The Federal Energy Regulatory Commission reaffirmed its authority Monday to regulate New York reliability support services agreements, rejecting a rehearing petition filed by the state Public Service Commission challenging its jurisdiction (ER15-1047).
The NYPSC had argued that it had sole jurisdiction over the rates and terms of an RSSA it had ordered between Exelon’s troubled R.E. Ginna nuclear plant and Rochester Gas & Electric. (See NYPSC Challenges FERC Jurisdiction over Ginna.) FERC in April rejected the proposed rate schedule in the agreement and ordered hearing and settlement proceedings.
FERC rejected the contention that it would be setting retail rates, asserting that it was properly exercising its authority under the Federal Power Act to regulate wholesale markets.
“Preventing the exercise of market power through [reliability-must-run] agreements is important to ensure that wholesale rates are just and reasonable,” FERC said. “Therefore, finding that the commission does not have authority to regulate such agreements — which keep RMR resources online, provide them out-of-market compensation and remedy a potential opportunity to exercise market power — would be inconsistent with the congressional intent behind the FPA.”
The agreement, set to be retroactive to April 1 once approved, 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.
FERC did, however, reverse its stance from April when it said it would not consider the issue of Ginna “toggling” between the RSSA and NYISO. In its original order, the commission said it would only reconsider how much Ginna would have to repay in the event the plant returned to the market after the agreement’s expiration — saying that this provision was “a sufficient disincentive” to prevent toggling. (See FERC Rejects Ginna Rates, Orders Settlement Proceeding.)
“We find that the pleadings raise disputed issues of material fact concerning Ginna’s incentive to toggle between RSSA compensation and the NYISO markets,” FERC said. That issue has been added to the roster of items to be decided in the ongoing proceeding before a FERC administrative law judge.
In Monday’s order, FERC also rejected rehearing requests from several parties that challenged several aspects of the agreement. The commission
Again accepted the NYISO Ginna Reliability Study that justified the RSSA;
Upheld the September 2018 end date for the RSSA, saying early termination clauses in the contract are consistent with FERC policy to keep RMRs of limited duration; and
Reiterated its stance that consideration of the “price-suppressive” effects Ginna’s contract would have on the capacity market is beyond the scope of the proceeding.
Meanwhile …
In the concurrent proceeding before the administrative law judges of the NYPSC, RG&E last month requested a temporary rate surcharge to avoid rate compression over a shorter duration of the RSSA. Whatever rate increases it will eventually collect are being held in abeyance until the RSSA is approved by state and federal regulators.
RG&E estimates that its deferred collection will reach approximately $25 million from the effective date of the RSSA through July and will continue to grow, with interest. “By authorizing a temporary rate surcharge, the bill impacts resulting from the deferred collection amount would be mitigated,” it wrote.
In a brief filed Monday, RG&E said the commission “should find that the company’s proposed temporary rate surcharge tariffs are in the public interest and authorize the company to immediately implement the surcharges, subject to refund.”
PSC staff filed a brief Monday that supports the move, proposing Sept. 1 as the effective date.
“The RSSA is not in effect,” the state consumer advocate wrote. “Neither the commission nor FERC have reached a final conclusion to accept the RSSA, so RG&E has not, and might never, incur any financial obligations to Ginna under the RSSA.”
The administrative law judges said they will set a schedule to recommend a decision once reply briefs due July 20 are filed.
New York utilities have filed 15 demonstration projects for consideration under the state’s Reforming the Energy Vision initiative, many of them designed to increase consumer awareness and reduce power consumption.
Consolidated Edison’s proposed Building Efficiency Marketplace would be offered to 2,100 medium to large commercial buildings across its territory with interval metering and the potential to benefit from remote analytics.
Rochester Gas & Electric and New York State Electric and Gas, both units of Iberdrola USA, have proposed three projects: the Energy Marketplace, an ecommerce website enabling consumers and distributed energy resource providers to interact; the Flexible Interconnect Capacity Solution, a model for connecting large-scale, controllable distributed generation to the grid, with the ability of the utility to either dispatch or curtail the power; and the Community Energy Coordination program, which would use community-based energy asset planning to procure distributed energy resources.
