Iberdrola USA and UIL Holdings have agreed to clean up an abandoned power plant site in New Haven if Connecticut regulators approve their proposed $3 billion merger.
The companies on Thursday agreed to a consent order with the state’s Department of Energy and Environmental Protection that would allow the contaminated English Station site to be cleaned up for reuse.
The Connecticut Public Utilities Regulatory Authority rejected the proposed acquisition in June on other grounds, saying that the plan was not in the public interest. The companies refiled a new plan in July that they said addressed regulators’ objections. (See Iberdrola Refiles Acquisition Bid for UIL Holdings.)
The state estimates site remediation would cost under $30 million. The companies have committed to spend any amount in excess of that if necessary.
The agreement was announced in a statement by Gov. Dannel P. Malloy, Attorney General George Jepsen and DEEP Commissioner Robert Klee. “The state will strongly oppose any attempt to recover remediation costs from ratepayers. The companies will propose the scope of work to fully examine the pollution and clean it, and DEEP will review and approve the scope of work,” they said.
“This is an important settlement — to New Haven and to Connecticut. The English Station has long been a site that absolutely needed to be cleaned up and given a second life, and now it will be,” Malloy said in the statement.
The plant is situated on Ball Island in the middle of the Mill River in New Haven. It was operated by UIL unit United Illuminating for 63 years and closed in 1992. It is contaminated with polychlorinated biphenyls, heavy metals and other contaminants.
Administrative proceedings will continue against UIL to determine responsibility for cleanup of contamination in the river, according to state officials.
The acquisition, which includes natural gas distribution companies in Massachusetts, must also be approved by that state’s regulators.
Connecticut regulators will conduct hearings on the acquisition in October. A decision is expected by Dec. 4.
FERC said last week it will require the North American Electric Reliability Corp. to provide the commission access to NERC databases in what Chairman Norman Bay said is an effort to apply “Moneyball” techniques to reliability.
The commission issued a Notice of Proposed Rulemaking that would give FERC access to NERC’s transmission availability data system (TADS), generating availability data system (GADS) and protection system misoperations databases (RM15-25).
“It takes the concept of ‘Moneyball’ to our analytics on reliability,” said Bay, referring to the best-selling book on Oakland Athletics General Manager Billy Beane’s use of statistical analysis in evaluating baseball players.
The commission said access to the data “would inform the commission more quickly, directly and comprehensively about reliability trends or reliability gaps that might require the commission to direct [NERC] to develop new or modified reliability standards.”
TADS and GADS contain data on transmission and generation outages, respectively, including cause codes.
The protection system database collected information on about 2,000 misoperations in 2014, including causes. “Protection system misoperations have exacerbated the severity of most cascading power outages, having played a significant role in the Aug. 14, 2003, Northeast blackout,” FERC said.
“While the aggregated TADS, GADS and protection system misoperations data provided in NERC’s periodic reports afford the commission some insight into the reliability and adequacy trends identified by NERC, we believe that having direct access to the underlying data will assist the commission in its understanding of the periodic reports, thereby helping the commission to monitor causes of outages and detect emerging reliability issues,” FERC said.
FERC Micromanaging NERC?
Commissioner Cheryl LaFleur issued a concurring statement expressing concern that the proposal could be seen as micromanaging NERC. Although FERC has ordered NERC to initiate standards on geomagnetic disturbances and physical security, LaFleur said that authority should be used sparingly.
“It is important that we recognize the distinction between [FERC’s] oversight role and NERC’s primary responsibility to monitor reliability issues and propose standards to address them. Ultimately, I believe our efforts to sustain and improve the reliability of the bulk electric system are furthered by mutual trust and shared priorities between the commission and NERC,” she said.
“I understand that today’s proposal might be controversial within the NERC community. I therefore welcome comment on the proposal, including any potential issues or concerns not identified in the NOPR.”
Comments on the proposal are due 60 days after publication in the Federal Register.
The commission also gave final approval to two sets of reliability standards and preliminary approval to a third.
