’ pocketbooks.
“Continual delays are not the answer. It’s time for the PUCO to do the right thing,” he said. “It’s important for Ohio and its energy policy, Ohio jobs, taxes, economic development, and in fact, the future of the generation business in Ohio.”
AEP has been joined by Duke Energy and FirstEnergy is asking for income guarantees for certain of its plants. AEP had another, smaller-scale plan before PUCO that was denied. But the commission has not yet ruled on any of the other requests before it.
In May, new PUCO Chairman Andre Porter said a decision was several months out. “My focus is to ensure that we do whatever is best for Ohio,” Porter said. “Our state will be most successful, in my view, with a commission that confronts the biggest challengers.”
But Akins said a ruling from PUCO is critical for all involved, and he expressed frustration at the delay. “It just looks like it is some continued delay really,” he told one analyst during the conference call. “We don’t seem to be getting answers or schedules or the things we need to be able to get the answers we’re looking for. They seem to be putting some of the decisions further out into the future.”
Critics, including consumer advocates and environmentalists, say that AEP’s plan undermines Ohio’s status as a deregulated state.
“In a situation like this, when a utility is buying power from an affiliate, you have to assume that the fix is in,” Rob Kelter, senior attorney for the Environmental Law and Policy Center, told The Columbus Dispatch.
The Omaha Public Power District’s Fort Calhoun Station nuclear plant was taken offline July 20 to repair a water leak on one of its four reactor coolant pumps. The outage’s duration will depend on the extent of the required repairs.
An OPPD press release said the outage’s timing was coordinated with SPP to ensure grid reliability and said any additional energy to meet customer needs will be purchased through the grid.
Fort Calhoun is a single unit plant 20 miles north of Omaha, Neb., producing 479 MW of power. The plant returned to full power June 15 following a two-month refueling outage.
Cleco Gets FERC Approval for Acquisition by Macquarie
Louisiana-based energy company Cleco announced last week it had received approval from the Federal Energy Regulatory Commission for its proposed acquisition by a consortium of investors headed by Macquarie Infrastructure and Real Assets.
Cleco, parent company of Louisiana utility Cleco Power entered into a definitive agreement to be acquired by the investor group last October. The agreement valued Cleco at roughly $4.7 billion, including about $1.3 billion of assumed debt. The acquisition is expected to close in the second half of 2015, subject to approval by the Louisiana Public Service Commission.
In addition to Macquarie, the investor group includes British Columbia Investment Management, John Hancock Financial and other infrastructure investors.
Pepco Slowest Utility in US to Connect Solar Projects
A report by EQ Research shows that Pepco is the slowest utility in the United States when it comes to connecting solar projects to the grid.
The report, sponsored by the solar industry, showed that the Washington, D.C., utility takes an average of 76 days to connect solar projects in Maryland and an average of 51 days in D.C. Pepco said the long time is necessary to protect the grid, but just to the north, Baltimore Gas & Electric takes an average of 15 days. BG&E is owned by Exelon, which has proposed to acquire Pepco’s parent company.
The report shows that Eversource in Connecticut has the fastest connect time: Five days. The national average is 25 days.
Iowa Co-op to Start Charging $85 ‘Facilities Fee’ for Solar Customers
Pella Cooperative Electric, a 3,000-member electric co-op in Iowa, notified members that it is tripling a fixed charge on its bills for solar and other self-generating members, from $27.50 a month to $85.
“I think it is unlawful, and I think it’s outrageous compared to any other RECs (rural electric cooperatives) that I know of,” one member said. That member, Mike Lubberden, was contemplating installing solar panels but said he is now canceling those plans. The fee seems to be one of the highest in the Midwest, according to a policy analyst with The Alliance for Solar Choice.
John Smith, Pella’s CEO, said the co-op decided on the increase after conducting a cost-of-service study. He said the study found that members who generate some or all of their energy – there are only 12 in the co-op – aren’t paying their fair share of the cost to maintain the system. Smith, however, declined a request to show the study to Midwest Energy News. The co-op is giving current customer-generators five years before they have to pay the higher fee.
Caroline Dorsa, PSEG’s CFO, to Retire in 4th Quarter
Dorsa
Caroline Dorsa, CFO of Public Service Enterprise Group since 2009, will retire in the fourth quarter.
“Caroline has been an invaluable partner to me and an asset to PSEG, both as a board member and CFO,” Ralph Izzo, chairman, CEO and president, said in a statement. “She improved our financial discipline and helped us establish one of the strongest balance sheets in the industry.”
PSEG is currently seeking a replacement for Dorsa. The company is the parent of Public Service Electric & Gas, New Jersey’s largest utility.
DTE Energy is planning to build a solar array in a cemetery in Ypsilanti, Mich.
A cemetery spokesman said the solar array would be in a lower section of the property and shouldn’t be able to be seen from the other parts of the cemetery. “I think that it’s going to be respectful, and the revenue will allow us to work on the history assets in the cemetery,” said Barry LaRue, Highland Cemetery board member.
