NERC: Industry Needs More Time to Meet Clean Power Plan

By William Opalka

The U.S. electric industry will face reliability concerns in four years if the interim goals of the Environmental Protection Agency’s Clean Power Plan aren’t relaxed, the North American Electric Reliability Corp. said last week.

NERC released a reliability assessment of the CPP Tuesday that concludes EPA’s proposed 2020 targets — 80% of the total CO₂ emission reductions the agency seeks — can’t be reached in several regions.

The 69-page report provides additional ammunition for critics who have called for changes to the interim goals and the provision of a reliability “safety valve.” The report is NERC’s second on the impact of the EPA plan. Its initial review, released in November, examined EPA’s assumptions and provided a broad view of potential reliability risks. (See MISO, SPP: EPA Clean Power Plan Threatens Reliability, Needs Longer Compliance Schedule.)

Scenarios Analyzed

The new report examines in detail how the plan would impact the generation mix and resource adequacy. It also provides a high-level analysis of transmission needs and identifies major shortfalls of reactive power needed to maintain voltage stability. In addition to a business-as-usual baseline, NERC compared a scenario assuming state-by-state compliance with one allowing for regional compliance with interstate trading. It also conducted sensitivities on the impact of lower gas prices.

NERC concludes the plan will accelerate the transition in the generation mix as natural gas, wind and solar power replace coal. The report predicts about 60 GW of natural gas-fired generation will be added by 2020, rising to 80 GW by 2030. Coal retirements are projected to total at least 18 GW by 2020 and an additional 18 GW by 2030.

Much of the remaining coal fleet will have to change from baseload to seasonal and peaking use, making the plants less economic, NERC said. Between 14 GW and 22 GW of coal plants remaining in service after 2020 will be at risk because they would be operating at capacity factors of only 11% to 19%.

The report warns that new generators will be needed before the transmission and pipeline infrastructure to support them can be built. While most combined-cycle gas turbine plants go from conception to operation in an average of 64 months, transmission infrastructure can take from five to 15 years. Local and regional pipeline infrastructure will also need to be in place to deliver gas to the new plants.

“More time is needed to develop coordinated plans for this shift in generation and corresponding transmission reinforcement,” said John Moura, director of reliability assessments.

NERC noted there are regions where compliance will be easier, but says New York and the New England states in the Northeast Power Coordinating Council will need more than 7 GW of new capacity by 2020, with ERCOT in need of 11 GW over the same time frame.

The report also predicts major changes in transmission flows, with Canada tripling its exports to the U.S. and PJM-East shifting from being a net importer to a net exporter as generating units in Regional Greenhouse Gas Initiative states become more competitive with the imposition of carbon pricing nationwide.

MISO Central would reduce its exports to MISO North due to cheaper imports from Canada while increasing its exports to MISO South.

EDF Challenges Report

The Environmental Defense Fund disputed the report’s conclusions.

“NERC’s modeling uses unrealistic assumptions that are contradicted by what’s happening on the ground today,” Cheryl Roberto, EDF’s associate vice president of clean energy said in a statement.

NERC “fails to capture the great innovation happening now – with major investments in renewables, efficiency, natural gas and transmission infrastructure,” Roberto said. “NERC’s report also assumes flat-footed regulators, when the truth is regional and state-level regulators have repeatedly demonstrated they are up to the task of planning for future power needs. In short, NERC’s assessment does not take into account the transformation unmistakably underway in our electric system.”

April 28, 2015June 15, 2023

PJM Considering Change to Day-Ahead Deadlines in Response to FERC Gas Schedule Order

By William Opalka, Chris O’Malley and Rich Heidorn Jr.

PJM is considering changing its day-ahead market schedule in response to the Federal Energy Regulatory Commission’s April 16 ruling revising the interstate gas nomination timeline.

Other RTOs’ reactions varied, with ISO-NE saying it has no plans to change its schedule and NYISO looking to respond to its neighbors. MISO stakeholders will discuss the issue Friday, while an SPP task force is expected to make recommendations on any changes by July.

FERC moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (12:30 p.m. to 2 p.m. ET). It also added a third intraday nomination cycle (RM14-2). (See FERC Approves Final Rule on Gas-Electric Coordination.)

In response, PJM is considering moving up its day-ahead schedule by three hours, Adam Keech, senior director of market operations, told the Markets and Reliability Committee on Thursday.

PJM’s day-ahead market results currently are published at 4 p.m. ET, which would not provide enough time for selected generators to purchase gas, Keech said.

PJM is proposing that day-ahead offers close at 9:30 a.m. ET, with results published no later than 1 p.m. That would allow at least one hour for gas generators selected to run the next day to purchase fuel before the timely nomination cycle deadline.

The rebid period and reliability unit commitment (RUC) also would be moved up, running from 1 p.m. to 4:30 p.m., with results published by 6 p.m., allowing at least one hour for gas nominations before the evening nomination cycle deadline, which FERC left unchanged.

The changes would condense the day-ahead market solution window to 3.5 hours.

Joe Wadsworth of Vitol asked if PJM would be coordinating its changes with neighboring regions. He said moving PJM’s day-ahead deadline to 9:30 a.m. could inhibit trading with NYISO, which publishes its day-ahead results at about 9:30 a.m. That could hurt day-ahead convergence along the NYISO-PJM seam, he said.

