NRC Gives Exelon’s Limerick Extension for Fukushima Fix
Limerick (Source: Exelon)
The Nuclear Regulatory Commission granted Exelon’s request for an additional two years to make upgrades to the reactor buildings at its Limerick Nuclear Generating Station. The NRC in 2012 ordered Exelon to take steps to prevent hydrogen buildups similar to what occurred during the Fukushima disaster in Japan in 2011.
The Limerick reactors share some design similarities with the Japanese units. The NRC ordered installation of a “hardened wetwell vent” system to extract combustible gas from building up and possibly exploding. “The installation of such vents is one of our post-Fukushima requirements,” said NRC spokesman Neil Sheehan. Exelon will have until the end of a refueling outage in spring 2018 to complete the work at Unit 1 and until the end of a refueling outage in spring 2017 to complete the work at Unit 2, the NRC said.
The higher water temperatures of Long Island Sound aren’t too high for the Millstone nuclear plant to use, according to the Nuclear Regulatory Commission. The NRC granted Dominion’s Millstone Unit 2 a license amendment to allow operation if its cooling water, drawn from the Sound, rose in temperature to 80 degrees. Unit 2 was forced offline for 12 days in 2012 when Sound water temperatures rose above the then 75-degree limit. The NRC is considering a similar amendment request for Millstone Unit 3.
“We’ve seen a long-term trend over the last 40 years of Long Island Sound temperatures steadily increasing,” Millstone Spokesman Ken Holt said. In 2012, the average temperature in the Sound near the Unit 2 intake pipe was about 77 degrees, he said. The company believes the five-degree margin will be sufficient to allow it to continue operations without costly unplanned shutdowns, he said. “We think we can stay well within the limit,” he said.
Additional natural gas pipeline capacity is coming to the Southeast with the Federal Regulatory Commission’s approval of an application for the construction of Transco’s Mobile Bay South III Expansion project. Williams Partners LLP said the project is expected to be completed by spring 2015.
Stakeholders split last week over a PJM proposal to change how the RTO captures the cost of deploying additional reserves during extreme weather.
PJM’s Lisa Morelli presented a first read of the proposal — which is intended to capture operators’ reliability actions in Locational Marginal Prices rather than uplift — at last week’s Markets and Reliability Committee meeting.
Stakeholders representing generation expressed support for the proposal while those representing load said they feared it could lead to unduly conservative operations and higher overall costs.
It would increase day-ahead and real-time reserve requirements when hot- or cold-weather alerts or max emergency generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.
“On a day like this there’s a ton of uncertainty,” said PJM Executive Vice President for Operations Mike Kormos, citing generator performance and forecasts for weather, load and interchange. “We can’t roll the dice and hope things go away.”
The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion (MAD) synchronized reserve requirement of 1,300 MW.
The increases would be implemented only if operators believe the additional resources can be scheduled without causing operational problems. The real-time adder would be reduced to 50% of the MAD synchronized reserve requirement or lower if the higher amount becomes problematic.
The increased reserves would be reflected in market clearing engines, ensuring that the costs go into LMPs and not uplift.
“This has been a long time coming,” said PJM Vice President for Market Operations Stu Bresler. “… This is very important to us.” Bresler said the best solution — changing reserves in real time — would be more complex and less transparent.
Ed Tatum, of Old Dominion Electric Cooperative, called the proposal “reactionary.”
“Sixteen years and 24 days into this LMP business … we keep on doing non-market things,” he said. “… We are moving further and further away from the concept of a market. We’re taking it more into an administrative construct.”
David “Scarp” Scarpignato, of Direct Energy, said the proposal could lead to overly conservative operations and increase costs to load. PJM already carries reserves equal to 150% of the largest single contingency, while other regions use only 100%, he said.
“We have very big problems with this,” he said. “PJM already has more conservative synchronized and primary reserve targets than other areas.”
Jason Barker, of Exelon, said Scarp had mischaracterized the PJM proposal. Last July, Barker said, PJM dispatched demand response at $1,800/MWh and Exelon’s peaking generators at “hundreds of dollars” at a time when LMPs were only about $60/MWh. “All of these [costs] were paid through uplift,” he said.
PJM, which wants to implement the changes in time for this summer, will bring the proposal to votes at the MRC and Market Implementation Committee next month. It was developed during meetings of an MIC subgroup on Energy/Reserve Pricing & Interchange Volatility.
