FERC last week certified a settlement between Entergy Services and the Louisiana Public Service Commission in the corporation’s ninth annual bandwidth filing under its system agreement, saying it “resolves all issues of dispute” (ER15-1826).
Entergy filed the settlement in March. In April, FERC staff filed supporting comments and Louisiana PSC staff approved the agreement, which had been set for hearing and settlement procedures in October. (See FERC Sets Hearings for Entergy’s Cost Allocations.)
Entergy’s Nine Mile 6 Plant in Westwego, La. Source: Entergy
At issue was Entergy’s exclusion of its Arkansas subsidiary from the allocation of its operating companies’ 2014 production costs. The corporation’s cost allocation under its system agreement has been regularly challenged by regulators since it took effect in 2007.
Entergy’s six operating companies essentially operate as one system, although each has different costs. Payments are made annually by Entergy’s low-cost operating companies to the highest-cost company in the system, using a “bandwidth” remedy that ensures no company has production costs more than 11% above or below the system average.
Public Policy, Market Efficiency Theme of PJM’s Grid 20/20
Public policy goals and market efficiency are the topics of PJM’s upcoming Grid 20/20 conference, to be held Aug. 18 in Audubon, Pa., the RTO announced.
Panelists will explore how market rules can further public policy goals without distorting market principles. Discussions will include changing the minimum offer price rule, restructuring the process of procurement and other “outside the box” alternatives.
Constellation, Direct Energy Vie for Residential Customers
Exelon subsidiary Constellation has begun offering residential electricity supply plans in Delmarva Power territory. The company is featuring fixed-rate plans of one or two years with gift cards and no enrollment charge.
Also this summer, the state declared Direct Energy the “electric retail supplier exclusively contracted by the state of Delaware.”
In addition to lower fixed prices, Direct Energy gives residents who enroll a free Nest Learning Thermostat and a six-month heating and cooling equipment protection plan.
Louisville Gas & Electric and Kentucky Utilities have filed a request with the Public Service Commission to start a community solar network. The solar facility would be established in Shelby County on a subscription-based system, allowing residential, business and industrial customers to join and receive solar energy credits.
The PPL-owned utilities said the site is big enough for a 4-MW facility, but plans call for it to be built in 500-kW sections, based on customer demand. Construction would begin when the first section is fully subscribed.
Hundreds in Financial Limbo as Solar Credits Fade Away
Hundreds of rooftop solar users have been thrown into financial limbo after the state’s Department of Revenue warned in July that it had run out of money to fund tax credits intended to promote installations.
Lawmakers decided last year to cap the solar tax credit program in the face of worsening budget woes. Legislators also widened the cap to cover everyone who purchased solar in 2015, including those who bought their systems well before any changes were proposed.
The solar tax credit is among the most generous in the country, covering up to 50% of the first $25,000 spent to install a rooftop solar system, or up to $12,500 total. It can be combined with a 30% federal tax credit for extra savings. The program had a 2017 sunset, but lawmakers went a step further last year and capped credits for purchased systems at $25 million.
Kinder Morgan surveyors are mapping the route of its proposed 2-mile natural gas pipeline, part of the three-stage $86 million Connecticut Expansion Project, through a state forest.
The state Department of Conservation and Recreation granted permission for surveying and marking the pipeline’s right of way through Otis State Forest. No permission for land clearing has been granted as the developers await FERC approval, and legal challenges to the project continue.
Opponents argue that the old-growth forest is protected by the state constitution, as the land was acquired by the state for conservation a decade ago at a cost of $5.2 million.
Gov. Charlie Baker on Monday signed a bipartisan bill that requires utilities to obtain 9,450 GWh annually of clean energy from large-scale Canadian hydropower, onshore wind power and solar, and 1,600 MW of offshore wind from developers who currently hold federal leases.
“Massachusetts is always at the forefront of adopting innovative clean energy solutions, and this legislation will allow us to build on that legacy and embrace increased amounts of renewable energy, including hydropower,” Baker said. The bill was passed a week ago in the waning hours of the recently concluded legislative session. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Attorney General Bill Schuette says Enbridge Energy’s application to install more pipeline support anchors is evidence that the company’s Line 5 pipelines under the Mackinac Straits are currently in violation of safety standards, which require pipe-support anchors at least every 75 feet.
Enbridge recently submitted a request for a permit to install up to 19 additional anchors. The company says it informed state officials of the need for more support after a June inspection.
The company has been under heightened scrutiny since a 2010 pipeline break spilled more than 800,000 gallons of oil into the Kalamazoo River. In July, it agreed to pay $177 million to settle claims in connection with that spill.
The state Supreme Court last week unanimously ruled to block a referendum from appearing on the Nov. 8 general election ballot that could have restored favorable net metering rates to customers. The court ruled that the way the question was formed was “not only inaccurate and misleading, but also argumentative.”
The referendum question has been seen as a battle between NV Energy and the solar industry. The state, after heavy lobbying from NV Energy, set lower net metering rates this year. Many solar companies announced they were leaving the state, saying the new rates effectively suffocated the solar industry there.
Solar advocates expressed disappointment in the ruling, but said they would pursue alternative strategies. “We look forward to crafting strong solar policies that give Nevadans the freedom to power their homes and communities with clean solar energy,” said Erin McCann, campaign manager for Bring Back Solar.
PUC Adopts New Energy Efficiency Resource Standard
The Public Utilities Commission approved an Energy Efficiency Resource Standard, creating a framework for achieving cost-effective energy savings.
Programs will be required to demonstrate they are cost-effective and satisfy goals laid out in the standard. According to the PUC, the standard will help the state meet its 10-year State Energy Strategy goals.
During the first three-year period of the EERS, the cumulative goal for electric savings will be 3.1% of delivered 2014 kilowatt-hour sales, with interim annual savings goals, by 2021. Programs under the standard will begin on Jan. 1, 2018.
Public Regulation Commission staff have expressed doubt about the public benefits of Public Service Company of New Mexico’s plans to install advanced metering infrastructure (AMI), while eliminating the jobs of the 125 employees who monitor them.
Charles Gunter, accounting bureau chief for the PRC’s utility division, said the commission staff support the concept of advanced metering, but PNM’s projected costs to replace about 531,000 electricity meters “are uncertain and indicate that the AMI project would not produce sustained savings, compared to the existing metering system, until 2024.”
The attorney general’s office also submitted testimony from an expert witness, Columbia Group President Andrea Crane, who said the project would result in a net cost of $12 million instead of the net savings of nearly $21 million that PNM claims.
The state toxicologist said he discussed with Gov. Pat McCrory the “scientifically untrue” health advisories the state released that downplayed the risk of well water contamination near Duke Energy plants, but the governor’s office strongly denied ever having that conversation.
State Toxicologist Kenneth Rudo testified in a deposition that state-issued health advisories saying the water was safe to drink were wrong and that he told McCrory and other state officials. Rudo, in a later interview with The Charlotte Observer, said he spoke with the governor by phone for about four minutes and said he advised that well owners should be warned of the risk, as an earlier state-issued comment had done. Instead, the state issued a statement saying tests showed well water met federal clean water standards.
“We don’t know why Ken Rudo lied under oath, but the governor absolutely did not take part in or request this call or meeting as he suggests,” Chief of Staff Thomas Stith said in a statement. Lawmakers passed legislation calling for Duke to provide clean drinking water to affected residents.
Opponents of a new $1 billion natural gas power plant lost their appeal to the Utilities Commission because they failed to post a nearly $100 million guarantee to cover potential construction delays.
The commission had approved the Ashville plant to take the place of a coal-fired facility run by Duke Energy.
The appeal was filed by NC WARN and the Climate Times.