Wadsworth said PJM also needs to consider that liquidity in the next-day gas markets sometimes doesn’t occur until after 10 a.m. on high gas-demand days. In such circumstances, there may be little or no natural gas price transparency prior to PJM’s day-ahead market bid deadline, he said.

Ed Tatum of Old Dominion Electric Cooperative suggested PJM coordinate the changes through the ISO/RTO Council and consider changing the start of the electric day.

Keech said FERC’s order neither mandates nor precludes changes to the electric day.

Keech’s comments came during a first read of a proposed problem statement to respond to the FERC order. Although the initiative won’t come up for a vote until the May 28 MRC meeting, PJM will conduct an educational session following the May 6 Market Implementation Committee meeting.

PJM and other regions must make compliance filings — adjusting their tariffs to comply with the final rule or explaining how their current rules are compliant — by July 23.

NYISO

“Because electricity markets are interdependent, the NYISO’s response to FERC’s order will need to account for its neighbors’ compliance efforts,” NYISO spokesman David Flanagan said. “If no changes are determined to be necessary, FERC’s decision will provide New York generators an additional hour-and-a-half to nominate the gas they require following the posting of the NYISO’s day-ahead market. FERC’s order also will increase the gas procurement flexibility available to New York generators that participate in the NYISO’s real-time market.”

MISO

MISO spokesman Andy Schonert said the RTO is “working internally and with stakeholders to figure out how we will respond to FERC’s order.” The Electric and Natural Gas Coordination Task Force will discuss the issue in a meeting May 1.

SPP

SPP spokesman Tom Kleckner said the RTO’s Gas Electric Coordination Task Force discussed the FERC ruling at a meeting Thursday and will be making a recommendation to SPP’s Board of Directors at the board’s July meeting.

“The [task force] is evaluating what changes can be made to the day-ahead and reliability unit commitment timelines,” Kleckner said. “It will be up to our stakeholders to make any changes to our timeline that are presented to the board.”

ISO-NE

ISO-NE, which shifted its day-ahead market schedule two years ago to align with the natural gas trading day, believes it is already in compliance with the FERC rule, spokeswoman Marcia Blomberg said.

“However, we are very disappointed at the decision not to change the gas day,” Blomberg said. “We continue to believe it would have been a material improvement to reliability. Without the change, obtaining fuel in order to meet their obligations will be more challenging for generators during upcoming winters. We are supportive of the change to the timely nomination cycle, which will help owners of gas-fired generators incrementally by improving their ability to timely nominate and schedule gas.”

April 28, 2015

PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained

By Suzanne Herel

WILMINGTON, Del. — PJM stakeholders last week approved tighter rules on generator lost opportunity costs but rejected a proposal to limit eligibility to the most flexible combustion units.

The rules concern compensation for combustion turbines that are scheduled in the day-ahead energy market but not committed in real time.

The vote by the Markets and Reliability Committee on Thursday was a partial setback for PJM and Independent Market Monitor Joe Bowring, who said current rules provide incentives for units to offer and clear in the day-ahead market but not in the real-time market.

PJM and the Monitor won a change preventing combustion turbines from receiving start-up and no-load costs when they do not run in real time — correcting what Bowring called “an algebra mistake” that resulted in generators receiving payments for costs they did not incur.

The change — including no-load and start-up costs as avoided costs in LOC calculations — was a reform the Monitor had sought since 2012. PJM has estimated the change could reduce LOC payments by about $40 million annually.

‘2×2’ Rule Rejected

The Energy Market Uplift Senior Task Force also had approved a proposal that would have allowed only the most flexible “2×2” CTs — those with start-up plus notification times and minimum run times of two hours or less — to receive lost opportunity costs if they are not dispatched in real time after clearing the day-ahead market.

Resources with start-up plus notification times or minimum run times of more than two hours would not have received lost opportunity payments unless PJM barred them from running in real time to avoid transmission overloads or other reliability problems.

But the task force’s proposal received less than 60% support in a sector-weighted vote of the MRC, short of the two-thirds minimum for passage.

An alternate motion that retained the current technology-specific LOC eligibility rules — combustion turbines and combined-cycle plants operating in simple-cycle mode — was then approved with nearly 92% support and a round of applause.

The MRC last month tabled the task force’s proposal, sending it back for more discussion, after some members, including Ed Tatum of Old Dominion Electric Cooperative (ODEC), complained that the 2×2 requirement was too restrictive. (See PJM Tables Rule Change on CT LOCs.)

Several proposed amendments emerged from the task force’s April 17 meeting: one by Dominion Resources, allowing for start-up costs to be paid if a unit operates in real time at PJM’s direction during any portion of its “temporally contiguous” commitment period; one from PJM clarifying the definition of “temporally contiguous”; and one from ODEC that would have extended LOC eligibility to 2×5 units with minimum run times of up to five hours.

Economic Choice

“We believe units with greater than a two-hour minimum run time are valuable to dispatch,” Tatum said. “We should be making decisions on units’ capability and not on an algorithm’s limitations.” (See PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs.)

Bowring disagreed. “I don’t agree there is any physical basis for any minimum run time. It’s not required by manufacturers … it’s typically an economic choice,” he said. “I would suggest, if anything, that two hours is too long, not too short.”

Bowring added, “Part of the reason we got into this problem in the first place is PJM wasn’t really looking out four or five hours. Five hours is nowhere near flexible.”

Neither amendment by Dominion nor ODEC was cleared as “friendly,” so membership voted on the main EMUSTF proposal, which failed.