FERC approved reliability standards PRC-002-2, which specifies requirements for time-synchronized data for post-disturbance analysis (RM15-4), and PRC-005-4, adding sudden pressure relaying systems to the protection system maintenance rules (RM15-9).
It also approved a NOPR proposing to approve standard PRC-026-1, which would require that protective relay systems differentiate between faults and stable power swings (RM15-8).
The six New England states aren’t an island, but the region sometimes feels that way when it comes to its winter power supply. Although transmission ratings and maximum generation output is higher during the cold weather and peak load is lower, the ability to import power is a major concern.
“Transmission interfaces into New England are going to be loaded up pretty much around the clock every day,” Peter Brandien, ISO-NE’s vice president of system operations, told FERC on Thursday. “Which means that any sort of contingencies … I’ll have to handle with the resources internal to New England.
“People are talking about ramping up their efforts for the winter, but for us, [preparation occurs] throughout the year,” he continued. “I look forward to the time when I can come down here and say that we’re all set and we don’t have any concerns going into the winter. I feel like a broken record every time I’m down here talking about the same concerns.”
In addition to the familiar concerns over constraints on gas pipelines from the west, he also cited worries about diminished supplies from Nova Scotia. Natural gas supplied 44% of the region’s power in 2014, nearly tripling its share since 2000.
The lack of infrastructure also causes New England prices to be “higher than just about anywhere else,” Brandien said.
ISO-NE will again rely on the winter reliability program it has used for the last two winters, which gives oil generators incentives to secure fuel at the beginning of the winter. Last year, it added incentives for liquefied natural gas. “Hopefully, there will be LNG injections like last year,” Brandien said.
The RTO’s Pay-for-Performance program, which rewards successful generators and penalizes those who fail to meet their commitments, goes into effect in 2018.
Gas-electric communication, “a 12-month project,” has improved in response to FERC orders, he said.
The RTO hired a former gas industry veteran to help evaluate gas availability and developed a gas usage tool that scrapes the electronic bulletin boards of the five interstate pipelines serving the region.
This winter, the RTO also will begin allowing generators to change offers on an hourly basis in the day-ahead and real-time markets, improving incentives for following dispatch orders. “We think that’s going to pay dividends to us,” he said.
The RTO’s assumptions for the Winter 2015/16 Forward Reserve Auction included a reserve requirement of 2,363 MW.
“I’m somewhat comfortable that we have insight into all of [the challenges, that] we have the right communication, that we have the right emergency procedures and that we’ll be able to implement any operational actions in time,” Brandien said.
Still, ISO-NE said in its presentation: “[The] loss of any major non-gas unit or significant disruptions in gas supply or pipeline capability will create major challenges for ISO operations.”
FERC issued a preliminary order Thursday that would require RTOs and ISOs to align their settlement and dispatch intervals, saying it was the first of a number of proposals the commission plans to act on based on what it learned from the price formation proceeding it began last year.
The Notice of Proposed Rulemaking (RM15-24) would require organized markets to settle real-time energy and operating reserve transactions financially at the same five-minute time interval that it dispatches those resources. It would also require the markets to eliminate any lag between declaring a shortage and beginning shortage pricing.
Inaccurate Price Signals
The commission said current practices in some markets are not resulting in appropriate price signals.
Although all organized markets dispatch resources in five-minute intervals, ISO-NE, MISO and PJM settle those transactions based on the average price for all dispatch intervals during the hour (“hourly integrated prices”).
“This misalignment between dispatch and settlement intervals may distort the price signals sent to resources and fail to reflect the actual value of resources responding to operating needs because compensation will be based on average output and average prices across an hour rather than output and prices during the periods of greatest need within a particular hour,” the commission said.
In addition, some markets do not trigger shortage pricing unless the shortage lasts a minimum time — resulting in a delay before prices begin reflecting the shortage. The rule would require a shortage of any duration to be reflected in prices.
