FERC last week gave final approval to a NERC reliability standard on protective relays and a preliminary endorsement to rules that would ensure small generators are able to stay connected to the grid during abnormal frequency and voltage events.
NERC standard PRC-026-1 is intended to ensure the use of protective relay systems that can differentiate between faults and stable power swings. The standard applies to all planning coordinators and to generation and transmission owners that use certain load-responsive protective relays (RM15-8).
FERC ordered NERC to develop the standard in 2010, citing findings that the cascading 2003 Northeast blackout was accelerated by relays that tripped facilities because they could not differentiate between dynamic, but stable, power swings and actual faults.
The order told NERC to consider requiring the retirement of such relays. But NERC declined to include a prohibition, saying such a rule “may have unintended negative outcomes for bulk power system reliability.”
“It is generally preferable to emphasize dependability over security when it is not possible to ensure both for all possible system conditions,” NERC said.
FERC agreed with NERC’s argument, saying that two existing reliability standards require covered entities to develop corrective action plans to address relays not covered by the new standard.
Small Generators
The commission also issued a Notice of Proposed Rulemaking that would revise the pro forma small generator interconnection agreement (SGIA) to require generators smaller than 20 MW to “ride through” abnormal frequency and voltage events and not disconnect (RM16-8).
Source: birgstockphoto.com
FERC said its action was warranted by the increase in grid-connected solar PV generation and generator interconnection requests driven by state renewable portfolio standards.
“The commission already requires generators interconnecting under the large generator interconnection agreement to have this capability, and it would be unduly discriminatory not to also impose these requirements on small generating facilities,” the commission said.
The commission cited NERC reports warning that the increasing penetration of distributed energy resources could harm reliability without corrective action. Without the new rule, FERC said, “small generating facilities, in the aggregate or in significant combination, could exacerbate an initial disturbance by tripping offline instead of riding through a disturbance.”
It said small generators now have more ability to ride through disturbances because of smart inverters and a new standard from the Institute of Electrical and Electronics Engineers (IEEE) that allows wider trip settings.
The commission said it was not seeking to adopt specific frequency and voltage ride through parameters. “Instead, we propose to allow for the development of appropriate system-specific standards, which we expect will be based on work by recognized standards setting bodies, such as IEEE.”
FERC also said the NOPR is not intended to interfere with state interconnection procedures and would apply only to interconnections made subject to a jurisdictional open access transmission tariff (OATT).
The new rule would apply to any new small generating facility that executes an SGIA after the effective date of the rule. Comments on the rule change will be due 60 days after publication of the NOPR in the Federal Register.
The General Services Administration, Pepco Holdings Inc.’s biggest customer in the district, joined the chorus opposing Exelon’s revised merger proposal last week while the two companies continued their advertising campaign seeking approval.
In a filing Thursday, the GSA urged the Public Service Commission to reject the companies’ March 7 petition proposing three potential paths to approving the deal, saying none complies with the PSC’s requirement that all settling parties agree. Also making a filing was the Water and Sewer Authority, which told the PSC it would accept only the original settlement agreed to by Mayor Muriel Bowser. The Mid-Atlantic Renewable Energy Coalition reiterated its opposition to the deal, as did DC Solar United Neighborhoods. WGL Energy said it would support the terms proposed by Commissioner Joanne Doddy Fort or Exelon’s proposal to redirect $20 million earmarked for smart grid and environmental programs in the Bowser settlement to rate relief.
Exelon has asked the commission to act by April 7.
IPL Gets less than Half Of Requested Rate Increase
The Utility Regulatory Commission approved a rate increase that will give Indianapolis Power & Light about $30 million in annual revenue, less than half of the $68 million the company requested.
IPL said it is still calculating how the decision will shake out on rates for different customer classes. The final rates must be submitted and approved by the IURC.
The commission also closed an investigation into IPL’s underground transmission and distribution network. A series of underground explosions spurred the investigation. The commission ruled that the company’s network is “basically sound at this time.”
