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.
MISO and its wind generators are having trouble getting along.
Just two days after FERC rejected allegations that MISO was blocking a wind farm from exporting power to PJM, the RTO was hit with a new complaint accusing it of giving special treatment to external generators seeking to deliver power into the Midwest.
The disputes have arisen as the RTO is attempting to close a capacity shortage that could arise as soon as 2020.
Acciona Wind Energy USA accused MISO in May of blocking it from selling power into PJM by improperly interpreting a process designed to streamline energy exports.
The company complained that MISO had excluded a portion of its 180-MW Tatanka wind farm’s capacity from participating in its pre-certified path study process, which allows interconnection customers to avoid lengthier studies when MISO evaluates their transmission service requests (TSRs). (See Acciona: MISO Blocking Access to PJM.)
MISO Acted ‘Reasonably’
But FERC ruled Sept. 2 that the claim was without merit, saying that MISO conducted Acciona’s system impact study in accordance with its Tariff and business practice manuals. “We find that MISO reasonably concluded that it was appropriate to deny the TSRs given the lack of available transmission capacity absent upgrades,” the commission ruled (EL15-69).
FERC also rejected the company’s claim that MISO was requiring it to make “several hundred million dollars” of upgrades, saying the estimate appears to include all of the costs of the N. LaCrosse-N. Madison 345-kV multi-value project rather than the “but for” upgrades required for Acciona’s service request.
Two days after FERC’s ruling, three wind generators filed a complaint asking the commission to block MISO from enacting rules that would exempt external generation from having to provide “cash at risk” deposits to enter the definitive planning phase, the final stage of the RTO’s study queue (EL15-99).
EDF Renewable Energy, E.ON Climate & Renewables N.A. and Invenergy said MISO’s external network resource interconnection service (E-NRIS) protocol is unfair to internal generation, which is required to make the M2 milestone payments. MISO won FERC approval for the milestone payments in 2012, arguing that they were necessary to weed out speculative projects, whose withdrawal from the queue results in time-consuming restudies.
‘No Safeguard’
The three companies sought fast-track status for their complaint, saying that MISO plans to add 7 GW of external generation into the queue, which it said could have an “enormous impact.”
“There is no safeguard to protect MISO’s queue management from further delay and restudies (and cascading restudies) if any of the 7 GW of [external projects] withdraws; nor is there any safeguard to protect interconnection customers from shifts in network upgrade costs if any [external] customer withdraws,” the complaint said.
The companies called the M2 milestone payment, which is based on generating capacity and transmission voltage, an “extreme burden,” saying a 150-MW project could be required to put up as much as $1 million.
They filed the complaint after MISO’s Planning Advisory Committee delayed a vote Aug. 19 on a proposal by Wind on the Wires that would have imposed the M2 costs on external generators. (See Interconnection Deposit Proposal Tabled.)
MISO and PAC members agreed to postpone the discussion to the Sept. 16 meeting, the companies said, but MISO later informed members that the E-NRIS protocol is final.
Capacity Worries
MISO is seeking to attract and retain capacity resources to offset retirements of coal-fired generation as a result of federal environmental rules and competition from low-cost natural gas.
In 2014, MISO projected it would face a 2.3-GW capacity shortfall beginning next year. In June, however, the RTO said its newest survey with the Organization of MISO States indicated it will have enough capacity to offset any zonal shortages until 2020. (See MISO Survey: No Shortfall Until 2020.)
VALLEY FORGE, Pa. — Capacity Performance resources cleared at $151.50/MW-day in the transition auction for the 2017/18 delivery year, PJM said Wednesday, calling the results “demonstrably competitive” at nearly $60/MW-day below the RTO’s price cap.
The results meant at least a temporary reprieve for Exelon’s Quad Cities and Byron nuclear plants, which cleared the transition auction after failing to clear in the Base Residual Auction for 2017/18. Exelon said Thursday morning that all of its nuclear plants in PJM cleared in the transition auction and that the company will defer any decisions about the future of Quad Cities and Byron for one year.
PJM held the auction Sept. 3-4 to obtain CP resources for 70% of the updated reliability requirement for 2017/18, procuring its target of about 112,195 MW, said Stu Bresler, senior vice president for markets. The clearing price cap was $210.83/MW-day, or 60% of the net cost of new entry.