Contractors are pumping about 7,500 cubic yards of grout into an abandoned underground lignite mine, part of a project conducted by the Abandoned Mine Lands Division of the Public Service Commission. The drilling and grouting project will prevent dangerous sinkholes from forming as a result of mine subsidence.
The cost of the work is covered by federal reclamation fees on active coal mines. The division has conducted two major and one minor project this year; since its start in the 1980s, it has conducted more than 100 reclamation projects, usually finishing four to 10 annually.
Wilton was the focal point for state lignite mining in the early 20th century.
Offshore Turbine Installation Starts at Block Island Project
Deepwater Wind has begun installation of the first offshore wind turbines in the U.S. at its project 3 miles off Block Island. The turbines will each rise 589 feet above the ocean’s surface.
The work kicked off a month-long push to complete construction of the 30-MW wind farm. Two months of testing will follow before full operation starts in the fall.
Deepwater has budgeted three days to put up each turbine, the company says. In Europe, where thousands of offshore wind turbines are in operation, the standard is a day and a half.
Natural Resources Board Buys Riverfront Land from Xcel
The Natural Resources Board last week approved the purchase of nearly 1,000 acres of riverfront property from Xcel Energy, which had planned to build a power plant on the site.
With the board’s approval, the state’s Department of Natural Resources will pay almost $2.1 million for 990 acres along the Lower Chippewa River southwest of Eau Claire. The property includes 18,000 feet of shoreline and a section of the Chippewa River Trail.
Xcel was planning to use the site for a nuclear power plant that it never built. The utility still owns just more than 3,400 acres of nearby riverfront land.
University Receives Xcel Grant for Microgrid Research
The University of St. Thomas has received a $2.1 million grant from Xcel Energy for microgrid research.
Engineering professor Greg Mowry said about $1.5 million of the grant will be used to construct a research facility and a 30- to 60-kW microgrid, with an accompanying solar array.
The initial goal is not to supply power to the university, though that may come later. The first phases of the project involve managing “dummy loads” and simulating different energy sources, such as a wind turbine “emulator” controlled by researchers and students.
Gov. Matt Mead appealed to the U.S. Interior Department to end its moratorium on new coal leases in a 76-page letter with 4,179 pages of attachments sent to Secretary Sally Jewell and Bureau of Land Management Director Neil Kornze.
“States like Wyoming, where coal is produced and environmental stewardship is a model for the nation, were not consulted and were caught by surprise,” Mead wrote. “Now, national revenues, energy users across the nation, coal miners and their families are at risk. The justification for this moratorium and the manner it was unveiled are unjustifiable.”
Mead said the moratorium, announced Jan. 15, is dramatically impacting jobs, energy security and energy independence, and that it specifically targets the state, the nation’s leader in coal production. The state produces roughly 40% of the nation’s coal, most of which is mined from federal land.
A segment of the long-awaited Tres Amigas transmission project in New Mexico is expected to begin transmitting power to CAISO in early 2017. A company executive confirmed that construction of a 35-mile portion of the line called the Western Interconnect began after FERC approved the project last December and is expected to be completed at the end of the year.
“It’s a huge win for New Mexico: that much wind developed here and going all the way to California [is] a great business development piece, and a great asset for the state,” Tres Amigas CFO Russell Stidolph said.
The Broadview and Grady wind farms will be allocated 497 MW of the line’s 1,100 MW of capacity.
NextEra to Sell $1.5B in Equity to Help Finance Oncor Purchase
NextEra Energy said it will sell $1.5 billion of equity units to Goldman Sachs, Credit Suisse and Mizuho Securities.
Each equity unit will be issued for $50 and will consist of a contract to purchase NextEra common stock in the future and 5% interest in a $1,000 NextEra Energy Capital Holdings debenture, a bond without collateral, due Sept. 1, 2021. The proceeds of the sale will go toward financing the company’s acquisition of Oncor, it said.
After announcing it would spend $1 billion on wind projects in Iowa, Alliant Energy’s CEO said the company will also consider investing in wind buildout in neighboring Wisconsin.
“We are also evaluating additional wind energy purchases and future investments for Wisconsin customers,” Alliant CEO Pat Kampling said during an earnings call. “This will add economic and stable energy to our fuel cost and allow us to offset market purchases of energy.”
Alliant reported net income of $86.4 million ($0.37/share) for the second quarter this year, compared to $67.6 million ($0.31/share) for the same period last year.
Dynegy reported a net loss of $800 million for the second quarter this year, compared to net income of $388 million for the same period last year.
The announcement comes as Dynegy completed a “rebranding,” with a new logo and redesigned website, in recognition of becoming one of the country’s largest independent power producers after purchasing 17 power plants from Paris-based ENGIE.
Solar Mosaic Raises $220M for Solar Installation Loans
Solar Mosaic, a six-year-old California company that acts as a middleman between residential customers and solar installation companies, raised $220 million to finance installations around the U.S. The company provides loans with fixed interest rates to residential customers, with an average loan of about $30,000.
The company has previously secured about $200 million in debt in April and said that it would support loans for about 5,000 customers. More than 250 solar companies use Solar Mosaic to arrange funding for their customers.
Exelon has named Maggie FitzPatrick, formerly of Johnson & Johnson, as its senior vice president of corporate affairs, philanthropy and customer engagement, effective Aug. 29. She takes the place of Jamie Firth, who is retiring at the end of this year.
FitzPatrick will oversee communications, brand strategy and the disbursement of charitable giving out of D.C., where Exelon’s headquarters moved following its acquisition of Pepco Holdings Inc. She also takes a seat on Exelon’s executive committee.
Exelon’s Pepco subsidiary hired Clarissa Beyah-Taylor as its vice president of communications to oversee public outreach for the three PHI utilities: Atlantic City Electric, Delmarva Power and PEPCO.
El Paso Electric officials said the company has become coal-free and no longer is using the fossil fuel, making it the only electric utility in Texas and New Mexico without any coal-fired generation.
EPE recently completed the sale of its part ownership in the Four Corners coal-fired power plant on the Navajo Indian Reservation near Farmington, N.M., the company’s sole source of coal power. The company received 5% of its power this year from the plant, which has been replaced with natural gas-fueled generators and solar power.
ExxonMobil to Invest $15M in Renewable Energy Research
ExxonMobil announced it invested $15 million in the University of Texas at Austin Energy Institute to research integrating renewable energy sources into the nation’s current portfolio to reduce the impact on water, air and climate. The research will take advantage of the school’s renewable energy, battery technologies and power grid modeling.
PECO Gives Customers a Glimpse into Neighbors’ Homes
PECO Energy has embarked on a behavioral experiment to reduce power consumption by sharing customers’ usage with their neighbors.
The utility plans to provide the reports every other month for two years. All customers, regardless of whether they were chosen to receive the mailed reports, can view the data online.
The plan is part of PECO’s effort to cut 2 million MWh and lower peak demand by 161 MW by 2021.
Black Hills Energy in Midst of $20M Tree-Trimming Effort
South Dakota’s Black Hills Energy has invested more than $10 million during the past three years trimming trees and other vegetation along its electricity lines and intends to spend $10 million more in 2016-17, according to a report approved Aug. 2 by the state’s Public Utilities Commission.
The five-year project to trim vegetation along 69-kV rights of way stems from a 2012 agreement between the company and the commission to protect the utility’s distribution system. Outages caused by trees numbered 116 in 2011 but fell to 38 in 2014.
PUC Chairman Chris Nelson said the results looked good but expenses have been “surprisingly” more than expected. “The numbers are higher than we had been anticipating, and we have been given an explanation why that is.”
Once Fastest-Growing Austin Firm, Solar Company Faces Bankruptcy
Austin-based Revolve Solar, formerly one of Texas Hill Country’s largest clean-tech companies, has filed for Chapter 11 bankruptcy protection.
