That was the question Independent Market Monitor Joe Bowring posed during his Year in Review presentation at PJM’s Annual Meeting last week, setting off a lively debate with one of the consultants that Richard and Kevin Gates, enlisted in their high profile defense against market manipulation allegations.
“If the rules are imperfect, is it OK to do anything not explicitly prohibited?” Bowring asked.
He quickly provided his own answer. “It is not permissible,” he said, citing what he called the “duty” of market participants to inform RTO officials and federal regulators of such “money trees.”
Bowring referred to PJM’s poorly designed rules on rebating excess line losses, which allowed the Gates brothers’ Powhatan Energy Fund and a handful of other traders to profit through what the Federal Energy Regulatory Commission later called riskless, back-to-back up-to-congestion trades. The rules were later changed. The Gates brothers and their associates — despite stopping the practice after being warned by Bowring — are now facing up to $29.8 million in fines. (See FERC Staff Seeks $30 Million Fine in Powhatan Case.)
“Almost all of the market knew these opportunities existed and chose not to take advantage of them,” Bowring said. “That raises the question: Who’s the smartest guy in the room? The guy who took advantage or the guy who didn’t?”
That brought a response from consultant Roy Shanker, who is quoted on the Gates’ brothers’ website criticizing FERC’s case. “It’s really unfair to have an ill-defined affirmative obligation to do something,” Shanker said.
On the website, Shanker says he believes the Gates and their associates “were simply engaging in rational economic decision making.” He rejected FERC’s contention that the trades were riskless “wash trades.”
In response to Bowring, Shanker cited traders that schedule power deliveries through the IMO interface with Ontario’s Independent Electricity System Operator. Bowring has identified the interface as a location where traders can manipulate PJM’s pricing rules by breaking transactions into multiple “back-to-back” transactions, a practice he has called “sham scheduling.” (See Monitor Gives Lukewarm Review to PJM ‘Sham Scheduling’ Fix.)
“It may be a money tree or there just may be [ambiguity] about the rules,” Shanker said. “We know that ambiguity is out there. It sits like a heavy stone on everyone.”
“When you find something, [the RTOs should] identify it, post it and try to change the rules,” Shanker said. “Because you can’t hit every [possibility] that doesn’t mean that you do not try to address some.”
“Would you be supportive if we proposed such [an affirmative obligation] rule?” Bowring asked.
“Yes,” Shanker responded.
He later explained that he would support “the coupling of an affirmative obligation on market participants” with a “safe harbor” that would protect traders from manipulation charges as long as they stop activity of concern after being specifically warned. “Then it is up to RTO or IMM to act to clarify or change rules,” he said, adding that he was speaking for himself and not the Gates brothers.
Andy Ott, senior vice president for markets, said he, too, would support such a rule. As long, he said, as it was not seen as an “inoculation” for traders that have done something not explicitly listed.
The state is offering a cash rebate of up to $3,000 to buyers of electric cars. An incentive program offers customer rebates and will provide dealers with bonuses for selling electric or hydrogen vehicles. The incentive program is funded by $1 million that the state received as a condition for approving the 2012 merger of Northeast Utilities and NStar into Eversource Energy.
The funds are enough to offer rebates for as many as 457 electric or hydrogen vehicles. The program will allocate $800,000 for cash rebates and $200,000 for dealer bonuses.
The state has 1,625 electric vehicles registered as of May 18. The rebates are available to state residents, businesses and municipalities that buy or lease electric vehicles. Fifteen vehicle models qualify.
Boston-based consumer advocacy group Acadia Center and Eversource Energy are sparring over a state bill that would cap fixed-rate charges to customers of electric utilities. An Acadia report found that more than half of Eversource’s customers would see their electric bills decrease if the legislation, which would cap fixed-rate charges at $10, is approved.
Eversource argues that more than half of its customers would see an increase in their overall bill if the fixed charge is lowered and that a $10 fixed charge is more regressive than a $19.25 fixed charge. Daniel Sosland, Acadia’s president, said the utility is misleading lawmakers. An Eversource spokesman said the company stands by its analysis of the legislation’s impact.
A statewide electricity purchase pool, as an alternative to Delmarva Power & Light’s standard offer, is unlikely to bring customer savings, and costs could be higher under some scenarios, according to a state consultant advising against the idea.
Exeter Associates reported the conclusion after a nationwide survey of aggregation programs. State lawmakers called for a study last year.
However, state officials could consider other options, Exeter said, including allowing customers to specify shares of electricity from renewable power sources or options that let customers specify peak use times.