FERC said the changes “will help provide correct incentives for market participants to follow commitment and dispatch instructions, to make efficient investments in facilities and equipment, and to maintain reliability. The proposed reforms will also help provide transparency and certainty so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system.”
“Requiring settlement intervals to match dispatch intervals would make resource compensation more transparent by, among other things, increasing the proportion of resource payment provided through payments of energy and operating reserves rather than uplift,” the commission continued. “This increased transparency, in turn, better informs decisions to build or maintain resources and enhances consumers’ ability to hedge.”
Comments on the proposed rule will be due 60 days after its publication in the Federal Register.
Offer Cap Issue Coming to FERC
FERC’s price formation proceeding included workshops and staff reports touching on a variety of obscure — but often controversial — issues, including offer caps and uplift allocation. (See FERC Sets Feb. 19 Deadline on Price Formation Comments.
In its Thursday order, FERC said it “expects to undertake further action addressing various price formation topics, including offer price caps, mitigation, uplift transparency and uplift drivers,” though it gave no schedule for future action.
But the commission will be facing the offer cap issue shortly, with PJM planning to seek a rule change — with or without stakeholder consensus — by the end of October. The Markets and Reliability Committee will discuss the issue in a special meeting Thursday. (See PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight.)
But Commissioner Philip Moeller was impatient. “I wish we had done a little bit more and a little bit sooner,” he said Thursday. Moeller’s term expired June 30, but he has remained on the panel awaiting a new nominee from President Obama.
Industry, RTO Reactions
The Edison Electric Institute praised the commission’s action.
“We thought [the NOPR] was a good start to a really comprehensive look at these issues,” said Richard McMahon, EEI’s vice president of energy supply and finance. “The fact that they teed up these other important issues [for future action] is very encouraging.”
The current disconnect means resources will be under-compensated for energy produced during price spikes, or overpaid for energy produced during low prices in an hour where most intervals have high prices.
MISO
MISO’s Market Monitor David Patton has been recommending five-minute settlements since his 2012 State of the Markets Report.
“Even though a very small share (1 to 2%) of the energy produced and consumed in MISO is settled through the real-time market, the spot prices produced by the real-time market affect the outcomes and prices in all other markets,” Patton said in his 2014 report in June. “For example, prices in the day-ahead market, where most of the energy is settled, should reflect the expected prices in the real-time market. Similarly, longer-term forward prices will be determined by expectations of the level and volatility of prices in the real-time market. Therefore, one of the highest priorities from an economic efficiency standpoint must be to produce real-time prices that accurately reflect supply, demand, and network conditions.”
Patton said MISO has the metering and data necessary to make the change, which he said will require “only modest changes to MISO’s existing settlement calculations.”
At its Market Subcommittee meeting in August, MISO categorized the switch to five-minute settlements for generation schedules as “planned” and said that it was evaluating the “market efficiency benefits” and “process and system impacts.”
MISO implemented five-minute settlements for interchange schedules, as required by FERC Order 764, on June 30.
“We’re in the process of reviewing the NOPR now and will begin discussions with stakeholders soon about the implementation and timing,” MISO spokesman Andy Schonert said. The RTO addressed the implications of sub-hourly settlements in its comments to FERC on the price formation initiative in March. (See pp. 17-18 of the comments.)
PJM
In an April order on pricing of reserves, FERC rejected as out of scope a call from Public Service Enterprise Group that PJM implement five-minute settlements (ER15-643).
PJM Executive Vice President and COO Mike Kormos said in an interview after the FERC meeting that the change “was on the radar for sure.”
He noted that the order may require generators to make software changes and update old meters.
“It’s not just going to be ‘What’s the impact on PJM?’” he said. “It’s ‘What’s the impact on everybody?’”
ISO-NE
ISO-NE is already discussing with market participants a switch to five-minute settlements. At the Sept. 2 New England Power Pool Markets Committee meeting, RTO officials said they plan to settle generation, pump hydro and imports and exports on a five-minute basis but will continue to settle load assets and bilaterals hourly in real-time.