The company’s CEO, Tim Padden, said the bankruptcy filing was the result of a billing dispute with a vendor and that he was optimistic the matter could be resolved. Revolve filed a voluntary petition for bankruptcy on July 31 in U.S. Bankruptcy Court for the Western District of Texas.
The bankruptcy comes less than a year after Revolve was honored as the second-fastest-growing Austin company, with revenue of more than $10 million from 2012 to 2014. During that time, the company said its revenue grew from $1.76 million in 2012, the year it was founded, to $15.9 million in 2014.
American Electric Power purchased a series of solar and energy storage projects in Hawaii from EnSync Energy Systems. Neither AEP nor the Wisconsin-based company put a price tag on the acquisition, but EnSync said the projects were the “major portion” of its investment of $13 million.
EnSync is switching to a business model according to which it will be more reliant on projects using power purchase agreements, rather than selling its energy storage equipment.
AEP’s subsidiary, AEP OnSite Partners, sees more opportunity in Hawaii. “Hawaii provides ideal conditions to create customer value with solar resources combined with energy storage,” said Joel Jansen, COO of AEP OnSite Partners. “These projects are the first integrated solar and storage projects in Hawaii.”
EFH Creditors See Industry Vet as Luminant, TXU Energy CEO
Energy Future Holdings creditors filed court papers last week that said energy veteran Curtis Morgan would become CEO of power generator Luminant and retailer TXU Energy once their parent company emerges from bankruptcy.
Morgan has 35 years of experience with Reliant Energy, NRG Energy and EquiPower Resources, and he was an operating partner at Energy Capital Partners. He has served on a committee of private equity consultants advising Dallas-based EFH as it winds its way through one of the largest bankruptcies in U.S. history.
If the company’s bankrupty reorganization is approved later this year, Luminant and TXU Energy will break away from EFH as a tax-free spinoff. EFH’s other main business, distributor Oncor, is expected to be sold to NextEra Energy for $18.4 billion.
FERC Commissioner Tony Clark announced through Twitter that he would leave the commission after its next open meeting in September.
Clark
“After 4+ years on FERC, I’m announcing today that the September Commission meeting will be my last,” Clark posted. “Public service has been an honor, but these aren’t meant to be forever jobs. Looking forward to next chapter, whatever that may be.”
Clark announced in January that he would not seek reappointment after his term expired June 30. He had said that he may serve beyond his term until a replacement is found. President Obama, however, has yet to nominate anyone to fill the seat vacated by Philip Moeller, let alone Clark’s. His departure means that FERC will be left without a Republican commissioner.
Report: More EE Standards Under Obama than Any Other President
Under the Obama administration, the Energy Department has finalized more energy efficiency standards than under any other administration, a recent report said.
Regularly updating and creating energy efficiency standards has been part of the department’s duties since President Ronald Reagan signed the National Appliance Energy Conservation Act in 1987. While the department has been publicly touting its progress, the report by two independent groups, the Appliance Standards Awareness Project and the American Council for an Energy-Efficient Economy, validates its claims. The department has adopted 45 standards under President Obama and will potentially adopt 10 more before his term ends next year.
The runner-up to Obama is President George W. Bush; under his presidency, 27 standards were adopted. Bill Clinton’s administration adopted the fewest with only six, the report said. Obama made energy efficiency a top priority for the department after it fell behind in its mandated update quota under Bush, according to the report.
American Petroleum Institute Challenging EPA Gas Rule
The American Petroleum Institute has filed a lawsuit against EPA with the D.C. Circuit Court of Appeals, challenging the agency’s final rule on emissions for new and modified natural gas facilities. The suit says the agency didn’t follow Clean Air Act limitations when developing the regulations.
API joins a coalition of 14 states and a number of trade groups in challenging the rules.
A federal judge last week sharply reduced the potential fine against Pacific Gas and Electric in its criminal trial over gas pipeline violations related to the San Bruno explosion in 2010, which killed eight people and destroyed 38 homes.
U.S. District Court Judge Thelton Henderson slashed the penalty from $562 million to $6 million at the request of prosecutors in the case. Neither Henderson nor the prosecutors provided a reason for the move.
The original penalty would have represented one of the largest corporate criminal fines in history. San Bruno Mayor Jim Ruane said the fine was less important to him than seeing the utility punished.
FERC issued a notice last week alleging that National Energy & Trade and one of its traders, David Silva, engaged in fraudulent trading in the natural gas market in January 2012 by selling a large position in the Texas Eastern M3 market at low prices and then benefiting from the resulting market uptick.
The Nuclear Regulatory Commission issued the final safety evaluation for Duke Energy’s proposed Williams States Lee nuclear plant to be built in Cherokee, S.C., bringing the company one step closer to beginning construction. The commission found no safety issues to prevent the plant from being built.
Duke applied for the licenses in 2007 and received the commission’s final environmental impact statement in 2013, but it still hasn’t made a final decision on whether to go ahead with construction. That decision would come after the commission has issued the two necessary operating licenses, according to the company.
DOJ Opens Investigation into Westar-Great Plains Deal
Coming on the heels of a Missouri Public Utilities Commission staff recommendation that the commission should have jurisdiction over the pending $12.2 billion Westar Energy-Great Plains Energy merger, the federal Department of Justice is also looking into the deal.
Word of the Justice Department investigation came in a report Westar filed with the Securities and Exchange Commission. “We and Great Plains Energy intend to fully cooperate with the DOJ in its investigation,” Westar said in its filing, which did not give details about the reason for the inquiry.
The PUC staff filing said it is looking to see if it can claim jurisdiction, even though Westar operates only in Kansas. Great Plains operates in Missouri. “Staff maintains that all of the known evidence supports a determination that the proposed transaction is detrimental to the public interest and ought not be permitted to go forward,” the staff said.
EIA Predicts NA Carbon-Free Power to Grow to 45% by 2025
The Energy Information Administration projects that by 2025, energy generation from renewable and nuclear resources will grow from 38% to 45%. Part of the outlook is predicated on the recent agreement between the U.S., Canada and Mexico to attain a goal of 50% by then.
EIA also included energy efficiency in the figures, but it didn’t break out the three resources. It predicted a decline in coal-fired generation of about 13% by 2025 and an increase in natural gas generation by 4%. It noted that Canada has already attained a level of 80% clean energy generation, primarily because of its large hydroelectric capacity.
Mexico’s combined nuclear and renewables should grow to 29% by 2025, EIA said. The outlook assumes EPA’s Clean Power Plan is upheld.
White House Requiring All Agencies to Consider Climate
The White House Council on Environmental Quality last week issued guidance under the National Environmental Policy Act that requires all federal agencies to consider the environmental and climate implications of projects.
The directive requires agencies to quantify greenhouse gas emissions and note the potential climate change impacts of each project during the review process. “This increased predictability and certainty will allow decision-makers and the public to more fully understand the potential climate impacts of all proposed federal actions,” the council said in a statement.
The policy change was first proposed in 2010. Republicans complained that it would allow the Obama administration to institute regulations without congressional approval.
NRC Upholds Entergy’s ‘No Booze’ Policy at Vermont Yankee Plant
The Nuclear Regulatory Commission upheld Entergy’s zero-tolerance rule for alcohol at its Vermont Yankee nuclear plant. The commission’s decision was prompted by Entergy’s 2014 suspension and firing of an employee after unopened bottles of alcohol were found in a private vehicle.
A company panel of managers later overturned the suspension, but a further company review reinstated it. A company spokesman said the zero-tolerance policy extended even to empty alcohol bottles that were headed for recycling. “You can’t even have the perception” of alcohol on site, the spokesman said.