Delmarva has about 260,000 customers who subscribe to the company’s standard offer.
Opposition Against Exelon-PHI Merger Grows as Comment Window Nears Close
A fifth councilmember came out Friday against Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., expressing “serious concerns” about the deal in a letter to the district’s Public Service Commission. The 27th of the district’s 40 Advisory Neighborhood Commissions formally opposed the deal.
The district is the last entity to decide on the merger, which Maryland regulators narrowly approved on May 15 and Delaware approved several days later. Public comment in the district closes May 27. (See Update: Md., Del. PSCs OK Exelon-Pepco Deal.)
“While it is clear that this merger would provide great benefit to PHI shareholders, the benefits to ratepayers do not appear proven or clear,” Councilmember Brianne Nadeau said.
Should the commission approve the merger, she said, members should consider using the proposed Customer Incentive Fund to support development of renewable energy sources for low- and fixed-income residents.
The Public Utilities Commission won’t reconsider its controversial decision to cut $38 million in proposed funding from an energy efficiency program. The commission’s 2-1 vote means that funding the Efficiency Maine Trust will fall to the legislature. The trust subsidized the purchase of 2.5 million energy-efficient light bulbs for consumers last year and helped more than 3,000 businesses convert to energy-saving equipment.
The PUC voted in March not to provide the funding for the trust, after a close review of language in the 2013 energy law showed that a single word was missing, apparently as the result of a clerical error. On Wednesday, PUC Commissioners Mark Vannoy and Carlisle McLean argued that petitioners for reconsideration had not brought forward additional information to support changing the panel’s March 17 decision.
Bowie homeowners are beginning to take advantage of a solar cooperative purchasing program sponsored by the city and Maryland Sun, a renewable energy nonprofit organization.
Thirteen residents have signed contracts, 18 are considering proposals and 12 have site visits scheduled, said Maryland Sun program director Corey Ramsden.
At 157 committed members, Bowie is the largest collective the group has created in the state. It has 27 similar co-ops running in Maryland, D.C., Virginia and West Virginia.
A union representing 1,900 Eversource Energy workers in the state has authorized its leaders to strike over stalled negotiations on a new contract. The current contract expires at midnight on June 1.
The Utility Workers Union of American Local 369 said its members voted “overwhelmingly” to allow the strike if its leaders so choose. The union said in a statement that Eversource and the union have been unable to agree on provisions about staffing, health care and the possible elimination of a no-layoff clause.
Minnesota Power’s Great Northern Tx Line Gains OK from PSC
The Public Serivce Commission approved Minnesota Power’s certificate of need for its 500-kV Great Northern Transmission line, a crucial step in the estimated $710 million project. The 220-mile line would deliver hydro power from Manitoba to northeastern Minnesota.
A separate route permit is pending. So is a permit from the U.S. Department of Energy to approve the cross-border line.
Legislation that would pave the way for an orderly sale of Eversource Energy power plants was pulled from the House floor at the last minute last week. The bill would set the stage for a “universal settlement” on a variety of utility issues that would affect customer rates. Eversource has proposed to sell its power plants, but who would pay for the losses that would be incurred is a sticking point. (See Eversource to Sell New Hampshire Plants.) Some legislative leaders also are concerned the bill would pre-empt an ongoing review of electric rates by the Public Utilities Commission.
South Jersey Gas last week filed an amended application including “new details” with the Pinelands Commission seeking approval for a 22-mile pipeline that would carry natural gas to a power plant in northern Cape May County.
The proposed pipeline, which would largely follow a roadway through part of the protected, 1.1 million-acre Pinelands Forest Management Area, has been criticized by conservationists and four former governors. The Pinelands Commission blocked it last year in a 7-7 vote.
But the project is heavily supported by Gov. Chris Christie, who since then has replaced a long-time advocate on the commission with a new member, Robert Barr, who has not disclosed his position on the project.
With the retirement of the Oyster Creek nuclear plant in 2019, PJM and the state Department of Environmental Protection have said that repowering the B.L. England plant — which would use natural gas instead of coal — is necessary to retain reliability on the grid.
The New York Power Authority has approved a contract with about 560 workers from the International Brotherhood of Electrical Workers, including about 215 at the Niagara Power Project in Lewiston. The deal is retroactive to April 2011, when the previous contract expired, and runs through March 31, 2019.
