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.
A principal in the Middletown company that wants to build a 63.3-MW fuel-cell power plant in Beacon Falls says the project’s plan will be submitted to the Connecticut Siting Council by the end of month.
The Beacon Falls Energy Park, which was announced in May, will be built on part of 24-acre site near Lopus Road west of the Naugatuck River. The council will have 180 days to rule on the application.
The companies developing the plant have said the project will yield up to $90 million in local property and state sales taxes over the plant’s 20-year life. The Beacon Falls Energy Park will produce enough electricity to power more than 60,000 homes.
Beachgoers can now charge their electric cars at three Tanger Outlets locations in Rehoboth Beach. Each of the outlet stores offers four charging stations. Situated between several parking spaces, they can charge eight vehicles at once.
The charging stations are Level 1, which can provide 4 ½ miles’ worth of juice for a Nissan Leaf in an hour.
The Delaware outlets are among 23 Tanger locations nationwide providing the charging stations as part of the company’s effort to go green. It’s also looking into installing solar panels at its Rehoboth Beach locations.
Kansas Gov. Sam Brownback’s campaign approached a Westar Energy official for cash earlier this month as part of an effort to pay down its debt. The Topeka Capital-Journal obtained documents that show a Brownback campaign operative contacted Westar Energy executive Mark Schreiber two weeks ago seeking help retiring debt left over from the governor’s re-election campaign last year.
The Kansas Corporation Commission is set to rule this fall on a $152 million rate request from Westar. The KCC is made up of three commissioners who are appointed by the governor and confirmed by the state Senate. If the request is approved, about $93 million would be raised from residential customers, amounting to a 12.1% increase.
Asked about the campaign’s decision to approach the Westar official, a governor’s spokeswoman said his office “does not influence the operations or decision-making process of the Kansas Corporation Commission, which is an independent commission.”
Environmental Groups Allowed to Intervene in Westar Case
The Kansas Corporation Commission ruled last week that a variety of solar and environmental interest groups can intervene in a limited capacity in Westar Energy’s pending rate case before the commission. The KCC held two hearings last week to gather public input on Westar’s proposed $152 million rate-increase request.
At issue is Westar’s proposal to create three new optional service plans. The plans shift more of each monthly electric bill to fixed charges, increasing from $12 per month to $27 per month by 2019, and reducing volumetric charges based on consumption. The proposal prohibits renewable energy users from participating in at least one of the options, resulting in higher base rates while limiting the ability to lower the bills through conservation.
Westar said solar power activists, including some from out of state, are misrepresenting the utility’s “common-sense approach to renewable energy.”
Texas Company to Build New England’s Largest Wind Farm
EDP Renewables North America has filed an application with the Maine Department of Environmental Protection to build New England’s largest wind farm, able to power about 70,000 homes. The 250 MW Number Nine wind farm in Aroostook County would be located near the Canadian border.
The Texas company is proposing to erect up to 119 turbines rated at between 2 and 2.1 MW. The cost of the project is $613 million. EDP has been working on the project for at least two years.
The project would also include a 50-mile transmission line to connect the wind farm to the ISO-NE power grid. In January, Central Maine Power and Emera agreed to allow EDP to use a portion of a key transmission corridor known as the Bridal Path, between Houlton and Haynesville in Aroostook County, to connect its wind farm to the grid.
Winslow is set to begin drafting regulations that could pave the way for a solar farm potentially 20 times bigger than the largest current solar facility.
Ranger Solar, a private Yarmouth-based energy firm, is contemplating siting a 10- to 20-MW solar project estimated to cost as much as $25 million and take up as much as 100 acres. Winslow would be the first municipality in the state to create a utility-scale solar ordinance that would create standards for such projects, according to town officials.
The ordinance has to be in place by October so Ranger can take advantage of federal tax credits. The program provides a 30% federal income tax credit for commercial or residential solar systems, which will decrease to 10% after 2016.
Pepco Fights Back Against Motion to Stay Merger OK
Pepco Holdings Inc. says that a motion to stay the state’s approval of its merger with Exelon is without merit.