Susan Bruce of the PJM Industrial Customers Coalition then made what became the winning proposal, suggesting that the language regarding LOC eligibility be returned to the status quo and considered for approval along with Dominion’s amendment and PJM’s definitional clarification.

“My understanding is that [the 2×2 issue] was a bit of a surprise to some people,” she said. “That will move us past this issue.”

PJM’s Adam Keech, director of wholesale market operations, said that regardless of a mandated minimum run time, PJM will be making procedural changes “because we think we can do better,” noting that the RTO paid $25 million in lost opportunity costs in February. “We’re going to look at less flexible CTs, with lead times eight to 10 hours, and run them more often,” he said.

Because the less flexible units will retain their LOC eligibility, committing them in real time will ensure they are paid based on LMPs instead of being compensated via uplift.

Because the day-ahead payments to the units are a sunk cost, the less flexible units in many cases become essentially a “free resource” to PJM operators, Bowring explained.

After the meeting, Tatum said he was pleased with the vote. “We’re good for now — until the next shoe drops,” he said.

April 28, 2015June 15, 2023

ISO-NE May Delay DR Integration into Markets

By William Opalka

ISO-NE is considering delaying full integration of demand response into its markets by a year due to uncertainty about the Federal Energy Regulatory Commission’s authority over the resource.

A 33-page Markets Committee contingency plan released April 17 suggests not implementing DR until 2018 because of the time needed to develop procedures once the issue is resolved.

The U.S. Supreme Court was scheduled to consider FERC’s appeal of the D.C. Circuit Court of Appeals decision threatening the agency’s jurisdiction at its conference Friday. But no decision was announced Monday and the court said no news is likely for at least a week.

The D.C. Circuit vacated FERC Order 745, which set rules for compensating DR in RTO energy markets, saying the commission had intruded on state jurisdiction (Electric Power Supply Association v. Federal Energy Regulatory Commission). There is disagreement over whether the ruling also voids FERC jurisdiction over DR in the capacity and ancillary services markets. FERC filed its appeal with the Supreme Court in January. (See FERC Files EPSA DR Appeal with Supreme Court.)

“Without direction from the U.S. Supreme Court and the FERC, the region’s next steps are uncertain,” according to ISO-NE’s plan. “Possible scenarios range from maintaining an approach that is fairly consistent with the status quo, to allowing demand response participation solely in the capacity and ancillary services markets, or to removing demand resources from the supply-side of the wholesale market platform altogether.”

If the Supreme Court grants FERC’s request for a writ of certiorari, ISO-NE said, a ruling is not likely before mid-2016. Then FERC must interpret how the court’s direction impacts the integration of DR in wholesale markets.

“In addition to the potentially protracted legal process in this case, it is also unclear how narrowly or broadly the decision in EPSA will be interpreted — primarily by the commission, but potentially by the U.S. Supreme Court as well,” the plan says.

ISO-NE had planned to implement full integration of DR into the energy and reserves markets by June 1, 2017, a transition it says will require at least two years of modifications to its software and system infrastructure.

“The ISO would be at least one year into the project to meet the June 1, 2017, implementation date before knowing the Supreme Court’s ultimate decision,” the plan says. “And for all of the time, money and effort expended up to that point, the Supreme Court may nevertheless uphold the D.C. Circuit’s previous ruling. Substantial resources will be wasted if the ISO moves forward to fully integrate demand response into the energy and reserves market by June 1, 2017, and the Supreme Court ultimately upholds EPSA.”

The Markets Committee will discuss the issue when it meets May 5-6.

FERC last month rejected as premature PJM’s contingency plan to include demand response in its capacity auctions in the event the EPSA ruling is allowed to stand. (See FERC: PJM Demand Response Stop-gap Measure ‘Premature’.)

April 28, 2015January 3, 2024

State Briefs

Dynegy CEO: Exelon Bill Endangers Jobs, Plants

Legislation proposed by Exelon that would impose a customer surcharge to provide more revenue for its Illinois nuclear fleet would put jobs at risk at competing coal-fired power plants, Dynegy CEO Bob Flexon said. “It’ll have a severe economic impact on jobs downstate,” he told Crain’s Chicago Business, placing Dynegy’s plants “more at risk for shutdown.”

“What I would like the Legislature to avoid is disrupting the market by introducing a subsidy for one generator at the expense of other generators,” he said. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)

More: Crain’s Chicago Business

INDIANA

Small Railroad Wants to be Heard in IPL Fuel Switch

Indianapolis Power & Light wants to switch its Harding Street plant from coal to natural gas. Cleaner fuel, more modern plant, better reliability, right? Who would complain?

Well, the small railroad that last year delivered 1 million tons of coal to the plant might. The Indiana Utility Regulatory Commission has recognized Indiana Rail Road Company to be an intervenor in the case. “This conversion will have a substantial, adverse financial impact,” the company wrote. The status as intervenor will allow it to cross-examine IPL witnesses. The rail company has not said whether it will try to stop the fuel conversion.

More: The Indianapolis Star

KENTUCKY

Landfill Project Will Generate Electricity from Methane Gas

The East Kentucky Power Cooperative plans to begin construction next month on a landfill-gas power plant after receiving approval from the Kentucky Public Service Commission.

The facility at the Glasgow Regional Landfill, which will generate electricity from methane gas produced from buried trash, could be operating by September. Other landfills in the state have embarked on such projects over the past decade.