At the time of the violation, the plant, which has since been retired, was in full operation with 636 employees.
NRC Reviewing NextEra’s Plan to Correct Seabrook Concrete Issue
The Nuclear Regulatory Commission is reviewing NextEra Energy’s plan to address concrete degradation issues at its Seabrook nuclear generating station.
The degradation is being caused by an alkali-silica reaction (ASR) in the concrete throughout the plant. It was first discovered in 2009 when Seabrook employees found portions of an underground electrical conduit tunnel degrading. It has since been found in numerous walls throughout the plant.
ASR is a chemical reaction that forms a gel in some concrete mixtures. The moisture-caused reaction forms the gel, which then expands and forms cracks. Approval of NextEra’s plan is critical to NRC issuing a license extension.
FERC last week approved Apple’s application to sell solar capacity at facilities it owns in Nevada, Arizona and California on the wholesale market. The ruling allows it to enter the wholesale market with 20 MW of generation capacity in Nevada, 50 MW in Arizona and 130 MW in California.
“Based on your representations, Apple Energy meets the criteria for a Category 1 seller in all regions and is so designated,” FERC wrote in a letter to Apple attorneys.
Google also has received FERC approval to sell solar capacity into wholesale markets.
Years in the making, a settlement between PJM and transmission owners over the RTO’s procedure for allocating the costs of major transmission projects is receiving criticism from stakeholders that say they weren’t invited to the table.
The case has dragged on for nearly a decade, with FERC’s orders on how to allocate costs for transmission projects at or above 500 kV twice being remanded by the 7th U.S. Circuit Court of Appeals back to the commission.
PJM’s “postage-stamp” cost allocation for the projects was challenged by the RTO’s Midwestern utilities. The method billed all PJM utilities in proportion to their load, regardless of where the projects were located.
The commission had originally approved the postage-stamp method in 2007 and attempted to justify it in its order on remand. The court, however, ruled that FERC had again failed to show how a western utility would benefit as much as an eastern utility from new transmission facilities in the east. (See FERC Orders Proceedings to Decide PJM’s Postage-Stamp Cost Allocation.)
In June, after more than a year of negotiations, a large majority of stakeholders submitted to FERC a settlement that created a cost allocation formula for projects approved prior to Feb. 1, 2013, when PJM abandoned the postage-stamp method (EL05-121).
“The overwhelming majority of the PJM transmission owners and all of the state regulatory authorities that have actively participated in this proceeding are either settling parties or have agreed not to oppose the settlement,” the filing reads.
The agreement would require collecting fees from customers on the eastern side of PJM’s territory and distributing them to customers on the western side. For projects that have been or will be completed, the settlement assigns 50% of costs on a load-ratio-share basis and the remaining 50% under the solution-based distribution factor (DFAX) methodology — the same method used for regional 500-kV projects approved since 2013.
Abandoned or canceled projects would be assigned using the violation-based DFAX method. The charges would be retroactive to Jan. 1, 2016.
Retroactive Issues
The settlement didn’t sit well with Direct Energy and the Retail Energy Supply Association, which argued they were neither invited to participate in the settlement talks through the PJM stakeholder process nor informed that they’d be expected to pay for the result.
On Monday, RESA appealed the denial of a previous motion to intervene in the case. In the appeal, the group stated that the settlement would require its members to pay their allocated share retroactively, “even if the customers who should be billed for the amounts have migrated to another supplier.”
Under deregulation, customers of the load-serving entities that make up RESA’s membership can switch companies quickly, so LSEs aren’t able to pass along retroactive charges to those who’ve left in the interim, the group said.
The denial, written by Acting Chief Administrative Law Judge Carmen A. Cintron, called RESA “a party that is uninformed of the delicate and complex negotiations that transpired in its absence.”
“When entities wait unreasonably long to seek intervention, [FERC] has stated that they ‘assumed the risk that the parties would settle the case in a manner not to their liking.’ Such is the situation that RESA’s delayed request has created for itself,” Cintron wrote.
RESA said it only became aware of the proceedings by reading the published settlement and that its suggested changes would “create minimal, if any, disruptions.”
“This is not a situation where an intervenor seeks to scuttle a settlement,” RESA said.
The group suggested two options to solve the issue: change the date for when charges should go into effect to sometime in the future, or put the burden of recovering the costs on electric distribution companies.
RESA is “hopeful” its new arguments will allow it to intervene, spokesman Bryan Lee said.
Marji Philips of Direct Energy said her company estimates the settlement will cost eastern ratepayers about $287 million.
“The LSEs are going to wind up having to pay for these costs that everybody agreed should be rate-based, and the calculation when it was originally done was done incorrectly,” she said.
Comments Pro and Con
Direct Energy and RESA are not alone in their opposition to the settlement. Linden VFT, which owns merchant transmission facilities, said it would not receive benefits in the settlement commensurate with the costs it would incur. In filed comments, Linden said the solutions-based DFAX method is “unduly prejudicial” to companies like itself.
But many stakeholders filed comments in support of the settlement.
“Pennsylvania’s ratepayers have been unfairly burdened, since 2007, with an excessive portion of those costs associated with the transmission projects encompassed by the settlement,” the state’s Public Utility Commission said. “The settlement agreement resolves those inequities and establishes a more reasonable and equitable cost allocation for both previously incurred costs as well as costs yet to be recovered.”
The PJM Board of Managers has suspended the controversial Artificial Island transmission project pending a “comprehensive” staff analysis to be completed by February, at which time it will decide a course of action, CEO Andy Ott said in a letter to stakeholders Friday.
“It has become evident to all involved that the projected costs to resolve the problems at Artificial Island have increased significantly. PJM has been examining alternatives in an attempt to offset some of the increases,” Ott wrote. “In addition, questions have arisen about whether the currently proposed solution would perform as intended without further expense. Because of these concerns, PJM has come to the conclusion that a pause in the project is necessary before any new financial obligations are incurred by the project developers.
“In light of the current uncertainties around the changing scope and configuration of the project, it is imperative that we understand the basis for any alternatives that may exist to manage the operational issues at Artificial Island.”
Salem and Hope Creek Nuclear Reactors on Artificial Island Source: Wikipedia
This is the second time the board has overturned the stability project — PJM’s first competitive solicitation under Order 1000.
Initially, PJM planners recommended awarding the work to Public Service Electric and Gas, but the board reopened bidding to finalists following protests from spurned bidders, state officials and others. (See PJM Board Puts the Brakes on Artificial Island Selection.)
PSE&G, one of three entities eventually designated to build a 230-kV transmission line from the New Jersey nuclear complex under the Delaware River to Delaware, said Friday it was “committed to working with PJM and will provide PJM with any information and support they request.”
LS Power’s Northeast Transmission Development, picked to construct the transmission line, said Friday it was “disappointed” by the board’s action.
“The modeling errors in question do not relate to Northeast Transmission’s designated portion of the Artificial Island project and Northeast Transmission was not involved [in] the associated modeling activities,” it said. “Northeast Transmission was surprised by the PJM board’s decision, as Northeast Transmission had received no indication prior to the announcement from PJM on Aug. 5 that PJM had any concerns with PJM’s or PSE&G’s modeling of the system protection and control upgrades.”
Pepco Holdings Inc., chosen to work with PSE&G on the project, did not immediately respond to requests for comment.
The board approved the stability fix for the complex that houses the Salem and Hope Creek nuclear generators last summer. But in April, PJM revealed that PSE&G’s portion of the project — which the RTO initially pegged at $137 million — had nearly doubled to $272 million once the transmission owner completed a detailed analysis. (See Artificial Island Cost Increase Could Lead to Rebid.)