The contract includes wage increases for each year starting in 2014 and requires the union members to increase their contributions to the cost of their health insurance. The wage increases are 3.5% in 2014, 2% in 2015 and 2016 and 2.5% in 2017 and 2018. IBEW members who have been working at NYPA since the expiration of the previous contract will receive a $4,000 lump-sum payment; others will receive a pro-rated payment.
Heavy winter snow caused ground-mounted photovoltaic panels at a large solar farm in Feura Bush to collapse. The 4.5-acre facility is owned by Constellation Energy, which sells power to an Owens Corning insulation plant next door. Owens Corning has said that the farm will be able to offset the costs of about 6% of the factory’s electricity needs. None of the panels went offline during the winter but all need to be remounted for optimal position.
New York State Electric & Gas filed for an increase in electricity delivery charges that would add about $8 to the average residential customer’s monthly electric bill. The increase would cost consumers about $126 million. NYSEG said it needs the increase to help pay for an expanded program to manage vegetation along the 35,000 miles of electric lines it maintains across its upstate service territory. The company also is seeking to recover more than $260 million in restoration costs that it incurred during storms such as Sandy in 2012. State regulators would review the proposal over the next 11 months, with the earliest effective date in May 2016.
FirstEnergy Heading to Hearings on Income Guarantee
Hearings begin in June on FirstEnergy’s request for an income guarantee for seven plants in the state, a case that already has generated thousands of pages of filings with the Public Utilities Commission.
Under the plan, the plants would be guaranteed enough income to cover costs plus a profit. Consumers would make up the difference if the actual income fell short; if the plants exceeded their targets, customers would receive credits.
The FirstEnergy plan affects Davis-Besse Nuclear Power Station, the coal-fired W.H. Sammis plant and the company’s share of jointly owned coal-fired plants.
PUCO has rejected similar proposals from American Electric Power and Duke Energy, but it said their underlying concept was legal.
More layoffs will be coming soon for Murray Energy because of low prices and demand for the coal it mines, its CEO said last week. The St. Clairsville company operates 13 mines in West Virginia, Ohio, Illinois, Kentucky and Utah.
“We had 8,600 employees until last month. We’ve had to reduce some since then. I can’t keep all those jobs,” Robert E. Murray told a gathering of the North American Coal Bed Methane Forum.
Coal prices are down about 10% from a year ago. Murray blamed low demand on environmental rules and cheaper natural gas.
“If I had to describe today’s coal industry … I call it extremely dangerous,” he said. “Not from a safety standpoint, from survival.”
PUC OKs PECO’s Updated, Pricier Long-Term Upgrade Plan
The Public Utility Commission approved PECO Energy’s updated long-term gas infrastructure improvement plan, which is expected to cost the Philadelphia-based company more than $534 million and take two decades to complete.
The two-year-old plan was amended earlier this year, in part to speed up the replacement of at-risk natural gas mains. While those pipelines make up just 12% of the entire system, they are responsible for nearly all of PECO’s leaks.
Under the proposal, spending on upgrades would jump from $34 million to $61 million by 2018. Total costs would rise from the initially forecast $371.3 million to $534.4 million.
Rhode Island Fast Ferry has been awarded a 20-year contract to operate a specialized boat for the construction and maintenance of a five-turbine wind farm that Deepwater Wind will install in waters near Block Island starting this summer. The new vessel will transport workers to and from the offshore wind farm, which will be the first of its kind in the U.S. The company will spend $4 million to build the boat and train crew members to operate it. It is expected to be ready to provide crew and equipment support in spring 2016 in advance of the installation of the turbines for the Block Island Wind Farm.
Fearing Levee Breach, Entergy Shuts Down Hydro Plant
Entergy took its Lewis Creek units 1 and 2 offline Saturday night in order to lower reservoir water levels and reduce the risk of levee failure.
“This is absolutely the right decision for the protection and safety of Montgomery County residents and the long-term reliability of the plant,” said Sallie Rainer, CEO of Entergy Texas. Company and MISO officials said that taking the two 271-MW units offline will not result in any immediate reliability issues.
On Thursday, Entergy Texas notified local authorities of the potential for a failure due to heavy rainfall that saturated the earthen dam near Willis. The company is hauling in truckloads of limestone rock to stabilize the base of the levee.
3 Down, 2 to Go in Wisconsin Energy-Integrys merger
The Public Service Commission last week finalized its approval of Wisconsin Energy Corp.’s $9.1 billion acquisition of Integrys Energy Group.
The Federal Energy Regulatory Commission and the Michigan Public Service Commission previously signed off on the deal. The Wisconsin PSC had only indicated verbal approval.