ISO-NE spokeswoman Marcia Blomberg said the idea of settling bilaterals subhourly also is under discussion.
Real-time reserve payments and inadvertent energy also would be settled every five minutes but the charge allocations would remain hourly.
On Sept. 2, the RTO told the NEPOOL Markets Committee that it plans to present Tariff language changes in November with a vote in December and implementation in 2017.
“We’re still reviewing the NOPR and evaluating what’s needed for compliance, but in terms of the proposal we’re discussing with participants, significant changes to the ISO’s settlement systems would be required to accommodate new calculations and significantly increased data volume, and market participants’ information systems would also require changes,” Blomberg said Monday.
NYISO announced Wednesday that its Board of Directors has selected Bradley C. Jones, senior vice president and COO of ERCOT, to replace Stephen G. Whitley as president and CEO, effective Oct. 12.
Jones is a distinguished energy industry executive with 29 years of wide-ranging experience, including grid operations, power plant operations, generation development, project finance, wholesale and retail market design, and regulatory and legislative affairs.
At ERCOT, Jones had responsibility for operations, grid planning and commercial operations.
Jones (left), Whitley (right) (Source: NYISO)
Jones joined ERCOT from Luminant, the competitive generation subsidiary of Energy Future Holdings, where he was vice president for government affairs. He previously worked at TXU Corp., rising from a plant engineer to become vice president for generation development.
A licensed professional engineer, Jones has a bachelor’s in mechanical engineering from Texas Tech University at Lubbock and an MBA from the University of Texas at Arlington.
“Brad has a strong commitment to reliability and a firm belief in the power of markets to benefit consumers,” NYISO Chairman Michael Bemis said in a statement. “His talent, experience and demonstrated commitment to excellence make him a great choice.”
Jones was chosen following a nationwide search conducted by Heidrick & Struggles. He could not be immediately reached for comment.
Whitley, appointed CEO in 2008, will remain with the ISO during the transition and then act as an advisor to the board.
The developers of the abandoned PATH transmission project would be denied recovery of more than $10 million of their $121.5 million claim under an initial decision by a FERC administrative law judge Monday.
Judge Philip C. Baten recommended that the commission deny the developers, American Electric Power and the former Allegheny Energy (now FirstEnergy), recovery of lobbying and advertising costs as well as part of their legal costs and losses on the sale of the property they acquired (ER09-1256-002, ER12-2708-003). The commission can accept the recommendations in whole or in part.
The proposed 765-kV “coal by wire” Potomac-Appalachian Transmission Highline project was approved by PJM in 2007 to run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md.
By 2011, however, PJM said the need for the line had moved several years beyond 2015 due to reduced load growth following the recession. The PJM Board of Managers ordered transmission owners to suspend work on the line pending a more complete analysis in 2011 of all upgrades in its regional transmission plan and terminated it in 2012.
Victory for Pro Se Interveners
Although the developers would recover most of their request, the judge’s ruling was a victory for two PATH opponents from West Virginia, Keryn Newman and Allison Haverty, who filed a pro se intervention challenging the companies’ request for recovery of $6 million in spending on lobbying and advertising campaigns intended to win political support for the project. The judge denied recovery of any of the expenses.
Baten also said $3.6 million in losses that the companies incurred on past land sales are not recoverable and that recoveries from any future land transactions “must be accomplished by commercially reasonable procedures.”
The judge also denied recovery for part of $3.9 million in legal expenses, for which the companies’ failed to provide documentation, and cut the companies’ proposed 10.4 % return on equity for the abandonment costs to 6.27%.
But Baten approved recovery for the purchase of property for a planned substation in Maryland and rejected a request by state consumer advocates to reject $29 million in spending incurred in 2010-2012 as imprudent.
The advocates said that the PATH companies should have recommended to PJM that the project be terminated by the beginning of 2010 and that expenses between that point and the actual termination should be denied.
The judge ruled that the expenses were recoverable because the PATH companies had a contractual obligation to construct the transmission projects as assigned by PJM. “The PATH companies did behave as a prudent utility by proceeding with their assigned obligations until otherwise instructed by PJM,” he wrote.