“PJM conducted a preliminary estimate regarding the interconnection to Salem,” a PSE&G spokeswoman said Friday. “We then conducted a detailed, design-level analysis of the interconnection to Salem. We had not previously prepared a detailed estimate for Salem because our proposal would have terminated in Hope Creek.” (See PSE&G Defends Artificial Island Cost Increase.)
The sticker shock prompted PJM planners to consider other alternatives, including terminating the line at Hope Creek.
“However, in reviewing this alternative, an issue arose related to one of the other components of the project: that is, whether proposed system protection and control upgrades would perform as intended,” Steve Herling, PJM’s vice president for planning, said in a letter to stakeholders Friday. “Specifically, PSE&G identified an error related to the modeling of circuit breaker clearing times associated with those upgrades. The effect would be a reduction in the margin of stability provided by those upgrades, regardless of any alternatives to the transmission solution under review, requiring further steps and expense to correct.”
In an informational filing with FERC submitted Friday, PJM said, “By virtue of this suspension, all designated entities are placed on notice to cease incurring any new financial obligations on the Artificial Island project until PJM completes its analysis and the PJM board has made a subsequent determination based on that analysis.”
Neither of the letters PJM sent out Friday mentioned the cost allocation controversy.
Delaware Gov. Jack Markell released a statement commending the PJM board for its action.
“This decision is one that the state of Delaware welcomes,” he said. “The project as it was proposed would have placed an unjust burden on the state, resulting in higher electric rates for our consumers and businesses. I hope that upon further review, a more equitable solution can be identified.”
Bob Howatt, executive director of the Delaware Public Service Commission, said the agency was still analyzing the board’s decision.
“It seems like the political and economic concerns may have succeeded in stopping what has been called the most efficient and cost-effective solution because PJM and FERC have failed to address the cost allocation issue,” he said, adding that the decision seemed “totally unfair” to LS Power.
Howatt said he worried what effect the suspension would have on the desire of independent transmission companies to participate in the Order 1000 process.
“If I were an independent transmission company, why would I waste a lot of time on a project that could get overturned?” he said. “I just see it chilling the competitive transmission market that FERC has been attempting to create.”
Exelon announced Tuesday it has purchased the James A. FitzPatrick nuclear plant for $110 million from Entergy.
Officials from both companies were joined by Gov. Andrew Cuomo at the plant’s gates to announce the deal, which is subject to regulatory approval.
“We are pleased to have reached an agreement for the continued operation of FitzPatrick,” Exelon CEO Chris Crane said in a statement. “We look forward to bringing FitzPatrick’s highly skilled team of professionals into the Exelon Generation nuclear program, and to continue delivering to New York the environmental, economic and grid reliability benefits of this important energy asset.”
Entergy executives had reiterated last week that the company did not intend to continue operating the troubled plant in upstate New York beyond January 2017.
“There are no plans to continue to run the plant under Entergy ownership,” Bill Mohl, president of Entergy Wholesale Commodities, told analysts during the corporation’s second-quarter earnings call Aug. 2.
Fitzpatrick Nuclear Plant Source: Entergy
The company had announced plans to shut down both FitzPatrick and the Pilgrim nuclear plant in Massachusetts, but it recently said it had opened negotiations with Exelon over FitzPatrick. (See Entergy in Talks to Sell FitzPatrick to Exelon.)
Mohl told analysts if Entergy and Exelon are able to gain regulatory approvals for the transaction, refueling activities would begin in January. Otherwise, the decommissioning process would begin instead.
“We’ve made a commitment to reduce the size of the EWC footprint,” Mohl said. “If we’re unable to reach commercial agreements with Exelon or we’re not able to achieve those regulatory approvals, we’ll begin the regular decommissioning process and stay on the same path that we have previously been on.”
New York’s Public Service Commission on Aug. 1 unanimously approved 12-year subsidies for the state’s nuclear power plants on Lake Ontario, which have been buffeted by market forces. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
Entergy reported second-quarter net income of $572.6 million ($3.11/share). That beat analyst expectations of $1.05/share, as polled by Thomson Reuters.
Revenue dropped to $2.46 billion, from $2.71 billion in the second quarter of 2015. The company said its March purchase of a 1,980-MW natural gas plant in southern Arkansas helped support revenue during the quarter.
Company shares, up 18.9% this year before the earnings announcement, have dropped 94 cents since, closing at $80.33 on Aug. 3.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week rejected a request to allow economic dispatch of reliability-must-run (RMR) units over the objections of the ISO’s Independent Market Monitor and several of its Houston-area market participants.
NRG Texas drafted nodal protocol revision request 784, which addresses how RMR units are priced and dispatched, about the same time as ERCOT made its recent decision to extend into 2018 an RMR contract for NRG’s Greens Bayou Unit 5 near Houston.
The contract requires ERCOT to pay $3,185/hour for the duration of the agreement and an incentive factor of as much as 10% to reserve the 371-MW gas-fired unit’s capacity during summer months through June 2018. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)
NRG’s request would allow security constrained economic dispatch of RMR units to relieve transmission congestion after all other capacity available for transmission congestion relief had been exhausted.
Market Monitor Beth Garza supported the proposal, which she said would increase the dispatch price of RMR units, allowing other market units to be dispatched to resolve the constraint first.
In ERCOT’s energy-only market, an RMR agreement results from either a poorly designed evaluation process — which mistakenly identifies a resource as needed — or a failure of the market to provide sufficient revenue to justify continued operation of a needed resource, she said.
“Should the failure be in the RMR designation process, the resource is unlikely to be deployed and its energy offer price will be immaterial,” Garza said. “However, if the failure is in the market signal to units in this constrained area, the unit is likely to be deployed and the energy offer price will matter.”
Bill Barnes, NRG Energy’s director of regulatory affairs, said the request underscores the importance of sending the right price signals in the ERCOT market.
“We’re spending $60 million on an RMR contract for the months of June, July, August and September,” he said. “When you look at the State of the Market report for 2015, the real-time congestion rent for three of the major north-of-Houston constraints is $5 million. We’re spending $60 million to solve a $5 million problem. There are legitimate situations where the market solves the problem in a cheaper way. The boogeyman that is high prices gets pummeled by the boogeyman that is RMR.”
As drafted, NPRR784 would only apply when generator offers are mitigated because there is inadequate competition. RMR units are currently subject to the same offer mitigation as other units in such a situation, with Greens Bayou Unit 5 likely being offered at around $50-60/MWh. When there is adequate competition, RMR units are offered at $9,000/MWh under either the status quo or the NPRR.
The revision request would instead require all RMR units to be offered at the highest possible price that would still allow SCED to dispatch the unit for congestion. In Greens Bayou’s case, the estimates are as high as $700/MWh.
The NPRR failed to gain the Protocol Revisions Subcommittee’s endorsement during a roll-call vote July 14, but NRG appealed to the TAC. The revision request eventually fell short of the necessary two-thirds approval, with 54% positive votes and four abstentions.
NRG on Friday filed another appeal with the Board of Directors, which will consider the proposal at its Aug. 9 meeting.
“How do you prevent future RMR? By sending the right price signals,” Barnes said. “The presence of the RMR is evidence the market signal has failed. 784 addresses the most important RMR issue: How do you send the right price signal? It’s not a perfect solution, but is it better than what we have today? We believe the answer is yes.”
Garza supported Barnes’ position, although she also said she is a “huge believer” in ERCOT’s stakeholder process and “what this room can do.”
“Our position has been the objective of the RMR should be the price should be reflective of the unit not being there, but we should have the energy available to resolve the constraint,” Garza said. “It is absolutely a shortage condition. If that situation did not exist, Greens Bayou would be on the way to the scrap heap right now.