National Grid
National Grid has proposed projects at three locations around the state.
Renewable energy integration and automated demand management would be provided at the Buffalo Niagara Medical Campus, along with in-front-of-the-meter solar generation in a lower-income neighborhood. The company also has proposed a partnership with Clarkson University and the State University of New York at Potsdam to determine the feasibility of a community microgrid. In Clifton Park, it is proposing advanced metering for residential and small commercial customers to monitor and control energy use.
Central Hudson Gas & Electric
Central Hudson Gas & Electric, which got a jump on the others when it incorporated its demonstration projects in its recent rate case, has included a targeted demand response program that met PSC criteria. (See Central Hudson Gets Rate Hike, OK on REV Project.)
Its other projects include a utility-scale community solar project that would offer fixed rates to subscribers. Central Hudson and its partners are conducting a feasibility study for a microgrid project. Its “energy exchange” would provide customers with energy management information, including products and services, on a web-based platform.
Orange & Rockland
Orange & Rockland has proposed partnerships with third-party product and service partners to increase customer awareness on energy consumption, motivate customers to participate in utility programs, increase adoption of distributed energy and develop new revenue streams.
Consolidated Edison
Consolidated Edison has filed three separate plans. Its CONnectED Homes program would provide customers with tools to connect them with efficiency programs.
The Building Efficiency Marketplace is intended to illustrate the value of interval meter data analytics in engaging commercial customers to reduce their demand.
The virtual power plant would aggregate 1.8 MW of behind-the-meter distributed solar with battery storage to improve grid resiliency.
Massachusetts Attorney General Maura Healey has commissioned a study to assess New England’s natural gas supplies and other energy needs.
The study, which is being funded by the Boston-based Barr Foundation, will identify options to address electric reliability needs through 2030. Economic consulting firm Analysis Group has been commissioned for the study, which will be completed by October.
“Our goal with this study is to identify the most cost-effective solutions for ratepayers that will also allow us to achieve our regional climate goals,” Healey said in a statement. “As the state makes long-term decisions about additional gas capacity investments, we should understand the facts — what the future demand is, and which cost-effective energy and efficiency resources can be deployed to meet that demand.”
Questions about the need for gas infrastructure have been tackled in studies by various states, stakeholders and ISO-NE, but Healey said they are either flawed or incomplete. “While there have been a number of prior studies conducted, none have answered the precise question of how much additional gas is needed in the New England region and whether that gas can by supplied by [liquefied natural gas] or additional pipeline capacity is needed,” the statement said.
Kinder Morgan has proposed a controversial natural gas pipeline that would bring gas from the Marcellus region of Pennsylvania, through New York and into Massachusetts and New Hampshire, with a terminus at Dracut, Mass. (PF14-22).
The Massachusetts Department of Public Utilities in April opened a docket to evaluate ways to bring extra natural gas into the state, including contracts between electric distribution companies and gas distributors, with cost recovery from ratepayers (15-37).
In light of the study, Healey asked the DPU to reconsider its denial of her motion to stay DPU approval of gas distribution companies’ contracts for capacity on the Kinder Morgan pipeline. The attorney general said there are significant factual disputes to resolve, as well as questions about the legality of pipeline funding through ratepayer charges.
VALLEY FORGE, Pa. — A task force unanimously approved by the PJM Planning Committee last week will craft minimum design standards for greenfield projects that are competitively solicited under Federal Energy Regulatory Commission Order 1000.
PJM and stakeholders said the standards are needed because entities designated for such projects are not required to follow the design standards of the involved transmission owner. (See Task Force Would Create Standards for Order 1000 Projects.)
“The purpose of establishing minimum design standards is to assure a minimum level of robustness is provided such that the new competitively solicited facility would not introduce a weak point in the system in terms of performance,” according to the problem statement.
Participation in the group will be open to all PJM members.
The standards will address transmission lines, substations and system protection and control design coordination. They will take into account factors such as the physical geography of a site and local ordinances.
The rules will not apply to upgrades or non-competitive projects.
The task force also is expected to explore the creation of a “common facility ratings methodology.”
