VALLEY FORGE, Pa. — A months-long debate over whether to create “historic” capacity rights for some load-serving entities took a twist last week when PJM staff returned with a different proposal angled to achieve the same result.
“This has very little similarity, if any, to the previous approach,” PJM’s Jeff Bastian told the Market Implementation Committee on Wednesday.
PJM has been wrestling with how to help the Illinois Municipal Electric Agency meet its internal resource capacity requirements when it needed to use resources located outside of the Commonwealth Edison locational deliverability area to serve its Naperville, Ill., load. (See PJM Debate over ‘Historic’ Capacity Rights Gets a Face: IMEA.)
After failing to gain traction with skeptical stakeholders, staff veered from the notion of “historic” capacity to recommend a proposal that would apply only to Fixed Resource Requirement (FRR) entities — LSEs permitted to avoid direct participation in the Reliability Pricing Model auctions by meeting their capacity requirements using internally owned resources.
Under a proposal approved by PJM, the Independent Market Monitor and IMEA, the internal capacity requirement would not have an effect unless there was price separation for the relevant LDA.
IMEA will put in its offer after PJM defines the auction parameters. If its LDA has price separation when PJM clears the auction, it will be required to meet the internal requirement for the next auction, avoiding the internal capacity rule for only one auction, Market Monitor Joe Bowring explained.
The changes put IMEA where it was before PJM changed the rules regarding the trigger for the internal capacity requirement.
“Within an LDA that is being modeled separately, for reasons other than [Capacity Emergency Transmission Objective or Capacity Emergency Transmission Limit] threshold test or non-zero locational price adder in past three auctions, the FRR entity would not be subject to an internal minimum requirement until the first year after the LDA actually in an auction — or they could resort back to RPM the following year,” Bastian said.
Stakeholders, however, asked for more information regarding the thought process behind the changes before they considered approval.
Committee members were presented with the first read of three competing proposals addressing the issue of how to compensate Tier 1 synchronized reserves.
Since October 2012, Tier 1 reserves have been compensated at the synch reserve market clearing price (SRMCP) when the non-synch reserve market clearing price (NSRMCP) is greater than $0. While Tier 1 reserves are paid the same as Tier 2, only the latter is subject to penalties for non-performance.
The problem statement the proposals seek to solve asks whether it’s appropriate for such reserves to be credited when they are not responding to a synch reserve event, and if so, how much? (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
Tier 1 reserves are made up of on-line resources that are able to ramp up from their current output within 10 minutes in response to a synchronized reserve event.
The proposals come from PJM, the Independent Market Monitor and PJM’s Industrial Customer Coalition.
The PJM proposal would retain the status quo of paying Tier 1 reserves the SRMCP when the NSRMCP is greater than zero. The ICC recommends paying the non-synch reserve price in that scenario. The Monitor says Tier 1 resources should not be paid except during a synch reserve event.
PJM’s proposal alone would impose an obligation on Tier 1 resources to respond, with a refund owed for nonperformance.
Independent Market Monitor Joe Bowring said the payments to Tier 1 resources are an unnecessary “windfall” that have totaled up to $15 million in the first quarter of this year alone.
“There’s no reason to pay Tier 1 anything additional than what they’re being paid now,” Bowring said. “That’s fully compensatory for what they’re doing.”
Changes Would Allow Earlier Replacement Transactions
The committee will be asked to vote at its next meeting on manual changes that would allow replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year.
Such replacements would be permitted when the owner of the replaced resource could show the expected final physical position of the resource at the time of the request.
Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project is cancelled or delayed. Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.
Resources replaced would not be able to be recommitted for the delivery year.
VALLEY FORGE, Pa. — PJM will propose a two-tiered fee schedule for proposed transmission projects, officials told the Planning Committee last week.
Instead of asking for $30,000 to study any project costing at least $20 million, it will request that amount only for projects of at least $100 million.
For projects between $20 million and $100 million, PJM will recommend collecting a fee of $5,000.
The $30,000 fee proposal was approved Feb. 26 by the Markets and Reliability and Members committees after the Federal Energy Regulatory Commission rejected as discriminatory a previous plan to apply the charge to all greenfield projects but not upgrades of less than $20 million. (See FERC Rejects Fee on Greenfield Transmission Projects.)
“Because we put this threshold in place, we were going to be collecting for a larger number of projects,” PJM’s Fran Barrett told the committee. “Staff said that we could find ourselves over-collecting.”
The Planning Committee will be asked to approve the proposal, which would be tested over a two-year period, at its next meeting on July 9.
The fee schedule would be applied based on the cost estimates presented by those proposing the projects.