At a meeting of the subgroup yesterday, PJM officials said that logistical problems prevented them from producing simulations to gauge the impact of the changes.
Members agreed to consider changing the $1,000/MWh offer cap last week following a debate over whether unusually high gas and electric prices during January were a fluke or a sign of winters to come.
The Markets and Reliability Committee approved PJM’s proposed problem statement, which says stakeholders should consider lifting the cap because this winter’s extreme conditions had for the first time put the limit at odds with rules requiring capacity resources to offer their output into the day-ahead energy market. The accompanying issue charge was also approved.
The initiative passed with 27 abstentions and 11 “no” votes. Susan Bruce cast 10 of the no votes and four abstentions on behalf of the PJM Industrial Customer Coalition. Bruce said the coalition had never voted against a problem statement before.
“We are perhaps rushing to judgment,” she said, noting that PJM had not released all of the results of its analysis of the winter. “… As I sit here today, I don’t know what I don’t know.”
The measures were amended to include an Oct. 31 target date for completion, in order to facilitate a Federal Energy Regulatory Commission order by the end of the year. Also added was the Market Monitor’s request to clarify the offer cap’s application to incremental, startup and no-load costs.
FERC Orders
On Jan. 24, FERC granted the RTO’s request for a waiver allowing make-whole payments for generators with operating costs above the $1,000 cap. PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked to $140/mmBtu.
The January order allowed PJM to fund the make-whole payments through uplift charges. On Feb. 11, FERC granted a second waiver eliminating the cap through March 31, allowing high-cost generators to set Locational Marginal Prices.
FERC lifted the cap over the objections of consumer advocates, state regulators and others, who said allowing the RTO’s most inefficient generators to set clearing prices would provide a windfall to the vast majority of generators with costs well below $1,000. (See Stakeholders Preview Offer-Cap Debate.)
The proposal to consider changing the cap appeared to have the support of generators. Jason Cox, of Dynegy, praised PJM for being “proactive.”
But most of the comments came from those representing load.
Will High Prices Repeat?
“It’s not exactly clear to us that this sort of issue is going to happen over and over again,” said Raghu Sudhakara, of Rockland Electric Co.
“If the purpose is to pull the wool over the eyes of people … and finagle something through without us understanding it, I have a problem with that,” said Gloria Godson, of Pepco Holdings Inc., who insisted the stakeholder process include an examination of high gas prices. PHI abstained on the vote.
Carl Johnson, who said he considered voting no, ultimately cast 15 abstentions on behalf of the PJM Public Power Coalition. “It’s seems [PJM] is taking everything in the FERC order and trying to put it into the Tariff,” he said. “We don’t think having to get a waiver is always a bad thing.”
He also said that the actual impact of the FERC waivers — which yielded about $9,000 in make-whole payments to generators whose production costs went above the offer cap — might not warrant months of prickly debate.
Walter Hall, of the Maryland Public Service Commission, said he was concerned that PJM was “somewhat telegraphing the result you are expecting.”
Not Hypothetical
Bob O’Connell, of J.P. Morgan Ventures Energy Corp., warned members that a no vote would not end efforts to lift the cap.
An MRC rejection “doesn’t prevent members from creating a user group and rushing this through an alternative stakeholder process that may disenfranchise certain members,” O’Connell said. “I suspect there are [at least] five members sitting at this table today that would want to move this forward.”
Steve Lieberman, of Old Dominion Electric Cooperative, said ODEC would have voted no but feared rejection of the measure would lead PJM to make a unilateral section 205 filing with FERC to lift the cap.
Executive Vice President for Markets Andy Ott indicated Lieberman’s concern was well founded, saying PJM needs to act.
“This is not theoretical; this is an issue where we had [generator] costs over $1,000,” Ott said. “No matter what happens at FERC [with relation to future gas prices], we could have gas prices where the $1,000 offer cap doesn’t work. We feel it needs to be addressed by next winter.”
ODEC’s Ed Tatum lamented that efforts to lift the offer cap were the latest of recent PJM initiatives — following changes to limit imports and demand response in the capacity market — that could increase prices for load.
In a discussion over which stakeholder group should address the issue, Tatum argued in favor of the MRC, noting that it involves reliability. He expressed reservations about the Capacity Senior Task Force, which he said had not been a friendly venue for load.
“This RPM [Reliability Pricing Model] stuff has not worked out well for the left side of the room,” he said, referring to where representatives of cooperatives, industrial customers and public power were seated. “We’re not getting a lot of love.”
