ALBANY, N.Y. — New York regulators on Thursday refined their rules on how municipalities can aggregate customers to purchase gas and electricity and rejected a request that the program abandon its opt-out structure (14-M-0224).
| Wikipedia
The New York Public Service Commission’s Community Choice Aggregation program is part of the state’s Reforming the Energy Vision initiative to encourage the greater use of cleaner and distributed energy resources. The CCA was approved in April, building on a pilot program that was still being organized but did not fully launch until June. (See NYPSC OKs Municipal Aggregation for Energy Purchases.)
Opt-In vs. Opt-Out
The commission rejected complaints that the CCA program is premature. “Given the potential benefits of CCA programs, and the continued operation of retail energy markets while the commission considers further action, delaying the authorization of CCA programs is unnecessary and even potentially harmful,” the order said.
Thursday’s order denied National Fuel Gas Distribution’s request to switch the CCA from an opt-out to an opt-in process. The company said the PSC should require customers to opt into the program because uncertainty exists over the development of the retail market.
In an opt-out program, all customers are enrolled and, after an outreach program run by the municipality is launched, customers are required to notify it if they want to remain with the host utility.
“If we required opt-in, we’d be killing this idea before we gave it a fair chance to succeed,” Commissioner Gregg Sayre said at the PSC’s Thursday meeting.
“Our experience in the retail market and in other states is that the opt-out is necessary for CCA programs to be successful,” Assistant General Counsel Ted Kelly said. New Jersey’s aggregation program failed to gain traction until it switched from the opt-in model, he said.
New York City Wins Clarification
The commission also granted New York City’s request for clarification that the original order did require the CCA to be implemented citywide. The commission agreed with the city that rolling out a new program in large geographic areas with dense populations would prove unwieldy, allowing the city to introduce the changes in stages.
The PSC said the CCA order was intended to provide municipalities flexibility. “Allowing municipalities to implement CCA programs on a partial or phased basis is consistent with this design. Municipalities may choose a partial or phased approach as a pilot of CCA, to manage the implementation process given a large geographic footprint or overlapping jurisdictions, or for another reason beneficial to their program,” the commission said.
The commission also clarified that each implementation plan submitted by a municipality or CCA administrator will be open to public comment and said utilities can exclude customers’ phone numbers from data sent to municipalities, bowing to privacy concerns. The PSC said a multicounty CCA has been proposed by the Municipal Electric and Gas Alliance to eventually serve roughly 500,000 residents in 11 counties from the Finger Lakes to the Hudson Valley.
Westchester Pilot Operating
Meanwhile, the state’s first pilot program, by Sustainable Westchester, has been operating for three months, officials said.
The pilot, dubbed Westchester Power, has about 91,000 customers in more than 20 municipalities. Westchester Power has negotiated to buy electricity at a bulk, fixed price and started enrolling customers in June.
LuAnn Scherer, acting director of the PSC’s Office of Consumer Services, said the commission asked Consolidated Edison to provide an early glimpse of consumer reaction. The company sampled about 1,500 customers. While savings are not guaranteed, customers have saved an average of $10/month in the pilot program, Scherer said.
She said the program has received 14 complaints, mostly related to customers misunderstanding some line items on their new utility bills.
“One of the lessons is that municipalities are going to have to do more for customer education,” Scherer said.
Sustainable Westchester’s first report to the PSC is due in June 2017.
“It’s early, but at least we know we’re headed in the right direction,” PSC Chair Audrey Zibelman said.
Commissioner Diane Burman – who opposed the original CCA order, saying a statewide rollout was premature – abstained Thursday. “While my concerns still are there, I do embrace working through them in a robust way on the work ahead,” she said.
FERC last week rejected MISO’s attempt to exempt external generators from interconnection milestone payments, saying the fees should be applied equally to all classes of customers (EL16-12, et al.).
MISO had exempted from its M2 milestone payments external network resource interconnection service (E-NRIS) customers and NRIS-only customers. NRIS allows a generator to deliver power over MISO’s grid with the same rights as any other network resource. E-NRIS service allows generators outside the RTO to participate in capacity auctions and deliver their output into the system.
MISO said the M2 payment should not be assessed to E-NRIS customers because it is intended to deter speculative projects and is refunded once a generator begins commercial operations. E-NRIS customers are either in-service, under construction or have an executed interconnection agreement with the transmission provider to which they directly interconnect.
MISO’s position was challenged last year by EDF Renewable Energy, E.ON Climate & Renewables North America and Invenergy, which contended the RTO’s policy created a competitive disadvantage for new internal generation, which is required to make the milestone payments.
In its order last week, FERC said MISO’s defense that the M2 milestone payment was only needed to deter speculative projects was unconvincing.
“To the contrary, we find that the reduction of late-stage terminations and the resultant restudies, as well as the mitigation of potential cost increases to lower-queued customers due to any restudies, are equally important goals of the M2 milestone payment,” the commission said.