Tariff Tweaks Address Merchant Network Upgrades
The Planning Committee unanimously approved changing some tariff language to more accurately reflect how PJM processes requests for merchant network upgrades.
“We’re not actually changing the way we treat merchant upgrades,” PJM’s Jason Connell said.
He said the language was outdated because it addressed the only type of customer PJM accommodated in 2003: the interconnection customer. In 2006, it added other types of upgrade requests.
The changes address definitions, queue entry, agreements and the capacity market.
Two-Tiered Transmission Project Fee Heads to FERC
PJM will file with FERC a two-tiered fee schedule for proposed transmission projects, the Planning Committee agreed.
For projects of $20 million to $100 million, the RTO will collect $5,000 to cover its study costs. For proposals greater than $100 million, it will charge $30,000.
PJM’s Fran Barrett called the fee schedule, which will be implemented on a two-year trial basis, “conservative.”
“We may be in a situation where we’re under-collecting,” he said, in which case the RTO would lean on the planning system budget. If the opposite turns out to be the case, the excess funds will be disbursed to members.
The Members Committee in February had approved a $30,000 fee for any project greater than $20 million, but planners subsequently concluded that was unnecessarily high. (See PJM Lowers Proposed Tx Project Study Fee.)
Initially, PJM had suggested that $30,000 be assessed on all greenfield projects and on all upgrades costing more than $20 million, but FERC rejected the idea, calling it discriminatory. (See FERC Rejects Fee on Greenfield Transmission Projects.)
Load Model Picked for 2015 IRM Study
The Planning Committee approved using a load model based on the 2003-2012 period in its calculation of Installed Reserve Margin (IRM) requirements.
Last year’s selected load model used the timeframe of 2004-2011, but PJM’s Patricio Rocha said that wasn’t a good fit for this year because load models including 2012 were better aligned with coincident peak distribution. The alternatives were 2001-2012 and 1998-2004.
The 2015 study will set IRM requirements for base capacity auctions for delivery years 2016 through 2019 and establish the initial IRM for 2019/20.
Members warned PJM officials last week that the way the RTO plans to calculate Capacity Performance could lead generators to ignore dispatch instructions to avoid penalties.
PJM expects generators’ output to match their Capacity Performance obligations even at the beginning of a no-notice emergency, leaving no allowance for ramping. That could lead generators that are not producing at their full CP commitment when the emergency is called to exceed their obligation later in the hour to avoid or minimize penalties, stakeholders said.
The discussion came during an Operating Committee briefing by PJM officials on the operating impacts of the rule changes and how they would assess penalties under several scenarios.
“We could have a lot of people not following PJM dispatch on no-notice events just to avoid these penalties,” said Ed Tatum of Old Dominion Electric Cooperative.
Gabel Associates’ Mike Borgatti said the rules could result in “perverse” market results. “It seems like a weird incentive structure,” he said.
“PJM [could] lose control of the system,” agreed David Pratzon of GT Power Group.
Vice President of Operations Mike Bryson acknowledged that the rules could lead to penalties for a generator, for example, with a 200-MW CP obligation that is producing only 100 MW at PJM’s instructions when an emergency is called. (See “GEN Bill” example in chart.)
PJM officials last week briefed the Operating Committee on how hypothetical Capacity Performance resources would have been judged had CP rules been in place June 23, when storms resulted in a no-notice manual load dump action in the Atlantic Electric region in New Jersey. The emergency was called at 7:03 p.m. and lasted until 8:52 p.m. Units with “yes” under the column “CP Assessment” would face penalties.
“Right now I think that’s the case,” he said. “We’ll take it back for more discussion.”
Performance Assessment Hours
The briefing focused on “Performance Assessment Hours” — whole or partial clock-hours for which PJM has declared an Emergency Action in response to locational or system-wide capacity shortages. Emergency Actions include voltage reduction warnings and actions and manual load dump warnings and actions.
Generators ordered off-line by PJM because of transmission constraints would be exempt from penalties.
Pratzon said he was concerned that could lead to subjective and inconsistent judgments in PJM settlements for CP penalties. “It’s very difficult for us to see [how the penalty decision is made] isn’t a very judgmental thing, based on what we know now,” he said.