That leaves regulators in Illinois and Minnesota next to give their blessings. Any drama likely would come from Illinois, where Chicago Mayor Rahm Emanuel late last year asked the state Commerce Commission to reject the acquisition.
Southern Co. and three Missouri utilities say that MISO has billed them more than $21 million in excessive transmission rates since Entergy joined the RTO in December 2013.
In a complaint filed Wednesday with the Federal Energy Regulatory Commission, the companies accuse MISO of imposing a “massive and unlawful increase” for power moved over the Entergy system (EL15-66).
Long-term, firm point-to-point transmission service rates under the Entergy OATT vs. MISO OATT.
It alleges MISO shifted and reallocated sunk costs and network upgrade costs from its legacy region in the Midwest to Entergy export customers in the South. The companies allege the allocations violate MISO’s Tariff and FERC findings that — with the exception of certain multi-value projects — point-to-point export services are provided under a no-cost-sharing rule.
Bringing the complaint are Kansas City Power & Light’s Greater Missouri Operations Co., The Empire District Electric Co., Associated Electric Cooperative Inc. (AECI) and five Southern Co. affiliates: Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power.
MISO spokesman Andy Schonert said that FERC is already litigating these issues in docket EL14-19, a section 206 proceeding it initiated in February 2014. “These claims are not new,” he said. “We are reviewing the legal arguments and plan on responding.”
FERC began that case to investigate MISO’s proposed regional “through and out” rate. AECI complained that most legacy customers would be charged a zonal rate based on the facilities in their zone. Thus, the co-op argued, it and other customers would be forced to pay rates based on both the MISO and Entergy footprints after the Entergy integration into MISO.
The case was consolidated with others involving challenges by stakeholders in the South over what Entergy should be able to collect in rates as part of MISO. Many of those disputes have been under settlement talks over the last two years. Last week, FERC terminated settlement procedures and set the matter for hearing.
‘First of its Kind’
At the heart of the new complaint is the no-cost-sharing provision in MISO’s Tariff that, according to plaintiffs, acknowledges the historical lack of coordinated planning between MISO’s legacy region and the newly added Entergy region.
With no basis to conclude that customers of one region benefit from projects planned and constructed to benefit customers of the other region, the Tariff provides that any system-wide rate or cost allocation under the Tariff “shall be limited to the planning area where the project terminates,” the complaint states.
Because FERC noted that Entergy’s integration into MISO as the “first of its kind,” the commission justified the separation of the MISO footprint into two distinct regions for cost allocation and rate design purposes, the utilities say.
They asked FERC to force MISO to modify rate schedules in the Tariff related to export service and to ensure that the no-cost-sharing rule be applied to exports from the Entergy region.
The complainants said they were customers of Entergy prior to its MISO integration and hold long-term, point-to-point transmission service contracts with the company.
Charges for long-term, point-to-point transmission service under Entergy’s Open Access Tariff have jumped from $1.78/kW-month to $3.33/kW-month — an 87% increase — since Entergy joined MISO, they said.
“This massive rate increase should never have happened. It was and remains unauthorized,” the utilities said.
Increases Detailed
The utilities say much of the transmission is used to move wind generation from the Southwest to the Southeast.
When Entergy joined MISO, “it essentially became a continental divide stretching from the nation’s northern border to [the] southern border — with MISO as the gatekeeper for the delivery of Western wind to Southeastern loads and delivery of low-cost Southeastern base-load generation to Western loads,” the complaint states.
Southern said it has paid $8 million more in transmission fees between December 2013 and April 2015.
KCP&L said it paid Entergy $6 million a year for point-to-point transmission service prior to MISO but that the amount has nearly doubled since then.
AECI said it is paying $8.3 million a year, up 94% since Entergy joined MISO.
Empire District, based in Joplin, Mo., said only that its total costs for point-to-point transmission service on Entergy’s system have doubled.
Efforts to keep the Ginna nuclear plant operating has spurred a turf war between federal and state regulators who are conducting independent reviews.
The New York Public Service Commission asked the Federal Energy Regulatory Commission on Thursday for a rehearing of FERC’s April ruling that rejected the rate schedule in the reliability support services agreement between Ginna’s owner and the local distribution utility (ER15-1047). FERC ordered settlement and hearing procedures. (See FERC Rejects Ginna Rates, Orders Settlement Proceeding.)
The PSC said FERC interfered by “illegally” claiming jurisdiction over retail rates when it rejected some contract terms. It said FERC also violated the Federal Power Act when it declared the RSSA a reliability-must-run agreement and interfered with state jurisdiction to determine a mix of adequate resources.