First Impression
Baten said that the case “presents significant issues of first impression” on FERC Order 679, a 2006 initiative that sought to accelerate transmission investment through incentives.
“This case addresses some new issues and gives the commission a unique one-stop opportunity to review and set policies for the comprehensive litigation scheme arising from Order No. 679,” Baten wrote.
The PATH project was initiated with PJM’s 2007 Regional Transmission Expansion Plan, and in 2008 FERC accepted a formula rate that entitled the developers to recover all prudently incurred costs if the project were cancelled.
In 2012, the companies filed for recovery of $121.5 million in abandonment costs. After settlement attempts with opponents failed, hearings in the case were held in March and April.
Lobbying Campaign
The pro se interveners contested spending on public relations agencies, advertising and public coalitions intended to influence public officials during the zoning and certificate of public convenience and necessity (CPCN) proceedings in Maryland, Virginia and West Virginia.
“When utilities are seeking selection or CPCN approvals from governmental entities, the utilities should rely on the established governmental approval processes to persuade the officials and not indulge in collateral efforts such as public education, outreach and advertising activities,” the judge ruled. “… If the selection or CPCN application has merit, the governmental selection process provides a sufficient vehicle for the utilities to present their engineering, marketing and economic studies and thereby hope to merit the vote of approval from these officials. In this regard the PATH companies spent over $8 million on attorney fees to prosecute the CPCNs before the respective governmental bodies, which begs the need for these collateral expenses.”
Among the spending rejected was $332,000 on a public opinion poll, $2.7 million in advertising and $94,000 paid to the then head of the West Virginia Democratic Party, Larry Puccio.
The judge said that the “nature and origins of the PATH companies’ business relationship with Puccio are somewhat amorphous” and that the companies paid him $31,000 “before his assignments were even formulated.”
“The invoices of record provide little description of his services. When the PATH companies were asked in discovery to provide additional details, their response was that such records are not available. While the PATH companies make protestations that Puccio’s services were not to lobby and instead were to educate the public and public officials, without proper documentation the only factual inference that can be drawn is that his services were to influence public officials, and the PATH companies have failed in their burden of proof to show otherwise.”
VALLEY FORGE, Pa. — Members debated four potential changes to the $1,000/MWh energy offer cap last week at a specially called meeting of the Markets and Reliability Committee, failing to agree on any one — or even which should be the main and alternate proposals.
Further discussion was deferred until Sept. 24, giving stakeholders only a few weeks to reach consensus before the Board of Managers takes the matter into its own hands before winter.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during periods of extreme temperatures, such as the 2014 polar vortex.
Direct Energy had kicked off the latest effort to reach agreement in July with its plan to raise the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers. The number is 50% more than the highest offers reported by PJM last winter. PJM said that it would support the Direct Energy proposal. (See PJM Stakeholders Struggle for Consensus on Offer Cap.)
Joe Wadsworth of Vitol reiterated his concern about potential unintended consequences inherent in applying different rules to the day-ahead and real-time markets. “We could be artificially creating arbitrage opportunities,” he said, adding that such a scenario might invite increased scrutiny from FERC enforcement.
“We need to ensure the day-ahead and real-time market parameters are the same whenever we can,” he said.
Jim Jablonski, of the Public Power Association of New Jersey, said that whatever the proposed offer cap is, it’s critical it be able to be supported by data. “We can’t get to FERC and say, ‘Oh, we just doubled the old one.’”
Jablonski asked Direct Energy’s Jeff Whitehead if he could estimate exactly how much uplift a higher cap might eliminate. “I’d love for somebody to say, ‘This is how much,’” he said.
Whitehead responded, “The higher the offer cap, the less uplift we’ll have.”
Steve Lieberman of ODEC called his plan “the only proposal that was a joint effort of load and supply.”
It would allow cost-based offers of up to $1,800/MWh and allow them to set LMPs.