“If it turns out that a lot of people are trying to get around that with [estimates of] $99,999,000 we’ll have to revisit it,” said Steve Herling, vice president of planning.
Task Force Would Create Standards for Order 1000 Projects
A problem statement and issue charge introduced on first read Thursday would create a task force to develop minimum design standards for competitively solicited greenfield projects under FERC Order 1000.
The idea arose from concern that the designated entities for such projects would not be required to follow the design standards of the zonal transmission owner.
“We don’t want this new product to fix one problem but introduce a weak point in the system,” PJM’s Suzanne Glatz said, reflecting stakeholder feedback.
The design standards would apply to transmission lines, substations, and system protection and control design and coordination. They would take into consideration geography and physical and local needs of the project.
The task force would be open to all PJM stakeholders and would report to the Planning Committee.
Still Searching for Ways to Incent Early Project Submissions
The committee endorsed a problem statement and issue charge to find ways to incent customers to submit transmission projects earlier in the queue window.
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The issue will be assigned to the Planning Committee, which will have three to six months to identify better incentives to encourage earlier participation. (See PJM to Try Again to Speed Interconnection Filings.)
The imposition of non-refundable fees that escalate later in the queue window have had little effect on changing participants’ behavior, said Dave Egan, manager of interconnection projects.
Meanwhile, those who have done their due diligence in their submittals are being held up by late, deficient entrants, PJM says.
The Federal Energy Regulatory Commission last week rejected requests by two PJM generators seeking the recovery of “stranded” natural gas costs incurred during the polar vortex last year.
But the commission also ordered PJM to change its Tariff to allow generators to submit day-ahead offers that vary by hour and to update their offers in real time. PJM is the only RTO that doesn’t allow such variable offers.
Duke Energy (EL14-45) and Old Dominion Electric Cooperative (ER14-2242) both argued that they were owed compensation due to the events of January 2014, when a cold snap sent gas prices soaring. Duke purchased $12.5 million worth of natural gas for its Lee plant in Illinois, only to have it not called on in real time. Similarly, ODEC complained that PJM canceled multiple dispatches that left gas it had purchased for its plants unused.
ODEC also said its plants’ operating costs on Jan. 23, 2014, exceeded what it could recover in the day-ahead market due to the $1,000/MWh offer cap at the time. The co-op asked for an extension of the waiver FERC granted PJM on Jan. 24, which allowed capacity resources to receive make-whole payments if their costs exceeded the offer cap for a limited time.
Duke, which was able to resell some of its gas, sought $9.8 million, while ODEC said it was due nearly $15 million.
Different Arguments, Same Result
While PJM supported the companies receiving one-time waivers, FERC denied both requests, citing its rules against retroactive ratemaking. The commission said that in both cases, ratepayers had not given prior notice that they would be responsible for natural gas-related costs.
Additionally, FERC disagreed with Duke’s assertion that it was due indemnification under section 10.3 of the PJM Tariff, which the company claimed required PJM to hold it harmless for obligations to third parties as a result of directives from the RTO. Duke told FERC that PJM had effectively ordered it to buy gas on Jan. 27, as it was likely Lee would be called upon to maintain reliability.
Although PJM supported the waiver requests, it said it was not permitted to provide Duke relief under the Tariff. “Any extension of section 10.3 to cover the type of loss Duke incurred under the circumstances at issue would read the indemnification provision into a blanket insurance policy for losses of whatever sort, caused by accident, act of God or plain misfortune that a market seller may incur in responding to PJM dispatch,” PJM told FERC in response to Duke’s complaint. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
FERC agreed with PJM’s interpretation of the section. “The PJM indemnification provision should not be interpreted to guarantee reimbursement of a generator’s losses on gas purchases incurred in meeting its capacity resource obligations in PJM,” the commission said. “Fulfilling its energy market commitments are among the risks the generation capacity resource has assumed … when choosing to participate in the market.”
FERC also disputed Duke’s claim that PJM’s communication with Duke on Jan. 27 constituted a “directive” by the RTO. FERC said that PJM was merely advising that Lee was likely to be dispatched for reliability reasons.
And while PJM’s Independent Market Monitor objected to ODEC receiving compensation for its purchases of gas, it supported the co-op’s request to extend FERC’s waiver by a day in order to receive $2.7 million in make-whole payments. FERC said it saw no difference between the requests.
Offer Flexibility
FERC, however, found that PJM’s Tariff may be unjust and unreasonable because it does not allow generators to submit offers in the day-ahead market that vary hourly or to update their offers in the real-time market. ISO-NE gave its generators that flexibility in December, leaving PJM as the only RTO that does not allow such changes. (See related story, ISO-NE Prices Down Sharply in Q1; Generators Using Offer Flexibility Rule.)