Bryson said the decision to restrict a generator’s output will be made based on distribution factor analyses to answer, “Is the unit going to help or hurt?”
“It’s not judgmental. It’s going to be based on power engineering,” he said.
Incremental Auction Opens
The second Incremental Auction for delivery year 2016/2017 opened Monday and will run through 5 p.m. Friday. Participation is mandatory for existing generators with a “positive minimum available position” and voluntary for other resources. Suppliers must confirm the modeling of their capacity resources before their sell offers will be accepted.
SPP will soon file a full report on the Integrated Marketplace’s first year of performance, but its most recent quarterly State of the Market report indicates the market expansion hasn’t affected the fundamental dynamics in the region.
Electric prices are continuing to track natural gas prices, and congestion patterns “have generally remained consistent” with those under the old Energy Imbalance Service, according to the spring market report by the RTO’s Market Monitoring Unit.
The Integrated Marketplace, which launched in March 2014, includes a day-ahead market with transmission congestion rights and a reliability unit commitment process and real-time balancing market. It also incorporated a price-based operating reserve market and combined the region’s balancing authorities into a single SPP balancing authority.
The Federal Energy Regulatory Commission told SPP and its MMU to file an information report 15 months after the implementation of the market. A draft of the report is expected to be presented to the Board of Directors during its July 28 meeting.
Here are some highlights from the MMU report:
Gas, Electric Prices
Average gas prices for March, April and May were about half those for last year’s spring, averaging $2.46/MMBtu, as compared to $4.66/MMBtu in 2014. That decline has led to a corresponding decline in the LMP. Day-ahead LMPs averaged $22.13 this spring, compared to $37.03 in 2014. Real-time LMPs were $20.95, compared to $34.72 last year.
DA/RT Divergence
At the same time, the SPP system’s day-ahead to real-time price divergence hit a high of -46.9% in March. Day-ahead prices were $22.06, compared to real-time average prices of $20.46. Divergence eased to -7.4% and -7.2% in April and May, respectively; it has only been in the positive once since the Integrated Marketplace’s implementation, coming in May 2014 at 3.8% ($35.58 for day-ahead compared to $35.97 for real time).
The report partially attributed the price divergence to significant price volatility in the real-time market. “Prices are expected to be more volatile in the real-time balancing market than the day-ahead market,” the report said.
Virtual Trading
The day-ahead market’s virtual trading is intended to promote convergence between day-ahead and real-time prices, improve day-ahead efficiency and moderate market power. The report said cleared demand bids — most placed by financial-only participants — steadily increased before leveling out this spring.
SPP said gross virtual profits for the Integrated Marketplace’s most recent 12 months totaled just over $92 million, with gross virtual losses totaled nearly $71 million. It noted every Integrated Marketplace month has had a net profit from virtual transactions save for May 2014, which had a net loss of just over $700,000.
Cleared virtual bids as a percentage of reported load is averaging about 3% since the Integrated Marketplace’s implementation; cleared virtual offers as a percentage of reported load is averaging just over 4%.
Cleared virtual transactions averaged 7% of load since March 2014. April 2015 saw the largest amount of virtual transactions, at 9.75% of reported load.
Gas-Electric Price Correlation Continues
SPP also pointed to a positive metric comparing gas prices from the Panhandle Eastern Pipeline with electricity prices. (SPP uses PEPL costs as a proxy for overall gas costs in its footprint).
SPP power costs continued to track natural gas costs in the first year of the Integrated Marketplace.
“Historically, gas prices and real-time prices have been highly correlated in SPP,” the report said, noting the trend has continued into the Integrated Marketplace. “Workably competitive markets should experience highly correlated gas costs and energy prices in general.”
Congestion Patterns
The report said congestion patterns have remained consistent with the Integrated Marketplace’s implementation. Newly energized transmission service has eased congestion in northwest Kansas and the Kansas City area, but congestion remains an issue in the Texas Panhandle and northwest Oklahoma, where four flowgates registered the highest shadow prices in SPP’s footprint this spring. (Shadow prices reflect congestion’s intensity on a flowgate’s path, indicating the marginal value of an additional megawatt of relief on a constraint in reducing the total production costs.)