“FERC ignores the fact that the NYPSC has an obligation under state law to ensure the availability of adequate generation facilities needed for reliability and is currently exercising its authority in reviewing the Ginna RSSA,” the New York regulators wrote. “The commission’s assertion of jurisdiction over the underlying terms of the RSSA would interfere with the NYPSC’s authority and represents an impermissible overreach of the commission’s jurisdiction.”
The RSSA was ordered by state officials and is scheduled to be retroactive to April 1, once approved by regulators. The agreement would cost about $175 million a year and be effective through late 2018. Ginna says it lost more than $150 million between 2011 and 2013.
Several other parties also asked FERC for clarifications or rehearings of the April order last week:
Industrial and commercial customers questioned the September 2018 end date for the RSSA, noting that a proposed transmission project that is supposed to make Ginna’s continued operation unnecessary may go online in early 2017. The intervenors suggest the RSSA should be terminated at that time and not after its entire term.
Entergy Nuclear Power Marketing asked that the issue of the initial term also be considered in the settlement process.
TC Ravenswood wants FERC’s review to expand into a consideration of the “price-suppressive” effects Ginna’s contract would have on the capacity market.
The Alliance for a Green Economy asked for another reliability study, saying information from discovery in the NYPSC proceeding undermines the rationale for the RSSA.
Exelon’s Constellation Energy Nuclear Group, Ginna’s owner, proposed a cost-of-service cap to address FERC’s rejection of the negotiated rates with Rochester Gas & Electric.
Entergy’s Arkansas and Mississippi operating companies will pay $32.6 million to their sister companies under a bandwidth recalculation report approved by the Federal Energy Regulatory Commission on Thursday (ER07-956).
Regulators in each state where the company operates have regularly challenged the annual bandwidth filings.
The updated report approved last week was based on 2006 test data and reflected adjustments on issues such as accounting for interim storm damage costs stemming from Hurricanes Katrina and Rita.
It will result in additional payments of $26.5 million by Entergy Arkansas and $6.1 million by Entergy Mississippi. The recipients are Entergy’s Gulf States Louisiana ($19 million), Louisiana ($2.7 million) and Texas ($10.9 million) operating companies.
The company said it will provide updated bandwidth payment/receipt amounts to wholesale customers on their next monthly bill.
Commissioner Colette Honorable, former chairman of the Arkansas Public Service Commission, did not participate in the ruling.
Gulf States Split
The case was complicated by Entergy Gulf States’ 2007 split into Entergy Texas and Entergy Gulf States Louisiana.
Texas industrial energy consumers filed a protest contending that because Entergy Gulf States was in operation in 2006, the allocation of payments due to the company should be addressed by state regulators in Texas and Louisiana.
The company balked, noting that because the Texas and Louisiana commissions adopted different allocation methods, Texas retail customers were credited $19 million more in 2007 bandwidth payments than were received.
FERC sided with the company, noting that Entergy Gulf States “no longer exists.”
FERC said that while Entergy Gulf States Louisiana and Entergy Texas did not exist in 2007, “it is only logical to place them into Entergy Gulf States’ position in order to ensure rough production equalization.”
OATT Revisions ‘Moot’
FERC also ruled last week in the matter of Entergy’s 2011 proposed revisions to its Open Access Transmission Tariff to comply with Orders 729 and 676-E. Because Entergy’s OATT was cancelled with its 2013 integration into MISO, Entergy’s compliance filing “is now moot,” FERC said (ER10-3357).
WASHINGTON — Federal regulators said Thursday they expect sufficient resources to meet peak electric demand this summer despite coal-fired retirements, a continued drought in the West and modest load growth driven by a rebound in industrial activity. Prices are expected to be moderate, based on forwards.
Staff of the Federal Energy Regulatory Commission gave a presentation at its Thursday meeting, shortly before the board of the North American Electric Reliability Corp. approved its summer reliability assessment.
NERC noted that the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) took effect in April 2015. “While this rule has contributed to retirement of fossil-fired generating units, the retirements have not caused the Planning Reserve Margin to fall below the NERC reference margin level,” the report said. “However, there is less resource capacity overall compared to previous summers to manage unforeseen challenges and severe conditions.”
Nationwide generating capacity has declined by about 3% since last summer, as retirements of coal-fired generation outweighed an increase of 2 GW of utility-scale solar and about 3.5 GW in wind generation, a 6% increase.