EKPC, comprised of 16 owner-member distribution cooperatives, will purchase the methane gas from the city-owned landfill, and Farmers Rural Electric Cooperative Corp. will buy the electricity produced from the facility.

More: Glasgow Daily Times

MARYLAND

Hogan to Sign Bill Opening Transmission Construction to Non-Incumbents

Gov. Larry Hogan is scheduled to sign a bill Tuesday opening transmission construction to non-incumbent transmission developers.

Senate Bill 460 authorizes persons other than “electric companies” to obtain a certificate of public convenience and necessity (CPCN) to build overhead transmission at or above 69 kV and to obtain land access through condemnation proceedings. Under current law, that authority was limited to existing electric distribution companies — companies already delivering power to retail customers. The bill allows a transmission developer with a regionally cost-allocated project to obtain a CPCN if the Public Service Commission finds the permit is in the best interest of state residents.

The bill was backed by LS Power and NextEra Energy, two competitive developers seeking to gain business as a result of the Federal Energy Regulatory Commission’s Order 1000, which eliminated incumbent transmission developers’ federal rights of first refusal (ROFR). Order 1000 does not bar state ROFR preferences, but FERC Chairman Norman Bay has suggested such laws may be unconstitutional. (See FERC Rejects Rehearing Request on SPP Order 1000 Filing.)

More: Md. Department of Legislative Services

MICHIGAN

Democrats Propose Bill to Double Renewable Standards

While Republicans in Lansing are looking to gut or abandon the state’s renewable energy standard, Democrats are seeking passage of a bill that would double the clean energy standards. The bill, “Power Michigan’s Future,” was introduced last week and now heads for Republican-controlled committees.

The legislation would double the renewable portfolio standard, to 20% by 2022, while also increasing energy efficiency standards to 2% of a utility’s annual sales by 2019.

More: Midwest Energy News

Detroit Zoo Energy Plans: 400 Tons of Animal Manure

The Detroit Zoo is raising funds for a proposed power generator that would be fueled from something it has plenty of: animal manure. It is using an online crowdsourcing site – Patronicity.com – to help it obtain $55,000 in funds to match an offer by the Michigan Economic Development Corporation.

The zoo wants to build a biodigester that would capture methane from the manure to generate both heat and power for the zoo’s 18,000-squre-foot Ruth Roby Glancy Animal Health Complex. The zoo estimates it could save between $70,000 and $80,000 a year in energy costs. “The biodigester will turn one of our most abundant resources – manure – into energy, and represents a significant step on our green journey,” said Detroit Zoological Society CEO Ron Kagan.

More: MLive

NEBRASKA

Wind Energy Credit Bill Advances in Legislature

A bill that would create a wind energy tax credit moved forward last week with a 25-3 vote in the Senate. The bill would provide for a 1-cent tax credit per KWh of power produced. The credit would decline by a tenth of a cent every two years, and then end after 10 years. The federal wind energy tax credit, which expired last year, was 2.3 cents per KWh.

The bill’s sponsor, Sen. Jeremy Nordquist of Omaha, said the wind industry is ready to step in to replace production that will be lost from coal-fired plants being forced into retirement by federal emissions standards. The state has a high amount of potential wind energy, but ranked only 18^th in the nation in production while neighbor Iowa was first.

Iowa is one of six states with state production tax credits, according to a report last year by the Iowa Department of Revenue. “We need to be in the game,” Nordquist said. “Right now, without a [state] production tax credit, we are not in that game.”

More: Omaha World-Herald

NEW JERSEY

BPU Investigating JCP&L’s Operations, May Order Audit

The Board of Public Utilities has ordered its staff to examine Jersey Central Power & Light’s operations, finances and customer service, and indicated that the initial probe could extend into a full audit. The team conducting the probe is expected to report back to the board by its next meeting in May.

JCP&L has been the target of frequent criticism for its outages. The FirstEnergy subsidiary was handed a blow earlier this year when the BPU signed off on a rate case that reduced revenue by $115 million.

While JCP&L has upgraded substations to improve reliability, regulators have said the company is still under the microscope. “Even today, there lingering concerns about operations and management of the company,” said BPU President Richard Mroz.

More: NJSpotlight

Three N.J. Utilities Issue RFPs To Increase Solar Certificates

While not ready to build their own solar facilities, three utilities in New Jersey are seeking power purchase agreements with solar generators for about 80 MW of solar capacity. Atlantic City Electric, Jersey Central Power & Light and Rockland Electric Company are looking to secure Solar Renewable Energy Certificates to satisfy state mandates.

The three-year SREC program, certified by the Board of Public Utility’s Office of Clean Energy, awards one SREC for each MWh of solar generation. ACE is looking for 23 credits, JCP&L is in the market for 52 credits and Rockland needs 4.5 credits.

More: PV Magazine

NEW MEXICO

PRC Nixes Public Service’s Plan To Shutter San Juan Unit

The Public Regulation Commission’s refusal to allow Public Service Co. of New Mexico to shut down one half of its coal-fired San Juan Generating Station to meet federal emissions standards could spell trouble for the plant’s future, according to the company.

Public Service wants to retire two of the plant’s four units, and install emissions controls on the other two. While the hearing examiner agreed to closing the units, he nixed the company’s proposal to absorb 132 MW of excess coal capacity in one of the remaining two units. The company said its plan is necessary because some of the plant’s co-owners will pull out in 2017.