“We find that it is just and reasonable that all interconnection customers post the M2 milestone payment in order to protect other customers from the potential harm that any interconnection customer may cause by a late-stage withdrawal,” it added.
FERC gave MISO 30 days to make the Tariff changes and set an April 5, 2016, refund date.
In a separate order, the commission also rejected MISO’s request for rehearing on the basis that existing and external customers are not “similarly situated” to other interconnection customers and forcing them to pay the milestone payment would be fraught with “practical difficulties” (EL15-99, et al.). FERC said its April order “only found that it may be unduly discriminatory to exempt existing generators” and did not constitute a final determination, so it could not be challenged.
LITTLE ROCK, Ark. — SPP’s Strategic Planning Committee on Thursday endorsed the Competitive Transmission Process Task Force’s recommendations for improving the competitive solicitation process for transmission projects under FERC Order 1000.
SPP’s first run-through of its transmission owner selection process resulted in the award of a competitive project, only to have the project’s notice-to-construct (NTC) withdrawn in July because of falling load projections.
The task force recommended raising the minimum threshold for competitive projects from $100,000 to $3 million, seating the selection panel sooner and requiring it to quickly publish its selection criteria. It also said SPP should allow restudy requests before an NTC is issued. The SPC unanimously approved all the recommendations.
The SPC also approved using a consistent template for annual transmission revenue requirement (ATRR) responses, based on the expected rate recovery under the SPP Tariff.
Much of the remaining work will be handed off to other stakeholder groups and SPP legal staff, who will draft the revision requests, revise business practices, prepare FERC filings and revise the ATRR template. The finished products are scheduled to be brought to the Markets and Operations Policy Committee in January.
The task force’s chair, Bill Grant of Southwestern Public Service, said the group discussed a higher threshold before settling on $3 million. SPP Director Harry Skilton proposed a $5 million threshold, with the idea that FERC would accept a lower number.
“The risk in starting out with a high number is that FERC flat out rejects it and sends it back to you,” Sunflower Electric Power’s Tom Hestermann said.
Board Chair Jim Eckelberger said he was comfortable with the lower $3 million threshold, assuming it’s “defendable.”
“I think that number is defendable, because that’s what we’re going to spend just to seat the [selection] panel,” Grant said, referring to the $300,000 projection to train and seat the industry expert panel (IEP). A company bidding on competitive projects is required to put down 10% of the project’s cost — $300,000 for a $3 million threshold.
Grant said seating the IEP early in the solicitation process and requiring the panel to publish its scoring criteria as early in the process as possible would allow transmission companies to submit more focused bids, reducing potential cost variances.
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The task force determined developing “a more robust” ATRR template that includes special modeling needs for various business models would negate the need for a standard, regionwide formula rate. The template will include incremental costs specific to the RFP project.
“My biggest concern is not the highway projects this will be applied to. My biggest concern is with the byway projects,” Grant said. “When you evaluate based on incremental basis, everyone’s on the same playing field.”
The withdrawal of the NTC on SPP’s first Order 1000 project, a 115-kV line from Walkemeyer to North Liberal in southwest Kansas, led to the recommendation that the solicitation process be suspended to allow for re-evaluations in the case of a significant load change. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)
“Under the Tariff, the developer had to get an NTC before it could be re-evaluated,” Grant said. “If there’s been a substantial change, we don’t want to have to wait to go through the RFP process and get an NTC.”
FERC last week agreed to consider whether the failure of some power sellers to file compliant price reports contributed to unreasonably high rates for long-term electricity contracts filed during the Western Energy Crisis of 2000-2001 (EL02-71-052).
| FERC order EL02-60-007, April 12, 2016.
The case, which involves Shell Energy North America, TransCanada Energy, Koch Energy Trading, Allegheny Energy Supply, Merrill Lynch Capital Services and other sellers of energy and ancillary services into the CAISO market during the crisis period, was remanded to FERC last year by the 9th U.S. Circuit Court of Appeals (12-71958).
FERC’s decision breathes life into California’s contention that reporting deficiencies may have helped conceal market manipulation and create a “pricing umbrella” under which California’s Department of Water Resources was compelled to sign overpriced contracts near the conclusion of the crisis.
“We agree with California parties that evidence regarding a pricing umbrella theory could be relevant to the 9th Circuit’s instructions on remand to examine the nexus between reporting deficiencies, market power and market outcomes, including evidence of how reporting deficiencies may have masked manipulative behavior by sellers,” the commission wrote.
The California parties — which include the Public Utilities Commission, Attorney General Kamala Harris, Pacific Gas and Electric and Southern California Edison — asserted that the sellers’ quarterly reports did not meet requirements during the crisis period because they contained no hourly transaction detail or any information on the timing or location of the trades. The reports provided only aggregate quarterly or monthly sales data along with a range of prices, the parties contended.