The market report said low-cost generation north of the constraints and limited import capabilities were some of the driving factors.
Regulation Market
The report notes that SPP implemented its regulation-compensation market to comply with FERC Order 755 on March 1. The market includes payment to market participants based on changes in energy output for regulation deployment.
This March, SPP cleared more regulation mileage than necessary with a regulation mileage factor of 1.0 for both regulation up and down, according to the report. The 1.0 factor was adjusted to a more realistic value, averaging near 0.2, in April and May, resulting in fewer unused mileage make-whole payments.
Five 170-foot-tall concrete foundations that will support the nation’s first offshore wind farm have been completed in Houma, La., and are starting their barge journey to the Deepwater Wind construction site off Block Island, R.I.
The 1,500-ton foundations, which will support five 6-MW turbines manufactured by Alstom, are expected to arrive off Block Island in mid-July, according to Deepwater Wind CEO Jeffrey Grybowski. The turbines are scheduled to be installed in mid-2016, with the project expected to be operational by the end of that year. National Grid has agreed to buy the wind farm’s output under a 20-year contract.
Facebook Powering New Texas Data Center Entirely with Wind
Facebook announced that its new data center in Fort Worth, Texas, will run entirely on wind energy. The Fort Worth facility will be the third Facebook server center to be powered entirely on renewable energy. The other two are in Altoona, Pa., and Lulea, Sweden.
Facebook said it is working with Citi Energy, Alterra Power and Starwood Energy to tie 200 MW of wind energy to the Texas grid, and then to the data center. It said the wind facility will cover a 17,000-acre site about 100 miles from Fort Worth. Facebook says that it aims to produce 50% of its power needs from renewable energy by 2018.
Facebook’s news follows separate announcements from tech giants Google and Amazon.com that they plan to step up commitments to renewable energy.
Brattle Report Puts Nuclear Industry’s GDP Input at $60 Billion a Year
A report commissioned by a nuclear promotional group said U.S. atomic power contributes about $60 billion annually to the country’s gross domestic product.
The report by the Brattle Group, commissioned by the trade organization Nuclear Matters, said the industry accounts for 475,000 full time jobs and provides 19% of U.S. electricity. The report said the industry provides about $10 billion in federal taxes and $2.2 billion in state taxes.
More than Half of Large Businesses Generating Some of Own Power
A Deloitte survey shows that more than half of about 600 large businesses in the U.S. are able to generate some of their energy on-site. Two years ago, only about a third of the companies generated some of their power.
The study showed that the largest companies – those with $500 million in annual revenue or more – are investing more in energy management, ranging from on-site generation to energy efficiency. The majority of the on-site power is still provided by diesel generators, but it is increasingly likely to include renewables such as solar or wind.
Peabody Energy, in asking a federal judge in Wyoming to dismiss a lawsuit filed by protesters who were jailed after demonstrating at a shareholders meeting, also wants the judge to purge the lawsuit of the famous John Prine protest lyrics that mention the company’s name.
Thomas Asprey and Leslie Glustrom, who were jailed after demonstrating at a 2013 Peabody shareholders meeting, cited the lyrics from Prine’s 1971 song “Paradise” in the lawsuit. Peabody said the lyrics tarnish its name.
The lyrics include the refrain about the company’s mining practices in Muhlenberg County, Ky.:
And Daddy won’t you take me back to Muhlenberg County
Down by the Green River where paradise lay?
“Well, I’m sorry my son, but you’re too late in asking
Environmentalists Say Dominion’s Coal Ash Plans Inadequate
A coalition of environmental groups says Dominion Virginia Power’s plan to close its 11 coal ash ponds doesn’t do enough to prevent toxic materials from seeping into nearby rivers, and they’ve asked the state to step in.
The environmentalists have asked the Virginia Department of Environmental Quality to halt Dominion’s plans to remove the coal ash if it shows pollutants are escaping. “Dominion’s proposal to cap in place will not stop heavy metals and other toxic pollutants from leaking out of the sides and bottom of coal ash ponds right into water bodies used to kayak, fish and swim,” said Emily Russell of the Virginia Conservation Network.