“The consequences of such a decision will likely lead to a collapse of the restructuring of the San Juan ownership interests … and ultimately endanger continued operations at San Juan,” the company wrote in a filing last week. If Public Service has to find outside sources for the lost generation, rates could increase for customers, it said.

More: Albuquerque Journal

NEW YORK

Anti-Fracking Report Due Out Soon

A several-thousand-page document that will lay out the rationale for prohibiting hydraulic fracturing will be released soon, state Environmental Conservation Commissioner Joseph Martens said. The Supplemental Generic Environmental Impact Statement will end seven years of study that paves the way for Martens to issue an order preventing large-scale fracking.

In December, Martens said he would move to prohibit high-volume fracking “at this time” after state Acting Health Commissioner Howard Zucker issued a report recommending against proceeding, citing concerns about health risks and gaps in science.

To formalize a ban, the state Department of Environmental Conservation has to complete the environmental impact statement. State law mandates the document must be available for public review for at least 10 days before Martens issues a “findings statement,” the legal document that would finalize the state’s decision.

Poughkeepsie Journal

Caithness Long Island Says 2nd Plant Could Save $192 Million a Year

Caithness Long Island Energy, which already operates a 350-MW plant in the center of Long Island, released a study that says construction of a second plant could lower regional energy costs up to $192 million a year.

The company said its proposed 750-MW Caithness II plant in Yaphank would also decrease the island’s dependence on power imports and on older plants. The company released the report after PSEG Long Island, operator of the local distribution company, announced that no new sources of power were necessary until 2024.

Caithness President Ross Ain called PSEG’s analysis “one-dimensional” and said it didn’t take into account other savings from both the proposed plant and from Caithness I. PSEG Long Island’s parent company also produces power that would be in competition with the Caithness project.

More: Newsday

NORTH CAROLINA

Most Wells Near Duke Ash Ponds Show Contamination

State environmental regulators issued health warnings after some tests of private water wells near Duke Energy’s coal ash ponds showed contamination. The Department of Environment and Natural Resources said that 87 of 117 test results mailed recently to property owners cited contamination that exceeded state water safety standards.

The state indicated that the water would pass federal standards for municipal water supplies. Nevertheless, the state included warnings not to use the water for drinking or cooking.

While the tests have not yet shown a direct link between the coal ash ponds and the contaminants, many of the contaminants were those often found in coal ash, such as toxic heavy metals. Duke said it believes the high levels of contaminants are naturally occurring. “Based on the test results we’re reviewed thus far, we have no indication that Duke Energy plant operations have influenced neighbors’ well water,” the company said.

More: The Charlotte Observer

Officials Approve Offshore Seismic Surveys With Some Caveats

The state Division of Coastal Management gave the go-ahead for seismic surveys off the North Carolina coast by two oil and gas exploration companies.

Although Spectrum Geo Inc. and GX Technology now have state permits, they still need approval from the Bureau of Ocean Energy Management and the National Marine Fisheries Service. The state division also set other conditions, such as conducting the surveys at times that don’t conflict with recreational fishing tournaments, avoiding certain protected habitats, and following federal mitigation methods to reduce or eliminate impacts to marine life.

More: Carteret County News-Times

Attempt to Scale Back RPS Foiled by House Vote

A House committee voted against an attempt to roll back renewable portfolio standards. House Bill 681 would have allowed utilities to freeze the amount of renewable energy they procure at 6% for the next three years. The current Renewable Energy and Energy Efficiency Portfolio Standard requires utilities to obtain 12.5% of their energy from renewable sources by 2021. The bill was defeated in committee 15-14.

More: WRAL

Duke Energy Moves Ahead With N.C. Solar Construction

Duke Energy is on track to complete three more utility-scale solar projects by the end of the year as part of a $500 million investment in North Carolina solar: the 65-MW Warsaw facility in Duplin County; 40-MW Elm City plant in Wilson County; and the 23-MW Fayetteville Solar Facility in Bladen County.

Duke is also building a 13-MW solar plant at Marine Corps Base Camp Lejeune. The company said last week that it will employ more than 900 workers on the plants at the peak of construction.

More: The Charlotte Observer, Duke Energy

PENNSYLVANIA

PUC Gives Initial Approval To New AEPS Regulations

The Public Utility Commission voted unanimously to revise the state’s Alternative Energy Portfolio Standards with new rules for net metering customers. The rules would allow “customer-generators” to produce up to 200% of their annual power needs, receiving retail prices for any excess they sell to the grid. The rules also would reduce PUC deadlines for approving net metering applicants.

Final approval is pending a comments session. The AEPS requires distribution companies and generation suppliers to source 18% of electricity from alternative sources by 2021.

More: The Philadelphia Inquirer, PUC

FirstEnergy’s Bruce Mansfield Plant Tagged with Notice of Violation

The Department of Environmental Protection issued a notice of violation to FirstEnergy Corp. for emissions at its Bruce Mansfield coal-fired plant in Shippingport. The DEP said that the plant’s Unit 2 stack exceeded emissions limits earlier this month. The NOV did not identify the emissions.

Workers at the plant found a leak in a duct and repaired it, a plant spokeswoman said. A DEP spokesman said union employees at the plant brought the issue to the attention of state regulators, and that “served as a way to gets us out there.”