As a result, FERC will allow California to introduce relevant evidence at a future hearing — evidence that could “provide greater context and depth” into the examination of factors that enabled sellers to charge the state exorbitant rates.
Mobile-Sierra Caveat
Embedded in FERC’s ruling, however, was one important qualification: that the commission disagreed with the state’s contention that evidence of a reporting violation alone could overcome the Mobile-Sierra presumption of the “justness and reasonableness” of any of the bilateral contracts at issue.
“The Mobile-Sierra analysis requires more than just an unlawful act,” the commission said.
In support of that determination, the commission cited the Supreme Court’s 2008 decision in Morgan Stanley Capital Group Inc. v. Public Utility District No. 1 of Snohomish County, which stated that a contracting party’s engagement in unlawful activity in the spot market does not automatically strip its forward contracts of Mobile-Sierra protections.
“We find that the California parties’ argument, if accepted, would require us to abrogate the contracts at issue based solely on an unlawful act itself (i.e., the misreporting), without the required causal connection between an unlawful act and an unjust and unreasonable rate, as required by the Supreme Court,” the commission wrote.
In the words of the 9th Circuit, the commission concluded, the purpose of the remand is to determine whether “reporting deficiencies fostered the subtle accumulation of market power and resulted in an excessive rate.”
LITTLE ROCK, Ark. — Heather Starnes, counsel for the Missouri Joint Municipal Electric Utility Commission, briefed the Strategic Planning Committee on Thursday on the work that the Billing Determinant Task Force she chairs has done in developing a business practice for behind-the-meter generation.
The task force has produced a revision request (BRR158) that sets guidelines to determine a customer’s network load and define the parameters for what should be considered BTM generation.
However, the Regional Tariff Working Group remanded the change back to the task force in June to address SPP’s request to delineate responsibility for reporting network load. With the consolidation of SPP’s legacy balancing authorities into one, Starnes said the RTO has been having difficulty gathering complete zonal information from the transmission zones’ lead transmission owners.
“SPP’s position is they would like to see something created that mimics what it did before we created the consolidated balancing authority,” she said.
Under the revision, network load would include all network service, including the sum of generators’ metered values behind the delivery point. If the generator’s meter data is not available when it’s online, network customers would use its nameplate rating.
Starnes said the task force meets later this week and hopes to send BRR158 back to the RTWG for final consideration.
LP&L Task Force Looks at Precedent
SPC Chair Mike Wise, senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative, encouraged the task force studying the migration of Lubbock Power & Light’s load to ERCOT to identify any strategic implications of the municipality’s exit. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
“This is an entirely new study process,” he said.
“Certainly there are broader implications beyond just Lubbock,” said Oklahoma Gas & Electric’s Jake Langthorn, the Exit Study Task Force’s chair. “It’s kind of an absence of facts … no one’s given much more thought at this point to what happens, but we’ll certainly pursue that as well.”
SPP and ERCOT are conducting separate studies on LP&L’s proposal to move 430 MW of load into the Texas market in June 2019. The grid operators will file a joint report to the Public Utility Commission of Texas next spring, though it has yet to be determined who will pay for the studies.
“Where’s Lubbock?” one member asked pointedly. PUC Chair Donna Nelson has said she doesn’t believe ERCOT ratepayers should pay for the studies, a sentiment shared in ERCOT.
“I didn’t get the sense from anyone in the group that SPP should pick up the costs,” Langthorn said. “We believe the party that wants to get it done, Lubbock, should pick up the costs.”
Judge Recommends Pause To TEP’s Rooftop Solar Plan
An administrative law judge has recommended that state regulators defer approval of Tucson Electric Power’s plans to expand company-owned solar energy programs pending findings of a separate proceeding on the value of rooftop solar.
As part of a renewable energy plan filed last year, TEP wants to expand a program in which it installs solar panels on the roofs of customers who pay a flat monthly fee for power. It also seeks to build neighborhood-scale solar farms and offer nearby customers the power at a flat rate.
Judge Jane Rodda found that expansion should wait until the results of technical studies and potential modifications to net metering tariffs are known.
SolarCity Spent $140K on Corporation Commission Election
SolarCity last week disclosed that it has spent $140,000 on an independent campaign to re-elect Republican Bob Burns and elect Democrat Bill Mundell to the Corporation Commission.
The commission is expected to decide as early as 2017 the rate structure for utility customers who generate some of their own power through solar. The disclosure comes as the commission debates whether to force Arizona Public Service, which is fighting net metering in the state, to disclose how much it spent to influence the election of two Republicans to the commission. Burns has issued a subpoena to APS for its records, but the state attorney general has said that would require a majority vote from the commission.
Mundell and fellow Democrat Tom Chapin have said they would deliver the necessary votes if elected. But Mundell last week lamented the spending on both sides. “I wish everyone would stay out of the race,” he said.
SoCalGas Down to Final Safety Tests at Aliso Canyon
Southern California Gas is nine safety tests away from reopening its Aliso Canyon natural gas storage facility in Los Angeles, which it shut down in October 2015 following a massive methane leak.