The motion was filed July 21 by the state Office of People’s Counsel in the Circuit Court for Queen Anne’s County. In addition to requesting a stay of the Public Service Commission’s decision, the People’s Counsel asked to present additional evidence regarding an alleged conflict of interest of former Commissioner Kelly Speakes-Backman, who took a $200,000/year job with an industry-backed nonprofit three days after the vote.
The merger still needs the approval of the D.C., which is set to make a decision next month.
With the opening of a 3.56-MW solar installation built over a capped landfill, North Adams will become the largest per capita solar city in Massachusetts, according to Mayor Richard Alcombright. The town, which also has a power-purchase agreement to buy electricity generated by two other solar installations, says the reduction in dependence on fossil fuel-produced power will save the community more than $300,000 a year.
The solar farm at the landfill consists of about 7,000 solar panels covering about 13 acres. It is producing at 65% of its capacity because the National Grid substation in Adams isn’t equipped to handle all its output. The utility company is upgrading the substation, Alcombright said.
The city is contemplating building another 1-MW project, but officials say it will wait until net metering caps are lifted by the state.
Ameren Energy Efficiency Hearings Begin Before PSC
The Public Service Commission began hearings last week on a new energy efficiency plan to replace Ameren Missouri’s three-year-old program, which expires at the end of 2015. The PSC is weighing two competing designs that have split environmental groups and state government officials.
State law allows utilities to bill customers to recoup the costs of the efficiency programs and sales lost due to energy savings, but it doesn’t require utilities to participate. Ameren has indicated it does not like how the public counsel and the PSC staff want to structure the program. The state’s utility customer advocate told regulators eliminating energy efficiency rebates for Ameren customers would be better than adopting the utility’s new efficiency plan.
The Natural Resources Defense Council, which has been a critic of what it said were low savings targets in the utility’s prior proposal, is now backing Ameren’s plan. Other environmental groups have sided with PSC staff and public counsel.
Rate Hike Would Cover Upgrades that may Have Been Unneeded
Montana Dakota Utilities spent hundreds of millions of dollars on environmental upgrades at plants to comply with federal emissions standards that are now being challenged. If the federal Mercury Air Toxic Standards, or MATS, is successfully challenged, it might mean that the utility’s improvements were unnecessary.
MDU has applied for a 21% rate increase to pay for the upgrades. Residential bills may rise $178 a year to cover the pollution controls. But the utility says the upgrades, which cost about $348 million for one plant alone, were mandated to meet the mercury standards, which are still in force. “The rule is still in effect,” MDU Spokesman Mark Hanson said. “We still have a deadline to meet. It’s tough to run your business when you don’t know what the rules are.”
The Montana Public Service Commission has not yet granted the increase. “Twenty-one percent is a large increase, and it’s very rare to see an increase from our large utilities that’s in the double digits,” Commissioner Travis Kavulla said.
Nebraska’s Wind Energy Catching Up with Other States
Timothy Texel, executive director and general counsel of the Nebraska Power Review Board, says the state had only three wind turbines generating 2 MW of power when he first joined the regulatory body in 1998. Speaking to the Grand Island Rotary Club last week, Texel said Nebraska now has 475 wind turbines capable of generating 801 MW at 16 separate wind farms.
“We have more wind turbines than people think, but they’re mostly in remote location where people never see them,” he said. Texel said recent regulatory changes have allowed private entities to build “energy export facilities” that can generate power for utilities in other states. He said the expense of building transmission lines is an issue — only one such line has been built since 2010 — but SPP’s cost-allocation process could lead to power being exported through the RTO.
The Logan County Board approved a $400 million wind project after the owners made changes to address earlier board concerns.
The Meridien Project, an 81-turbine wind farm, is being built by Relight U.S. The board deadlocked 6-6 when it voted on the project initially. The new plan addresses noise levels, increases setback distances, pays out more money for community projects and sets up a decommissioning plan. The board voted 8-4 to approve it this time.