And, he said, “Old Dominion firmly believes in the need for a cap that is the same in both markets.”
The Monitor’s proposal would allow cost-based offers to exceed $1,000/MWh when a unit’s short-run marginal costs exceed that cap. Price-based offers would have to be less than or equal to such cost-based offers. Monitor Joe Bowring said the approach addresses the issue of market power when the overall market is tight.
The P3 proposal was the only one that had not previously been presented.
In making the presentation, David “Scarp” Scarpignato of Calpine said that because generators have a must-offer requirement to enter into the day-ahead market, it’s essential they be able to recover their costs.
“The uplift method is a bad idea,” he said. “It’s unhedgeable, and there’s extra risks added to load prices. If you don’t put them into LMP, you lose a very important market signal.”
In allowing offers to set LMPs, according to the proposal, higher prices incent generators to perform.
Like Lieberman, Scarp said the day-ahead cap must equal the real-time cap. Under his proposal, cost-based offers for both markets would be capped at cost plus 10%; market-based offers would be capped at the higher of $2,700/MW or the cost-based offer.
The proposal also sets penalty factors of $1,350/MW for synchronized or primary reserves, and $750/MW for excess synchronized or primary reserves.
PJM has reduced the number of potential transmission fixes for the AP South/AEP-DOM constraints to six candidates.
Six other projects were eliminated following sensitivity analyses for changes in load forecasts and fuel prices.
The projects remaining cleared the 1.25 benefit-cost ratio under all sensitivities and also reduced both AP South and AEP-DOM congestion in combined 2019 and 2022 simulations.
The six proposals include three by Dominion Resources and one submitted by Dominion High Voltage Holdings and Transource Energy (itself a partnership of American Electric Power and Great Plains Energy). The finalists also include one project each from LS Power and Duke-American Transmission Co. Costs of the projects range from $25 million to $301 million.
The fuel price sensitivity looked at natural gas costs $1/MMBtu higher and lower than the prices assumed in the base case. The load forecast sensitivity included an increase and decrease of 2% in load.
LS Power’s Sharon Segner questioned the planners’ screening. “There’s nothing that puts any kind of weight on the cost side and cost containment,” she said. LS Power’s $48.6 million proposal includes a cost cap.
Paul McGlynn, PJM general manager of system planning, said planners will consider cost certainty in further pruning the list of finalists.
Planners hope to select a winning project in time to include it in the 2015 Regional Transmission Expansion Plan.
Last month, they announced the selection of 11 other market efficiency projects with a combined cost of $59.2 million to address congestion in other areas of the footprint. (See “11 Market Efficiency Projects Selected; 12 still in running for AP South/AEP-DOM,” in PJM TEAC Briefs.) Those projects will be recommended to the PJM Board of Managers in October.
McGlynn noted that the RTO has done relatively few market efficiency projects in the past. “We’re very pleased to be having on the order of a dozen [market efficiency] projects to be taking to the board,” he said.
Planners also will reevaluate nine proposed projects to address constraints on the Loretto-Wilton Center 345-kV line, which caused the COMED locational deliverability area to bind in the 2018/19 Base Residual Auction in August. COMED cleared at $215/MW-day, $50 above the RTO price. (See PJM Capacity Prices Up 37% to $165/MW-day.)
The projects, with costs ranging from $11.5 million to $290 million, fell short of the 1.25 benefit-cost ratio in the original analysis. But one or more could clear the threshold if the analysis shows they can increase COMED’s capacity emergency transfer limit, McGlynn said.
Reliability Projects
The 2015 RTEP also will include reliability projects selected from among 91 proposals — 26 transmission owner upgrades and 64 greenfield projects — made in response to Window 1, which closed July 20. The window covered N-1 and N-1-1 thermal and voltage problems as well as generation deliverability and common mode outage and load deliverability issues.
The proposals range in cost from $13,000 to $167.1 million.
The RTEP recommendations also will include dozens of generation-related network upgrades (see pp. 34-68 of the PJM presentation).