The committee voted to assign the issue to a new task force reporting to the MRC.
Stakeholders last week approved draft regulations to protect the electric grid from physical threats even as many criticized the rules as rushed and poorly defined.
The draft regulations, drawn up by a North American Electric Reliability Corp. working group of 11, are now being considered by the NERC board. NERC must submit proposed regulations to the Federal Energy Regulatory Commission in June. FERC has scheduled a technical conference June 10 to discuss “policy issues related to the reliability of the Bulk-Power System” at which the NERC filing is likely to be a centerpiece.
The plan won 82% approval in polling of NERC members last week. Among PJM members, Duke Energy, Exelon, FirstEnergy and Dominion all said they support the draft standards, while AEP voted no.
“Are we being overly reactive?” a stakeholder from AEP asked, according to a summary of feedback to the draft regulations that was compiled by NERC. “Poorly executed, these standards could carry astronomical … costs.”
“We need to spend time to get this right and not rush something through,” a stakeholder from the Nebraska Public Power District wrote. “This expedited standard development has the potential to derail our entire NERC standard development process.”
The regulations are in response to concerns resulting from the sabotage of a PG&E Corp. substation last year. Under pressure from Congress, FERC on March 7 ordered NERC to develop standards to address physical attacks within 90 days. (See FERC Orders Rules on Grid’s Physical Security.)
Critical Substations
Dominion Virginia Power plans to spend as much as $500 million to upgrade security at its substations, including the installation of anti-climb fences, as in the simulation above. (Source: Dominion)
The NERC draft calls for utilities to provide protection for “critical” substations, but it allows each utility to determine what substations are critical. The rules call for third-party review of critical facilities but would allow utilities to act as each other’s third party. (See related story, NERC Draft Rules for Physical Security.)
The draft rules don’t require hardening critical substation sites with blast barriers or other defenses, as some critics have suggested.
Several stakeholders were critical of the short time FERC gave NERC to comply. Others said the standards should apply not just to transmission owners and operators but also to transmission planners, reliability coordinators and generation owners and operators.
Still others said the standards were too loosely defined. “As described, the objective of protecting critical facilities of the [Bulk Electric System] is stated too broadly and it is not apparent what countermeasures would be considered adequate or sufficient,” wrote the Bonneville Power Administration.
Brightline Criteria
Colorado Springs Utilities recommended a “brightline criteria” for the facilities covered by the standards, “based on either the Transmission Planning Standard TPL-004a [System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements] or identification of the largest single contingency for each interconnection. If we need a single number, [include] only facilities that provide or control over 3,000 MW of generation or transmission operating at 300 kV and above.”
AEP also questioned the proposed definition of critical facilities. “FERC and NERC have implied that the number of critical facilities identified in this process will be relatively small — fewer than 100 of the 55,000 transmission stations dispersed throughout the country. However, for previous `critical asset’ determinations requested by NERC, AEP has already identified almost that many just on our own system. This would indicate we are starting over with the definition of critical facilities, which is counter-intuitive if not counter-productive.”
One member, from the Southwest Power Pool, noted that NERC’s existing definition of Critical Assets is scheduled to be retired in 2016. “How does one then determine the list of ‘critical’ facilities if that definition no longer exists?” that member said.
Several stakeholders referred to a 2013 FERC power flow analysis on the 30 most critical substations nationwide. The analysis, which was leaked to The Wall Street Journal in March, reportedly concluded that the Eastern and Western Interconnections and ERCOT could be shut down for weeks or months if only nine of the substations were sabotaged.
“If a list of the most critical substations exists, why are we trying to develop a new process to determine the list?” a stakeholder from the Nebraska Public Power District asked. “I feel we have been blindfolded and put into a room and told to hit a small target with a dart and we don’t even know which wall or direction to throw the dart.”
Cost Concerns
AEP echoed concerns about the cost of the rules. The new standards, AEP wrote, “could result in massive changes, bringing excessive additional costs with no guarantee of desired outcomes … While we need to make whatever investment is necessary to adequately protect the grid, we also need to be responsible stewards of the grid and our ratepayers’ pocket books.”
In response to criticism of the draft rules cited in a Journal article April 17, NERC issued a statement defending the regulations and the process used to develop them.