Bresler said the results showed “a very steady, very rational progression of clearing prices given the steadily increasing proportion of our reliability requirement that we procured as Capacity Performance for these three delivery years.”
The transition auction for 2017/18, which cleared $17.50/MW-day higher, procured 70% of total requirements. Neither transition auction had locational restraints.
In the Base Residual Auction for 2018/19, where 80% of resources were CP, most of the RTO cleared at $164.77.
New Generation in COMED, ATSI Zones
Total capacity offered into the 2017/18 transition auction was 133,769 MW. Of the capacity that cleared, 102,178 MW represented resources committed in previous auctions that now will be converted to the new product at a higher price.
About 10,000 MW of the CP that cleared were from resources that did not clear in the Base Residual Auction in 2014, less than 9% of the total.
Bresler said most of the newly cleared generation was in the COMED (almost 4,000 MW) and ATSI (more than 2,300 MW) zones.
“I think it was fairly well publicized after the Base Residual Auction for ’17/18 the resources that did not clear,” he said. “It just speaks to those that were available to do so in this particular auction from those zones. And I think that’s what we saw.”
PJM reported that 4,339 MW of nuclear cleared for the first time in the transition auction.
Exelon confirmed that Byron Units 1 and 2 (2,336 MW) and Quad Cities Units 1 and 2 (1,737 MW) in Illinois, which did not clear the BRA for 2017/18, were among the winners this time around. (See How Exelon Won by Losing.)
The company said Thursday that it will continue operating Quad Cities through at least May 2018. Byron is already obligated to operate through May 2019. It said it will bid all its eligible nuclear plants, including Quad Cities, Byron and Three Mile Island into the 2019/20 BRA next year.
“While Quad Cities and Byron remain economically challenged, we are encouraged by the results of the recent capacity auctions. The new market reforms help to recognize the unique value of always-on nuclear power, while preserving the reliability of our electric system,” Exelon CEO Chris Crane said in a statement. “However, these plants are long-lived assets with decades of useful life left, and today’s decision is only a short-term reprieve. Policy reforms are still needed to level the playing field for all forms of clean energy and best position the state of Illinois to meet [the Environmental Protection Agency’s] new carbon reduction rules.”
The company said it will “continue its dialogue” with Illinois policymakers for state support for the nuclear units.
New Coal Also Clears
Some 4,165 MW of coal-fired generation also cleared for the first time in the transition auction.
In total, coal cleared 37,455 MW; gas 35,298 MW; and nuclear 29,970 MW.
Higher percentages of energy efficiency (almost 28%) and demand response (65%) came from new rather than previously cleared resources. Of 700 MW of DR acquired, 455 MW represented new commitments.
“I can’t really speculate on the drivers there,” Bresler said. “My hypothesis, I guess, would be that these demand response providers have since the Base Residual Auction for ’17-18 found additional resources that could provide the Capacity Performance level of reliability and therefore offered those resources into the auction.”
$1.7 Billion Increase
The Base Residual Auction for 2017/18 — held in 2014, before the introduction of the tougher CP requirements — cleared at $120/MW-day in most of PJM, with the PSEG locational deliverability area at $215. (See Capacity Prices Jump Following Rule Changes.)
The incremental cost of the transition auction was $1.7 billion, below the estimate of $3.1 billion to $4.2 billion PJM and the Market Monitor had predicted, Bresler said.
Independent Market Monitor Joe Bowring declined to comment on the results aside from saying that they were consistent with the rules. He said his office is working on a comprehensive report on all three CP auctions.
Walter Hall, of the Maryland Public Service Commission, said his agency is keeping an eye on how the prices will affect consumers. “Obviously, it’s going to increase prices somewhat,” he said. “That is a negative. It is a problem, but it’s a problem we knew was coming.”
Dan Griffiths, executive director for the Consumer Advocates of PJM States, said he still had to review the numbers.
But, he said, “I don’t think our position has changed, that this was an extremely excessive solution to the problems we faced.”
PJM, he said, “never considered the impact on consumers.”
Higher Risks, Rewards
The Capacity Performance construct allows capacity resources to receive higher prices in exchange for taking on stiffer penalties for non-performance.
The transition auctions, part of a five-year shift leading to 100% CP for the 2020/21 delivery year, had been delayed in order to allow DR and energy efficiency resources to participate, per a FERC order.
Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the Base Residual Auctions for those years as Capacity Performance resources.
The RTO’s 2018/19 Base Residual Auction, the first BRA under the CP rules, saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.
CP resources were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL LDA, the premium was $90. (See PJM Capacity Prices Up 37% to $165 /MW-day.)
CAMBRIDIGE, Mass. — PJM’s 2016/17 transition auction results were released shortly after the stock market closed at 4 p.m. Monday — coincidentally during an EUCI conference in Cambridge, Mass., that attracted PJM Market Monitor Joe Bowring, PJM Senior Economic Policy Advisor Paul Sotkiewicz and Jim Wilson, a consultant to consumer advocates in the RTO.
Wilson, a featured speaker, reported — critically — on the results shortly after they were released, sparking a lively debate with Sotkiewicz. Bowring, uncharacteristically, declined to offer an opinion.
“Unfortunately, the way [PJM] ran the auction, instead of paying people $10, $20, maybe $30 [per MW-day] to upgrade their capacity commitment to Capacity Performance, they created a new clearing price of $134/MW-day, paid to everybody,” Wilson said.
“Of the 95,000 MW that cleared, almost all of it was in the RTO region and not in [MAAC], and they were able to go from $60 their previous clearing to $134. They basically get a $60 windfall — or about $1.7 billion,” Wilson said, concluding: “Very inefficient.”
That sparked a response from Sotkiewicz, who had appeared on an earlier panel with Bowring — both of them already aware of the results but sworn to secrecy until their release.
Sotkiewicz said that during the January 2014 polar vortex, “a lot of [the high generator outages were] coal resources in the west, gas generators in the west who were behind the [local distribution company] city gate who had no firm transportation to the city gate. Even if they did, they could be curtailed by the LDC. [They] also didn’t have dual-fuel capability.
“So, quite to the contrary, a lot of the problems that we did see were in the west during January. So to say that [the CP acquired was] in the west and it’s useless I think is disingenuous and incorrect.”
Asked for his opinion on the “efficiency” of the auction after the conference ended, Bowring seemed uncharacteristically tongue-tied, pausing and exchanging glances with Sotkiewicz.
“We’ll be doing a report on it fairly soon and have a detailed analysis,” he said finally. “It’s hard to tell just looking at the prices. We reviewed the outcome. The outcome was consistent with the rules.”
The Independent Market Monitor for the Regional Greenhouse Gas Initiative found no evidence of anti-competitive conduct in the CO2 allowance secondary market, according to its “Report on the Secondary Market for RGGI CO2 Allowances: Second Quarter 2015.”
Potomac Economics found the average CO2 allowance futures price was $5.53, 2% higher than in the first quarter and 19% higher than in the second quarter of 2014. Prices ranged between $5.30 and $5.60 from April until Auction 28 in early June, and then prices increased steadily during June and reached $5.80 at the end of the quarter.
The report addresses the period from April to June 2015. It is based on data reported to the Commodity Futures Trading Commission and the Intercontinental Exchange, as well as other data.
Consumer Agency Objects to IPL’s Payments to Parent
The Office of Utility Consumer Counselor has asked regulators to deny Indianapolis Power & Light’s 5.6% rate hike request that would generate $68 million more per year, saying IPL deserves only a fraction of that — just $6 million more a year.
The state agency representing consumers alleges the utility has given lip service to asset management while sending $507 million in dividends to parent AES between 2010 and 2014. Since 2010 there have been 14 fires or explosions of IPL equipment, including some events that launched manhole covers into the air in crowded downtown Indianapolis.
The consumer advocate told the Utility Regulatory Commission it doesn’t think IPL has done enough to improve maintenance of its system. IPL countered that it has made numerous upgrades, including locks to keep manhole covers earthbound. IPL has not had a rate case since 1995.
Local Officials Shoot Down Black Hawk County Wind Project
The Black Hawk County Board of Adjustment last week rejected a proposed wind farm, citing residents’ concerns about health, decreased property values and dangers to wildlife.
An attorney for the project’s developers, Optimum Renewables, said there was no evidence that industrial turbines could endanger people or wildlife and said the harm to eagles and birds was exaggerated.
Co-op Rolls over on Solar Fee After Customers Complain
Pella Cooperative Electric is withdrawing its plan to charge customers with solar panels an extra $57.50/month after the plan touched off a firestorm of complaints. Pella notified the state Utilities Board that it was withdrawing the tariff it had filed earlier this year.