The commission said it expects PJM to implement new rules allowing such changes by Nov. 1 and said refunds would be effective with the order’s publication in the Federal Register. PJM was ordered to report within 30 days on its planned response (EL14-45, EL15-73).
Commissioner Philip Moeller agreed with the majority that PJM’s Tariff was potentially unjust due to the lack of offer flexibility, but he said that he was “troubled” that it was unwilling to grant the companies any relief.
PJM’s “inflexibility contributed to the inability of generation units … to recover legitimate fuel costs,” Moeller said in his dissents to the orders. The companies “acted in good faith to preserve system reliability during a time of extraordinary system stress and deserve appropriate compensation.”
Moeller also said that the majority ignored the companies’ arguments and applied “an overly narrow reading of the prior notice rule and prohibition against retroactive ratemaking to find that ratepayers somehow lacked adequate notice that they would, in fact, be responsible for paying the cost of services provided to them to ensure resource availability during system emergencies.”
The complaints should have at least been set for hearing and settlement judge procedures, he said.
The second transmission line proposed to bring Canadian hydropower into the Northeast under Lake Champlain has advanced with the release of its draft environmental impact statement.
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The New England Clean Power Link, proposed by Transmission Developers Inc.-New England (TDI-NE), is a high voltage, direct current line that would transport 1,000 MW of electricity 154 miles from Quebec to Ludlow, Vt. Ninety-eight miles of the cable would be buried under Lake Champlain, and most of its land-based route would be underground.
The U.S. Department of Energy released the draft on June 3 for the $1.2 billion for the project, which it says should be issued a Presidential Permit, required for the border crossing.
TDI also is planning another 1,200-MW line using a path underneath the lake and through existing rights-of-way to New York City. This project is furthest along the regulatory path, having received its final permits in April. (See Quebec-NYC Tx Line Clears Final Regulatory Hurdle.)
A third high-voltage transmission line proposed to transport Canadian hydropower into the Northeast, Eversource Energy’s Northern Pass in New Hampshire, is expecting its final EIS next month, as its review is taking longer than expected to complete. (See Eversource: Northern Pass Delayed Until ’19; Earnings Up.)
TDI-NE touts the Vermont project as a way to deliver renewable energy from Canada to the ISO-NE market. The company estimates that the regulatory process will take until the end of the year, with construction starting in 2016. The project is expected to be in service by 2019.
TDI-NE still needs permits from Vermont and has yet to announce customers for its electricity.
The release of the draft opens a 60-day comment period that is scheduled to close on Aug. 11.
Connecticut environmental officials are at odds with utility regulators over whether the state should seek cleanup of an abandoned power plant as a condition for Iberdrola’s acquisition of UIL Holdings.
Attorney General George Jepsen, the state Department of Energy and Environmental Protection and the City of New Haven see the merger as the best chance to clean up the contaminated site in the city, but the Public Utilities Regulatory Authority doesn’t seem inclined to force the issue.
Spanish conglomerate Iberdrola announced in February it would acquire UIL Holdings, which has electric and gas units in Connecticut and Massachusetts, in a $3 billion cash and stock deal. (See Iberdrola Broadens Northeast Footprint in $3B UIL Deal.)
English Station
The power plant that has emerged as a flashpoint is the English Station, a coal- and oil-fired generator that dates to the 1920s and sits on a man-made island in the Mill River. The plant was shut down by United Illuminating, the electric utility subsidiary of UIL, in 1992 and sold eight years later.
The new owner intended to revive the plant, but environmental problems killed that plan. It was later sold to a real estate developer.
State environmental regulators have closed the site pending an estimated $30 million cleanup of toxins. DEEP’s environmental remediation order for the site — while not yet final — would require UI and the subsequent owners to clean up the site.
In a brief filed June 5, the attorney general said the state should require the merger applicants to place $30 million in an escrow fund to pay for cleanup of the site, with an additional promise that Iberdrola pay any additional costs more than that amount. Jepsen said UIL “bears a significant portion of responsibility” for the contamination.
The utilities and PURA say that the environmental issues are beyond the scope of the merger.
‘Devoid of Evidence’
In a reply filed Friday, the companies rely on a recent PURA order that removed English Station from the merger’s consideration. “The record is devoid of any evidence upon which the authority could base a condition such as that recommended by the AG. As such, the authority should not entertain conditions related to matters it has already decided are beyond the scope of the proceeding and its authority and upon which it has no record evidence to decide,” they wrote.
PURA had said its docket is not the “appropriate forum” on responsibility for the cleanup.
