Tests conducted by the Department of Energy and the University of Hawaii have shown it is possible to generate energy using ocean waves and then transmit it to the state’s power grid. In tests that started this summer, a 20-kW wave energy generator was installed off the coast of Oahu and started trickling energy into the grid. The wave energy converter, called Azura, is made by Northwest Energy Innovations, of Portland, Ore., and is one of the first attempts to demonstrate the practicality of a technology scientists have long envisioned.
The floating platform captures the up-and-down and side-to-side motion of waves, converting it to electricity. It is anchored in water about 100 feet deep at a U.S. Navy testing facility. The small generator doesn’t even produce enough energy to serve a single household, but researchers say the data collected will be used to plan for a larger project in the future.
“Utilities and power project developers won’t even consider buying wave power technology unless they can see what an independent third party says it can really do,” said Steven Kopf, Northwest Energy Innovations CEO. “So we’re consciously running this test in all sorts of conditions, even when wave conditions are suboptimal for power production, just to get a complete picture of performance.”
House Speaker John Boehner said he favors lifting the ban on U.S. crude oil exports, a move that he said would create about a million jobs and strengthen the domestic oil industry. “If the administration wants to lift the ban for Iran,” Boehner said last week, “certainly the United States should not be the only country left in the world with such a ban in place.”
The ban was implemented after the Arab oil embargo of the 1970s, at a time when reduced imports drove up gasoline prices and even resulted in rationing. But since then, and particularly in the last 10 years, U.S. oil production has surged, partly because of the adoption of fracking.
Boehner joined Sen. Lisa Murkowski (R-Alaska), chairwoman of the Senate Energy and Natural Resources Committee, who is also pushing for lifting the ban.
DOE Expands Renewable Assistance to 5 American Indian Tribes
The Department of Energy is lending technical assistance to five American Indian tribes working on renewable energy projects.
The Blue Lake Rancheria Tribe of Blue Lake, Calif., is getting help producing a community microgrid with solar generation and battery storage. The Grand Portage Band of the Chippewa Indians in Minnesota will be getting help to determine the best way to transmit energy from a 2.5-MW wind project to tribal homes and facilities. The Oneida Tribe in Wisconsin is getting technical assistance on a 700-kW solar project. The Picuris Pueblo of Peñasco, N.M., is getting assistance developing a 1-MW solar project. And the Ute Mountain Tribe in Towaoc, Colo., will get help investigating the feasibility of community-scale solar as well as small-scale and closed-loop hydro projects.
These five tribes now join five Alaska Native villages getting federal technical assistance on a variety of energy efficiency and renewable energy projects.
Alberta Energy Minister Marg McCuaig-Boyd says that the decision on the Keystone XL Pipeline is out of the provincial government’s hands and that it will not devote any more energy lobbying for the controversial project.
“It’s in their hands,” the minister said, referring to the Obama administration. Her comments came in the wake of published reports that quoted Sen. John Hoeven (R-N.D.) saying that President Obama would reject the pipeline, probably this month.
A White House press official said that a decision would come during Obama’s time in office but wouldn’t elaborate. The pipeline would be a major link in getting Alberta’s oil sands to market, but there are competing pipelines in the planning stage. McCuaig-Boyd said Alberta would concentrate on those instead.
“We’re going with the ones that are probably going to have the most success soonest,” she said. “Energy East has some promise, and so does Kinder Morgan’s Trans Mountain. Those are the two right now to put our energies into.”
Kinder Morgan Hearing Draws Hundreds in Massachusetts
A Federal Energy Regulatory Commission hearing on a proposed Kinder Morgan pipeline drew hundreds of people last week, including nearly 100 who testified. Most were critical of the plan for the 412-mile pipeline, although some construction union representatives said they were in favor of it. The scoping session in Greenfield, Mass., was held to take public comment and help determine which issues FERC should address in its Environmental Impact Statement.
The Northeast Energy Direct pipeline would deliver Marcellus shale gas from Pennsylvania to markets in the Northeast. Existing pipelines serving the region are overburdened, as evidenced by the natural gas shortages during winter storms in the last two years.
A joint letter from six Massachusetts legislators asked FERC to stop the permitting work that has been conducted so far and to start over. The lawmakers and other opponents noted that Kinder Morgan only recently released thousands of pages of environmental and technical information and contended that the current permitting timeline doesn’t allow enough time to examine it all.
The Federal Energy Regulatory Commission on Wednesday said it needed more time to consider rehearing requests of its June 9 order largely approving PJM’s Capacity Performance plan after receiving a flurry of feedback from state regulators, consumer advocates, generators and the Independent Market Monitor.