All Pella residential customers currently pay a $27.50 fixed monthly fee, and the co-op had wanted to increase that fee to $85 for solar customers. Pella maintained the fee was a fair way to assign costs of operating its system to users. “We have decided to withdraw the proposed increase on the facility charge for members who own or lease distributed generation until such time that we can better educate our members and the community as to the fair and equitable recovery of fixed costs,” it said.
Solar customers rejoiced. “It kinda made my day,” hog farmer Bryce Engbers said. He added he would have taken the solar arrays off his barns rather than pay the increased fee.
By a 4-1 vote, the Public Service Commission approved a merger of Entergy Louisiana and Entergy Gulf States Louisiana. Company officials said the merger of the Entergy subsidiaries will result in up to $140 million in consumer benefits over the next nine years, including $107 million in bill credits.
The lone dissent was Commissioner Foster Campbell, who said he thought it unfair that residents and customers in the northern part of Louisiana will now be charged to help repair equipment damaged by storms that hit the southern Gulf Coast side of the state included in the Entergy Gulf States service territory.
Entergy Louisiana has about 700,000 customers. Entergy Gulf States Louisiana has about 400,000 electric and 93,000 gas customers.
Despite prodding from the state Commerce Department, Xcel Energy has approved just one community solar garden project, which has not yet been built.
The state issued a 2013 mandate to encourage development of community solar. Utility companies need to review and approve each proposed solar facility, and Xcel is currently reviewing 1,100 solar facilities.
Sunrise Energy Ventures, a Minnetonka-based solar developer, complained to state regulators about Xcel’s delay in approving its proposal. SunShare, another community solar developer, and Sunrise each have submitted plans to build 100 MW of solar gardens that collectively would serve more than 30,000 Xcel customers.
The Borough Council of Bloomingdale has introduced an ordinance that would prohibit unregulated pipelines from being built or operated in the borough, a move to discourage the Pilgrim Pipeline from locating within municipal boundaries.
The borough and its residents have been actively fighting construction of the proposed Pilgrim Pipeline, a dual, 178-mile petroleum pipeline that would carry crude oil from a rail terminal in Albany, N.Y., southward to a refinery in Linden, N.J., and refined products back to Albany. The pipeline would replace Hudson River barges, which now move most of those products.
As a petroleum pipeline, the Pilgrim project is not subject to approval by FERC.
Shale wells in the state produced record amounts of oil and natural gas in the second quarter of this year, the state Department of Natural Resources reported last week.
The state reported that more than 10 million barrels of oil and 405 billion cubic feet of natural gas were produced. During the same period in 2014, wells produced about 4.4 million barrels of oil and 156 billion cubic feet of natural gas.
Clean Air Council Suing Sunoco over Eminent Domain Use
The environmental group Clean Air Council is suing the developers of a planned 350-mile natural gas liquids pipeline in the state in an attempt to block it from invoking eminent domain to gain access to properties owned by uncooperative landowners.
The group argues that Sunoco Logistics Partners, developers of the planned Mariner East 2 pipeline, is not a public utility corporation and cannot invoke eminent domain. But the Public Utility Commission has ruled that the partnership’s subsidiary, Sunoco Pipeline, is a public utility, which Sunoco maintains gives it the authority to acquire easements through eminent domain.
Capital spending to comply with the Obama administration’s environmental regulations is dinging the credit outlook for Alliant Energy, parent company of Wisconsin Power and Light and Interstate Power and Light in Cedar Rapids, Iowa.
Moody’s Investors Service has changed its outlook for Alliant to negative from stable. “The negative outlook on the Alliant family’s ratings reflects financial metrics that are weak for their ratings and likely to deteriorate over the next few years as its utility subsidiaries incur incremental debt to finance their extensive, multi-year capital expenditure plans,” analyst Lesley Ritter said. If trends continue, Moody’s said, Alliant’s A3 senior secured rating “would likely be more appropriately reflected in a Baa1 rating.”
Since 2011 Alliant has invested $1 billion in environmental retrofits and is projected to spend up to $1.8 billion more to build gas-fired generating units to replace aging coal and gas units.
DTE Energy is planning to build a 2,800-panel solar farm in Ypsilanti, Mich., by the end of next year. The 800-kW facility would power about 150 homes.