Fuel supplies should be plentiful as a result of recoveries in coal stockpiles and gas storage levels. FERC said coal stockpiles have been recovering since last summer but that a rise in natural gas prices could increase coal-fired generators’ output, creating the potential for supply problems in the Midwest.
The drought in California and the West, now in its fourth year, will reduce hydroelectric production, likely resulting in higher prices but no threat to reliability.
New York’s reserve margin has improved thanks to repowered generation capacity and lower forecast demand.
MISO’s projected reserve margin increased to 18% from 15% in 2014. NERC said MISO’s capacity resources are up by 4.5 GW “due to improved accounting for the reduction of contract path-limited resources in MISO South.”
Demand Response
Less demand response will be available in PJM, NYISO and ISO-NE. PJM expects 6,900 MW of DR, down by nearly 2,500 MW from a year ago, and less than half of the 14,800 MW that cleared in the Base Residual Auction in 2012, for the 2015/16 delivery year. “A substantial number of market participants traded away these positions in the RTO’s [incremental] auctions and through other transactions,” FERC said.
New York’s DR fell by 65 MW (5%) over last year while it dropped by 62 MW (9%) in New England. None of the three regions called on DR last summer.
The staff of the New York Public Service Commission issued a report Thursday predicting adequate supplies and moderate prices. Current wholesale prices are about 4.4 cents/kWh, compared to 6.6 cents/kWh a year ago, the PSC said.
Demand, Weather Forecasts
The Energy Information Administration has forecast a 2.9% increase in electric demand from last summer, which saw unusually mild weather.
The National Oceanic and Atmospheric Administration is forecasting warmer-than-normal temperatures in the West and Southeast and below-normal temperatures for parts of Texas and eastern New Mexico.
Only three hurricanes are forecasted, compared with the average of seven. “Generally speaking, hurricanes do not have the same level of impact on the U.S. energy markets as they did several years ago, due to the substantial shift in natural gas production from the Gulf of Mexico to onshore shale production,” FERC said.
Forward Prices
A 5.7% increase in natural gas production and a 71% increase in storage inventories versus last year caused a big drop in gas futures. The injection season began April 3 with 1.5 Tcf of natural gas in storage, up 79% from 2014 and only 4% below the five-year average.
NYMEX gas futures for June through August are averaging $2.89/MMBtu, a 40% drop from 2014. Peak power forward prices are down by an average of 24%, with a 34% drop for the ISO-NE internal hub.
The Algonquin Citygate near Boston showed the biggest drop among gas futures, recording a 46% reduction to $2.96/MMBtu. However, FERC said gas generators in ISO-NE could face challenges when Spectra Energy Partners begins maintenance and expansion of the Algonquin pipeline in late August.
In contrast, the commission said the rebuilt Susquehanna-Roseland 500-kV transmission line between Pennsylvania and New Jersey, which went into service May 11, should lower congestion in that region of PJM.
Market Changes for ISO-NE, CAISO
The commission also noted market developments since last summer.
ISO-NE is now allowing generators to submit up to 24 separate hourly offers in the next-day market and to update their offers during the operating day. Until the change in December, resources were limited to a single day-ahead offer and could not change their offers during the operating day. The RTO also will allow resources to submit negative offers as low as -$150/MWh to provide price signals to curtail generation when consumer demand is low.
The CAISO Energy Imbalance Market, which began in November, also will be entering its first summer test. The EIM enables balancing authorities in five Western states served by PacifiCorp to voluntarily take part in the imbalance energy portion of the ISO’s real-time market.
Meanwhile, SPP and MISO South will enter their second summer with full LMP markets.
New Focus for NERC
NERC said that although its assessment shows enough resources to meet summer demand, the transformation of the nation’s resource mix continues to present challenges. Natural gas now represents 40% the nation’s generation capacity.
“NERC continues to monitor key measures of essential reliability services to provide greater insight on how this trend is impacting reliability,” said John Moura, NERC director of reliability assessments.
In addition to continuing its efforts to ensure that the new generation mix provides adequate levels of frequency response, voltage control and inertia, NERC for the first time is considering operational risks from ongoing resource outages.
“The operational risk approach provides a much clearer picture of the actual capability of a given system within the bulk power system and its resilience against extreme weather and system conditions,” Moura said.
GLASTONBURY, Conn. — A hearing in a Connecticut suburb last week offered a microcosm of the energy debate swirling across New England as the region grapples with expanding its infrastructure to support its increasing reliance on natural gas-fired generation.