Regulator Admits Withholding Funding From Center ‘Not Brightest Decision’
Geri Huser
Utilities Board Chairwoman Geri Huser said her choice to hold up funding to an energy research center last year was not “the brightest decision” but said she only did it to gain time to gather more information about the project.
Huser said she didn’t think withholding the $4.4 million from the Iowa Energy Center at Iowa State University was illegal, just ill-advised. When criticism of her decision arose, the board released the funding.
She told the state Senate Commerce Committee last week that she was unaware that the center, which promotes renewable energy, might have to close down without the funding.
KCC Delays Decision on Westar Rate Increase Request
The Corporation Commission has delayed a decision on Westar Energy’s request to raise its transmission delivery charge, which allows recovery of the costs of providing transmission. The proposal will add about $4/month to the average residential bill on April 1.
The commission also said staff is currently conducting an independent investigation of the proposal and intends to file a report and recommendation by May 30. If staff demonstrates that all or part of Westar’s request is excessive, the commission said, it may then order Westar to refund its customers.
The annual rate review is receiving additional attention this year because the allocation of costs among different classes of customers has changed, a Westar spokesperson said.
The Public Service Commission has concluded it does not have the authority under state law to approve or deny Duke Energy’s proposed $4.9 billion purchase of Piedmont Natural Gas.
Duke asked for the declaratory ruling in order to reaffirm that no state approval or hearing was needed to complete the Piedmont acquisition. In February, Duke said the purchase would not change its basic corporate structure or how it handles its electricity and natural gas operations.
Republican legislative leaders now want the Public Utilities Commission to decide the fate of net metering, not the state Legislature.
Rep. Nathan Wadsworth, the ranking House Republican on a committee considering a solar bill, released a statement calling for the PUC to “stay the course on net metering, protect existing solar customers, installers and the 400 jobs tied to the solar industry.”
House Republican Leader Ken Fredette told the Portland Press Herald that a “bill this complex” should have been considered earlier in the session and may not achieve its goals of preserving solar jobs.
Advocates say the proposed law could create 800 or so new jobs over five years. The bill aims to grow solar capacity in the state from about 18 MW to 250 MW in five years, or 2% of the state’s power needs.
Controversial New Incinerator Loses Permit for South Baltimore
A permit allowing a controversial waste incinerator to be built in South Baltimore has been declared invalid because construction activity has stopped, developer Energy Answers International was told last week.
The Department of the Environment said the permit expired because there had been no construction activity at the Fairfield site since October 2013. Energy Answers, a New York company that secured the permit in 2010, planned to build a $1 billion power plant that would have burned a fuel derived from solid waste.
The Environmental Integrity Project, an environmental advocacy group, had alerted state and federal environmental regulators last month that it intended to file a lawsuit demanding enforcement of the permit’s terms, which prohibit a pause in construction for 18 months or more.
Gov. Dayton Vows to Veto Attempts to Slow CPP Work
Mark Dayton
Gov. Mark Dayton told a group of students that he would press forward on plans to comply with the federal Clean Power Plan, notwithstanding calls from some legislators to bring efforts to a halt. He said he would veto any attempt to block compliance.
“I’d like to see Minnesota’s dependence on coal eliminated, and I won’t even set a date because I want it as soon as possible,” Dayton said. He noted that the state still gets 44% of its electricity from coal-fired plants, so he said efforts should concentrate on encouraging the development of renewable sources.
The governor received applause from the audience for these statements. But he also said fossil fuels will continue to have a place in the state’s energy portfolio, much to the displeasure of the students listening. “You know, there’s no free lunch on energy,” he said. “Until we create the kind of world that you envision, and more power to you, we’re going to be using fossil fuels, we’re going to be using oil.”
Mississippi Power’s Kemper Project ‘Fleeced’ the Public, Suit Charges
A customer lawsuit accuses Mississippi Power of “fleecing the public” to build the problematic Kemper County coal gasification power plant.
Seafood processing firm Biloxi Freezing & Processing, Island View Casino and Gulfport resident John Carolton Dean allege that Mississippi Power has tried to dodge liability for “fraud and mismanagement.”