Meanwhile, planners have begun reviewing proposals received in response to Window 2, which closed Sept. 4. The window sought solutions for transmission owner criteria and light load reliability criteria violations.
High Voltage Problem in AEP
Planners are considering more than $51 million in transmission upgrades to address a large increase in the number of high-voltage warnings in the AEP transmission zone and northeastern Mid-Atlantic regions. AEP also has seen a large increase in reactor switching for both low- and high-voltage conditions.
The problems, which generally occur during light load periods, are resulting from changes in dispatch due to new and deactivated generation, reactive support deficiencies and increased line charging from new transmission facilities.
Planners are considering spending $51 million to install a 450-MVAR static VAR compensator at the Jacksons Ferry 765-kV substation and a 300-MVAR shunt line reactor on the Broadford end of the Broadford–Jacksons Ferry 765-kV line in southern AEP.
They’re also planning six new shunt reactor installations in New Jersey, the cost of which is still being finalized.
Pratts Area Update
Planners said they will recommend selection of a Dominion project that requires no new right of way to address reliability problems near Pratts, Va.
PJM staff selected Dominion to build a 230-kV line from the Remington substation to the Gordonsville substation.
Dominion will build a new 230-kV line from the Remington substation to the Gordonsville substation and install a third 230/115-kV transformer at Gordonsville at an estimated cost of $103.7 million.
PJM announced last month it was reconsidering its selection of the Gordonsville-Pratts-Remington transmission upgrade after learning that it will require about 18 miles of new rights of way, far more than initially believed. The proposal from Dominion Resources and FirstEnergy was estimated at $129 million to $164 million.
The Virginia State Corporation Commission, which would have to approve the project, says that existing rights of way should be given priority as the locations for transmission additions.
In response to a question, McGlynn said planners had not independently verified Dominion’s assertion that the new line could be built in the existing 115-kV corridor. “We relied on the work of the entities that proposed the project,” he said.
A representative from Madison County, Va., which had urged PJM to reject the original plan, praised the new solution, saying it was “symmetrical with the identified need and an appropriate fix.” The county had complained that the original project was unnecessarily large for the rural county.
The cold weather temperatures produced by the polar vortex of January 2014 continue to haunt FERC.
The commission has denied another generator’s request for $1.3 million in make-whole payments for natural gas it purchased that was never used during the event, citing rules against retroactive ratemaking (ER15-952).
New Jersey Energy Associates, which owns the 290-MW South River combined-cycle plant, said PJM asked that a planned outage for the plant be canceled so it could be available for dispatch on Jan. 27, 2014. The plant purchased $2.7 million worth of gas, having been assured by PJM that it would be compensated for its fuel costs, according to NJEA. The RTO, however, repeatedly canceled the plant’s scheduled start time, forcing it to sell the gas at a $1.3 million loss.
The claims are similar to those of Duke Energy and Old Dominion Electric Cooperative. During the same week as NJEA’s claim, Duke purchased gas for $12.5 million when PJM said that its Lee plant in Illinois would be needed. The plant was never called on, however, and Duke was forced to sell the gas at a loss of $9.8 million. ODEC complained that PJM canceled multiple dispatches that left gas it had purchased unused and that it was due $15 million. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)
FERC, however, remained steadfast on its assertion that these kinds of complaints constitute retroactive ratemaking.
“Ratepayers had not received any prior notice of NJEA’s requested relief, which was sought roughly 12 months after the events in question,” the commission said. “We therefore conclude, as we did in the similar Duke and ODEC cases, that the relief sought by NJEA is prohibited by the filed rate doctrine and rule against retroactive ratemaking.”
FERC, however, did find that NJEA was entitled to recover its start-up costs under PJM’s Tariff. The Tariff allows market participants to recover costs related to the start-up of resources offered in the day-ahead energy market if PJM cancels its selection of those resources. While NJEA did not specify how much they would be allowed to recover under this provision in its complaint, it said “this would only be a fraction of its actual unrecovered costs.”