“English Station property is already the subject of pending legal actions in other appropriate forums such as [DEEP] and the U.S. Environmental Protection Agency,” it wrote in a May order.
FERC Approval
Iberdrola USA owns utilities New York State Electric & Gas and Rochester Gas & Electric in New York, Central Maine Power in Maine and significant wind power assets from coast-to-coast.
The Federal Energy Regulatory Commission approved its takeover of UIL on June 2 (EC15-103).
FERC said acquiring an electric utility in Connecticut and gas distribution companies in Massachusetts and Connecticut presented no significant concerns about the combined companies’ market power.
In the PURA docket, however, Jepsen has listed other objections to the takeover, joining the state’s consumer counsel in saying consumer benefits promised by the merging companies are elusive or non-existent.
MISO and its Transmission Owners sector have raised doubts about the eligibility of some municipal transmission owners that are seeking a 50-basis-point RTO adder, asking the Federal Energy Regulatory Commission for clarification in separate filings.
Last week, MISO filed a limited protest to a compliance filing it submitted last month on behalf of several municipal TOs who requested an adder as an incentive for RTO membership. FERC had ordered MISO to make it clear that only municipals that have turned over functional control of their transmission to MISO, or provide service over non-transferred transmission facilities with MISO acting as agent, may receive the RTO adder. MISO also said that all of the municipals who are seeking the adder fulfill these requirements.
MISO’s protest seeks to clarify that non-integrated facilities for which a TO receives credits under section 30.9 of the MISO Tariff are not eligible for the RTO adder (ER15-1067).
In its protest, the TO sector asked FERC to reject the compliance filing outright, asserting that MISO had not adequately fulfilled the commission’s requirements in its revisions.
“While the Tariff language submitted in the compliance filing appropriately limits the collection of the RTO adder, the compliance filing appears to state that certain municipals that do not meet these requirements but instead only use Attachment O of the MISO Tariff to calculate their revenue requirements for credits under section 30.9 of the MISO Tariff, are eligible to collect the RTO adder,” the TOs said.
MISO filed on behalf of the Municipal Energy Agency of Nebraska, the Central Minnesota Municipal Power Agency, Cedar Falls Utilities and about 15 member cities, boards and agencies.
An Environmental Protection Agency study of the practice of hydraulic fracturing found no evidence of widespread water supply contamination — but the agency said there is still a potential risk. The draft report detailed several instances where the practice — known as fracking, which has contributed to a domestic oil and gas boom — contaminated some drinking water supplies. It noted, however, that the number of instances was small considering the number of wells examined in the study.
The study examined more than 3,500 reports, studies, articles and other sources. It said that more than 25,000 wells were fracked each year between 2011 and 2014. EPA determined that there were about 6,800 public water systems within a mile of a fracked well.
Both supporters and opponents of fracking seized on the results. The draft report shows that “hydraulic fracturing is being done safely under the strong environmental stewardship of state regulators and industry best practices,” according to Erik Milito, director at the American Petroleum Institute. But Michael Brune, executive director of the Sierra Club, said the report vindicated arguments against the technique. “The EPA’s water quality study confirms what millions of Americans already know — that dirty oil and gas fracking contaminates drinking water,” he said.
Cardin Introduces Bill to Close Fracking ‘Loopholes’
Cardin
A U.S. senator has introduced a bill that will close what he calls “loopholes” that exempted some of the processes used in hydraulic fracturing from the Clean Water Act.
Sen. Ben Cardin (D-Md.) introduced the Focused Reduction of Effluence and Stormwater Runoff Through Hydraulic-Fracturing Environmental Regulation (Fresher) Act. Exemptions in 1987 and 2005 exempted fracking from certain provisions of the Clean Water Act involving collection and disposal of stormwater runoff and byproducts.
Environmentalists applauded the measure. “It’s well past time for the oil and gas industry to be held accountable to our core environmental laws,” Rachel Richardson, director of Environment America’s Stop Drilling Program, said in a statement.
House Republicans have crafted a spending bill that would cut the Environmental Protection Agency’s budget by 9% and slice its workforce to 15,000, down from a high of about 17,300 five years ago.
The bill, made public by the House Appropriations Committee, also covers the Department of the Interior and the Smithsonian Institution, as well as other agencies. Altogether, it set spending at $30.2 billion, about $246 million below last year’s budget and $3 billion less than the Obama administration requested.
“These reductions will help the (EPA) streamline operations, and focus its activities on core duties, rather than unnecessary regulatory expansion,” the committee said in a press release.