The Kemper County plant was intended to be among the first coal-fired facilities to employ state-of-the-art carbon capture technology. Cost overruns have tripled the initial project budget to $6.5 billion and put the plant two years behind schedule. The Public Service Commission recently ordered the utility to issue credits to its 186,000 customers related to the plant’s costs.
A state Senate bill would allow utilities to raise rates annually without going through a protracted rate hearing with the Public Service Commission.
The proposal would allow utilities to submit expenses for the previous year and get immediate reimbursement through rate approval if the expenses were deemed “prudent.”
Opponents of the measure say it strips too much power from the commission. “There’s nothing in this bill to keep rates from going up every year,” said James Owen, acting public counsel. The bill caps annual rate increase to 2% for the first two years and no more than 4.75% for any single subsequent year.
Environmental Groups File Lawsuit Against PRB Energy Development
Environmental groups have filed suit in U.S. District Court in Great Falls, alleging that the U.S. Bureau of Land Management’s plans to allow extensive fossil-fuel extraction in the Powder River Basin are illegal.
The lawsuit says the agency’s plans to allow the extraction of oil, gas and coal would make climate change worse and go against efforts to protect the greater sage-grouse species of bird. The lawsuit is backed by the Western Organization of Resource Councils, the Sierra Club and other groups.
PRC Judge Sides with Environmentalists in PNM Case
A Public Regulation Commission hearing officer sided with an environmentalist group that wants the state’s largest utility to publicly disclose its fuel-supply contract with Navajo Mine Coal Co. for the Four Corners Power Plant.
The issue arose last year when Public Service Company of New Mexico filed for a $123.5 million rate increase, which would boost residential rates by 15.8%. Western Resource Advocates argued that information affecting rates should be open to the public.
PNM has the right to appeal the hearing officer’s order to the five-member commission.
PSC Approves Smart Meters For ComEd in NYC, Westchester
The Public Service Commission approved Consolidated Edison’s plan to spend $1.5 billion over five years to install 4.8 million smart meters in New York City and Westchester County.
Con Ed estimates a net benefit of more than $1 billion from the wireless meters, which it says will also give it the ability to better manage outages and service connections during storms.
The utility will install 3.6 million electric smart meters and 1.2 million gas smart meters starting in 2017.
Gov. Pat McCrory’s office has disbanded the state Coal Ash Management Commission after the state Supreme Court ruled in January that the commission’s appointments were unconstitutional.
The nine-member commission was created to oversee the closure of Duke Energy’s 32 ash ponds in the state following a catastrophic spill of ash-laden water into the Dan River. McCrory, a former Duke Energy executive, last year challenged appointments to the commission.
The commission’s executive director, Natalie Birdwell, resigned after sending an email to legislative leaders on Monday saying she “had just been informed by the governor’s office that the commission was no longer a legal entity.” Days later the commission’s website went dark. The state Department of Environmental Quality said it is fully prepared to implement all ash remediation efforts.
The Office of the Ohio Consumers’ Counsel, the Appalachian Peace and Justice Network and the Ohio Manufacturers’ Association Energy Group on Monday asked the Public Utilities Commission to stay AEP Ohio’s request for a power purchase agreement pending a FERC decision on the matter.
“To protect 1.3 million Ohio consumers from paying non-refundable rates for a power purchase agreement, these proceedings should be stayed while the Federal Energy Regulatory Commission considers a complaint that would require a review of the PPA between affiliated companies,” the groups said in the filing.
The parties pointed to an incident in 2014 in which AEP was allowed to keep $463 million of state residents’ money after the state Supreme Court overturned a PUCO decision approving an unlawful fee collected from consumers while an appeal was pending.
The filing comes as PUCO is reportedly close to ruling on the PPAs. A decision could come by the end of the month, the Associated Press reported Monday.
Oregon Clean Energy Files To Boost Plant by 161 MW
Oregon Clean Energy, which is developing a combined cycle gas-fired power plant in northern Ohio, asked the Public Utilities Commission to increase the capacity from 799 MW to 960 MW.
The original capacity was set after consultation with PJM to take into account the available transmission capacity in the region. But a subsequent study showed that the grid could handle the increased capacity.