The project has been in the planning stages since 2007. One board member said she hoped the latest vote would allow all residents to move forward. “I would encourage everyone on both sides to really put the differences behind and to move forward and not let this have a long time of festering, because that would be a negative for the entire community,” she said.
The New Hampshire Public Utilities Commission announced that the Renewable Energy Fund is running out of money, and the state has put a freeze on new applications for solar, biomass and other renewable subsidies.
The fund had only collected $4.3 million in 2014 to pay for 2015 projects. Adding to the stress on the fund was a decision by legislative budget writers to raid the fund for $2.2 million over the next two years to make up the amount the now closed Vermont Yankee nuclear plant paid to finance the state Department of Homeland Security.
The state Board of Public Utilities is continuing to review utility response to a June 23 storm that left more than 400,000 residents without power.
The “macroburst” thunderstorms brought winds of up to 85 mph in Gloucester and Camden counties, hitting customers of Atlantic City Electric hardest and causing extensive damage to the utility’s infrastructure, according to the BPU.
The company reported that 17 transmission circuits and five substations were knocked out of service. The utility, owned by Pepco Holdings, had to replace transmission towers and distribution poles and rebuild thousands of feet of cable. For at least twelve hours after the storm hit, ACE was forced to revert to radios and manual processes to dispatch crews, as its mobile-data terminals failed.
New York’s top fiscal officer criticized Gov. Andrew M. Cuomo’s 2013 LIPA Reform Act in a report that says the law has left customers facing higher electric bills, increasing debt and less transparency from the utility.
State Comptroller Thomas DiNapoli raised questions about provisions in the law and PSEG Long Island’s contract to manage the distribution company, which stripped away mechanisms for oversight of the utility even as it created a new oversight agency — the Long Island office of the state Department of Public Service.
DiNapoli’s report found that LIPA customers now are facing higher bills “with new categories of charges as well as a proposed three-year rate increase, and bearing a debt burden that is projected to increase” to $8.3 billion by 2018. The report notes that the proposed 3.2% three-year rate hike by PSEG and LIPA “represents the largest rate increase LIPA ratepayers have faced” since LIPA took over from LILCO in 1998.
NYISO Board Approves Comprehensive Reliability Plan
The NYISO Board of Directors has approved the 2014 Comprehensive Reliability Plan for New York’s bulk power system. The plan concludes that the system will meet all applicable reliability criteria under expected system conditions during the study period (2015-2024), and confirms that the reliability needs initially identified in the 2014 Reliability Needs Assessment are being resolved. (See NYISO: Reliability Concerns Raised Last Year Resolved.)
“The NYISO’s comprehensive planning process works in conjunction with our markets that are designed to send price signals for entry of resources that sustain and enhance reliability,” NYISO President and CEO Stephen G. Whitley said in a statement. “The new capacity zone in the Lower Hudson Valley played a critical role in motivating suppliers to maintain existing resources and install new resources needed for system reliability.”
The New York Power Authority is playing a growing role in the Buffalo Niagara region’s economic development. The Power Authority is providing most of the $5 million funding for the 43North business plan competition, which announced recently it had attracted more than 3,000 qualified entrants.
Similar initiatives, some stemming from the agency’s 2007 relicensing agreement for the Niagara Power Project, have helped fund the Canalside project and subsidize dozens of local businesses through allocations of low-cost hydropower from the Lewiston plant.
“Think of it as a dividend,” Gil C. Quiniones, the Power Authority’s president and CEO, said during a meeting with editors and reporters of The Buffalo News.
Target filed an application to install solar arrays on eight more stores in North Carolina, bringing its total to 27 rooftop solar projects in the state.
According to filings with the North Carolina Utilities Commission, Target plans to invest about $22 million to complete the installations.
Pipeline Company Changes Route to Reduce Environmental Impact
The North Dakota Public Service Commission has approved 29 changes to a crude-oil pipeline route to reduce possible environmental impacts.
Sacagawea Pipeline Co. applied in March for approval of a 16-inch crude-oil pipeline that would run from McKenzie County to a rail terminal in Montrail County. Part of the $100 million pipeline will cross Lake Sakakawea. The company appeared before the commission last week to file for the changes, which it said were designed to minimize any environmental impacts.