The state Division of Oil, Gas and Geothermal Resources must approve the company’s safety testing of 114 wells at the facility before SoCalGas can request authority to resume injecting fuel into the field.
Twenty-seven wells have passed all safety tests, nine await results and 78 are temporarily out of operation, according to a report issued by SoCalGas in early October.
Environmentalists May Receive $72K ‘Interveneor’ Award in San Onofre Case
Environmentalist group Friends of the Earth could receive $72,000 for participating in the investigation of the San Onofre nuclear plant failure, making it the most recent recipient of so-called “intervener” funds. If approved by the Public Utilities Commission, the award would be significantly less than the $483,503 the group sought.
The commission has awarded more than $600,000 to participants in the case, which is the subject of a criminal investigation into improper contacts between regulators and utility executives.
The intervenor compensation program awards money to groups that contribute meaningfully to commission decisions. The program is funded by utility companies, which pass the cost along to customers.
‘Wiring Error’ Blamed for Flare-Off at Torrance Refining
| Source: Torrance Refinery
A “wiring error” associated with an ongoing equipment upgrade project in the South Bay has been blamed for a flare-off last week at Torrance Refining and a power outage affecting some 100,000 Southern California Edison customers.
Torrance Refining was shut down and partially evacuated, according to the Torrance police and fire departments.
Power was restored to the affected customers in parts of Gardena, Hawthorne, Hermosa Beach, Manhattan Beach, Redondo Beach and Torrance.
Committee Recommends Monterey County Join Power Collaborative
Monterey County’s alternative energy and environmental committee took initial steps last week to take local control over electric power purchasing from Pacific Gas and Electric and promote renewable energy.
The committee recommended that its Board of Supervisors sign a resolution to join the Monterey Bay Community Power agency. The agency calls for a collaborative, including Santa Cruz, Monterey and San Benito counties, which would combine their purchasing power to increase renewable energy in their portfolio and use savings from lower-cost power to invest in renewable energy projects.
If the board approves the resolution, the county could start developing a governing joint powers authority agreement and address financing.
Villages Agree to Joint Defense, Confidentiality for Power Line Fight
| Source: Wikipedia
Five villages bordering the Elgin-O’Hare Expressway are fighting a proposed Commonwealth Edison power line project and have agreed to individually approve a joint defense and confidentiality agreement.
Leaders in Schaumburg, Elk Grove Village, Hanover Park, Roselle and Itasca claim that the West Central Reliability Project, which calls for a transmission line stretching about 9 miles between substations in Bartlett and Itasca, would lower property values and create unpleasant views without serving their residents and businesses.
ComEd spokesman David O’Dowd said he wasn’t familiar with any precedent for similar agreements.
Residents overpaid more than $125 million for power for the 12 months ending in May 2016, according to an annual report issued by the Commerce Commission.
Residents of municipalities that contracted with alternative electrical suppliers other than Ameren and Commonwealth Edison rarely saved money.
Customers who used alternative carriers overpaid an average of $57 more per year, compared with rates offered by ComEd, the report found. Ameren customers using alternative providers largely broke even depending upon where they lived in the state.
Covanta will receive $562,000 in Pittsfield Economic Development funds to upgrade its solid waste-to-energy and recycling facility to meet state and federal environmental standards and remain profitable.
The Pittsfield City Council approved the funds to pay for a state-mandated recycling enclosure and upgrades to Covanta’s fossil fuel boiler.
Covanta, which had announced in July that it planned to close the facility, will sign a four-year contract extension with the city until June 2020.
Regulators Approve Shutdown of Xcel’s Coal-Fired Generators
State regulators approved last week Xcel Energy’s plans to shut down its coal-fired Sherco plant by 2026 but rejected the company’s plan to build a large gas-powered generation plant on the site as a partial power replacement.
The Public Utilities Commission asked Xcel to explore renewable energy options in conjunction with its proposed gas plant. The commission also told Xcel to consider more demand-side management.
The Sherco plant generators are the state’s largest emitters of greenhouse gases.
Community solar took a step forward last week when the Public Service Commission approved Ameren’s proposal to build one, and possibly two, 500-kW solar arrays, which could provide residential and small business customers with up to half their energy.
Ameren has indicated that it will not begin construction on the first array until it is fully subscribed.
“I think it sends a very good signal to industry and consumers that utilities are starting to invest more in renewable energy, and are allowing customers to invest in it also,” said Caleb Arthur, chief executive officer of Missouri Sun Solar and president of the Missouri Solar Energy Industries Association.
Data company Switch filed a September application with the Public Utilities Commission seeking to bypass middle-man NV Energy when it powers a new industrial center it is building in Storey County.
Switch wants to go competitive and have a choice in the energy market, according to Adam Kramer, executive vice president of strategies.