The plant is already under construction. It was not immediately apparent how the requested capacity increase would be obtained.
Fitch Ratings has assigned an A+ rating for bonds issued by the City of Lubbock on behalf of its municipally owned electric utility system, Lubbock Power & Light.
Fitch based part of its rating on LP&L’s plan to transition about 70% of its load into the ERCOT market in 2019 and secure medium-term power supply contracts to meet its power needs. A smaller portion of the utility’s system, largely consisting of assets it acquired in 2010 from Southwestern Public Service, will be isolated from the portion connected with ERCOT and will remain connected to SPP.
Fitch said it views the plan as reasonable, given the utility’s other options were more expensive and included building significant additional generation. Fitch cautioned, however, that the power-supply transition involves changes in the utility’s business strategy, requires significant capital investment and has a relatively short implementation timeframe.
State, Dominion and Microsoft Partnering on 20-MW Solar Plant
Terry McAuliffe
The state has agreed to buy power generated by Dominion Virginia Power’s 20-MW Remington solar project, and Microsoft will buy and retire the project’s renewable energy credits.
The agreement helps both the state and Microsoft attain renewable energy goals and provides a steady customer for Dominion. Gov. Terry McAuliffe has announced a goal of getting at least 8% of the energy needed for state facilities from renewable energy in the next three years.
Tenaska had sought to force PJM to restore $1.9 million the RTO deducted from the company for Tier 1 payments between October 2013 and July 2014.
Tenaska alleged that PJM did not have authority to deselect classes of generating sources, such as CTs, from providing Tier 1 synchronized reserves. The complaint said PJM violated its Tariff, the filed rate doctrine and the rule against retroactive ratemaking.
FERC backed PJM’s position that its Tariff gives it discretion to deselect resources from Tier 1 reserves, which can be provided by partially loaded generators able to provide energy within 10 minutes.
It said the RTO made its decision in real-time and not retroactively and that it had experienced performance issues with CTs as a class. The billing adjustments were consistent with the Tariff, PJM said, and exercised because of an error made by PJM Market Settlements.
NRG Energy filed comments in support of Tenaska’s complaint, while the Independent Market Monitor filed in support of PJM.
“We find that PJM reasonably interpreted [its Tariff] as vesting PJM with broad discretion to decide whether a generating resource is capable to reliably provide Tier 1 Synchronized Reserve,” the commission wrote.
FERC said Tenaska’s interpretation of the Tariff would require PJM to procure 4,000 MW to 9,000 MW of Tier 1 reserves, compared to the RTO’s requirement of 2,100 MW.
WASHINGTON — On-peak day-ahead electricity prices in the U.S. were down 27 to 35% in 2015 compared to 2014 largely because of cheap natural gas, FERC staff said in its State of the Markets presentation Thursday. LMPs in New York hit a 15-year low.
Gas prices fell sharply, selling as low as $1/MMBtu, as supply and storage surged to record levels last year, as they did in 2014, while demand only grew slightly. Natural gas production increased to 72.6 Bcf/d from an average of 68.4 Bcf/d in 2014. Storage reached a record high of 4 Tcf in November, almost 11% more than 2014’s high. (See FERC: 2014 a Record-Breaking Year for Natural Gas.)
The increase in supply has led to the addition of 51 Bcf/d in new pipelines in the last five years, with an additional 49 Bcf/d planned or proposed to come online by 2018. Demand for gas, however, grew only 1.3% last year as a result of a mild winter.
As a result of the low prices, gas-fired generation surpassed coal-fired on a monthly basis for the first time in April 2015, and beat coal in six of 11 months through November, according to the Energy Information Administration. Each provided about one-third of all electricity generation.
EIA predicted last week that natural gas will provide 33% of generation in 2016 while coal’s share falls to 32%. PJM’s Independent Market Monitor similarly predicted that gas would surpass coal for the RTO in its 2015 State of the Market report. (See Bowring Urges Return to ‘Fundamentals’.)
FERC staff said they expect the trend of lower gas prices to continue into 2016 but that production has likely plateaued and will decline in the long run, as the low prices begin to push higher-cost producers out of the market.