DTE says it’s the largest solar developer in Michigan, with 10 MW from 22 sites in the southeast part of the state. The utility said it has now met a state-mandated renewable portfolio standard.
The company did not release the estimated cost of the Ypsilanti project.
Duke Energy’s South Carolina Transmission Project Draws Angry Opponents
A Duke Energy proposal to build a 45-mile transmission line and a new substation in South Carolina to serve growing demand in western North Carolina drew about 800 people to a public hearing.
Most of the speakers at the South Carolina Public Service Commission’s hearing oppose the project. Their objections include the line’s location, the technique or type of transmission line or the very fact of its planned existence.
Bill Mills of Caroland Farms in South Carolina said he has studied all of the options and concluded that “the best solution for the Carolinas is to have this project canceled.”
Philadelphia Businessmen Buy Retired Exelon Plant for Hotel Project
Two Philadelphia businessmen, operating under the moniker Delaware Station LLC, have put down $3 million for the old Delaware Generating Station, formerly operated by Philadelphia Electric Co. They hope to convert the 16-acre property on the Delaware River to one or more hotels, as well as a shopping and catering complex.
Joseph Volpe and Bart Blatstein are the listed owners. Although there remain some small gas-fired turbines on the site, the main generating equipment at the station was retired decades ago.
FirstEnergy Starts Demolishing Cleveland’s Lake Shore Plant
FirstEnergy has begun tearing down its retired Lake Shore Generating Station in Cleveland, a process that is expected to take about 16 months. The first steps are a full site survey and the demolition of several smaller outbuildings.
The former coal-fired power plant went into service in 1911 and was officially retired earlier this year. FirstEnergy plans to retain the property for alternative uses, a company spokeswoman said. While all generating equipment will be removed, some transmission equipment will remain on the site.
BP restarted a crude distillation unit at its giant Indiana refinery near Chicago last week, a move that is expected to put the brakes on spiking gasoline prices in the Midwest.
The unit at the Whiting, Ind., refinery was shut down Aug. 8 for repairs, which took longer than expected. The extended outage of the 413,500-barrel-per-day refinery, BP’s largest in America, caused fuel shortages that sent pump prices skyward.
Dominion Resources, owner of Millstone Station nuclear plant, has reached a settlement with the Nuclear Regulatory Commission for its decision to halt the use of a safety-related pump in the event of a severe accident.
NRC on Thursday cited a “willful violation” for changes Dominion made without regulatory approval at its Millstone Unit 2 plant in Waterford, Conn. A Millstone spokesman said Dominion does not agree that the violation was deliberate.
Dominion agreed to change plant procedures governing the operation and testing of the charging pumps and provide complete and accurate information. Regulators said they became aware in September 2011 that Dominion submitted requests for approval of changes to the Unit 2 operating license that were incomplete and inaccurate.
Two studies released last week came to opposite conclusions on the need for additional natural gas pipeline capacity in New England.
The results were unsurprising: One study was funded by domestic natural gas producers; the other by a liquefied natural gas importer.
GDF SUEZ
One report, funded by GDF SUEZ Energy North America, which operates an LNG import terminal in Everett, Mass., concluded that the region has adequate pipeline capacity to meet winter power demand, especially if contributions from dual-fuel-capable generation and LNG are expanded.
Studies sponsored by domestic gas producers and a gas importer came to unsurprisingly opposite conclusions about the need for additional pipelines in New England.
The report, written by international consultant Energyzt Advisors, is highly critical of the proposal embraced by several New England governors to help fund added natural gas infrastructure with a tariff assessed on electricity ratepayers. (See New England Governors Revise Energy Strategy.)
“The proposed electricity ratepayer funding of additional gas pipeline capacity is an expensive and dangerous proposition in terms of ratepayer cost and healthy market function in New England,” the report says.
ANGA, API
The second report, sponsored by America’s Natural Gas Alliance and the American Petroleum Institute, which represent domestic oil and gas producers, says that the region will pay $5.4 billion in higher energy costs (2014 dollars) between 2016 and 2020 unless more pipelines and other infrastructure are built.
“The $5.4 billion in added costs will ramp up from 2016 through 2020, increasing the region’s electricity and natural gas costs by 9% in 2020, according to forecasted energy demand and costs,” says the report, written by Boston-based LaCapra Associates and the Economic Development Research Group.