More: Pittsburgh Post-Gazette

VIRGINIA

Dominion to Close All Ash Ponds in Virginia

Dominion Virginia Power said it will be closing all ash ponds at its Virginia power plants. The announcement came following the finalization of coal-ash disposal rules by the Environmental Protection Agency.

Virginia is the northern neighbor of North Carolina, which has been the scene of coal-ash legal action and legislation following a massive spill of toxic coal ash from a retired Duke Energy plant on the border of the two states. Dominion said it would close coal ponds at its Chesterfield Power Station near Richmond, the Bremo Power Station in Fluvanna County, the Chesapeake Energy Center in Chesapeake and the Possum Point Power Station in Prince William County.

The company said the ponds would be drained and sealed with a liner that would covered with a 2-foot layer of earth.

More: The Roanoke Times

McAuliffe Signs Clean Energy Bills on Earth Day

Gov. Terry McAuliffe signed several bills aimed at encouraging clean energy production, energy efficiency and jobs production:

- - HB 2267/ SB 1099: A bill creating the Virginia Solar Development Authority, which aims to spur construction of solar facilities;
  - HB 1950/ SB1395: Doubles allowable generation capacity of a solar net energy metering facility;
  - HB 2237: Authorizes utility cost recovery for construction or purchase of a solar facility with capacity over 1MW and establishes that 500MW of solar generation are in the public interest;
  - SB 1331: Clarifies how costs are evaluated by the State Corporation Commission to increase approval of natural gas energy efficiency programs;
  - HB 1446 /SB 801: Expands the Property Assessed Clean Energy (PACE) program, which creates loan programs for localities to finance energy efficiency projects on commercial buildings using private capital; and
  - HB 1843/ SB 1037: Extends $500 per job Green Jobs Tax Credit for three years to July 1, 2018

Some environmentalists applauded the move, but said more action is needed. “The fact that we’re celebrating Earth Day by witnessing several pieces of clean energy legislation get signed into law is proof of the growing movement in Virginia demanding solutions to climate change,” said Dawone Robinson of the Chesapeake Climate Action Network.

“Virginia currently has only 11 MW of solar installed, and that figure is embarrassingly low, especially compared to our neighbors. Virginia has as much or more solar potential than Maryland and North Carolina, yet those states have more than 200 MW and 950 MW of solar currently installed respectively thanks to much stronger state policies.”

More: Gov. McAuliffe, Chesapeake Climate Action Network

WISCONSIN

Contested Transmission Line Gains PSC Approval

The Public Service Commission last week approved the Badger-Coulee transmission project, and now land agents are fanning out to acquire the easements upon which it will be built. The 345-kV, $580 million line is a joint venture of Xcel Energy and American Transmission Co.

With the PSC’s approval, the companies received permission to pass the cost of the line on to consumers across the Midwest. The line is part of a larger project, the CapX2020, which will run across Minnesota and Wisconsin.

Construction work on that line is already underway. ATC and Xcel say the lines will provide a way to deliver cheaper wind-generated power to consumers.

More: Lacrosse Tribune

Alliant to Build $750 Million Gas-fired Plant in Wisconsin

Alliant Energy Corp. is seeking authority to build a $750 million combined cycle gas plant in Wisconsin, its first application for new generation since regulators rejected its 2008 proposal to build a coal-fired plant. The company is also proposing to build a new 2-MW, $9 million solar facility next to the gas plant.

The solar facility, if approved and constructed, would be the second largest in the state. The proposed gas-fired plant would be rated at about 700 MW. The proposal for the new complex coincides with Alliant’s plans to retire a coal-fired facility in Cassville, Wis. and coal boilers in Sheboygan to comply with an environmental settlement reached with federal regulators several years ago.

More: Journal Sentinel

April 28, 2015

PJM Markets and Reliability Committee Members Committee Briefs

The Markets and Reliability Committee approved Tariff and manual revisions regarding PJM’s use of sampling to measure and verify residential demand response.

The new measurement method was originally endorsed at the Jan. 22 Members Committee meeting. Thursday’s vote approved the inclusion of an additional transition year because of delays in filing the new method with the Federal Energy Regulatory Commission.

PJM now expects to make the filing in late April. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25, 2014.)

Tariff Harmonization Senior Task Force Charter Approved

The MRC approved the draft charter of the Tariff Harmonization Senior Task Force, formed to address inconsistencies and discrepancies in PJM’s governing documents. There was one abstention and one vote against the measure. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

Regional Planning Process Senior Task Force Placed on Hiatus

On first reading, MRC members approved the Regional Planning Process Senior Task Force’s recommendation directing the Planning Committee to develop guidelines for considering generation interconnection projects as drivers under the multi-driver transmission project approach.

The MRC also agreed to place the task force on hiatus, available to be returned to operation if needed based on future rulings by FERC.

Manual Change Endorsed

The MRC approved changes in Manual 14D: Generator Operational Requirements to reflect a recent advisory from the North American Electric Reliability Corp. on generator frequency response requirements. PJM sent Generator Operators a survey regarding governor dead band settings, droop setting and mode of operation on April 3. PJM will compile the responses, due June 3, and share the data with NERC.

FTR Auction Clearing Deadlines, Trading Periods Approved

The Members Committee approved minor “non-substantial” provisions regarding financial transmission rights’ auction clearing deadlines and trading periods.

April 28, 2015

Quebec-NYC Tx Line Clears Final Regulatory Hurdle

By William Opalka

A 1000-MW merchant transmission line that would deliver Canadian hydropower to New York City has completed its federal environmental review, clearing the way for construction.