About one-sixth of U.S. natural gas is a byproduct of oil production, which suffered as prices fell 66% between June 2014 and December 2015. According to the U.S. Bureau of Labor Statistics, the oil and gas industry shed about 17,000 jobs last year, while the U.S. oil rig count dropped by 61%.
“Long-term demand growth for U.S. natural gas will likely come from increased gas-fired electric generation, particularly in the Southeast, growing industrial demand, LNG exports and pipeline exports to Mexico,” staff said.
The price of LNG, which was exported for the first time from Cheniere Energy’s Sabine Pass terminal on the Texas-Louisiana border to Mexico last month, is indexed to oil in most long-term contracts.
LMPs down, Capacity Prices up
The fall in electricity prices was in sharp contrast to 2014, when prices rose across the country, in part due to the severe winter in the Northeast and Midwest.
While LMPs fell, capacity prices rose in PJM and ISO-NE, as the lower gas prices drove out coal-fired and nuclear generators and forced other nuclear plants to rely on capacity auctions for revenue. FERC noted that the clearing price for the Rest of RTO zone in PJM has risen 152.6% since 2013 and more than 200% in ISO-NE for the same period.
“These lower LMPs and higher capacity prices in PJM have resulted in the ‘all-in’ costs of energy, capacity, transmission and ancillary services to increase by 5% between 2013 and 2015,” FERC staff said.
“As the markets are calling for new resources, we’re seeing significant increases in the capacity markets, really stress testing the markets, and … I think ancillary services are going to get a lot more important in the future [to] balance all the interruptible resources,” Commissioner Cheryl LaFleur said.
Electricity demand fell by 1.1% in 2015 as a result of low economic growth and increased efficiency in appliances. Electricity use fell in the industrial sector, while residential and commercial customers showed little or no growth.
DER and Renewable Growth Continues
While the net generation of power plants nationwide has increased 1.2% since 2011, the total electricity sold back by net metering customers has increased by nearly 500%, FERC staff said. Demand response revenues, meanwhile, have also increased through the capacity markets in PJM and ISO-NE for the past three years, a trend FERC expects to continue as a result of the Supreme Court’s decision on Order 745, upholding FERC’s jurisdiction over DR.
Wind continues to be the dominant renewable energy resource in the U.S., rising to 4.6% of total generation. While solar rose to only 1% of total generation in the country, it makes up 13% of installed capacity in California, home to half of the country’s utility-scale solar.
FERC last week declined MISO’s request to reconsider a 2008 refund order stemming from transmission pricing complaints filed by the city of Holland, Mich., and DTE Energy Trading more than a decade ago (EL05-55-003, EL05-63-005).
Proceedings for the case go back to early 2005, when FERC found that MISO had violated its Tariff by charging the Holland Board of Public Works and DTE a higher hourly non-firm point-to-point transmission rate in instances when the utilities redirected the receipt point for their firm point-to-point service within the same transmission pricing zone — but on a non-firm basis. The commission ordered MISO to issue refunds with interest for the difference between the two hourly service rates. The RTO was also required to file accompanying refund reports for Holland, DTE and “other similarly situated customers,” effectively extending refund eligibility to other market participants incurring similar charges.
In May 2008, after conditionally accepting MISO’s 2005 and 2006 refund reports, FERC further ordered the grid operator to refund overcharges for ancillary services associated with customers’ redirect service.
In its rehearing request, MISO contested the ancillary services refund along with aspects of FERC’s earlier decisions. The RTO argued that FERC’s rulings had violated the Federal Power Act on two counts.
First, by directing MISO to refund the charges related to ancillary services, the commission had corrected its order outside the timeframe permitted under the FPA, namely before an appeal had been filed or in advance of the deadline for petitioning for judicial review. MISO also said FERC sought to exploit ambiguities in its refund order by rewriting the methodology associated with the refunds.
Second, FERC’s order directing MISO to issue refunds dating back to 2002 violated an FPA provision barring refunds for periods preceding a complaint filing, MISO said.