The company, which powers all its facilities with 100% renewable energy, is presently in litigation against the Public Utilities Commission and NV Energy over a ruling denying its application two years ago to leave the utility.
Voters Seek to Invalidate Energy Choice Ballot Question
Two voters filed suit in Carson District Court to invalidate a ballot question intended to deregulate the state’s energy market regardless of whether voters approve retail choice on Nov. 8.
The question “directs the Legislature to enact legislation providing for the establishment of an open, competitive electricity market by not later than July 1, 2023.”
The lawsuit claims that the ballot question improperly binds the Legislature and governor by mandating they enact specific legislation.
Four protesters carrying food, water and sleeping bags locked themselves inside the Algonquin Incremental Market Project pipeline for 16 hours last week at a worksite near the Indian Point nuclear power plant.
The protest, which coincided with Columbus Day (or Indigenous Peoples’ Day), showed solidarity with groups like the Standing Rock Tribe, which is protesting the Dakota Access oil pipeline.
Regulators Predict Decrease In Natural Gas, Energy Prices
| Source: Public Service Commission of Wisconsin
State regulators predicted natural gas and electricity will be cheaper this winter compared with recent years.
The average residential electric customer will pay 14% less than the five-year winter average, while gas bills will be 10% less, according to an analysis by the Public Service Commission.
Notwithstanding, the commission predicts heating bills will be slightly higher this winter compared with last year because of last year’s unseasonably warm weather.
Developers are expected to build some 4 GW of commercial-scale solar panel capacity in the state by the end of the decade, up from 559 MW this year, according to a report issued last week by Bloomberg New Energy Finance.
The report predicts that by 2020, solar power will cause a $2.58/MWh price drop during peak hours in the state’s west hub.
“Just having this new influx of daytime energy production is going to bring down energy prices on average during the day,” said Nicholas Steckler, an analyst at BNEF.
Regulators Approve $15.6M Decrease for Electricity Customers
The Public Service Commission approved a $15.6 million rate decrease for Rocky Mountain Power’s electricity customers after the utility beat forecasted fuel and electricity costs. The overall rate decrease is 0.8%, which includes about $6.84 in annual savings for a typical residential customer.
Iberdrola Offers to Pay for Favorable Wind Project Vote
Iberdrola Renewables has offered to pay 815 registered voters in two towns $14.1 million over 25 years if a wind project consisting of 24 turbines that would generate 82.8 MW of power wins voter approval on Nov. 8.
Iberdrola is seeking to build the state’s largest wind project on land spanning Windham and Grafton.
The offer does not violate state law, said Michael O. Duane, senior assistant attorney general. “The proposal doesn’t say that the funds go only to those people who signed a sworn statement that they had voted for it,” he said.
For the first time in the U.S., state residents will vote in November on whether to levy a carbon tax on polluters for the greenhouse gases they produce.
The proposed tax would start at $15/ton beginning in July and jump to $25 in 2017. Incremental increases would follow.
A La Crosse County judge heard arguments last week on whether to uphold state approval of a high-voltage power line with a $580 million cost that will be passed on to MISO ratepayers.
The 180-mile line is a joint venture of American Transmission Co. and several regional utility companies. It was not presented to the state as a project necessary to meet supply demand, but rather as one that would make the electric grid more resilient and ultimately save ratepayers millions of dollars.
The town of Holland argues the project violates state law because the need for it was not established, the environmental review was insufficient and existing poles should be used to route it through the town.
The U.S. Army Corps of Engineers is holding off on work for the $3.8 billion Dakota Access oil pipeline in southern North Dakota while it examines whether to reform how tribal views are considered for such projects.
Last week, the corps issued a joint statement with the Justice Department and Interior Department calling upon pipeline owner Energy Transfer Partners to voluntarily stop work on private land around Lake Oahe. The statement came in the wake of a ruling by the D.C. Circuit Court of Appeals that allowed construction after the Obama administration halted it.
Officials “look forward to a serious discussion … on whether there should be nationwide reform on the tribal consultation process for these types of infrastructure projects,” the statement said.
At a summit in the Rwandan capital of Kigali on Saturday, more than 150 countries sealed an agreement to phase out the use of hydrofluorocarbons (HFCs), potent greenhouse gases used as refrigerants.
Under the agreement, most developing countries will be required to begin their plans by 2019 and freeze their HFC levels by 2024. Developed nations, including the U.S., will be required to begin by 2024. The European Union adopted a measure to reduce its HFC emissions in 2014.
HFCs were designed to replace chlorofluorocarbons, which were phased out under the 1987 Montreal Protocol because of the damage they caused to the ozone layer. Secretary of State John Kerry hailed the Kigali agreement as a “monumental step forward” and said it would avoid as much as a half degree Celsius of global warming.
The U.S. federal government made its largest ever purchase of renewable energy Friday when it signed a power purchase agreement for the 150-MW Mesquite 3 solar power station in Maricopa County, Ariz. The power from the desert solar array will supply one-third of the power demands of 14 naval installations in California, including San Diego’s naval base and the Marines’ Camp Pendleton.