The Nuclear Regulatory Commission has approved DTE Energy’s plan to build and operate a new reactor at its Fermi site. Although the company has not yet committed to go ahead with the project, NRC approved plans to build a third unit at the existing 1,170-MW plant near Newport, Mich.
DTE is considering building a GE-Hitachi Nuclear Energy Economic Simplified Boiling Water Reactor (ESBWR) that will be rated at approximately 1,535 MW. It has passive safety features, such as the ability to cool itself for a week in the case of a complete power loss.
The company worked six and a half years to attain the combined operation license. The project is the fifth reactor nationwide to receive a combined license. “The potential of additional nuclear energy gives us the option of reliable, baseload generation that does not emit greenhouse gases,” said Steven Kurmas, DTE’s president and COO.
Entergy to Appeal ‘White’ Finding Levied by NRC at Pilgrim
Entergy is appealing a Nuclear Regulatory Commission sanction assessed following the shutdown at Pilgrim Station during a winter storm. NRC found that the scram was caused by a sudden loss of outside power during the storm and gave the power station a “white” safety finding.
“One of the complications during the shutdown involved the use of safety relief valves to reduce reactor vessel pressure as part of the reactor cool down process,” according to the NRC report. “During attempts to open one of the plant’s safety relief valves, the valve did not open based on observed system response. Plant operators safely completed the cool down using two other of the plant’s four safety relief valves.”
The inspectors said the operators should have anticipated the safety valve issue. Entergy says it has addressed all the safety concerns raised by the report, and that it will seek to have the “white” finding reduced.
Atlantic Coast Pipeline Opponents Say Meeting Transcripts Garbled
Opponents of the proposed 550-mile Atlantic Coast Pipeline (ACP) were shocked when they read transcripts of the Federal Energy Regulatory Commission scoping meeting where they spoke and were unable to make sense of how a stenographer recorded their comments.
In many cases, opponents say, their transcribed comments from a March 18 meeting in Nelson County, Va., were so “garbled” that it is “literally incomprehensible,” according to Joanna Salidis, president of Friends of Nelson.
One resident said at the meeting: “The one-mile swath of pipeline proposed for Shannon Farm would tear up sensitive wetlands and plow through the climax breech forest in our designated wilderness area. It would disrupt our organic gardens, where some members … grow a sizeable portion of their food.”
The FERC transcript reads: “The one hot swath of pipeline proposed for Shannon Farm would tear up sensitive wetlands and plow through the planet’s beech forests in our designated wilderness area and would destruct our organic environments for some members … for a sizeable portion of their food.”
“Again, we see that the agency charged with evaluating whether the ACP’s benefit to the public outweighs its harm does not take public concerns seriously,” Salidis said.
Tidal Power Project Asks for 2-Year License Extension
The developers of a tidal power project off Eastport, Maine, are asking the Federal Energy Regulatory Commission for a two-year extension of its license to complete testing of some technology.
The 300-kW Cobscook Bay Tidal Energy Project, run by Ocean Renewable Power Co., received its license in 2012 and began operations later the same year. Its license was granted as a pilot project, used to study the effect on ocean life and to test hydrokinetic technology.
Pilot licenses are granted to small, short-term projects that must be removable or able to be terminated at short notice. The Cobscook Bay project is ongoing, but the company wants an extension instead of a new license. Although it has been online since 2012, the technology is not suitable for commercial applications.
MISO stakeholders will complete voting on June 16 on three options for responding to the Federal Energy Regulatory Commission’s final rule on coordinating gas and electric schedules (RM14-2, Order 809). MISO could post ballot results as early as June 19 and announce a decision by June 30 for discussion at the July 7 Market Subcommittee meeting.
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). It also added a third intraday nomination cycle.
MISO and other RTOs are required to make compliance filings by July 23 that move the clearing and posting of the day-ahead market’s results to before the timely nomination deadline — or explain why it is not appropriate within their footprint. During a joint meeting last week of the Market Subcommittee and of the Reliability Subcommittee, Jeff Moore of Ameren asked MISO officials to what degree stakeholder votes will influence MISO’s final decision. “Is MISO going to consider themselves bound by the stakeholder vote? Are there other considerations?”
Kevin Vannoy of MISO said stakeholder votes “are very important to us” but noted a number of considerations are in play, including alignment with other RTOs and scheduling, staffing and market administration issues.
Moore said his takeaway from a natural gas availability study presented earlier in the week led him to believe natural gas supplies appear to be adequate in MISO in the years ahead and asked whether that would affect MISO’s decision regarding the three options presented for the day-ahead market.
“That’s something we’ll discuss as part of our final decision,” Vannoy said.