MISO further contended that any refunds should be limited to the original complainants, and that calculating and issuing refunds to all affected customers during the period in question will be “time-consuming and costly.” FERC has stipulated a refund period of February 2002 to January 2009.
In denying the rehearing, FERC reiterated that the commission has “authority to go back to the date that the violation first occurred” and its seven-year refund period was “consistent with the refunds previously provided and accepted in these proceedings.”
FERC also said that ancillary services are needed to maintain reliability for transmission service and should be priced accordingly.
“Because these ancillary services were necessary to accomplish transmission service, they are part of any transmission service, including redirect service, and should be priced consistent with the service being provided,” FERC said. “The commission’s general policy is to order refunds for overcharges and for violations of the filed rate.”
FERC last week granted Entergy permission to exclude from its system-wide “bandwidth” calculation the above-market portion of the price paid for electricity under two power purchase agreements with generators certified under the Public Utility Regulatory Policies Act and Louisiana’s Renewable Energy Pilot Program (ER14-1640).
Rain CII’s calcining Plant in Sulphur, LA (Source: Rain CII)
The March 17 ruling came despite a protest from the Louisiana Public Service Commission, which contended it was excluded from the settlement agreement.
The decision does not alter the actual value of Entergy Gulf States Louisiana’s PPAs with the Rain CII Carbon calcined petroleum coke facility in Sulphur and the Agrilectric rice hull-fueled power plant in Lake Charles. Rather, the commission is allowing Entergy to internally “re-price” the contracts to accommodate the “bandwidth” process the company uses to ensure that none of its subsidiaries have production costs 11% above or below the company average.
Supporters of Entergy’s position said the company’s re-pricing approach prevents the costs of local and state policy initiatives — such as renewable mandates — from being exported to other jurisdictions. However, the Louisiana PSC called the re-pricing practice “unduly discriminatory” to Entergy Gulf States Louisiana and its customers, which will incur increased costs to cover the entire above-market portion of the contract prices.
The PSC also called the settlement procedure an “abuse” because it only included parties that agreed with Entergy’s original 2014 filing.
FERC disagreed.
“We note that the settlement, and the proposed revision it approves, establishes a policy that is applicable to all similar renewable energy PPAs entered into by any of the participating Entergy operating companies,” FERC said. The commission added that Entergy entered into the PPAs “to meet the requirements of the [Renewable Energy Pilot] Program for the benefit of Entergy Gulf States Louisiana’s customers, rather than for the benefit of the Entergy system as a whole.”
Under the agreement, WPL will acquire five ATC substations valued at $458,820 in exchange for $370,863 in transmission-related equipment, which include a power transformer, storage batteries, 138-kV line frames and foundations, poles and historical air brake switches. The Wisconsin-based companies said the move will better “align ownership of the relevant facilities by function,” providing WPL new distribution facilities while handing ATC more transmission assets, which will be turned over to the operational control of MISO.
Both companies will pay current net book value for all facilities in cash without an acquisition adjustment. ATC said the transaction will have “virtually no effect on transmission rates,” noting that the difference in value between the assets being exchanged is only a “tiny fraction” of the company’s total net utility plant of $3.4 billion. WPL receives nearly all of its transmission services from ATC.
The city of Alexandria, La., is entitled to collect a MISO-related adder of 50 basis points on top of its authorized rate of return on equity without having to make a request to federal regulators, FERC ruled last week (EL15-75).
Alexandria, Louisiana Skyline
The commission said Alexandria’s petition to implement the RTO membership adder was unnecessary because the city was already eligible to do so under MISO’s municipal generic template, a formula municipal transmission owners can use to derive their revenue requirements. FERC last June directed the RTO to include the adder, which became effective immediately (ER15-1067).
The commission also granted Alexandria’s request to defer adder collection until after a decision on an ongoing complaint against MISO transmission owners (EL14-12). In that proceeding, MISO transmission customers argue that the current 12.38% base return on equity earned by owners should be decreased to 9.15%.