“I’m sympathetic to the argument that, ‘Gosh darn it, we spent $60 million on this unit, why can’t we use it?’” Garza said. “However, believe it or not, those are sunk costs … that don’t change if you resolve this situation. When you’re talking about resources necessary to resolve a transmission constraint, there are two factors: the offer price or mitigated offer cap, and the shift factor of the unit on that constraint — the effectiveness of that unit to relieve the constraint.”
“We generally agree with the IMM … but we disagree that 784 as a one-off is the solution,” said Energy Future Holdings’ Amanda Frazier, chair of the PRS. “We’re concerned [NPRR784] is reactionary. It doesn’t address whether Houston prices are high enough to allow RMR. If we pass this, we’re paying for incorrect price signals.”
Katie Coleman, with the Texas Industrial Energy Consumers group, represented the PRS position, arguing NRG’s proposal is punitive to loads, encourages unit retirements by providing scarcity pricing in non-scarcity conditions and prevents the RMR unit from solving other constraints beyond a single transmission line.
“We have concerns about requiring loads to also pay $600-800/MWh to use that unit for the very purpose it was placed under an RMR contract,” she said. “We have concerns about the incentive this creates for a generating company with a fleet of units in a certain area to retire units and get high pricing for its other units. [NPRR784] would require Greens Bayou to be priced at the highest possible price to solve, which would preclude it from solving other constraints in area.”
Noting that the revision request has been classified as urgent, Coleman said that electric retailers are concerned its requested September implementation timeline does not provide enough lead time for Greens Bayou and other generators in the area.
Coleman also noted customers are paying for Greens Bayou only until the Houston Import Project goes into service as early as 2018, when it is expected to solve the region’s congestion issues.
“This NPRR is sending a price signal too late to matter,” Citigroup Energy’s Eric Goff said. “The fact the contract exists is interfering with what would happen had the unit been allowed to retire. It gets to the point of whether there’s a weird incentive here.”
“If you’re a load outside of Houston, I have no idea why you’re not outraged,” Barnes said. “If the load in Houston has a small load-ratio share, I can understand why you would want someone else to solve your problem. We’re an energy-only market. Price signal is everything.”
Shortly after the TAC meeting concluded Thursday, ERCOT posted answers to questions it received from its request for proposals for must-run alternatives to the Greens Bayou RMR contract. (See ERCOT Seeks Alternatives to Houston-Area RMR Unit.)
Committee Discusses July 7 System Outage
ERCOT staff shared its analysis of the July 7 outage of its Energy Management System. The outage lasted 102 minutes and resulted in corrupted data being passed to downstream systems, including settlements and reports. Market participants said they saw a perceived drop-off in load and generation, but their primary complaints were around a lack of information coming from the ISO.
“When these things are occurring, I know ERCOT is scrambling to recover and get the grid stable again,” Barnes said. “From a market perspective, it was pure chaos. Market notices should be crystal clear about what is happening.”
“We just knew something was wrong because of operation notices,” Goff said. “Knowing the extent of the outage would be beneficial to the market.”
“We want to share with you the information we definitively know as quickly as possible,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “The tension we’re trying to balance is how long to hold information back until we can be sure” it’s accurate information.
The problem began at 11:41 a.m., when an operator mistakenly loaded test data into the active system, which corrupted data in the emergency system’s network model. Between 11:59 a.m. and 12:16 p.m., the market’s qualified scheduling entities were instructed to assume constant frequency control. By 1:23 p.m., the data had been corrected and verified, and operations returned to normal.
Corrected prices were posted for the affected SCED intervals, and staff said that it is continuing to evaluate alternatives that may affect subsequent settlements.
Barnes was successful with a second NPRR, dealing with ERCOT’s price-correction process following a SCED failure. NPRR696, which Barnes drafted on behalf of NRG subsidiary Reliant Energy Retail Services, passed with 72% of the vote.
“When the SCED system is not running, inputs grow stale. When it starts back up, things don’t make sense,” Barnes said. “It comes down to whether you believe the last best price, or whatever it spits out.”
NPRR696 establishes a price-correction policy that uses the last good price for settlement until ERCOT no longer requires manual action to stabilize the system. Barnes said that correcting prices for settlement intervals corresponding to the active watch period would give market participants transparency to known prices that reflect the last good SCED execution.
“This policy would extend that last good price for another 15 minutes,” Barnes said. “It could be the last high price or the last low price.”
The TAC unanimously endorsed six other NPRRs, a system-change request (SCR) and revisions to the Nodal Operating Guide (NOGRR), the Planning Guide (PGRR), the Retail Market Guide (RMGRR) and the Resource Registration Glossary (RRGRR).
NPRR738: Excludes from performance calculations intervals when an emergency response service generator is unable to meet its obligations because of transmission/distribution service provider (TDSP) outages.
NPRR747: Proposes new definitions related to voltage profiles, defines various entities’ responsibilities related to voltage support and clarifies that the interconnecting transmission service provider or its designated agent may modify a generation resource’s voltage set point.
NPRR767: Changes the eligibility check for the startup portion of the reliability unit commitment make-whole payment. Resources with lead times longer than six hours may submit a settlement dispute to have their resource-specific startup times considered when determining eligibility for startup costs included in the make-whole payment calculation.
NPRR770: Adds visibility and situational awareness to the market by posting the aggregate number of telemetered resources and their statuses to the ancillary service capacity monitor.
NPRR771: Clarifies that TDSPs must ensure an electric service identifier has been created in ERCOT systems before initiating electric service at a premises, avoiding related transactional, billing and out-of-sync issues.
NPRR774: Removes duplicate language regarding the calculation of seasonal transmission-loss factors.
NOGRR155: Clarifies voltage ride-through performance requirements for all generation resources immediately following a fault, stipulating that they must remain online and connected to the transmission system, and also maintain real power.
PGRR046: Aligns the planning guides with NERC’s TPL-007-1 reliability standard related to geomagnetic disturbances by specifying a process for developing geomagnetically induced system models.
RMGRR138: Removes the requirement for retail electric providers serving pre-pay customers to provide a weekly list of electric service identifiers to Oncor, replacing it with the requirement to provide the prepay list upon Oncor’s request.
RRGRR009: Adds three categories of data: voltage limits for resources’ substation transmission level equipment; geomagnetically induced currents and the presence of blocking devices to allow for the study of any vulnerability attributed to geomagnetic disturbances; and a most limiting single element (MLSE) allowing a resource entity to identify an MLSE on lines it doesn’t own.
SCR789: Updates the Network Model Management System topology processor to add a software tool commonly used by transmission-planning entities in ERCOT.
WILMINGTON, Del. — PJM needs to increase its fees to cover rising expenses and rebuild its diminishing operating reserve, officials told the Members Committee on Thursday.
Staff presented a first reading on five options for revising the administrative rate used to collect fees from members and market participants.
PJM is looking for member approval to increase the rates to $0.41/MWh of load served, up from the current $0.34/MWh. The options presented include a single change to a $0.41 rate, a 2.5% annual increase starting in 2018 through 2023 or an annual $0.01 increase through 2022. The 2017 rate in all options is $0.36/MWh.
A new method is necessary because PJM has been below its authorized operating reserve of $15 million since 2013. Staff had expected to rebuild the reserve to $17 million in 2015. Instead, it saw the reserve fall to $7 million because of lower-than-expected revenues. Although it trimmed expenses by $10 million below budget, to $273 million, it generated revenues of only $269 million.
PJM has changed the way it charges members and market participants several times over the past 20 years.
Before 1999, the RTO charged members a single formula rate based on load served. From then until May 2006, the RTO moved to multiple formula rates based on both load and market activity.
In 2006, PJM added a rider to cover the cost of the Advanced Control Center (AC2), and in 2011 it decreased service category rates by 3%, citing economies of scale. All proposals assume an early retirement of this rider because the debt attached to it will be paid off in September
The Finance Committee is expected to make a recommendation to the Members Committee and Board of Managers at its meeting Aug. 24.