“Standards are one piece of this complex, dynamic endeavor of providing a comprehensive approach to reliability,” NERC said. “NERC also has various other tools to fulfill this mission, including guidelines, training, assessments and alerts. This multi-pronged approach has resulted in a secure and reliable bulk power system for North America.”
In a win for PJM generation owners, the Federal Energy Regulatory Commission approved a rule change that will reduce capacity imports and likely increase clearing prices.
The commission approved PJM’s capacity import limits over the objections of consumer advocates, MISO’s market monitor and others who said it will unfairly raise prices and restrict competition (ER14-503). The new rules create five export zones with a combined limit of 6,499 MW for the May Base Residual Auction, a 17% reduction from what cleared in the 2013 auction.
FERC said the limits were based on “a reasonable methodology” to address the risk that imports may be curtailed by transmission providers outside of PJM. The commission said the methodology is an improvement over the current system, in which PJM assesses import capability by evaluating individual requests for long-term transmission service.
It rejected calls from intervenors to modify PJM’s proposal, noting that the commission’s role in a section 205 proposal is to determine whether PJM’s proposal is just and reasonable, “not to determine whether alternative proposals are more or less reasonable.”
AMP, MISO Protests Rejected
The commission rejected complaints by American Municipal Power Inc. (AMP) and MISO that the proposal gave PJM too much discretion.
AMP contended PJM’s assumption that no redispatch will be provided to support firm deliveries was contrary to MISO’s practices and will result in lower limits than are necessary to address PJM’s reliability concerns.
MISO said the proposal gives PJM too much discretion in how it sets the limit. The commission said it was satisfied by PJM’s promise that it will continue to coordinate with MISO on modeling used to calculate the limits.
In January, the commission requested PJM provide additional information on how it identified the five external source zones, which will each have their own limit. (See FERC Demands More Data on Import Cap.) The commission said PJM’s response was an “adequate explanation” of its methodology.
Commissioner John Norris filed a concurring statement warning that prices could rise if PJM is overly conservative in setting the limits. “I urge PJM and its stakeholders to continue to work towards ensuring that the calculation of the capacity import limit does not unnecessarily limit the most efficient utilization of available resources,” he wrote.
Monitor’s Proposal Rebuffed
Some PJM utilities and the Independent Market Monitor had asked the commission to require that all capacity resources be pseudo-tied, have confirmed, firm long-term transmission service and be subject to the same capacity must-offer requirement as internal resources. The commission said those conditions — which PJM proposed for resources seeking an exemption from the import limits — would limit competition from external resources without enhancing reliability.
The commission also rejected a challenge by consumer advocates who said the limit should not reflect a 3,500-MW deduction for the capacity benefit margin — a reservation for imports of energy during emergencies. The commission noted that the capacity benefit margin allows PJM to operate with a smaller reserve margin, reducing its purchases in the capacity auctions.
“If the Capacity Import Limit is not reduced by the capacity benefit margin, the emergency-only reliability purpose of the capacity benefit margin could be compromised because the total quantity of megawatts of external capacity available for emergency assistance may be overstated,” the commission said.
Regulators, consumer advocates and the Market Monitor last week urged the Federal Energy Regulatory Commission not to change a crucial rule for PJM’s upcoming capacity auction, warning that it would allow generators to exercise market power.
FirstEnergy Solutions Corp.’s request to change how PJM calculates the maximum price generators can offer into capacity auctions “would result in a direct transfer of potentially billions of dollars from customers to sellers,” said the PJM Industrial Customer Coalition and consumer advocates for Maryland, Pennsylvania, Delaware, New Jersey, West Virginia, Illinois and the District of Columbia.
In separate filings, the Ohio Consumers Counsel and the Organization of PJM States (OPSI), representing state regulators, also weighed in against FirstEnergy’s request.
PJM, however, said it agrees with FirstEnergy’s interpretation of its Tariff and urged the commission to approve the company’s request. Also siding with FE is the Electric Power Supply Association and the PJM Power Providers Group.
Declaratory Order Sought
On April 7, FE filed a petition for a declaratory order (EL14-36), asking FERC to rule that PJM’s Open Access Transmission Tariff requires the use of a generator’s cost-based energy offers in the determination of net projected PJM market revenues. Granting the request could result in higher Market Seller Offer Caps, likely increasing auction revenues for FE and other generators.
FE asked the commission for an expedited ruling by May 9, in time to set the rules for the Base Residual Auction that begins May 12.
FE’s request would change methodology the Monitor has used since 2007, which selects as an input whichever is lower, the unit’s market-based offer or the cost-based offer.