FERC has accepted MISO’s request to terminate a generator interconnection agreement (GIA) with EDF Renewable Energy’s 150-MW Merricourt wind project in North Dakota, eliminating the prospect the facility would be granted additional time in the interconnection queue before completing construction.
FERC said MISO’s interconnection policy is clear in denying such extensions unless a project’s development has been hindered by another project in the queue.
“No such circumstances are presented here, and, even if such circumstances were present, Merricourt could not extend its [commercial operation date more than] three years beyond the original COD,” the commission wrote (ER16-471).
Commissioner Cheryl LaFleur was the sole dissenter in the 3-1 ruling, citing worries that the decision could create barriers for other wind projects.
MISO revoked Merricourt’s GIA after the facility failed to meet a Dec. 1 deadline to begin commercial operations, despite a request to extend the term until Sept. 30, 2017. Merricourt maintained the project was eligible for such treatment because it had completed a significant amount of construction and was close to securing a long-term power purchase agreement. Development hit a snag in 2011 when Xcel Energy withdrew its PPA for the project, but Merricourt said it could bring the wind farm online by the end of this year.
FERC’s ruling pivoted on a narrow reading of the text within MISO’s GIA with Merricourt, particularly a provision permitting the developer to extend the in-service date after demonstrating “significant steps to maintain or restore operational readiness.” The commission ultimately agreed with MISO’s interpretation that the language only applies to a facility that has already begun — and then ceased — operating.
FERC added that keeping the wind project active could be unfair to other projects in the queue.
In her dissent, LaFleur focused instead on Merricourt’s progress with the project, which she said was so advanced that it would not cause harm to other project developers.
“In my view, our precedent provides the commission with clear authority to determine whether a COD extension is appropriate in a given case,” LaFleur wrote. “Here, I believe that Merricourt has both demonstrated meaningful progress towards reaching commercial operation in a reasonable timeframe … and effectively rebutted concerns expressed by MISO that the Merricourt project is speculative and potentially harmful to other customers in the queue.”
MISO has said that Merricourt is free to continue work on the project, which has so far cost about $20 million according to the developer. That will require it to re-enter the queue and obtain a new GIA.
VALLEY FORGE, Pa. — The estimated cost for Public Service Electric & Gas’ portion of the Artificial Island stability fix has nearly doubled, from $137 million to $272 million, PJMtold the Transmission Expansion Advisory Committee on Thursday.
“We certainly were surprised when we first saw the numbers,” Steve Herling, PJM vice president of planning, told RTO Insider. “In retrospect, we wish we’d had more foresight. We’re going to have to take a real hard look at what this tells us about our process going forward. We don’t like making an estimate that’s this far off.”
PJM stands by its selection of the project, which involves building a new 230-kV transmission line from the nuclear complex in New Jersey to Delaware.
“Based on what we have seen so far, we still believe we have the right project,” Herling said. “There are elements of the design that we continue to discuss, and we’re looking for opportunities to further optimize it and mitigate costs, but at this point we still believe we have the right project.”
LS Power was chosen to build the line, with PSE&G and Pepco Holdings Inc. assigned to construct the necessary connection facilities. LS Power won the deal in large part because it committed to limiting construction costs to $146 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)
“LS Power’s cost cap commitment has not changed, and LS Power continues to focus on successful development of its portion of the Artificial Island project,” company Vice President Sharon Segner said.
Paul McGlynn, PJM general manager of system planning, said the cost allocation of the project would remain the same, with the bulk of the price tag being designated to customers on the Delmarva Peninsula.
After Delaware and Maryland regulators and consumer advocates complained about the seemingly disproportionate cost assignment, FERC suspended PJM’s Tariff changes involving the project’s cost allocation pending additional review (EL15-95).
Herling said the Artificial Island project is unique and there was little to compare it to.
“This is the first time we’ve had to deal with so much work inside of a nuclear station,” he said. “We did our best to add substantial adders … but in some areas they weren’t big enough,” he said. “I don’t know how PJM could have done better with that other than doing more extensive detail design work,” which would be expensive and time-consuming, he said. “We will be talking about that, as far as how to do things differently moving forward.”