Company officials say the procedure for closing the ponds and moving the material to prepared disposal sites meets all state and federal regulations, and tests show the method is safe.
Ameren Reaches Settlement on Missouri Coal Ash Plan
Ameren Missouri has settled a series of lawsuits dating back more than five years over its coal ash disposal plan, allowing the power generator to go forward with construction of a coal ash landfill at its Labadie power plant that it says is crucial to the plant’s continued operation.
The settlement with Franklin County and the Labadie Environmental Organization requires Ameren to construct 5-foot berms to keep any ash or ash residue out of the Missouri River floodplain. The company also agreed not to bring in ash from other sites, or to use coal ash in the construction of the berms.
Construction has started on Maine’s largest renewable energy project, a $420 million wind farm in Bingham that will have a capacity of 185 MW.
Developer SunEdison said it had secured $360 million in financing for the 56-turbine farm, which will increase the company’s total wind generation capacity in Maine to 552 MW. The Bingham project’s output will be sold to Eversource, National Grid and Unitil.
Pump Malfunction Forces Indian Point Unit Shutdown
A water pump malfunction forced the shutdown of Entergy’s Indian Point Unit 3 on Wednesday. Control room operators shut down the nuclear reactor after they found that one of the unit’s condensate pumps automatically stopped while the unit was operating at full power, causing the steam generator’s water levels to fluctuate, according to Entergy.
The condensate pumps, which are part of the system that feeds water into the plant’s steam generators, are located away from the nuclear side of the plant, Entergy said. Operators safely shut down the reactor, the company said. The shutdown did not affect Unit 2, which is still operating at full power.
Entergy did not say when it expects to resume operations.
Ameren is planning a 15-MW solar farm on a 70-acre site in eastern Missouri. The project would be twice the size of Ameren’s first utility-scale solar facility near St. Louis. Ameren’s application with the Missouri Public Service Commission did not detail costs.
The state’s renewable energy standard has stoked interest in renewable projects, as utilities are required to generate a portion of their electricity from non-carbon sources. Developers also are racing to build projects before a federal tax credit for renewable energy falls from 30% to 10% at the end of next year.
Indianapolis Power & Light has broken ground on the first utility-scale battery storage project in MISO’s 15-state territory.
The AdvancionTM Energy Storage Array will provide 20 MW of interconnected energy storage. The facility, which will provide additional stability to IPL’s system, is due to go online in the first half of 2016.
IPL’s parent, AES, pioneered the use of grid-connected lithium-ion batteries in 2008, in Indianapolis. AES has 86 MW of energy storage projects in operation worldwide and has announced an additional 260 MW of interconnected battery-based storage.
Talen Energy, the independent power producer formed by the spinoff of PPL’s generating assets and competitive producer Riverstone Holdings, is looking to grow. The Allentown, Pa., company holds about 15,000 MW of generation, primarily in the PJM region and some in Texas.
“We’re as open to buying coal as gas as nuclear,” CEO Paul Farr told Reuters. But he said its fuel mix is more likely to become more “gassy” while gas prices remain low. He did say, however, that Talen is looking at American Electric Power’s coal generation holdings in Ohio. AEP has been signaling a willingness to unload its coal assets there.
Minnesota Power Shutting Down 2 Coal Units at Taconite Harbor
Minnesota Power announced last week that it will retire two coal-fired units at its Taconite Harbor plant in Schroeder, part of a larger plan to shift the company’s generation portfolio from coal.
The company’s commitment will be included in its “integrated resource plan” due to be filed with the Public Utilities Commission in September. Minnesota Power’s fuel-mix currently has about 75% coal-fired generation and 25% renewables. That will change over the next 15 years to about a third coal, a third natural gas and a third renewables.
“It’s a balanced portfolio of energy sources,” said Al Rudeck, vice president of strategy and planning. “We think it’s the best plan, and the most affordable plan, for our customers.” Environmentalists applauded the announcement.
FirstEnergy would spin off the transmission assets of Jersey Central Power & Light, Metropolitan Edison and Pennsylvania Electric into a new subsidiary under a plan it has submitted to regulators, saying the move would allow it to more cheaply and efficiently upgrade its grid (EC15-157).