The pipeline has a maximum capacity of 200,000 barrels a day.
A Shell Chemicals ethane plant proposed for Western Pennsylvania would generate all of its own electricity – more than 100 MW – and then some, according to the Associated Press.
The plant, proposed for Beaver County, would use natural gas-fired cogeneration on-site to create steam and electricity, with any excess power to be sold for use on the regional grid.
Shell, which paid $13.5 million for the former zinc smelting site, has not confirmed it will build the multi-billion-dollar facility.
Entergy Texas has filed a motion with the Public Utility Commission of Texas to dismiss the company’s application to purchase one of the four 495-MW generating units at the Union Power Station in southern Arkansas. The motion, if approved, would allow the unit to instead be acquired by Entergy New Orleans for $237 million, subject to the New Orleans City Council’s approval. The purchase is expected to close later this year.
Union Power is a 1,980-MW generating facility consisting of four combined-cycle natural gas-fired generating units. Under the original agreement, Entergy New Orleans agreed to buy 20% of the power generated by the two natural gas-fired units purchased by Entergy Gulf States. The company will purchase one of the Union Power Station units in lieu of the purchased power agreement. Entergy Gulf States will still purchase two of the generating unit and Entergy Arkansas will buy the remaining unit.
While New Orleans Entergy customers will now absorb a larger share of the purchase’s cost, Entergy New Orleans President and CEO Charles Rice said the deal “is an ideal way” to meet the city’s need for additional generation at “half the cost of building a comparable new unit.”
The Public Utilities Board granted Manitoba Hydro a rate increase of nearly 4%, a large part of which will go toward paying for its Bipole III transmission project. The 3.95% rate increase goes into effect Aug. 1.
Bipole III is a $4.6 billion transmission line project designed to deliver power from northern generating stations to southern Manitoba and for export to the United States.
Manitoba Hydro said it is on track to spend about $20 billion over the next 10 years on system improvements, including the Bipole III project. The utility said it would need to increase rates nearly 42% over the next 10 years to finance the improvements.
NYISO told the Federal Energy Regulatory Commission last week it does not plan to make any changes in its day-ahead schedule to comply with FERC Order 809, which adjusted the gas market schedule.
In a July 23 filing, NYISO said the existing day-ahead schedule satisfies the timing requirements directed by the order, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle (EL14-26).
FERC required RTOs and ISOs to adjust the posting of their day-ahead energy market and reliability unit commitment process results “sufficiently in advance” of the revised gas cycles, or explain why it is not suitable for their markets. (See FERC Approves Final Rule on Gas-Electric Coordination.)
The ISO said it posts its day-ahead schedules by 11 a.m. ET (10 a.m. CT) and that day-ahead reliability unit commitments are posted at the same time as successful day-ahead economic bids, giving generators at least one and a half hours before the nomination deadline for the existing timely nomination. “After Order 809 becomes effective, and the nomination deadline for the timely nomination cycle moves to 1 p.m. CT, the NYISO will be notifying electric generators of their day-ahead schedules at least three hours before the timely nomination cycle deadline,” the ISO said.
Illinois Attorney General Lisa Madigan last week joined industrial consumers in calling for changes to MISO’s capacity auction rules, while the RTO defended itself, in filings with federal regulators.
Madigan
MISO’s rules “are no longer just and reasonable and require modification,” Madigan said in comments filed July 20 with the Federal Energy Regulatory Commission (EL15-82). Madigan said last week that she supports proposals the Illinois Industry Energy Consumers made in a June 30 filing.
In May, the attorney general and Public Citizen filed complaints asking FERC to investigate Dynegy’s bidding behavior in April’s Planning Resource Auction, which resulted in a nine-fold price increase for Zone 4 (EL15-70).
IIEC said last May’s auction — which saw Zone 4 clear at $150/MW-day compared with just $16.76 a year earlier — will cost Illinois industrial companies $1.6 million each, on average. Madigan said the dramatic swing in auction prices also hurts Illinois’ residential ratepayers.