The Board of Managers, which approved the Artificial Island project, reviews cost increases but does not need to approve them unless the scope of the project is altered, Herling said.
“We review all significant changes with the board. They will ask us questions. They will ask us to get more information. They may suggest alternatives that we should be looking at. At the end of the day, we will do everything they ask us to do, and hopefully they will be satisfied with the information.” But, Herling said, “If the project continues in the [Regional Transmission Expansion Plan], the board does not have to approve revised costs.”
The board could decide to switch to another project, but that’s not likely, Herling said.
PSE&G’s portion of the project consists of three main elements: installing a static VAR compensator (SVC) at the New Freedom substation; putting in optical ground wire (OPGW) for high-speed relaying; and expanding the Salem substation. Herling noted that the SVC and OPGW work were common to all proposals and that any vendor likely would have run into the same cost issues.
The SVC work, which PJM estimated at $38 million, is expected to cost $43 million more, according to PSE&G, in part because of additional site work including wetland mitigation, storm water management and the relocation of a helicopter pad and several buildings. PSE&G also ran into higher vendor cost estimates, McGlynn said.
Additional site work for the OPGW installation increased PJM’s estimate of $25 million by $14 million.
The Salem expansion, estimated at $74 million, will cost an additional $78 million, in part because of the cost differential for security and access requirements needed to work in a nuclear facility.
“We understood that working in Salem would be more challenging than working at a 500-kV substation in the middle of a cornfield someplace,” McGlynn said. “What we’re trying to look at and consider and get a better understanding of is the difference in cost.”
A number of committee members were incredulous.
“Percentage-wise, this is a big miss as far as what we thought we were looking at,” said Dave Mabry, representing the PJM Industrial Customer Coalition, noting that there are no cost commitments involved in the PSE&G work, all of which is considered an upgrade as opposed to a greenfield project.
“We were at $250 million … now we’re up to $350 million,” Mabry said. “The concern here is, is there another shoe that’s going to drop?”
The Utility Regulatory Commission approved a rate increase that will give Indianapolis Power & Light about $30 million in annual revenue, less than half of the $68 million the company requested.
The Corporation Commission has delayed a decision on Westar Energy’s request to raise its transmission delivery charge, which allows recovery of the costs of providing transmission. The proposal will add about $4/month to the average residential bill on April 1.
The Public Service Commission has concluded it does not have the authority under state law to approve or deny Duke Energy’s proposed $4.9 billion purchase of Piedmont Natural Gas.
A permit allowing a controversial waste incinerator to be built in South Baltimore has been declared invalid because construction activity has stopped, developer Energy Answers International was told last week.
A customer lawsuit accuses Mississippi Power of “fleecing the public” to build the problematic Kemper County coal gasification power plant.
A Public Regulation Commission hearing officer sided with an environmentalist group that wants the state’s largest utility to publicly disclose its fuel-supply contract with Navajo Mine Coal Co. for the Four Corners Power Plant.
The Public Service Commission approved Consolidated Edison’s plan to spend $1.5 billion over five years to install 4.8 million smart meters in New York City and Westchester County.
Oregon Clean Energy, which is developing a combined cycle gas-fired power plant in northern Ohio, asked the Public Utilities Commission to increase the capacity from 799 MW to 960 MW.
Fitch Ratings has assigned an A+ rating for bonds issued by the City of Lubbock on behalf of its municipally owned electric utility system, Lubbock Power & Light.
Proceedings for the case go back to early 2005, when FERC found that MISO had violated its Tariff by charging the Holland Board of Public Works and DTE a higher hourly non-firm point-to-point transmission rate in instances when the utilities redirected the receipt point for their firm point-to-point service within the same transmission pricing zone — but on a non-firm basis. The commission ordered MISO to issue refunds with interest for the difference between the two hourly service rates. The RTO was also required to file accompanying refund reports for Holland, DTE and “other similarly situated customers,” effectively extending refund eligibility to other market participants incurring similar charges.
VALLEY FORGE, Pa. — The estimated cost for Public Service Electric & Gas’ portion of the Artificial Island stability fix has nearly doubled, from $137 million to $272 million,