With the formation of the new company, Mid-Atlantic Interstate Transmission (MAIT), all 24,000 miles of the Akron, Ohio-based company’s system would be managed by transmission affiliates.
The plan must be approved by New Jersey and Pennsylvania regulators and the Federal Energy Regulatory Commission. The company made no formal announcement of the proposal except for a June 19 filing with the Securities and Exchange Commission.
“When you have a separate transmission-only company, typically it carries a more favorable credit rating, so it can borrow money for less, and that results in lower costs for customers,” FirstEnergy spokesman Doug Colafella said. “It’s an arrangement that really allows a company to make the significant investments in transmission that we’re looking at. It also allows our separate utilities to stay focused on the distribution system and respond quickly to customer needs.”
FirstEnergy already operates American Transmission Systems (ATSI) in Ohio and northwest Pennsylvania and Trans-Allegheny Interstate Line Co. (TrAILCo) in western Pennsylvania.
The spinoff falls in line with FirstEnergy’s “Energizing the Future” initiative, announced in 2012, to enhance its high-voltage transmission system.
FirstEnergy expects to invest $2.5 billion to $3 billion over the next five to 10 years on upgrades in the JCP&L, Met-Ed and Penelec zones, Colafella said.
The company estimates that streamlining the projects through one company with a higher credit rating will save $135 million in interest over the 30-year life of $1.5 billion in projects, according to FirstEnergy’s filing with the New Jersey Board of Public Utilities.
“Consolidating all of the operating companies’ transmission assets in a stand-alone transmission company can reduce investors’ perception of financial risk, strengthen the credit profile of the transmission function and, in that way, provide improved access to capital and reasonable rates,” it said.
Ron Morano, a spokesman for JCP&L, said that being relieved of the task of operating its transmission system will allow the company to better focus on customers’ needs.
“For Jersey Central, it enables a more timely investment on new transmission projects,” he said.
Under the plan, MAIT would own and operate all transmission assets of the three utilities, which would lease to the transmission subsidiary their real estate and real property rights.
Colafella said the spinoff would not affect transmission-related jobs at the utilities.
“It won’t have any impact on employees day-to-day,” he said. “It’s more of an accounting arrangement.”
It is, however, expected to lead to the creation of about 200 FirstEnergy jobs in New Jersey and Pennsylvania, he said, and the projects should provide work for roughly 600 engineering, project management and construction jobs in those states.
CARMEL, Ind. — MISO will propose closing the day-ahead market one hour earlier during Daylight Savings Time and reducing the clearing time by an hour in response to the Federal Energy Regulatory Commission’s final rule on gas and electric schedules.
MISO officials said their proposal — Alternative 3 — was an effort to balance reliability and market efficiency concerns with stakeholder preferences. Most stakeholders preferred no changes.
FERC Order 809 moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (from 12:30 p.m. to 2 p.m. ET) and added a third intraday nomination cycle. The commission ordered RTOs to adjust the posting of their day-ahead energy market and reliability unit commitment process results “sufficiently in advance” of the revised gas cycles or explain why it is not suitable for their markets.
Three Alternatives
The RTO rejected Alternative 2, which officials said was most in line with Order 809 but was opposed by most stakeholders. In addition to reducing the clearing time by one hour, it would have aligned the day-ahead market with the timely gas nomination cycle by closing the day-ahead two hours earlier during DST and one-hour earlier during standard time. Only 18% of stakeholders supported the change.
Alternative 3 won a bare majority with 53% support, making it the second choice to the status quo Alternative 1, which was backed by 78%.
Alternatives 2 and 3 got much of their support from gas-dependent members in Zones 8 and 9 (Louisiana, Arkansas and eastern Texas).
“I know not everybody is going to agree with [the choice] given the voting that took place. I hope that everybody can understand how we got there and [that] it makes sense,” Joseph Gardner, MISO’s vice president for forward markets and operations services, told the Market Subcommittee last week in announcing the decision.
Gardner told stakeholders MISO will have to make a partial show-cause filing to defend the choice to FERC. MISO also will ask FERC to delay the implementation of the new hours to November 2016 rather than next April as required by FERC.