“While the people did not propose specific Tariff changes in their complaint, the changes recommended by IIEC address some of the issues raised in the people’s complaint and are necessary revisions to ameliorate the effects of market power in the MISO zones, and particularly in Zone 4,” Madigan said.
Industrials and Madigan say the idea that Dynegy’s bids are justified by the opportunity cost of selling power into PJM is specious. IECC said there is little transmission capacity and “very few” bilateral sales between MISO and PJM. That, Madigan said, calls “into question the existence of the opportunity to sell to PJM at the prices reflected in the initial reference level.”
The initial reference level is set “as if there were no limits on the transmission of MISO-generated megawatts in the PJM areas,” Madigan said.
Citing FERC’s Electric Quarterly Reports, consultant Robert McCullough, a witness for the state, said that prices of the few bilateral sales from MISO to PJM were low — with one at only $1.09/MW-day.
MISO Response
In a response filed July 20 (EL15-82), MISO said the IIEC comments “misapprehend” the concept of opportunity costs.
MISO said IIEC suggests that the RTO may only calculate an opportunity cost prior to the PRA based upon “having perfect knowledge” — not only of resources’ bids into MISO’s auction, but also of bids into PJM’s market.
“Then, MISO is somehow expected to create a clearing price for markets in both PJM and MISO based upon such perfect knowledge,” MISO shot back. “Obviously, this standard is impossible to meet and unnecessary to properly estimate a supplier’s opportunity cost.”
MISO also countered that IIEC’s proposal would result in double-counting resources and incentivize suppliers to not make offers into MISO, “which will lead to a less robust market and potentially higher prices.”
Confidentiality Needed
IIEC and Madigan said FERC should also reconsider how the initial reference level is communicated to generators. In Illinois’ auctions for default electric service, the market administrator determines a benchmark price, but it is kept confidential so that bidders base their offers on their own costs rather than pegging them to a higher level, Madigan said.
“In revising the MISO Tariff, the commission should require that the reference level be maintained as confidential so that bidders cannot structure their bids around the reference level,” Madigan said. “While a reference price that is properly established may be a useful tool to address market power, MISO’s Tariff perverts the role of the reference price from a meaningful cap to an instrument of market power.”
Counter-Flow Concerns
Finally, the attorney general supports another revision to MISO’s Tariff recommended by IIEC: reducing the local clearing requirement (LCR) by the amount of capacity exported into a neighboring market. They say that an LCR that is too high creates more opportunity for a large generator to exercise market power.
Madigan cited the Independent Market Monitor’s 2014 State of the Market report, which stated that the binding of the LCR in Zone 4 was impacted by about 1,200 MW exported from Zone 4 to PJM. The Monitor recommended that MISO file Tariff revisions to treat local capacity exports “as creating counter flow over the interface” into the zone.
“This would cause the capacity to be replaced by the lowest-cost capacity from any area in MISO, rather than requiring that additional capacity be procured from within the zone,” the Monitor wrote.
IIEC filed testimony claiming that if the 1,200 MW of exported capacity had been excluded from the LCR, the pivotal supplier’s opportunity to exercise market power would have been limited to $8/MW-day, compared to the $150/MW-day Dynegy received in the April auction.
‘Simply Incorrect’
MISO countered that IIEC “is simply incorrect” in stating that MISO fails to account for counter flows when it calculates each zone’s LCR. MISO said it has properly accounted for resources in one zone that are sold into another capacity market when it calculates each zone’s capacity import limit, which is used to establish the LCRs.
Subsequently counting zonal resource credits again when calculating the LCR would amount to double-counting a resource, MISO said.
“Artificially lowering the local clearing requirement would threaten resource adequacy in the MISO region and unjustly and unreasonably suppress capacity prices,” the RTO said.
Original Complaint
Meanwhile, the attorney general and Public Citizen have made filings asking FERC not to dismiss the complaints they filed in May, as Dynegy, NRG Energy and the Electric Power Supply Association have requested.