No changes. The day-ahead market closes at 11 a.m. ET, with next-day forward reliability commitment assessment (FRAC) results posted by 8 p.m. ET.
Align the day-ahead market with the timely gas nomination cycle by closing the day-ahead two hours earlier during daylight saving time (one hour earlier during standard time) and reducing clearing windows by one hour.
Align the FRAC with the evening gas nomination cycle by closing the day-ahead one hour early during daylight saving time and reducing the clearing window by one hour.
The status-quo alternative would require MISO to make a convincing filing with the commission, Joe Gardner, vice president of forward markets and operations services at MISO, told the Electric and Natural Gas Coordination Task Force on June 10.
Gardner said MISO estimates that alternative No. 2 could make available over one year an average of 7,500 MW more generation, while No. 3 could free up about 5,000 MW more than under the current system.
“Units that previously were not able to be considered because they [had] an hour or two longer start-up notification time than other units are able to be considered” in alternatives 2 and 3, he said.
“This allows basically just a few more units to be available for reliability purposes as part of the normal process,” Gardner added. “There is a reliability and an economic benefit.”
Other RTOs
ISO-NE reported last year that system operations had improved following changes it implemented in 2013 to move the day-ahead market and initial reserve adequacy analysis (RAA) timelines earlier in the day. It said the number of units committed in the day-ahead or RAA that were completely unavailable in real time due to gas procurement issues dropped from seven in the winter of 2012/13 to zero in the winter of 2013/14. Over the same period the number of generators with long start-up times dispatched before the day-ahead offer and bid deadline dropped from 12 to zero.
PJM, which currently posts its day-ahead results at 4 p.m. ET, is considering ways to post its results by 1 p.m., an hour before the first gas nomination deadline at 2 p.m. (See PJM Markets and Reliability Committee Briefs, “Members OK Gas-Electric Initiative.”)
Importance of Stakeholder Votes
During Friday’s MSC/RSC meeting, Lin Franks, senior strategist at Indianapolis Power & Light, said stakeholder votes are important for MISO to have a better understanding of generation owners’ concerns. That came after one stakeholder expressed reservations about MISO releasing to the public comments stakeholders made with their votes. (MISO agreed to withhold release of those comments upon a stakeholder’s request.)
“Fuel assurance is not MISO’s responsibility and that’s at the crux of this issue — managing the risks of natural gas. MISO did an amazing amount of work to formulate options for stakeholders to consider that appear to mitigate most of the concerns and risks we expressed with MISO collectively and individually,” Franks 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 increase natural gas use further.
The nine Northeastern and Mid-Atlantic states participating in the Regional Greenhouse Gas Initiative said their 28th auction of carbon dioxide allowances raised $85 million for investment in energy efficiency, renewable energy and other programs. More than 15.5 million allowances were sold at the clearing price of $5.50. Bids for the CO2 allowances ranged from $2.05 to $12.50 per allowance.
The market for cost-containment reserve (CCR) allowances was not as robust. The CCR is a fixed additional supply of allowances that are only available for sale if CO2 allowance prices exceed certain price levels ($6 in 2015, $8 in 2016, and $10 in 2017, rising by 2.5% each year thereafter to account for inflation). Ten million CCR allowances were for sale, and none sold.
The June 3 auction was the second auction of 2015.
Opposition to Delaware City Refinery’s Water Use Permit Growing
Opposition is mounting to a proposed permit that would grant the Delaware City Refinery continued use of 300 million gallons of Delaware River water a day for coolant.
A coalition of lawmakers and environmentalists has asked the Department of Natural Resources and Environmental Control to uphold an earlier recommendation that the refinery install a cooling tower system, which would reduce water consumption and kill less aquatic life. The refinery, which was designed and built in the 1950s, is using older technology that last received a five-year water-use permit in 1997. The refinery has been operating under permit extensions for more than a decade.
Regulators estimated the cost of a tower cooling system at about $75 million. Refinery owner PBF put the price at closer to $300 million. The public comment period on the proposed permit ends this week.
Stricter Water Temperature Limits Could Result in Closing of Two NRG Plants
New regulations setting temperature limits for Chicago-area waterways could doom two NRG Energy coal-fired plants, according to comments the company filed with the Pollution Control Board last week.
The board has set temperature limits for waterways into which NRG’s Joliet Station and Will County plant discharge cooling water. NRG sought a six-year period to conduct new studies, analyze the data and petition for variances. But the board denied the extension request and says NRG has only three years to meet the goals.
If finalized in their current form, the proposed thermal water quality standard would “result in the closure of certain industrial facilities,” NRG wrote in the request for the extension.