More Units to Call On
Gardner said Alternative 3 had several benefits. Moving the market before the Intraday 2 gas nominations could free up about 5,000 MW more than under the current approach.
“From a reliability perspective, by moving our timeframe up by shortening our window, we bring more units into the mix. That basically allows more units to be considered as part of the normal day-to-day process, in terms of getting them online [and] in terms of committing them economically,” he said.
MISO estimates that natural gas-fired generation could rise to 50% of its generation pool in 2016/2017 as coal-fired plants are shuttered in response to the Environmental Protection Agency’s Mercury and Air Toxics Standards. EPA’s proposed Clean Power Plan is expected to spur gas use further.
From a market efficiency standpoint, Gardner pointed to the value of being able to trade during the “most liquid” time of the day “and then having that price discovery and know[ing] what price to put into the day-ahead market. So that’s a consideration, too, as to why we didn’t go with Alternative 2.”
Not Ideal for Some
The change may be hard for some stakeholders to swallow. Gardner acknowledged that many have indicated that they found ways to manage their gas supply risks and thus didn’t support moving up the day-ahead schedule.
Marc Nielsen of Alliant Energy said his company plans to add additional gas-fired generation and already conducted a great deal of modeling. “We supported Alternative No. 1. We’re able with our gas supply resources to handle things perfectly as they are now,” he said.
Gardner said he recognized Alliant’s concern. “I hope people can understand how we ended up here,” he said. “It’s been a long journey.”
But the tone among stakeholders at the Market Subcommittee was mostly supportive.
“I appreciate you guys looking at your processes and working toward also shortening the [market clearing] time. I think that was a big step, too, so thank you,” Ameren’s Jeff Moore told Gardner.
Moore asked whether Gardner thought FERC would be amenable to MISO’s choice.
“I think we have a much better chance of succeeding [than sticking with the status quo], but we still are going to have to make a good argument,” Gardner said.
NYISO and ISO-NE are not considering any schedule changes in response to the Federal Energy Regulatory Commission’s April order on gas-electric coordination.
FERC Order 809 moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (12:30 p.m. to 2 p.m. ET). It also added a third intraday nomination cycle (RM14-2).
“We are not contemplating market timing changes at this point in time and believe the additional 1.5 hours for generators to arrange day-ahead gas purchases will be helpful to reliability,” NYISO spokesman Ken Klapp said.
ISO-NE, which shifted its day-ahead market schedule two years ago to align with the natural gas trading day, said it is already in compliance with the FERC rule.
PJM confirmed last week that it will seek to move the deadline for submitting day-ahead offers up 90 minutes, from noon to 10:30 a.m. ET.
Adam Keech, director of wholesale market operations, told the Operating Committee that the RTO will post day-ahead results as soon as they are complete — but no sooner than 12:30 p.m. — up from the current 4 p.m. The reliability assessment and commitment (RAC) run rebid window will be open until 2:15 p.m., up from the current 6 p.m.
Keech said PJM will seek to complete the RAC run assignments before the 3 p.m. deadline for the second intraday gas nomination cycle.
“We’re going to commit as much as we can by 3 p.m., recognizing that if system conditions change we’re going to need to make supplemental commitments,” Keech said.
The RTO’s explanation last week clarified the changes it outlined to the Markets and Reliability Committee on June 25. PJM officials acknowledged the lack of consensus among stakeholders on the changes but said they were necessitated by the Federal Energy Regulatory Commission’s April order moving the timely nomination cycle deadline for gas to 2 p.m. ET from 12:30 p.m. and adding a third intraday nomination cycle. (See PJM Moving on Day-Ahead Schedule Changes.)
Keech said PJM officials are considering changes to their algorithms as well as faster computer servers as a way to meet their goal of reducing the market-clearing time to three hours from four. He said FERC’s requirement that the RTO allow hourly pricing updates means it will have to process more data during the clearing process. (See “PJM Won’t Be Ready for Flexible Generator Offers by November” in PJM Markets and Reliability Committee Briefs.)
PJM told FERC in a report last week that it will implement hourly offers by Nov. 1, following consultations with stakeholders (EL15-73).