No Emergency
Opponents said there was no reason for FERC to rush to rule in the dispute.
“FES could have filed its Petition months (or perhaps years) ago,” said the Ohio Consumers Counsel. “Instead, FES chose to file five weeks before the BRA.”
Their colleagues in other states consumers agreed. “There is more potential harm in expediting a decision than in carefully reviewing the issue,” said the consumers’ filing.
State regulators said altering the methodology would require a Tariff change and thus should be subjected to PJM stakeholder review.
Calculating Marginal Costs
Because existing generators possess market power, PJM requires mitigation in the form of the Market Seller Offer Price (MSOP), a cap on the price they can seek in the capacity auction.
The MSOP is intended to represent the solution to the so-called “missing money” problem. It is calculated as the difference between the unit’s Avoidable Cost Rate — the cost of running the plant for another year — and its projected net revenue.
Net revenue is calculated as total energy and ancillary services revenues less marginal costs. It is the calculation of marginal costs that is at the heart of the dispute.
The Market Monitor has always calculated marginal cost as either the unit’s market-based offer or its cost-based offer, whichever is lower. The latter offer is a price cap designed to counter market power in the energy market.
“Cost-based” is a misnomer, according to the Monitor, because it can include a 10% “adder” to actual costs.
In practice, generators often make market-based offers that are below their cost-based offers — which the Monitor says better represents their marginal costs.
“Sellers want their unit dispatched when the market price (Locational Marginal Price (LMP)) is greater than marginal cost. Accordingly, a non-zero offer lower than the offer cap is the best available evidence of what the seller believes is its marginal cost,” the Monitor wrote in its filing last week.
FirstEnergy says it is unfair to use the lower offers in the MSOP calculations: Generators may offer into the energy market at prices below their marginal costs because they want to continue running regardless of the clearing price.
“The operational characteristics of some power plants require this strategy at times to maximize efficiency and to reduce long-term costs. For example, a unit might need to avoid cycling on and off in succession to prevent expensive tube leaks or other associated repairs, which in turn could result in forced outages, performance penalties in the capacity market, and obligations to pay for deviations in the energy market. Other units also may need to keep producing power to avoid incurring penalties under `take or pay’ fuel contracts,” FE said.
“By choosing to operate in some hours by generating when energy prices are below a plant’s marginal cost of production, the plant operator is making a rational decision to absorb a small loss to avoid an even greater loss caused by the inefficient cycling of the plant that would otherwise occur.”
Tariff Definition
PJM, in a filing last week, said it agrees with FirstEnergy. “Use of cost-based offers (and not the lower of price-based and cost-based offers) is required by the Tariff. Indeed, PJM could not remain complaint [sic] with its Tariff if it were to read unstated provisions into the rule to effect the outcome desired by the [Monitor].”
What neither PJM nor FirstEnergy told FERC, however, is why it took them so long to come to this conclusion.
Impact of change
The Monitor said FirstEnergy’s petition was filed after it rejected FE’s proposed offer price caps for certain of its coal-fired generating units. “FirstEnergy offers no attestation here or elsewhere that its price-based offers reflect anything other than FirstEnergy’s calculation of the actual marginal costs of the FE Units,” the Monitor said. “FirstEnergy’s behavior has been consistent with the behavior of other market participants who have for years accepted that their non-zero price offers lower than their offer price caps are the best indicator of their actual marginal costs.”
The Monitor said FirstEnergy’s offers could set or influence market prices. “For example, there is a possibility that the level of Sell Offers submitted for certain of the FE Units will influence whether specific zones clear as Locational Deliverability Areas (LDA) with price separation.”
The Monitor said it agrees that capacity market prices have been suppressed and noted recommendations it has made to address the issue. But it said the company’s attempt to upend long-standing practice is improper.
The Monitor said it discussed its method of calculating net revenues with FirstEnergy in November 2012 and again early this year.
“It is implausible that FirstEnergy did not calculate its own net revenues for prior RPM auctions. Yet FirstEnergy has never raised this issue before,” the Monitor said. “Any missing money problem faced by FirstEnergy did not emerge for the first time in the last thirty days.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:20)
The committee will be asked to endorse manual changes to implement lessons learned from the extreme weather in September and January. The committee also will be presented changes to four manuals that will implement new dispatch rules for demand response pending Federal Energy Regulatory Commission approval (ER14-822).