State Supreme Court Ruling Allows Luther College to Go Solar
Luther College says a 2014 state Supreme Court case that allows third-party ownership of solar arrays made it attractive for the school to install an 825-kW solar system. The court ruling made it possible for the nonprofit institution, which would not directly benefit from renewable-power tax subsidies, to finance its solar system through a third party that could take advantage of the tax breaks.
The system, which will be one of the state’s largest solar facilities, is designed to provide about 6% of the school’s electricity needs. A big benefit is that it will produce power during peak hours, helping the school to reduce its demand charge with the area utility, Alliant Energy, which currently makes up about 35% of its bill.
Nearly 60% of State’s Coal-Fired Plants Will Close by 2040
More than 58% of the state’s coal-fired power plants would be retired by 2040, even before taking into account proposed U.S. Environmental Protection Agency emission regulations, according to state Energy and Environment Secretary Len Peters.
Peters told a legislative committee earlier this month that state generators have already proposed retiring plants or converting them to natural gas to comply with EPA’s Mercury and Air Toxics Standards. Even without the pressure to meet the proposed Clean Power Plan, about 5,830 MW of the state’s aging coal-fired fleet will reach retirement age of about 65 years by 2040. Peters said the new emissions regulations and the price of construction means that it is unlikely Kentucky will see many, or any, new coal-fired plants being built.
New England’s first utility-scale electricity storage system is contained in three large shipping containers in Boothbay’s industrial park. The 3-MWh system, which uses valve-regulated lead acid batteries, is designed to help supply demand during peak summer hours and to provide grid stability and resilience.
The system, which would typically be charged at night and discharged during the day, was developed through a partnership led by New York City-based Convergent Energy + Power. The pilot program, which can supply up to 500 KWh for six hours, is being run by GridSolar for the Public Utilities Commission.
The political opposition has taken aim at Manitoba Hydro, the quasi-governmental utility that is seeking a 3.95% electric rate increase before the Public Utilities Board.
At a board hearing, Progressive Conservative party leaders called Manitoba Hydro’s predicted long-range losses of $75 million to $192 million “mind-boggling.” Though it predicts healthy profits during the next three years, the utility projects a downturn in power export opportunities and an expensive capital construction campaign that will turn profits into losses starting in 2018.
Premier Greg Selinger’s administration has touted the utility’s near-term success.
Consumer Advocate Appeals PSC OK of Exelon-Pepco Deal
Paula Carmody
The Office of People’s Counsel last week appealed the Public Service Commission’s approval of Exelon’s acquisition of Pepco Holdings Inc., saying consumers will suffer from the deal. The OPC filed its petition for judicial review in the Queen Anne’s County Circuit Court.
“The majority decision to approve this transaction was flawed and failed to address the single most important aspect of the law — first, do no harm,” People’s Counsel Paula Carmody said.
The PSC voted 3-2 to approve Exelon’s takeover, which would make the company the electric supplier for 80% of Maryland ratepayers. (See How Exelon Won over Maryland.) D.C. regulators have yet to rule on the deal.
Regulators OK We Energy’s Acquisition of Integrys; Just Needs Illinois’ Approval Now
The Public Utilities Commission on Friday approved We Energy’s acquisition of Integrys Energy Group, joining Wisconsin, Michigan and and various federal authorities. We Energy now needs just the nod from the Illinois Commerce Commission to complete the transaction. The $9.1 billion deal, when completed, will create WEC Energy Group Inc., which will have 4.4 million customers in four states and be headquartered in Milwaukee. WEC will also own 60% of American Transmission Co.
The ICC is expected to rule on the acquisition at the end of this month. At the forefront of the issue in Illinois is the ongoing multibillion-dollar gas main replacement project going on in Chicago by Integrys subsidiary Peoples Gas. Wisconsin Energy has said it will put together a new upper management team at Peoples. That company, and the gas main replacement project, was the subject of a highly critical audit. The final cost of the gas main project is still unknown, and the state Attorney General’s office has begun a probe into the entire project.
Eversource, political leaders, the state Office of Energy and Planning, the PUC Office of Consumer Advocate and staff members of the PUC participated in negotiations that led to the filing. The agreement is also supported by the electrical trade unions; the Conservation Law Foundation; trade organizations representing independent power plant owners and competitive electricity suppliers; and the New Hampshire Sustainable Energy Association.
The settlement is likely to yield about $380 million in customer savings over the next five years, according to state Sen. Dan Feltes. Hearings are expected to begin this fall, with legislative updates required in October and a PUC decision by the end of the year.
The owner of the former Revel casino and a third-party power supplier have struck a court-approved deal to keep the lights on.