It was issued by the newly formed New England Coalition for Affordable Energy, which also includes business groups, real estate interests and a utility workers union.
New England’s governors and ISO-NE have said existing pipelines are inadequate to supply the generation base, especially as more natural gas generation enters the power plant portfolio and older coal-fired plants retire.
The GDF SUEZ report says pipeline projects already underway are enough to meet peaking needs. It cited several projects, including Spectra Energy’s Algonquin Incremental Market Project and the Atlantic Bridge Project, which are expected to increase capacity by 600 million cubic feet per day by the winter of 2017-2018. (See Hearing on Algonquin Pipeline Expansion Highlights Local, National Issues.)
Winter Reliability Program
ISO-NE has used a winter reliability program the past two years to combat tight natural gas supplies that are diverted to heat homes and businesses on the coldest days. The program has created incentives for LNG use and for power generators to store oil on-site for plants that can burn either fuel. The GDF SUEZ report also cites ISO-NE’s Pay-for-Performance program, set to debut in 2018, as another reason additional pipelines are not needed.
“The issue is not lack of infrastructure but insufficient commercial contracts to access existing energy,” the report says. “The market is responding with dual-fuel capability and LNG contracts. This past winter 2014/15 has demonstrated the powerful ability of competitive natural gas and electricity markets to respond to price signals,” it adds.
The ANGA/API report counters that energy infrastructure constraints have cost the region at least $7.5 billion over the past three winters. “Pipeline infrastructure has not kept pace with this increased demand and is reaching maximum capacity, especially during the winter months, to meet both electricity generation and space heating demands,” it said.
The authors said their study is more comprehensive than other analyses that considered only a single type of infrastructure. It includes a scenario in which no new additional infrastructure investments are made and an “unconstrained” case assuming $9 billion in spending for natural gas pipelines, electric transmission and generation.
A federal district court judge in North Dakota has blocked the Environmental Protection Agency’s new water pollution rule just hours before it was to go into effect. Judge Ralph Erickson issued a preliminary injunction blocking implementation of the rule in 13 states that had joined the suit. But a day earlier, a judge in West Virginia ruled in favor of the Obama administration and declined to interfere with EPA’s rule.
The lawsuits are among 10 court challenges against the water rule filed by 29 states, along with groups representing the energy industry, real estate developers, farmers and others. The cases have been consolidated into one lawsuit at the Court of Appeals for the Sixth Circuit in Cincinnati, but Erickson argued that he could still issue his injunction.
The so-called Waters of the United States rule redefines and expands EPA’s jurisdiction under the Clean Water Act. An EPA spokeswoman said the rule would go into effect in the states that did not join the suit blocking the rule. The 13 states where the rule is on hold are: Alaska, Arizona, Arkansas, Colorado, Idaho, Missouri, Montana, Nebraska, Nevada, New Mexico, North Dakota, South Dakota and Wyoming.
US Economic Growth at 9-Year High, If You Ignore Energy
The U.S. economy grew at the fastest rate in nine years — if you don’t count energy, according to Bloomberg Business.
The plunge in oil and natural gas prices, along with the bleak outlook for coal, show an energy sector under pressure.
Investment in oil and mining projects by corporate investors fell 68% between April and June, following a 44.5% plunge for the January to March period.
Penn State Gets $2.9 Million to Study New PV Panels
Electrical and mechanical engineering teams at Pennsylvania State University are working with experts at the University of Illinois and a photovoltaics company in Durham, N.C., to develop the next generation of solar panels, inspired by technology used in spacecraft.
The teams have received $2.9 million from the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) to work on what they call “fixed-tilt photovoltaic cells.” The cells use plastic “lenslets” and a tracking system that follows the sun to concentrate sunlight at 400 times intensity. The panels are constructed of common materials, such as Plexiglas, which reduces construction costs.
The technology aims to exploit the high-efficiency solar cells installed on spacecraft to generate power.
President Obama used his platform at last week’s National Clean Energy Summit in Las Vegas to urge further investment and research on renewable energy. “This is not the time to pull back” on working on renewable technology and implementation, he said.
“We refuse to surrender the hope of a clean energy future to those who fight against it,” he said. He noted that some firms that used to be concentrated on fossil fuel technology, such as Southern Co., are beginning to make serious investments in renewable energy.