The Navy will buy the power at a fixed price for 25 years from owner Sempra Energy. “To me, the essence of solar power is, you know what the price of the fuel is going to be for the next 25 years, or more,” said Dennis McGinn, the Navy’s assistant secretary for energy, installations and environment. “It’s going to be reliable, it’s going to be cheaper than what we’re paying for brown power and it just diversifies our energy sources for these bases.”
The Energy Department says the growth of large-scale solar plants in the Southwest is a result of $4.6 billion in investments it made as part of the stimulus legislation passed in the wake of the 2008 financial collapse.
FERC Chairman Norman Bay on Monday announced the appointment of Judge Suzanne Krolikowski as an administrative law judge.
Krolikowski has served as an ALJ for the Social Security Administration since June 2015. She received her bachelor’s in civil engineering from the Massachusetts Institute of Technology and her law degree and a master’s degree in ecology from the University of North Carolina at Chapel Hill.
“I am pleased to welcome Judge Krolikowski to FERC,” Bay said. “Her legal and technical background and experience is impressive and will [be] an asset to the FERC bench.”
LITTLE ROCK, Ark. — The SPP Markets and Operations Policy Committee endorsed a 41% increase in a delayed 345-kV project along the Red River in southeastern Oklahoma as reasonable and reset the project’s baseline.
American Electric Power was supposed to have upgraded a pair of substations and built 76 miles of transmission line between Valliant, Okla., and a substation outside Texarkana, located on the Texas-Arkansas border, for $131.7 million. That total has grown to $185.8 million following a two-year delay attributed mostly to weather. The project was supposed to be energized in October 2014, but that date has now slipped to December 2016.
AEP’s Brian Johnson said the company was late to notify SPP of the delay because of internal communication problems between project management and those reporting costs. He said the company didn’t realize how far the project was outside its bandwidth until July, calling the situation “embarrassing.”
The company attributed 51% of the cost overruns to extensive flooding along the 76-mile route. The project was also hampered by siting problems and a landowner group’s opposition. “It was a combination of everything,” Johnson said.
The Project Cost Working Group, which reviews projects when updated cost estimates fall outside a 20% bandwidth, passed the recommendation on to the MOPC with a no vote from Kansas City Power & Light and two abstentions.
SPP Regional Entity: Wind Farms not Meeting New Standards
SPP Regional Entity General Manager Ron Ciesiel said wind farms unfamiliar with new NERC standards for reactive power, voltage controls and frequency caused a spike in reported reliability violations during the third quarter.
| SPP
There were 71 violations of the MOD-025-2 (Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability), PRC-019-2 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection) and PRC-024-2 (Generator Frequency and Voltage Protective Relay Settings) standards, most of them by individually registered wind farms.
“The only good news is they aren’t operating problems,” Ciesiel said. He said the violations resulted from wind generators’ lack of awareness with the new standards’ implementation plan and a shortage of third parties to conduct testing. Only 40% of the generation units covered by the new standards had their capability tested or settings verified by July 1, when the standards took effect, Ciesiel said.
The RE expects to report more than 200 violations this year, a number it hasn’t topped since 2011.
Ciesiel said 33 new or revised standards will take effect over the next 12 months.
Members Vote to Cancel 69-kV line in West Texas
The MOPC approved staff’s recommendation to withdraw a notice-to-construct (NTC) for the Hobart City-Roosevelt Tap-Snyder 69-kV line in West Texas, based on the availability of an AEP operating guide that can mitigate the congestion through pre-emptive redispatch.
The project was one of five withheld from the 2016 Integrated Transmission Plan (ITP) Near Term portfolio to determine whether they were needed to solve Scenario 5, which assumes renewable energy operating at 100% capacity.
Staff found while there have been 17 hours of congestion in the area since 2014, the 2017 ITP 10-year study indicated there were no congestion hours or future needs for the project, which had an estimated cost of $31 million.
Southwestern Public Service’s Bill Grant abstained from the vote, saying he did not want to live with operating guides forever.
The committee also endorsed staff’s recommendation to accelerate the NTC for an Oklahoma Gas & Electric 345-kV circuit upgrade project, but to leave a SPS 230-kV circuit upgrade in West Texas as is.
SPP staff said OG&E’s Amoco–Sundown project is necessary to meet additional congestion expected from more than 300 MW of wind energy added to the system this summer. With more wind energy on the way in Oklahoma, staff pushed the project’s in-service date to April 2018, a year earlier than originally planned.
The Market Working Group brought five revision requests to the MOPC, which approved all over a small handful of no votes and abstentions. The committee unanimously approved 10 more changes as part of its consent agenda.