Glenn Straub’s Polo North Country Club, which bought Revel for $82 million out of bankruptcy court in April, has temporarily resolved his dispute with ACR Energy Partners over the cost of energy services it supplies and whether his company should have to assume the previous owner’s commitments to pay for the costs of the ACR power plant’s construction. ACR initially cut service to the complex, but lawmakers ordered the company to restore service to maintain fire protection systems and the warning light atop the 47-story building.
Under the agreement, ACR will maintain power until one of four things happens: the parties reach a long-term contract; a state order requiring ACR to provide service is canceled or changed; a judge allows ACR to stop providing service; or Polo North finds a new energy provider.
The state’s transition to competitive electricity markets has contributed to dramatic benefits for consumers and the state’s power grid, including nearly $7 billion in savings and reduced costs and significant reductions in emissions, among numerous other impacts, according to a NYISO report.
The report, “Powering New York — Responsibly,” examines the 15-year period since the inception of New York’s competitive market in 2000. It quantifies the major contributions made by NYISO to help the state meet its future energy needs and achieve its goals for cleaner energy and improved efficiency.
“The federal and state policy decisions that produced electric industry restructuring were founded on the conviction that competitive wholesale electricity markets expeditiously and effectively facilitate evolution of the grid,” said NYISO CEO Stephen Whitley.
Duke Energy is staying out of the debate as state lawmakers consider bills that could affect solar development.
One bill would let homeowners lease or finance solar systems through third-party developers like SolarCity. Another would cap utilities’ required purchases of renewable energy at 6% of demand this year, compared with the current target of 12.5%.
“There have been a half-dozen bills in this session dealing with energy,” Duke CEO Lynn Good told Bloomberg News. “It’s difficult to handicap which ones will go through.”
State Supreme Court Gives Duke Some Relief from Ash-Cleanup Ruling
The state Supreme Court last week vacated a lower court ruling that said regulators could force the utility to take immediate action to clean up coal ash-contaminated groundwater. The high court said legislation passed last year ordering coal ash remediation made the “immediate action” ruling unnecessary.
Environmental activists said the lower court ruling, arising from a 2012 case and predating Duke’s January 2014 ash spill on the Dan River, meant that Duke should be forced to stop the pollution at the source before any work restoring groundwater is taken. But the utility and state regulators said full assessments of the groundwater contamination is necessary first.
“We think the court’s ruling is appropriate, and we are pleased to close this issue so we can continue moving ahead with safely and permanently closing ash basins,” Duke spokeswoman Erin Culbert said.
Boston-based Competitive Power Ventures wants to build a $900 million natural gas-fired power plant in western Pennsylvania that could be up and running by the end of 2019.
Vice President Michael Vesca said construction could start in 2017 on the plant, which would be located near Vinco, about 65 miles east of Pittsburgh.
Penelec Spends $6M to Serve New Gas-Pumping Station
Pennsylvania Electric Co. plans to spend $6 million to build new distribution lines to supply power to pumping stations being built in shale-gas producing areas of central Pennsylvania.
New electric distribution lines will deliver 2.8 MW from substations in McConnelltown and Blain to new pumping stations in Marcklesburg and Doylesburg.
Kinder Morgan has scaled back a natural gas pipeline proposed for New England, but the changes will have little effect on the overall project to supply power plants and home-heating utilities.
Kinder Morgan filed an updated plan with the Federal Energy Regulatory Commission on June 2 for its Northeast Energy Direct project, saying it was eliminating local laterals and related facilities due to the inability to sign up utilities to support those spurs. “We just don’t have the customers,” Allen Fore, vice president of government affairs at Kinder Morgan, told TheBoston Globe.
The pipeline is planned to run from New York through northern Massachusetts, cut into New Hampshire and return to Massachusetts, where it will terminate in Dracut.
Kinder Morgan, the parent of project developer Tennessee Gas Pipeline, said it is eliminating a nearly 15-mile spur through seven Massachusetts towns and a 1-mile spur in Connecticut, along with a new meter station and modifications at three existing stations.
Remaining in the project are 37 miles of laterals running off the main line, which will mostly follow existing rights-of-way.
“This revised scope, which will be reflected in Tennessee’s next draft environmental report filing, will allow Tennessee to meet the needs for all the shippers that have executed binding precedent agreements for the project,” the company wrote (PF14-22).
The pipelines are controversial because they would import fracked shale gas from Pennsylvania and be funded by utility ratepayers. (See New England Governors Revise Energy Strategy.)
Kinder Morgan said the pipeline could bring more than 2 billion cubic feet of natural gas per day into the region. It plans to file a second draft of its environmental report next month and a final pipeline application with FERC in October.