About 50 people attended a Federal Energy Regulatory Commission scoping meeting last week on the Atlantic Bridge Project, which would replace or expand 18 miles of the Algonquin pipeline in Connecticut, New York and Massachusetts. The project, which includes a section under the Connecticut River, would expand or replace three compressor stations and several metering and regulating stations, all in existing rights-of-way (PF15-12).
The meeting, one of a series being held in the three states, is part the initial phase of an environmental assessment.
Critics say the “segmenting” of the expansion review is a way to sidestep a review of the overall impact of the expansion. Developer Spectra Energy Partners says the project matches contractual supply commitments in place and does not need to address the region’s overall energy future.
Utilities, ISO-NE and most of the region’s governors strongly support proposals to build more pipeline capacity throughout New England to bring more natural gas from the Marcellus region.
Local landowners have complained of encroachments on their properties while environmentalists have invoked the national debates over climate change and natural gas extraction through fracking. (See related story, Another Meeting Day, Another Drama at FERC.)
Organized labor and business interests have aligned in support, citing jobs and economic development spurred by construction and lower electricity prices.
Nicholas Monacchio, representing the Laborers International Union of North America, highlighted the economy. “We are facing a real energy crisis due to the pipeline constraints … and the economic benefits will be a number of good-paying construction jobs,” he said.
“When businesses look around [and] they say ‘I can go to any state in the country and pay less for electricity than I do in Connecticut,’ we need to change that,” said Eric Brown, counsel for the Connecticut Business and Industry Association.
The counterargument came from the environmental community. “For every $1 million invested in gas, you get about five jobs. For $1 million in energy efficiency, you get 10 or 11,” said Martha Klein, communications chair for the Connecticut Sierra Club.
“These pipelines are meant for exports, which will lead to high profits for the pipeline, for which we are being forced to pay,” local environmentalist Dave Schneider said, referring to a proposed tariff by the states that would fund pipeline expansion through an assessment on electricity rates.
Spectra said the project will allow delivery of an additional 222,000 dekatherms of natural gas per day to Northeast markets by creating additional capacity between a receipt point on Algonquin’s system in Bergen County, N.J., and delivery points on the Algonquin and Maritimes systems.
In its latest monthly status report to FERC, Spectra reported that it has completed about 95% of the civil surveys required for the above-ground facilities and is conducting a geotechnical survey to document subsurface conditions and bedrock properties along the route. The geotechnical survey work will continue through the spring and summer of 2015.
The Department of Energy is expanding a biomass generation plant at its Savannah River Site. The project is part of the department’s Energy Savings Performance Contract program, in which a private company finances and maintains energy equipment in federal facilities. Framingham, Mass.-based Ameresco plans to boost output of the six-year-old 20-MW plant by 3 to 4 MW. Ameresco received $795 million to build the original plant, which uses forest residue and wood chips as fuel, and the expansion.
Oklahoma Sen. James Inhofe, chairman of the Environmental and Public Works Committee, thinks it’s time to scale back the Nuclear Regulatory Commission’s budget. He said despite a lower-than-expected workload associated with new nuclear licensing and review processes, the commission’s budget has grown by 34% and its workforce by 25% in recent years.
“The Nuclear Regulatory Commission’s workload is decreasing, but regulations are increasing,” he said. “I am going to work with Senate appropriators to adjust the NRC’s budget.”
Inhofe said breadth of the NRC’s oversight is also increasing in an effort to drive up the cost of compliance. “Every increase in regulation makes it more difficult for nuclear energy to remain cost competitive, and I believe there’s an intention to make that happen,” Inhofe said.
NRC Revising Rules on Foreign Ownership of Nukes in US
The Nuclear Regulatory Commission is changing how it assesses foreign ownership of U.S. nuclear reactors. Current regulations prohibit foreign ownership of commercial reactors, which is creating problems for some planned new commercial nuclear generating stations. Two years ago, NRC ruled that Unistar Nuclear Energy, a subsidiary of French company EDF, could not build a proposed plant on the site of the Calvert Cliffs nuclear station in Maryland.
The commission has told its staff to come up with a plan to set guidelines for partial foreign ownership. NRC said the decision to revise rules takes into account “the realities of today’s interconnected and global nuclear energy markets.”
The Department of Energy has given final approval for the Cheniere liquefied natural gas export terminal near Corpus Christi, Texas. Houston-based Cheniere plans to have the terminal in operation by 2018. The approval grants the facility a license to export up to 2.1 billion cubic feet of LNG per day for up to 20 years to countries with which the U.S. does not have a free trade agreement. Dominion Resources’ Cove Point LNG terminal in Lusby, Md., received the same authorization last week.