As he did in the Duke and ODEC cases, Commissioner Philip Moeller dissented. He once again noted that PJM is the only grid operator that does not allow its participants to vary their day-ahead energy market offers by hour or update their offers in real time.
As a result of the Duke and ODEC complaints, FERC found that PJM’s Tariff was potentially unjust and unreasonable in this regard and ordered the RTO to make Tariff changes by Nov. 1. While PJM agreed that changes were needed, and it began the stakeholder process to do so, the RTO told the commission in July that it would need until Nov. 1, 2016, to resolve the numerous questions raised by the changes (EL15-73).
“In light of this delay in reforming PJM’s markets,” Moeller argued, “the majority’s repeated failure to guarantee cost recovery for generators acting in good faith to ensure system reliability may regrettably impact reliability during the approaching winter of 2015-2016.”
BOSTON — New England’s states may have to set aside their self-interests to overcome high energy prices that are slowing the region’s economy, Massachusetts Gov. Charlie Baker told the 2015 ISO-NE Regional Plan meeting on Thursday.
The first-term Republican said the region’s competitive advantages are at risk, citing a “sense of desperation” among his fellow governors over energy costs.
“One of the things that’s going to be most fundamental to our ability to succeed is to develop strategies and plans that can get a lot of people who don’t necessarily agree on things to come together and find a way to put the optimal success of the region above what might be the most optimal solution for any particular player,” he said.
“We don’t believe we can achieve the energy security, competitiveness, reliability and affordability … alone. It’s got to be a regional conversation,” he said.
Massachusetts, Rhode Island and Connecticut agreed earlier this year to seek multi-state, long-term contracts to procure large-scale renewable resources. More problematic is building large, multi-state electric transmission and natural gas pipeline projects.
“I think it’s pretty hard to look at the data and conclude that we won’t need to increase our capacity over time,” Baker said, referring to New England’s increasing reliance on natural gas generation and the fuel shortages that occur in the winter months. (See Dueling Studies Dispute Need for More Pipelines in New England.)
He also endorsed exploring the feasibility of importing more hydropower, which would require expensive power lines. “Canadian hydro has potential to be a significant player in the region,” he said, adding that the decision to proceed will depend on how the projects affect ratepayers. “If it doesn’t make sense, we won’t do it,” he said.
Policy Mandates Sometimes at Odds with Market Forces, Panelists Say
Following the governor’s address, a panel discussed whether the region’s pursuit of public policy initiatives is incompatible with low-cost energy.
Over the past 16 years, panelists said, New England’s energy strategy has often been at cross-purposes. The development of competitive markets, the transition from coal to natural gas generation, the integration of renewables and the need for expensive infrastructure all have made it difficult to keep rates affordable.
“In New England, our representatives have decided that renewable energy is really important, notwithstanding whatever preferences the market may have in its short-term, day-to-day interest,” said Edward Krapels, founder of Anbaric Transmission.
“I see us going down two paths,” he said. “The planning by the ISO to maintain reliability leads you down one path. Actions by the governors to create a clean energy economy take you down a parallel path and the two don’t converge.”
He said the three-state model for procuring renewables is the beginning of that convergence.
Public policy has had to contend with “the historical forces of technology and geology” — cheap natural gas — said Katie Dykes, deputy commissioner for energy at the Connecticut Department of Energy and Environmental Protection.
“This low gas price environment that we’ve had has done more for the fuel mix of this industry than the [Environmental Protection Agency] and the environmental advocates have been able to do over the last several years,” said Bob Hayes, vice president of natural gas trading for Calpine.
But he cautioned that the region’s dependence on liquefied natural gas “for the foreseeable future is a precarious one at best and one that I’d definitely be concerned about.”
Tanya Bodell, executive director of research firm Energyzt, said EPA’s initial draft of the Clean Power Plan was an example of policy ignoring reliability. EPA backed off from its proposed early deadline of 2020, delaying it by two years, after widespread criticism.
“That change was needed to show that your state plan is going to result in a reliable outcome,” she said.