CFO Suzanne Daugherty said she expected the committee to choose an option calling for a 2.5% annual increase from 2018 through 2023, which would restore the reserve to full funding by the end of 2017 and maintain it through 2026.
PJM will return to the Members Committee in September for an endorsement vote. It will then make a filing with FERC with a target effective date of Jan. 1.
(Editor’s Note: An earlier version of this story incorrectly stated that PJM’s expected administrative rate for 2017 will be $0.37/MWh.)
Grid Remains Strong During Recent Heat Wave
PJM canceled maintenance outages for the first time under Capacity Performance rules as the system experienced seven days of hot weather beginning July 21, Mike Bryson, vice president of operations, told the Markets and Reliability Committee on Thursday.
The peak load for the period — 151,882 MW — occurred July 25. That was the RTO’s 13th-highest ever and the highest since July 2011, when PJM set an all-time record of 165,492 MW.
The daily average LMP for July 25 was almost $36/MWh, Bryson said. Forced outages for the period were less than 13,000 MW.
“The transmission system has been very strong on the voltage side,” he said. During the period, however, two 765/345-kV transformers tripped in different parts of the system, causing local congestion.
The Dumont T2 line in Indiana tripped July 21, and the Cloverdale-Joshua Falls line in Virginia tripped July 26 because of storms, Bryson said.
PJM Moves Toward Order 825 Compliance Filing
The MRC approved a problem statement to begin work on compliance with FERC Order 825, which set new rules for RTO settlement intervals and shortage pricing triggers. Staff will begin work at the Aug. 10 Market Implementation Committee meeting to identify and address potential impacts. (See “Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing,” PJM Markets and Reliability and Members Committees Briefs.)
The order requires settling transactions in the same time intervals they are scheduled, priced or dispatched, along with aligning shortage pricing to work in the same intervals. While PJM already incorporates shortage pricing, staff realized the current system requires changes to ensure pricing signals aren’t unnecessarily erratic. The RTO’s problem statement goes beyond the requirements of the order to address these issues as well.
The original language of the final key work activity didn’t sit well with some participants, who were concerned it might open the door for revising the demand curves rather than simply adjusting the pricing intervals within them. The language was updated prior to approval to read: “Develop a new set of steps within the demand curves to be implemented in the final rule, if necessary.”
The debate went on for nearly an hour, leading PJM CEO Andy Ott to weigh in and assure members that the point was to avoid wild price fluctuations, not to adjust the overall rate structure.
PJM’s plan is to smooth out the pricing signals over time so they only trigger shortage pricing when it’s a trend.
“The look-ahead engine looks out over time, and it has to see the shortage for a persistent period of time before it will pass the indicator over to the [real-time schedule] engine,” PJM’s Rebecca Carroll said.
PJM has only had one incident of shortage pricing in recent memory, on Jan. 6-7, 2014.
Susan Bruce, who represents the PJM Industrial Customer Coalition, supported the focus on shortage pricing. Under the current demand curves, she said, consumers can be charged higher prices for a whole hour for a shortage that might last only five minutes.
Work on Fuel-Cost Policy Updates Moves Ahead
PJM market analysis manager Jeff Schmitt presented a timeline for the days remaining before the RTO’s Aug. 16 deadline for making a FERC compliance filing on its fuel-cost policy protocols.
The Market Implementation Committee held a special meeting on July 27 and has another scheduled for Aug. 4. Schmitt said he hopes to have the language updated prior to the committee’s regular meeting on Aug. 10. He asked that any additional feedback be sent to him.
In June, FERC ruled that PJM “lacks provisions for sufficient review of cost-based offers and could permit a resource to submit inaccurate cost-based offers.” It ordered PJM to add to its Tariff and Operating Agreement a requirement that generators submit fuel-cost policies that are approved by the RTO prior to submitting cost-based offers, including a penalty structure for those that file inaccurate information (ER16-372).
Feedback from the MIC meetings will be used to update PJM’s Manual 15. Schmitt said PJM has asked for a Dec. 1 effective date but that implementation of the new language will be based on when FERC responds.
MRC Endorses Manual Changes
Members unanimously approved the following manual changes:
Manual 29: Billing. Clarifications and updates are the result of a regular review.
Manual Changes Clarify ‘Physicality’ of Transactions
MRC members endorsed changes to Manual 18 clarifying the rights and responsibilities involved in auction-specific bilateral transactions. (See “Members OK Clarifications to Preserve ‘Physicality’ of Auction-Specific Bilateral Transactions,” PJM Market Implementation Committee Briefs.)
WILMINGTON, Del. — PJM stakeholders rejected a pair of dueling measures Thursday, leaving a new senior task force to decide whether to reconsider a formula key to calculating nonperformance penalties under the new Capacity Performance rules.
The sector-weighted votes capped more than an hour of heated discussion at the Markets and Reliability Committee that included allegations of political maneuvering and a call for one member to be sanctioned for “ad hominem attacks.”
The debate was sparked by the proposed charter of the Underperformance Risk Management Senior Task Force (URMSTF), an item that had been approved by lower committees with little to no discussion, despite months of controversy over the problem statement that created the group. (See PJM Generator Risk Proposal Faces Resistance.)
In recent task force meetings, however, some members had raised the question of whether the RTO was using an unrealistic number in figuring its performance assessment hour (PAH) charge rate. They worried it would artificially lower penalties in the new regime, under which generators are eligible for bonus payments and exposed to financial penalties depending on their performance. Lowering the penalties, some members argued, would weaken generators’ incentive to perform under the new market model.
Thus ensued speculation over whether such a discussion fell within the task force’s scope.
Calpine Offers Problem Statement
Fearing that the issue might be determined to be beyond the group’s mandate, David “Scarp” Scarpignato of Calpine brought a problem statement to the MRC to ensure the formula would be discussed somewhere.
“PJM had suggested that maybe it could be covered under the” task force, Scarp said. “I had indicated that I wasn’t sure that was the group to cover it because they seem intent on reducing the incentives for performance.”
According to the problem statement, informed by data from the Independent Market Monitor, “The current PAH number used in the denominator of the nonperformance charge rate does not reflect the expected number of PAHs as intended. The use of 30 hours is not adequately supported. The average of the RTO-wide PAH in the last three years was 14 hours, including the 30 hours in delivery year 2013-2014 that resulted primarily from January 2014, an outlier year.
“Too low of an expected PAH value avoids confronting capacity resources with the intended nonperformance disincentives under CP philosophy.”
The penalty nonperformance charge rate is the net cost of new entry ($/MW-day) multiplied by 365 days and divided by the 30-hour PAH value. Thus, if the value were reduced from 30 hours to 14, the penalties would more than double.
Scarp said that he had raised this issue at the last task force meeting.
“People talked at least five minutes about what’s in the scope and out of scope with this charter. There were varying opinions. People for the most part wanted to go past managing the risk and talk about the penalties you’d be exposed to. … If the group is looking at risk, it can’t be only one side, to make CP weaker.”
If the task force is limited to hedging risk, he said, its charter might as well be called the “reduce the CP effectiveness proposal.”
Incentives Key to CP
Dan Griffiths, executive director of the Consumer Advocates of PJM States, said it was important to guard performance incentives.
“If the incentives are, in fact, less, we feel like we are losing ground here,” he said. “That’s the only thing [consumers] got out of this — it’s in the interest of consumers to have strong incentives.
“You can’t quintuple the actual rate, but there is a discussion to be had here.”