The order is only a procedural motion; without commission action within 30 days of a rehearing request, the request is automatically denied.
“In order to afford additional time for consideration of the matters raised or to be raised, rehearing of the commission’s order is hereby granted for the limited purpose of further consideration,” it said. “Rehearing requests of the above-cited order filed in this proceeding will be addressed in a future order.” No answers to the rehearing requests will be entertained, it said.
PJM’s new Capacity Performance product, a response to poor generator performance during the polar vortex of January 2014, aims to increase reliability by rewarding over-performing participants and penalizing non-performers. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
In seeking a rehearing of FERC’s approval, generators sought to relax the penalty provisions.
The PJM Industrial Customer Coalition, environmentalists, regulators and consumer advocates asked that demand response be allowed to participate in the transition auctions. On July 23, FERC issued a ruling ordering PJM to include DR and energy efficiency, thus delaying the auctions. (See FERC Orders PJM to Include DR, EE in Transition Auctions.)
Essential Power, Competitive Power Ventures, NextEra Energy and Invenergy Thermal Development contested FERC’s decision to eliminate monthly stop-loss limitations and said the commission erred in deciding that generator non-performance would not be excused, even in circumstances beyond their control.
The PJM Board of Managers today approved staff’s recommendation for the stability fix at New Jersey’s Artificial Island, despite numerous objections from spurned bidders and representatives of the Delmarva Peninsula, which will be allocated nearly the full cost of the project.
Winner LS Power’s proposal involves laying a 230-kV line under the Delaware River as well as expanding interconnection facilities at the nuclear complex, the latter task being assigned to Public Service Electric & Gas and Pepco Holdings Inc.
“These projects will resolve the operational performance issues around the Artificial Island area and provide important transmission support for the sub region,” said outgoing CEO Terry Boston in a letter to members following the private board meeting.
“The board also recognizes the valid concerns raised by [Delaware Gov. Jack] Markell, the Delaware Public Service Commission, the Maryland Public Service Commission and others regarding the allocation of costs associated with this project. PJM must follow its Tariff,” he said.
“With regard to the cost allocation provisions applicable to this project, PJM also must respect legal precedent in the Atlantic City case allocating specific rate filing responsibilities between PJM and its transmission owners. Nonetheless, we recognize that several parties have appropriately questioned the specific allocation in this case,” Boston continued. (See Officials Urge PJM to Reject Artificial Island Proposal.)
“Accordingly, PJM will continue to provide technical analysis and information to affected stakeholders in order to help [the Federal Energy Regulatory Commission] with its ruling on this particular cost allocation and its cost allocation rules in general.”
PJM planners outlined their rationale in a 44-page white paper, noting that $246.42 million of the $275.45 million total cost estimate will be assigned to the Delmarva transmission zone, with the remaining $29.03 million allocated to other transmission zones based on load ratio shares.
“This pilot case implementing Order 1000 principles and a competitive solicitation process will continue to be examined for a number of ‘lessons learned,’” Boston wrote. “The board thanks the Planning Committee for its thorough review, and we urge the adoption of changes that will improve the planning process.”
According to the Delaware Public Service Commission, the project could translate to a 25% increase in transmission costs in Delaware. Some of the state’s heaviest users could see their monthly bills surge by hundreds of thousands of dollars, Markell said.
In a statement Wednesday, Markell said, “I continue to have serious concerns about the cost distribution associated with the proposal approved by PJM, which would force Delawareans to bear a high cost for a project that provides little benefit to the state. I am working with the PSC and others concerned about this result to explore our options moving forward.”
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.) They urged the board to again halt the project.
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.
Home to the Salem and Hope Creek nuclear reactors, Artificial Island is the second largest nuclear complex in the country.
PJM’s competitive solicitation process sought “transmission improvements to provide the ability to generate maximum power from all three Artificial Island nuclear units while maintaining transmission system voltage within limits during various contingencies and line outages.”
SPP’s latest analysis of the Environmental Protection Agency’s draft Clean Power Plan indicates state-by-state compliance with the plan would result in nearly 40% higher costs than a regional approach.
According to SPP’s state-by-state compliance assessment released Monday, meeting the goals outlined in EPA’s draft rule would cost an estimated $3.3 billion annually in new generation capital investment and energy production costs. That is $900 million more than the $2.4 billion per year under a regional approach, on which SPP released a report in March. (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)
The assessment analyzed the rule’s impact on existing generation and resource-expansion plans. It did not include the cost of new transmission needed to maintain reliability, gas-infrastructure expansion, market-design changes or transmission congestion.