A revision request concerning the triggering of shortage pricing (MWG-MRR175) generated the most discussion among members — some concerned over sudden price spikes, others over a lack of scarcity events. The change incorporates language to comply with FERC Order 825 by using shortage pricing for any interval in which energy or operating reserves are short during the resources’ pricing. The change applies to any shortage, regardless of the duration or its cause. (See FERC Issues 1st RTO Price Formation Reforms.)
“Price spikes that occur over certain intervals can wipe out the entire day,” Nebraska Public Power District’s Paul Malone said. “There doesn’t seem to be any discussion about what can be done to mitigate this stuff. You can’t respond to a $500 price spike over five-minute intervals.”
The MWG recommendation was pushed for approval this month because it is a compliance matter. SPP staff and the group will both continue working to improve the process.
“We’re going to go back and see if we can make it better,” said Richard Dillon, SPP’s director of market design. “Scarcity pricing … is becoming more prevalent in the industry. We’d like to take a second look and see if we can do something better than the industry.”
“This will happen,” said AEP’s Richard Ross, chair of the MWG. “We are motivated to do something else, and staff is motivated to do something else.”
The motion passed with three no votes and two abstentions.
Golden Spread Electric Cooperative cited Order 825 in opposing a related change, (MWG-MRR173), which replaces the terms “head-room” and “floor-room” with “instantaneous load capacity.” Golden Spread said procuring rampable capacity for instantaneous load change, hourly load forecast or variable resource output through reliability unit commitment “masks shortage conditions in a manner inconsistent with the requirements of FERC’s shortage-pricing rule.”
Other rule changes approved by the committee were:
MWG-MRR183: Updates the violation relaxation limits (VRLs) operating constraint based on staff’s annual analysis, allowing additional redispatch to solve cases with fewer violations. Golden Spread abstained.
MWG-MRR188: Gives staff the option to include up to 100% of instantaneous load capacity (as opposed to the current 0% of capacity) in clearing the day-ahead market, an effort to minimize the gap between day-ahead and real-time energy prices. The motion received nine abstentions.
MWG-MRR193: Adds rules for solar resources to the market protocols and Tariff, including incorporating a solar forecast in SPP studies, increasing the solar forecast’s accuracy and including solar resources in dispatchable variable energy resource registration. Nebraska Public Power District cast an opposing vote, contending behind-the-meter generation would be required to register in the market should their loads change and they end up injecting power onto the system.
BPWG-RR123: Removes obsolete language and clarifies SPP’s current practices for short-term service requests and the system impact study process.
MWG-MRR178: Specifies that SPP’s Market Monitoring Unit will review the costs included in each mitigated resource offer, on an ex-post basis.
MWG-MRR179: Aligns the protocols with FERC-approved language (ER15-2265) ensuring long-term congestion rights are not affected by potential resource hub terminations, and that resource hubs used in bilateral contracts can’t be unilaterally terminated by the hub’s owner.
MWG-MRR181: Corrects outdated references in the Tariff and protocols related to the allocation of annual auction revenue rights, an oversight noted by FERC (ER16-13).
MWG-MRR182: Removes the term “control area,” which is no longer used by SPP, from the market protocols.
MWG-MRR184: Exempts resources from charges when they clear the day-ahead market with real-time meter readings of zero following either decommitment by SPP or dispatch to zero.
MWG-MRR185: Clarifies which document — SPP Planning Criteria or SPP Operating Criteria — is referenced when used in the market protocols and Tariff.
ORWG-RR168: Requires transmission owners to provide the highest available emergency ratings and specifies SPP’s interpretation of those ratings.
RTWG-RR176: Corrects and clarifies the responsibilities and requirements under the process that allows generation resources to be compensated for reactive support.
TWG-RR174: Revises Attachment AQ of the Tariff to no longer require transmission customers to submit a request for changes in delivery point facilities without a corresponding change in load.
Members of MISO’s Board of Directors last week expressed support for increasing their pay and relaxing their independence requirements, saying the changes were needed to ensure the RTO can attract strong candidates.
Directors at an Oct. 14 conference call of the board’s Corporate Governance and Strategic Planning Committee indicated support for MISO’s proposal to prune the current two-year pre- and post-service prohibition on affiliations with RTO members, affiliates and market participants.
MISO first proposed reducing the prohibitions in August with three options: eliminating the rule entirely, reducing it to one year, or reducing the pre-service restriction to one year and eliminating the post-service one. The directors chose the third option.
The board had postponed action on the service restrictions at its September meeting. (See “For Now, MISO Bylaw Changes Minimal,” MISO Board of Directors Briefs.)
MISO Managing Senior Corporate Counsel Corrie Bilke said the pre-service restriction in MISO’s Principles of Corporate Governance is in line with other RTOs, but only MISO mandates a post-service restriction.
“Initially I was in favor of a post-service restriction, but after reviewing [other RTOs], I’m comfortable with eliminating the post-service restriction,” Director Phyllis Currie said.