Mitigating Risk for Generators
On the other side of the debate was Bob O’Connell on behalf of PPGI Fund A/B Development, who authored the problem statement that begat the task force. PPGI is the parent company of Mattawoman Energy, which is building a combined cycle plant near Brandywine, Md., in Prince George’s County.
O’Connell introduced the initiative in October, saying CP allows companies with multiple generators to offset poor performance with over-performing units but does not allow after-the-fact offsets, such as bilateral trades, that could help smaller generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)
At Thursday’s meeting, he proposed a motion to put off reassessing the PAH charge rate formula until after PJM has submitted an annual informational filing mandated by FERC in approving the charge rate. It was seconded by Jason Cox of Dynegy.
Countered Scarp: “Putting this off into limbo is a terrible thing to do to a fellow stakeholder, and something I have never done.” He accused O’Connell of using “procedural moves to prevent voting on this order” and being “disingenuous,” which elicited a call from O’Connell to have him sanctioned for “ad hominem attacks.” Committee Chair Suzanne Daugherty did not formally act on his request.
Breaking a Rule of Thumb
Indeed, most members prefaced their comments by saying as a rule of thumb, they do not oppose problem statements. It’s highly unusual for them to be rejected.
But after O’Connell’s measure failed with slightly less than 49% approval, members also voted down the Calpine problem statement, which was endorsed by slightly more than 44% of the votes.
Members subsequently approved the task force charter by acclimation.
The votes cut across sector lines, with generators split on the issue but more favoring O’Connell’s motion. The only sector to unanimously support Calpine’s initiative was the End-Use Customers (albeit with one abstention).
Jason Barker of Exelon had provided the “second” needed for a vote on the problem statement.
“The data shows quite strongly that 30 hours … is vastly overstated,” Barker said.
He joined Scarp in criticizing his colleagues for “procedural shenanigans and weak arguments” and encouraged them to put aside politics, saying that no one got everything they wanted out of the CP construct. “Let’s be honest around the table,” he said.
FERC Has Spoken
Some members said they were hesitant to revisit the issue because FERC had approved the charge rate using the 30 PAH hours.
Although the commission approved the 30-hour proposal as a “reasonable approximation of the upper bound” of hours during which PJM is likely to experience emergency actions, it also required the RTO to submit informational filings for five years evaluating the impact of the 30-hour assumption on resource performance. “We also encourage PJM, as it gains more experience under its new capacity construct, to reassess the assumed number of performance assessment hours and file with the commission if it believes a revision is warranted,” the commission said.
Scarp noted that FERC’s order hasn’t stopped stakeholders from questioning other aspects of the ruling, including operating parameters and seasonal capacity. The 30 hours, he said, is an error.
Carl Johnson, of the PJM Public Power Coalition, said, “We do not like to oppose a problem statement — that’s how we got to move forward with the URMSTF and seasonal capacity. But in this particular case, we’re talking about something so specific that FERC gave us a directive on.”
He referenced PJM’s recent experience spending months hammering out consensus on a ramp rate for the CP product, only to have FERC reject it.
“I’m not inclined to use our time on this,” he said. “I don’t want to spend time taking things to them that aren’t going to go anywhere.”
Susan Bruce, of the Industrial Customer Coalition, agreed that the charge rate was a core issue of CP, but she said it was just one and hesitated to approve re-evaluating it without looking at others.
“If you say we can’t talk about those other components, I think it’s a conversation to be had in a vacuum,” she said.
Scarp responded, “If you think that there are other numbers that are incorrect, I’m happy to look at them. I am not redesigning CP in any way. I’m probably one of the few people in the room who has never tried to redesign CP.”
Public policy goals and market efficiency are the topics of PJM’s upcoming Grid 20/20 conference, to be held Aug. 18 in Audubon, Pa., the RTO announced.
Exelon subsidiary Constellation has begun offering residential electricity supply plans in Delmarva Power territory. The company is featuring fixed-rate plans of one or two years with gift cards and no enrollment charge.
Kinder Morgan surveyors are mapping the route of its proposed 2-mile natural gas pipeline, part of the three-stage $86 million Connecticut Expansion Project, through a state forest.
Attorney General Bill Schuette says Enbridge Energy’s application to install more pipeline support anchors is evidence that the company’s Line 5 pipelines under the Mackinac Straits are currently in violation of safety standards, which require pipe-support anchors at least every 75 feet.
The state Supreme Court last week unanimously ruled to block a referendum from appearing on the Nov. 8 general election ballot that could have restored favorable net metering rates to customers. The court ruled that the way the question was formed was “not only inaccurate and misleading, but also argumentative.”
The Public Utilities Commission approved an Energy Efficiency Resource Standard, creating a framework for achieving cost-effective energy savings.
Public Regulation Commission staff have expressed doubt about the public benefits of Public Service Company of New Mexico’s plans to install advanced metering infrastructure (AMI), while eliminating the jobs of the 125 employees who monitor them.
Opponents of a new $1 billion natural gas power plant lost their appeal to the Utilities Commission because they failed to post a nearly $100 million guarantee to cover potential construction delays.
Deepwater Wind has begun installation of the first offshore wind turbines in the U.S. at its project 3 miles off Block Island. The turbines will each rise 589 feet above the ocean’s surface.
The Natural Resources Board last week approved the purchase of nearly 1,000 acres of riverfront property from Xcel Energy, which had planned to build a power plant on the site.
A segment of the long-awaited Tres Amigas transmission project in New Mexico is expected to begin transmitting power to CAISO in early 2017. A company executive confirmed that construction of a 35-mile portion of the line called the Western Interconnect began after FERC approved the project last December and is expected to be completed at the end of the year.
NextEra Energy said it will sell $1.5 billion of equity units to Goldman Sachs, Credit Suisse and Mizuho Securities.
After announcing it would spend $1 billion on wind projects in Iowa, Alliant Energy’s CEO said the company will also consider investing in wind buildout in neighboring Wisconsin.
Dynegy reported a net loss of $800 million for the second quarter this year, compared to net income of $388 million for the same period last year.
PECO Energy has embarked on a behavioral experiment to reduce power consumption by sharing customers’ usage with their neighbors.
South Dakota’s Black Hills Energy has invested more than $10 million during the past three years trimming trees and other vegetation along its electricity lines and intends to spend $10 million more in 2016-17, according to a report approved Aug. 2 by the state’s Public Utilities Commission.
Austin-based Revolve Solar, formerly one of Texas Hill Country’s largest clean-tech companies, has filed for Chapter 11 bankruptcy protection.
American Electric Power purchased a series of solar and energy storage projects in Hawaii from EnSync Energy Systems. Neither AEP nor the Wisconsin-based company put a price tag on the acquisition, but EnSync said the projects were the “major portion” of its investment of $13 million.
The American Petroleum Institute has filed a lawsuit against EPA with the D.C. Circuit Court of Appeals, challenging the agency’s final rule on emissions for new and modified natural gas facilities. The suit says the agency didn’t follow Clean Air Act limitations when developing the regulations.
A federal judge last week sharply reduced the potential fine against Pacific Gas and Electric in its criminal trial over gas pipeline violations related to the San Bruno explosion in 2010, which killed eight people and destroyed 38 homes.
Coming on the heels of a Missouri Public Utilities Commission staff recommendation that the commission should have jurisdiction over the pending $12.2 billion Westar Energy-Great Plains Energy merger, the federal Department of Justice is also looking into the deal.
The Nuclear Regulatory Commission upheld Entergy’s zero-tolerance rule for alcohol at its Vermont Yankee nuclear plant. The commission’s decision was prompted by Entergy’s 2014 suspension and firing of an employee after unopened bottles of alcohol were found in a private vehicle.
The Nuclear Regulatory Commission is reviewing NextEra Energy’s plan to address concrete degradation issues at its Seabrook nuclear generating station.