A final version of the rule is expected to be released in August. The draft version proposes reducing U.S. carbon dioxide emissions 30% from 2005 levels by 2030.
More Disruptive
Lanny Nickell, SPP’s vice president of engineering, told the RTO’s Regional State Committee on Monday that a state-by-state compliance approach would be more expensive to administer than a regional approach. He said a state-by-state solution “would be more disruptive … to the significant reliability and economic value that SPP provides to its members as a regional transmission organization.”
Nickell offered the example of one state taking a physical approach to carbon-reduction and limiting the amount of coal generation in November and December, only to have a neighboring state take a different approach and add renewable generation. That might force the first state to resort to additional coal generation to maintain grid reliability.
“All we look at in our market systems is price,” Nickell said. “The price offered into the market in [one state] could force the dispatch of more energy than planned elsewhere.”
A previous analysis predicted that SPP’s Integrated Marketplace, which went online in March 2014, would yield its participants $131 million in annual net savings in its first year. According to the latest report, SPP expects a reduction in the Integrated Marketplace’s savings to comply with the rule under any implementation strategy, but a state-by-state approach “would have a much more negative impact.”
SPP’s analysis was based on EPA’s proposed individual state-reduction goals in its draft rulemaking. SPP said its study does not take a position on the appropriateness of those goals or EPA’s supporting assumptions.
Apples-to-Apples
SPP’s state-by-state approach used the same analysis format as it did with March’s regional approach, using a $45/ton carbon-cost adder for an “apples-to-apples” comparison between the two plans. As before, the carbon adder was used as a mechanism to simulate the dispatch of lower carbon-emitting resources.
Click to zoom.
Coupled with modifications to current resource plans, the report said, that would “indicate the implications of meeting SPP’s regional and states’ emissions goals by 2030.”
The assessment says up to 15.1 GW of generation expected to continue running under current planning assumptions could be at risk of retirement under a state-by-state compliance approach. The study also added 5.5 GW of wind energy and 4 GW of gas-fueled resources above currently planned capacity, which already includes approximately 4 GW of new wind and 22 GW of new gas resources.
However, the assessment did not take into account renewable tax credits, currently being debated in Congress. The Senate Finance Committee last week voted 23-3 to approve extending tax credits for wind energy, along with subsidies for biodiesel and cellulosic ethanol.
“We did not assume renewable credits would be an option, because we interpreted the draft plan as they wouldn’t be allowed,” Lanny Nickell said. “Now the final plan may very well allow those credit exchanges over state boundaries.”
SPP did use wind as a reasonable abatement measure in both the regional and state-by-state compliance assessments, because of the high wind potential in most SPP states and the desire to maintain a consistent approach for comparisons.
The state-by-state compliance scenario’s analysis assumed approximately 4,700 MW of coal retirements incremental to those retirements already planned. SPP said this assumption could be conservative, as its analysis indicates nearly all the region’s existing coal-fired generation would operate above an 80% capacity factor in the business-as-usual model, but approximately 13,400 MW of coal-fired generation would operate below an 80% capacity factor after applying the $45/ton carbon-cost adder.
Three Models
The state-by-state assessment used three different models: a business-as-usual (BAU) case, a BAU model with the $45/ton carbon-cost adder, and a third model with a variable cost adder.
Incremental coal retirements were assumed using a tiered approach. The first tier came from additional information gathered in preparation for a 2017 transmission-planning study. Updated projections found an additional 300 MW of coal units expected to be retired by 2030. The next three tiers took an age-based approach, targeting units’ ages in 2030: over 60 years, 55-60 years and 50-55 years.
The state-by-state compliance plan is the third study SPP has conducted of the proposed Clean Power Plan. The RTO’s first study in October 2014 found that the rule did not allow enough time to build the generation and transmission infrastructure needed to maintain system reliability and avoid severe system overloads that could lead to cascading outages.
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.
Tests conducted by the Department of Energy and the University of Hawaii have shown it is possible to generate energy using ocean waves and then transmit it to the state’s power grid. In tests that started this summer, a 20-kW wave energy generator was installed off the coast of Oahu and started trickling energy into the grid. The wave energy converter, called Azura, is made by Northwest Energy Innovations, of Portland, Ore., and is one of the first attempts to demonstrate the practicality of a technology scientists have long envisioned.
A Federal Energy Regulatory Commission hearing on a proposed Kinder Morgan pipeline drew hundreds of people last week, including nearly 100 who testified. Most were critical of the plan for the 412-mile pipeline, although some construction union representatives said they were in favor of it. The scoping session in Greenfield, Mass., was held to take public comment and help determine which issues FERC should address in its Environmental Impact Statement.