Increasingly, individuals are driving the movement, he said. “People are beginning to realize they can take more control over their own energy — what kind they use, how much and when,” he said.
Appeal of EPA Clean Power Plan on Accelerated Timetable
The D.C. Circuit Court of Appeals panel hearing challenges to the Environmental Protection Agency’s Clean Power Plan have agreed to an expedited pace for the case and ordered both sides to file their major legal arguments before the Labor Day weekend.
Those challenging the plan — state and industry groups — say the expedited schedule puts them at a disadvantage. States challenging the Clean Power Plan said the Aug. 3 promulgation of the rule is forcing them to develop sweeping regulatory changes before the legal challenges to the rule are heard.
Some observers say EPA’s push for a hurried schedule can be attributed to the planned global summit on climate change to be held in December in Paris. The Obama administration’s EPA says it wants the rule in place before the summit so that it “shows the world that the United States is committed to leading global efforts to address climate change.”
Schumer Proposes Extension, Changes to Solar Tax Credit
Schumer
Sen. Charles Schumer (D-N.Y.) is proposing changes to the federal solar investment tax credit that would extend the credit and make it apply to more businesses.
The tax credit, scheduled to phase down from 30% to 10% after 2016, would be extended “beyond 2016,” he said. One reason for the longer timetable is to allow large-scale solar projects to develop. A phase-down of the credit is making it difficult for developers to secure financing.
Schumer also wants the tax credits to apply earlier in a project’s life than currently allowed, which provides that solar-panel owners can get tax credits only when the system is placed in service. In contrast, wind tax credits are applied as soon as a project begins construction.
ST. PAUL, Minn. — MISO has a pile of 22 active recommendations made over the years by its Independent Market Monitor, all in various stages of progress.
One, which would optimize the interchange and improve price convergence with PJM and SPP, dates back to 2005.
“We are working through all those,” Jeff Bladen, MISO’s executive director of market design, said at last week’s Markets Committee of the Board of Directors. Bladen said action on some items has been delayed by technology upgrades and others by the need to reach agreement with neighboring regions.
His update on the status of Monitor David Patton’s State of the Market recommendations was instructional about the roadblocks that can stand in the way of even what arguably are the best ideas.
Dependencies
Of 15 past recommendations through the 2013 State of the Market Report, MISO is working to implement six. Two are “externally dependent” and the other two are “infrastructure-dependent.” Five are still being evaluated: one from 2008 and two each from 2010 and 2012.
Perhaps the best-known externally dependent recommendation is to eliminate the hurdle rate involving transfer of power between MISO’s southern and central regions, the subject of settlement talks with SPP. The IMM has recommended collecting transmission costs that may be payable to SPP and other parties under the settlement through a fixed charge. (See related story in MISO Market Committee Briefs.)
As an example of an infrastructure-dependent recommendation, Bladen cited a five-minute real-time settlement for generation, which he said is dependent on rule changes and replacement of the RTO’s settlement software. A virtual spread product is another example.
Board Chair Judy Walsh called for urgency on technology upgrades needed to address some recommendations, saying they should be identified by staff and vetted by the board “sooner rather than later.”
Director Baljit “Bal” Dail said he was curious if MISO tracks the time it takes to “close out” a recommendation. “I’m just trying to get a sense of [whether] things are progressing at the pace they should be progressing,” Dail said.
Bladen said MISO does not have such a metric but that it might be worth considering.
ELMP
Director Paul Feldman noted a past recommendation that has come to fruition — extended LMP — and asked whether it has achieved expectations.
ELMP allows fast-start resources that are either scheduled at limits or offline to set price, an effort to smooth price spikes and minimize uplift. (See “Extended LMP Starts” in MISO Board of Directors Markets Committee Briefs.)
Bladen said ELMP “has met our rather modest” expectations since it was initiated March 1. “We’ve seen noteworthy changes in price that reflects the kind of change we would have thought should occur given the design,” he said.
Bladen said MISO staff would provide a fuller report at the November Markets Committee meeting, when it will have eight months of operating data under the new rules.
Director Michael Curran drew laughter when he recommended that MISO provide a “scientific, wild-ass guess” as to when a recommendation might be completed.
Curran also recommended that staff include a chart indicating what recommendations have already been implemented. “Otherwise you’re just looking at backlog and not really getting the credit you should for the successes you’ve had,” he said.