The array will generate about 800 KW on a plot of ground 150 feet by 1,000 feet. The city estimates the facility will also generate about $38,000 a year in tax revenue. DTE will pay the city a one-time $35,000 utility fee as well as a $33,800 a year to lease the property. The Highland Cemetery and the city will split the lease money 75-25.
Dominion Virginia Power announced it is seeking bids for up to 20 MW of new solar capacity. The company said it is taking proposals for solar facilities between 1 to 20 MW that will be operational in the next two years.
It said it would announce the results of the solicitation in the fourth quarter.
Hawaii’s Governor Opposes NextEra Takeover of Hawaiian Electric
Ige
Hawaii Gov. David Ige is opposed to NextEra Energy’s proposed $4.3 billion acquisition of Hawaiian Electric and said he will recommend that the Hawaii Public Utilities Commission nix the deal.
Ige, who recently signed a law that mandates that the state switch to 100% renewables by 2045, said he didn’t think the Florida-based company was the one to help the state reach that goal.
“We are committed to a 100% renewable future, standing alone among the 50 states in the nation in that action,” he said. “We need an electric company that sees Hawaii as the center of its work and the opportunity we represent as one of the greatest moments in history for any utility. We have not seen that in this proposal.”
Minnesota Co-op Opens Ethanol Plant in North Dakota
Minnesota electric cooperative Great River Energy has opened the first new ethanol plant to go into operation in the U.S. in five years.
The Dakota Spirit AgEnergy ethanol plant is located next to a coal-fired generating plant the company owns near Jamestown, N.D. The ethanol plant, 78% of which is owned by the co-op, will produce 65 million gallons of denatured alcohol a year.
“We have found a way by co-locating with industry to generate power more efficiently and with less environmental impact than an ethanol plant by itself or a power plant by itself,” said Greg Ridderbusch, Great River vice president.
Dominion Latest Utility to Use Drones for Line Inspections
Dominion Virginia Power will soon use small aerial drones to inspect its transmission lines, the company said. Several other utilities, including Southern Co., are also using drones for line inspections.
The drone flights, due to take off next month, come after a year of testing at the company’s Chester, Va., training facility. Steve Eisenrauch, a company manager, said the drones will first be used for routine line inspections, but he said they could eventually be employed as damage assessment tools after storms. “When you look at a drone in the air versus a helicopter, we look at that as a safety gain for Dominion,” he said.
The company is contracting with several private companies to provide the drones and piloting services. Each drone will be controlled by a two-person team and fly no higher than 200 feet.
Vermont Changing Way it Gives Out Yankee Decom Funds
Vermont officials are changing the way they disburse $10 million in economic development funds provided by Entergy as part of the decommissioning plan for the Vermont Yankee nuclear station.
Entergy promised $2 million each year for five years as a way of cushioning the blow on communities from the plant’s closure. Secretary Patricia Moulton of the Agency of Commerce and Community Development said only $814,000 of the available $2 million was awarded last year to five of 26 groups that applied for funds.
“We realized the first time around we wanted to be more versatile,” Moulton said. This year, $3.2 million will be available.
SNC-Lavalin Picked to Head up PSEG’s Keys Energy Center Project
Public Service Enterprise Group selected Canadian firm SNC-Lavalin to provide engineering, procurement and construction services for its Keys Energy Center in Prince George’s County, Md. PSEG recently acquired the 755-MW combined-cycle plant construction project from Genesis Power.
This is the third such project SNC-Lavalin has undertaken in the United States. The plant is scheduled to be completed in 2018.
SunPower to Build 100-MW Solar Plant for NV Energy
SunPower has signed a 20-year power purchase agreement with NV Energy in Nevada to build a 100-MW solar plant in Boulder City, Nev. The plant will be the fourth it has built in Nevada, including two at Nellis Air Force Base and a 20-MW plant in Lyon County.
“Today, power generated from solar plants is cost-competitive with power from traditional, fossil fuel burning plants – and becoming more cost-competitive every day,” said Tom Werner, SunPower CEO and president. “Increasingly, utilities are adding solar to their energy mix to ensure their customers are taking advantage of the reliable and emission-free power of the sun.
The new plant is expected to be completed in 2016.
Third Party to Lead MISO Stakeholder Redesign Sessions
MISO has firmed up the schedule for its stakeholder process redesign initiative, with the first of four workshops scheduled for Aug. 5 at its Carmel, Ind., headquarters.
Michelle Bloodworth, MISO’s executive director, said the meeting will be led by an independent facilitator who will share results of a stakeholder survey and engage participants in more discussions about redesign issues.
Later, a smaller group consisting of up to two representatives from each of the 10 sectors will convene to reach a consensus on guiding principles and priorities and initial set of recommendations, Bloodworth told the MISO Advisory Committee last week.
There are no plans to change MISO’s tariff, but rather to streamline current stakeholder processes that at times have become duplicative and cumbersome. The Organization of MISO States, which represents state utility regulators, has been working with MISO on the stakeholder redesign initiative.
While some utilities fear a “death spiral” from distributed generation, NRG Energy is taking an “if you can’t beat ’em, join ’em” strategy.