“We are competing for talent. It seems like we shouldn’t place ourselves at a competitive disadvantage,” Director Paul Feldman said. He also said MISO should include language forbidding sitting board members from engaging in job interviews with prohibited entities.
Bilke said three MISO sectors that responded to a call for feedback on the proposed changes were supportive. After all members have weighed in on the changes through stakeholder meetings, the entire board will review the proposal at its December meeting.
MISO Proposes Upping Director Compensation
The committee also voted to approve a proposal by a consulting firm to increase board member compensation by $4,000 annually.
“We want to remain competitive in our compensation of board members,” MISO Vice President of Human Resources Greg Powell said.
Willis Towers Watson recommended increasing the director retainer from $55,000 to $89,000 while eliminating meeting fees for the first six scheduled board meetings and two annual strategic retreat meetings.
The firm also recommended eliminating board committee fees in return for a $9,000 committee retainer for the first six meetings with compensation of $2,000 for each additional meeting.
MISO should keep its director and committee chair retainers at $15,000 and $7,500, respectively, Willis said.
Board members’ total compensation would increase to $116,000 from $112,000. Committee chairs would be paid $124,000, up from $120,000, and the board chair would be boosted to $131,000 from $127,000.
Under MISO’s Transmission Owners Agreement and bylaws, the consulting firm’s recommendations will be enacted unless two-thirds or more of the members vote to reject them. No date has been set for a vote.
WASHINGTON — The Nuclear Regulatory Commission’s Inspector General last week issued his annual report on the agency’s most serious management and performance challenges, highlighting concerns over cybersecurity, reactor inspections and licensing.
The report, which summarizes previous audit findings, noted that “challenges do not necessarily equate to problems.”
“These challenges represent what [the Office of the Inspector General] considers to be inherent and continuing program challenges relative to maintaining effective and efficient oversight and internal management controls,” IG Hubert T. Bell said. “As a result, it is likely they will continue to be challenges from year to year.”
In addition to regulating about 100 commercial nuclear power generators and 31 research and test reactors, the commission is responsible for overseeing the safe use of radioactive materials used in medicine, academia and industry.
The IG cited the “increasing risks” to the security of NRC information systems and urged the agency to continue its efforts to develop new regulations for the “unique requirements of decommissioned nuclear power plants, which present different security considerations than operating plants.”
Bell cited concern over the commission’s Network Security Operations Center (SOC), staffed mainly by contractors, which is responsible for ensuring the security of the agency’s networks and monitoring it for suspicious activity. The commission’s contracts do “not clearly define SOC performance goals and metrics” and different departments work with different security function descriptions, the IG said.
NRC Operations Center | NRC
The result, as detailed in an audit in January, is confusion among NRC staffers and contractors about which policies and responsibilities govern the security work protecting NRC computer systems.
Another audit in March found the commission failed to collect identification cards from one-third of the 1,452 employees and contractors it terminated from 2014 through November 2015. “As a result, there is a risk of unauthorized physical access to NRC and other federal facilities,” the IG said.
The report also cites the IG’s second review of NRC’s response to the Reducing Over-Classification Act of 2010, which was enacted over concern that excessive classification increases information security costs and improperly limits public access to information.
The IG found that the commission had implemented the recommendations from a 2013 audit and said a review of NRC classification actions from April 2013 through January 2016 “revealed no systematic misclassification.” However, it said the agency “lacks a cohesive approach to records management of classified information” and has not reviewed classified records for disposition and declassification as required.
Other previous findings cited by the IG included:
A call for improving NRC’s licensing of Advanced Passive 1000 (AP1000) pressurized water reactors, a new design for which operators have never been licensed. Four AP1000 reactors are under construction in the U.S. and about 70 licensed operators will be required by 2020.
A risk of inconsistent reactor inspections because of a lack of clarity in the definition of mandatory and discretionary inspection procedures.
A finding that NRC lacked “a well-structured approach” for enforcing regulations governing the conditions under which licensees may make changes to their facilities or procedures, and conduct tests or experiments, without prior NRC approval.
Weaknesses in NRC’s process for determining the significance of reactor inspection findings. The IG said the the agency has not regularly evaluated resources needed for its Significance Determination Process workflow and has not communicated clear expectations to employees.
As part of a renewable energy plan filed last year, TEP wants to expand a program in which it installs solar panels on the roofs of customers who pay a flat monthly fee for power. It also seeks to build neighborhood-scale solar farms and offer nearby customers the power at a flat rate.
Community solar took a step forward last week when the Public Service Commission approved Ameren’s proposal to build one, and possibly two, 500-kW solar arrays, which could provide residential and small business customers with up to half their energy.
Four protesters carrying food, water and sleeping bags locked themselves inside the Algonquin Incremental Market Project pipeline for 16 hours last week at a worksite near the Indian Point nuclear power plant.
A La Crosse County judge heard arguments last week on whether to uphold state approval of a high-voltage power line with a $580 million cost that will be passed on to MISO ratepayers.