DOE Warns Against Chinese Investment in LNG Projects
The Department of Energy is advising American firms against allowing Chinese investment in U.S liquefied natural gas projects, an industry executive said. Freeport LNG chief executive Michael Smith said the warning has led to a dearth of gas export deals with China. “We were advised by the DOE to be careful who our customers were, because this is very political,” Smith said.
The Bureau of Ocean Energy Management approved Royal Dutch Shell’s oil-exploration plan in the Chukchi Sea after the company submitted a renewed and reinforced plan for its Arctic drilling operations.
“We have taken a thoughtful approach to carefully considering potential exploration in the Chukchi Sea, recognizing the significant environmental, social and ecological resources in the region and establishing high standards for the protection of this critical ecosystem, our Arctic communities and the subsistence needs and cultural traditions of Alaska Natives,” BOEM Director Abigail Ross Hopper said. “As we move forward, any offshore exploratory activities will continue to be subject to rigorous safety standards.”
Shell still needs to obtain other permits, including one to moor its equipment in Seattle’s harbor. A city-hosted hearing on that is scheduled for this week, but protests were already forming by Saturday.
The owners of a hydroelectric station said to have lured Henry Ford to open a vehicle assembly plant in St. Paul 90 years ago have won a regulatory victory forcing Northern States Power to keep buying its electricity.
The Federal Energy Regulatory Commission on Thursday denied an application by Northern States Power to terminate its mandatory purchase obligation from Twin Cities Hydro (QM15-2).
Twin Cities’ parent, Brookfield Renewable Power, has operated the 18-MW qualifying facility on the Mississippi River since taking it over from Ford Motor Co. in 2008. Three years later, Ford closed its St. Paul plant.
Northern States Power has been obligated to buy the power under the Public Utility Regulatory Policies Act. It provides for the termination of purchasing electricity from a facility if that facility has “nondiscriminatory” access to certain types of markets.
Northern States argued that it should no longer be required to buy Twin Cities’ power because the hydro facility has been selling energy into MISO’s wholesale energy markets since 2008.
But FERC adopted “rebuttable presumptions” that a facility with a capacity at or below 20 MW does not have nondiscriminatory access to markets. The commission has maintained that such smaller facilities are often interconnected at the distribution level and thus may “lack the same level of access to markets as those connected to transmission lines.”
These smaller facilities may face obstacles such as pancaked delivery rates and administration burdens to access distant buyers, FERC said.
FERC ruled that Northern States failed to demonstrate that the Minnesota hydro facility has non-discriminatory access to both energy and capacity markets.
Northern States “thus acknowledges that the Twin Cities [facility] cannot, at present, access the MISO capacity market. In contrast to the MISO energy market, [Twin Cities] has no history of sales into the MISO capacity market,” FERC said in its decision.
Twin Cities said because it is interconnected through Northern States’ distribution system, it would have go through the MISO interconnection process to obtain network resource interconnection service, at considerable cost and time.
“Here, both NSPM and Twin Cities note that transmission constraints exist which will directly impact the Twin Cities [facility’s] access to the MISO capacity market.”
The facility’s dam was completed in 1917 by the U.S. Army Corps of Engineers. Ford added the hydroelectric generating station in 1924.
Brookfield Renewable Power operates 7,000 MW of hydro capacity on 74 river systems in 14 power markets in North America, Latin America and Europe.
The Federal Energy Regulatory Commission proposed Thursday to change when it assesses annual charges to hydropower operators that are not state and municipal entities.
Under FERC’s Notice of Proposed Rulemaking, the charges would start two years from the effective date of a project license, exemption or amendment authorizing new capacity — not when construction on a project commences (RM15-18).
The revisions would eliminate the need for licensees and exemptees to notify FERC of construction starts in order to invoke the fees. FERC also no longer would have to contact the entities to elicit the information. FERC said the change would provide certainty as to when the charges would go into effect and improve administrative efficiency.
The fees apply to projects exceeding 1.5 MW of installed capacity. Original licenses, relicenses, exemptions and amendments adding new capacity generally require that construction start within two years of the date of issuance. The changes would mean that charges will be assessed regardless of when the projects commence or whether or not FERC has granted an extension.
FERC predicts that an average of 5.2 licensees and/or exemptees annually will end up paying annual charges before the start of construction. On average, 10.6 entities are expected to be affected by the rule change.