The U.S. Army Corps of Engineers on Tuesday issued a permit to Transmission Developers Inc. that allows the Champlain Hudson Power Express project to be placed in U.S. waters along the proposed route. The entire 333 miles from the Quebec border to the Astoria neighborhood in Queens will be underground or underwater, including sections beneath Lake Champlain and the Hudson River.

TDI said the project has secured all of the federal and state siting permits necessary to proceed with construction, which could start next year. The permit authorizes TDI to construct the project under Section 10 of the Rivers and Harbors Act and Section 404 of the Clean Water Act.

The estimated $2.2 billion project would boost Canada’s interest in exporting electricity to New York and New England. (See Hydro-Quebec Seeks to Boost Exports to Northeast.)

“The terms of the permit reaffirm that our project will take appropriate steps to protect New York’s environmental and commercial resources, and we are excited to have moved substantially closer to the moment when we will begin to deliver cleaner, lower-cost power to New York’s residents and businesses,” TDI CEO Donald Jessome said in a statement.

The project has been under development since 2008. Its proponents claim it could reduce energy costs for consumers and businesses by $650 million a year.

The Independent Power Producers of New York, a trade association whose members would be in direct competition with imported energy sources, opposed the project. IPPNY insists the project is not financially viable without subsidies from Canadian power producers and an above-market-rate contract with New York utilities transmitting the energy.

The New York Public Service Commission has rejected those claims.

TDI plans to finance the project through private equity and support from shippers and contractors. TDI’s lead investor is the Blackstone Group.

April 28, 2015

PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out

By Suzanne Herel

VALLEY FORGE, Pa. — PJM planners will recommend to the Board of Managers that LS Power build a new 230-kV transmission line from New Jersey’s Artificial Island to Delaware to address stability issues at the nuclear complex, they announced Tuesday at a special meeting of the Transmission Expansion Advisory Committee.

LS Power’s commitment to limit construction costs to $146 million was a driving factor of the decision, said Paul McGlynn, general manager of system planning. PJM also felt the proposal has the best chance of being able to secure permits.

“It is our opinion that the LS Power proposal provides greater flexibility and can mitigate some of the permitting risk involved in siting,” he said. “It is staff’s intent to recommend installing a 230-kV line under the Delaware River using horizontal directional drilling technology and designate that to LS Power.”

Public Service Electric & Gas and Pepco Holdings Inc. were chosen for necessary connection facilities. Dominion Resources and Transource Energy, which were among the finalists, were not included in PJM’s recommendation. PJM will make the recommendation to the Board of Managers after May 29, the deadline for stakeholders to submit comments.

artificial island — PJM planners recommended the selection of LS Power to build a new 230kV circuit from Salem to a new substation near the 230kV corridor in Delaware, using horizontal directional drilling the bury the line under the Delaware River. The new line would tap the Red Lion-Cartanza and Red Lion-Cedar Creek 230 kV lines. (Source: PJM Interconnection LLC)

Sharon Segner, vice president for LS Power, said in an interview that she appreciated PJM recognizing the value of being able to choose from an overhead or submarine crossing.

“It’s going to be a difficult river crossing. We go into it with our eyes wide open,” she said. Yet, she said she was confident the company would be able to complete the four-year project within the cost cap. “We’ve assessed the situation, assessed the risks and feel very comfortable in the commercial feasibility of our project.”

Roles for PSE&G, Transource

PSE&G would be responsible for expanding the Salem substation and building a static VAR compensator (SVC) upgrade at New Freedom. Pepco Holdings Inc., Transource’s partner, would oversee interconnecting the new substation to the existing Red Lion-Cartanza and Red Lion-Cedar Creek 230-kV lines.

PSE&G and PHI together would be responsible for optical ground wire (OPGW) upgrades.

The SVC upgrade project is estimated at $31 million to $38 million, and the OPGW work at $25 million.

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.

First Order 1000 Solicitation

The call for proposals for a fix, which went out two years ago, signaled PJM’s first competitive transmission project under the Federal Energy Regulatory Commission’s Order 1000.

Last summer, PJM planners recommended PSE&G for the job, but the Board of Managers reopened the bidding following an outcry from losing bidders, environmentalists and New Jersey officials.

PSE&G was a finalist in the new round of bidding, along with LS Power, Transource and Dominion.

“We’re disappointed with the outcome,” Jorge L. Cardenas, PSE&G vice president for Asset Management & Centralized Services, said after the meeting. “We will put our comments together in the next 30 days.”

All of the projects include new transmission lines connecting the nuclear complex to Delaware. LS Power and Transource offered a southern, submarine crossing of the Delaware River, with LS Power also including an overhead option. Dominion and PSE&G proposed a northern, overhead crossing. (See Artificial Island Finalists Face Off in Tense Meeting.)

All are expected to be met with permitting obstacles.

Planners had expected to make a recommendation in January but held off so consultants could look into concerns that Dominion’s proposed use of thyristor controlled series compensation (TCSC) could threaten reliability.

At the last TEAC meeting, PJM said that Siemens Power Technology International had completed a sub-synchronous resonance analysis of Dominion’s proposal and found it could result in “negative damping” for several resonant frequencies.

Exponent, an engineering and science consulting firm hired by PJM to review the Siemens study, expressed its own concerns with the Dominion plan, which proposes a 90% post-contingency TCSC compensation — well above the usual 70 to 80% compensation used in the industry.