In Houston, NRG is preparing for solar power and other distributed generation by using a house near downtown as a lab to test new products. The home features portable solar panels, rooftop water heaters and batteries.
“Sure, we might sell less power, but at the end of the day the customer is going to use less anyway,” NRG Retail President Elizabeth Killinger said. “Someone’s going to help them.”
NRG CEO David Crane warned investors last year the day was coming when homeowners and businesses would generate “most of the electricity they consume on the premises.”
WILMINGTON, Del. — Members approved changes to Manual 18 necessary to incorporate Capacity Performance in the upcoming Base Residual Auction.
The motion passed over one objection and 25 abstentions.
PJM officials said stakeholders have expressed concern about approving manual language when some aspects of the new product are still in flux. (See PJM Delays Vote on Capacity Performance Rules.)
They said more educational workshops are planned and that the minutes of Thursday’s meeting will explicitly state that the vote was taken with the recognition that additional details may need to be worked out as the process moves forward.
In separate but related changes to Manual 20: PJM Resource Adequacy Analysis, members set constraints for two limited availability resources that will be permitted to participate in the 2018/19 and 2019/20 delivery years. The constraints are necessary to ensure reliability.
Base Capacity DR is available for interruption every day from June 1 through Sept. 30 and unavailable the rest of the year. Its constraint was set at 8.3% of the resource requirement.
Base Capacity Generation is assumed to be available throughout the delivery year except for one week at the winter peak. Its constraint was set at 18.9%.
Details of the constraint computation methodology were added as Section 6.
Early Capacity Replacement Approved
The committee endorsed manual changes allowing market participants to enter replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year if the need is linked to a physical reason that would prevent a participant from meeting its commitment. The changes prohibit generation that is replaced early from being recommitted for the delivery year. (See Earlier Replacement Capacity Transactions Approved.)
The PJM motion passed with a 68.8% sector-weighted vote. As a result, an alternative proposal by Baltimore-based CPower was not considered. It would have allowed the early replacement transactions without the restrictive conditions. Consultant Tom Rutigliano, who made the proposal, said that PJM’s restrictions are discriminatory against demand response and energy efficiency resources, prevent resources from following price signals and restrict options for reliability.
Task Force to Study Regulation Market Issues
The Independent Market Monitor won approval of a problem statement and issue charge surrounding concerns that PJM is buying too much fast-responding RegD resources in the regulation market. The initiative also will consider changes to the marginal benefit factor that defines that substitutability between RegA and RegD megawatts, which the Monitor says is faulty. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)
The motion passed with 65.8% in a sector-weighted vote.
Some stakeholders voiced concern over approving a new initiative while PJM is examining related issues through its Operating Committee and still digesting the transition to Capacity Performance.
Monitor Joe Bowring said it makes sense for the study of market design and of the marginal benefit factor to be considered on parallel tracks.
“I don’t think we can allow the market to be dysfunctional much longer,” he said. “There’s always going to be a million things going on at PJM.”
Added Mike Kormos, committee chair, “We cannot continue to carry as much RegD as we have and maintain control.”
Tariff Harmonization Task Force to Become Subcommittee
Instead of creating a separate group to clean up language in the RTO’s governing documents that is “ambiguous, incorrect or requires clarification,” the committee agreed to remodel the Tariff Harmonization Senior Task Force as a subcommittee and assign it the task. (See PJM Law Proposes Cleaning up Language in Governing Documents.)
Garnering just 59% of a sector-weighted vote, Old Dominion Electric Cooperative fell short of winning approval for a proposal that combined recommendations from PJM and the Market Monitor in redesigning the financial transmission rights and auction revenue rights process. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)
The committee later unanimously agreed to disband the FTR/ARR Senior Task Force.
Two-tiered Fee Schedule for Order 1000 Projects OK’d
Members endorsed a two-tiered fee schedule for proposed transmission projects. For greenfield projects or upgrades between $20 million and $100 million, PJM will assess $5,000 to cover its study expenses. Projects costing at least $100 million will be charged $30,000. Previously, a $30,000 fee for all projects greater than $20 million had been approved, but planners later realized they likely wouldn’t need to collect that much to cover the costs of reviewing the proposals. (See PJM Lowers Proposed Tx Project Study Fee.)
Tweaks to Merchant Network Upgrade Language Approved
The committee endorsed new tariff language to more accurately reflect how PJM processes requests for merchant network upgrades. The changes address definitions, queue entry, agreements and the capacity market.
Manual 01, 13 Changes Endorsed
Members unanimously approved a significant update and reorganization to Section 5 of Manual 01: Control Center and Data Exchange Requirements, introducing definitions of two major data types: System Control and Monitoring (Instantaneous) and Billing (Accumulated). Changes also update references to OASIS and add requirements regarding synchrophasor data exchange.
The MRC also endorsed amendments to Manual 13: Emergency Operations, including administrative changes, clarifications and updates. The committee added a reference to Manual 12 for member actions when PJM loads 100% synchronized reserves and a reference to the instantaneous reserve check process.