PSE&G Challenge

Still outstanding is a complaint PSE&G submitted to FERC accusing PJM of breaking its own rules in the bid solicitation process (EL-15-40). PJM in March asked FERC to defer ruling on the matter until it had chosen a bidder for the project. (See PJM: PSE&G’s Remedy for Artificial Island Bid Process ‘Draconian,’ ‘Self-Serving’.)

“We still have our complaint in to FERC, and we will pursue that and hope for the best,” Cardenas said.

April 24, 2015

FERC OKs PJM Request to Delay Capacity Auction

By Rich Heidorn Jr.

The Federal Energy Regulatory Commission Friday granted PJM’s request to delay May’s Base Residual Auction, allowing the RTO more time to seek FERC approval for its Capacity Performance proposal.

“PJM’s request for waiver will allow the commission to consider the additional information submitted by PJM in support of its Capacity Performance proposal, as well as comments and protests regarding that additional information, while also providing clarity regarding the timing under which PJM will conduct its auction following commission action on that proposal,” the commission said.

PJM filed the request on April 7, after FERC issued a deficiency letter over the Capacity Performance plan (ER15-623). It sought a waiver from the Tariff requirement that the auction be held in May. It said it would hold the auction 30 to 75 days after a commission order on the merits of the proposal, but no later than the week of Aug. 10-14.

The proposed delay drew more than two dozen comments, mostly from supportive stakeholders, but also from critics who said a postponement would create more market uncertainty than it is seeking to quell. (See PJM Bid to Delay Capacity Auction Draws Flurry of Support, Criticism.)

In granting the delay, the commission ruled that PJM’s request was of limited scope, remedied a concrete problem and would not harm third parties (ER15-1470). (The commission later issued an errata to fix its incorrect reference to the in paragraphs 1 and 2, which should have referred to the 2018/19 delivery year.)

FERC acknowledged the delay would result in “some uncertainty.”

“We recognize that some protestors argue that delaying the auction will harm them by increasing their costs to participate in the auction. We acknowledge these concerns, but agree with PJM that it is important that the commission have the opportunity to consider the full record in the Capacity Performance proceeding prior to PJM running this year’s auction.”

The commission said PJM’s commitment to conduct the auction no later than mid-August mitigates the potential impacts on market participants, and noted that “any additional costs incurred by participating resources may be included in their capacity sell offers, to the extent permitted by the rules in place for the auction.”

April 23, 2015

Entergy Out-of-Cycle Requests Win MISO Board OK

By Chris O’Malley

CARMEL, Ind. — Over the objections of transmission developers and independent power producers, MISO’s Board of Directors voted unanimously Thursday to approve Entergy’s request for $217 million in out-of-cycle transmission projects.

There was no discussion by the board nor comments from stakeholders on the topic.

The outcome seemed all but certain following a unanimous vote Tuesday by MISO’s Board of Directors System Planning Committee to recommend that the full board approve Entergy’s requests.

Most of the opposition centered on the largest of the Entergy projects, a $187 million project to serve additional load in the Lake Charles, La. industrial zone in the midst of an economic revival.

Opposing stakeholders have alleged the increased load is speculative, that the project is beyond what is needed for a base reliability upgrade and that there was inadequate stakeholder review.

They also wanted a shot at competing for the project.

On Tuesday MISO staff outlined a checklist of steps taken that they say conforms with tariff and business practice manual procedures.

The bulk of the controversial Lake Charles project involves adding a 500 kV tap line that will extend seven miles to a new substation in Lake Charles, where Entergy said numerous industrial customers have committed to adding facilities.

MISO studied alternatives, including upgrading a 230 kV line and providing supply from more distant sources, but concluded they were less effective, said MISO Director of Planning Jeff Webb. “This is a straightforward, and I think ideal, solution,” Webb told the committee last week.

The committee pointed to an April 2 letter from Louisiana Public Service Commissioner Eric Skrmetta that expressed dissatisfaction with the review of the projects at MISO, calling on MISO to streamline the out-of-cycle approval process.

“Nothing should be permitted to interfere with the location of significant new load in southwest Louisiana and the economic benefits it will bring to the people of this state,” wrote Skrmetta. “…The consideration of these projects has gone on long enough. Second, numerous stakeholders have expressed dissatisfaction with MISO’s out-of-cycle consideration and approval process.”

Webb told the committee that MISO had 16 OOC projects last year and seven in 2013. Director Baljit “Bal” Dail, who is not a member of the committee but sat in on Tuesday’s meeting, asked Webb why Lake Charles was so controversial.

Webb cited the size of the project and said he recalled only one other controversial project over the years — also one of substantial size.

Clearly, large projects would be more lucrative for transmission developers hoping for a competitive project. MISO staff have maintained that Lake Charles is a reliability project, which would be ineligible for competition.

Board Chairman Judy Walsh — who substituted as chair of the meeting due to a medical issue involving chair Mike Evans — said the OOC process is designed to prevent MISO from becoming a “stumbling block” to needed reliability upgrades.

“In order for this process to work it has to be fast. It has to be efficient,” she said.

Earlier this month, in response to the controversy over Entergy’s request, MISO launched discussions that could lead to refinements in its procedures for handling out-of-cycle requests. (See MISO Seeks Stakeholder Input on Out-of-Cycle Process amid Entergy Controversy.)