These include the split of DR into pre-emergency and emergency categories and implementation of 30-, 60- and 120-minute response windows.
Last month, FERC issued a deficiency notice requesting additional information on pre-emergency dispatch of DR and the reduction in the default response time from two hours to 30 minutes. (See FERC Questions May Delay New DR Rules.)
Below are some of the key changes to each manual:
A. Manual 18: PJM Capacity Market — Conforming the manual to recent FERC orders, including seasonal verification testing and Capacity Import Limits effective with the 2017/2018 delivery year.
B. Manual 13: Emergency Operations — The changes will allow declaration of Cold Weather and Hot Weather alerts several days in advance instead of the day before.
C. These revisions will implement demand response “operational enhancements,” which are pending FERC approval:
Manual 11: Energy & Ancillary Services Market Operations — Specifying Emergency Demand Response price caps based on lead time, as well as an Economic DR price cap.
3. REGIONAL PLANNING PROCESS TASK FORCE (RPPTF) (9:20-9:50)
The committee will vote on Operating Agreement (OA) and Tariff revisions implementing multi-driver transmission projects. The proposed rules developed by the RPPTF would allow multi-driver project combinations as part of the annual Regional Transmission Expansion Plan, both parallel (combining standalone projects) and incremental projects (adding a market efficiency or public policy project “on top” of a reliability project). PJM will apportion the respective value of the combination(s).
4. SETTLEMENT FORMULATION REVIEW – PHASE II (9:50-10:00)
PJM will seek approval of Tariff and OA revisions to clarify the calculation of the deviation between the regulation set point and the expected output of each regulation resource.
5. CREDIT AVAILABLE FOR VIRTUAL TRANSACTIONS (10:00-10:20)
PJM will seek approval of Tariff changes to more accurately reflect current PJM practices regarding credit provided for virtual transactions.
6. CLARIFICATION TO TARIFF AND MANUALS FOR SYNCHRONIZED RESERVE MARKET PENALTY CHARGES (10:20– 10:30)
Stakeholders will be asked to endorse changes to Manual 11: Energy and Ancillary Services Market Operations and Manual 28: Operating Agreement Accounting clarifying that generation owners providing Tier 2 synchronized reserves will be measured in the aggregate when PJM evaluates their performance under a new penalty structure.
8. OFFER CAP REVIEW PROBLEM STATEMENT (10:45-11:00)
PJM will seek approval of a problem statement and issue charge intended to reconsider PJM’s $1,000/MWh energy offer cap. On first read at last month’s MRC meeting, stakeholders representing load said they may oppose a change in the cap. (See Stakeholders Preview Offer-Cap Debate.)
The committee will be asked to endorse changes to the Tariff, OA and Joint Operating Agreements with neighboring regions to reflect the change in PJM’s mailing address, which took effect Jan. 1.
Members Committee
2. CONSENT AGENDA (1:20-1:25)
B. Members will be asked to approve revisions to the Tariff and Operating Agreement to clean up the list of agreements and transactions to which PJM Settlement, Inc. is not a counterparty.
C. The committee will be asked to approve Tariff and OA revisions reflecting changes to eSuite application names. eSchedules and EES will be changed to InSchedule and ExSchedule, respectively.
The Environmental Protection Agency said it will miss by a month its own deadline to issue a regulation to minimize the impact of industrial and power plant water cooling structures on fish populations. “In spite of its best efforts, EPA will not meet the April 17 deadline, but will require an additional 29 days, i.e., until May 16, 2014, to complete inter-agency consultation with the services,” the agency told a federal court.
As proposed in 2011, the rule would require plants to slow the velocity of their intakes or find some other way to stop fish from being trapped or killed. Environmental groups had sued the EPA for not issuing the rule — required by section 316(b) of the Clean Water Act — but settled when the agency agreed to finalize it. The most recent court-approved agreement had required the agency to issue the rule by last Thursday. The EPA said the delay was caused by its consultations with the federal Fish and Wildlife Service and the National Marine Fisheries Services, who are tasked with Endangered Species Act enforcement.
Riverkeeper Inc., an alliance of environmental groups that brought the lawsuit against the EPA to force it to issue the regulation, blasted the EPA’s delay. “EPA’s breach of the legal commitment it made to issue a final 316(b) rule by April 17 is yet the latest in a long string of failures by this agency to meet its own deadlines, leaving us no choice but to return to federal court where we can seek an order compelling the rule’s issuance,” Reed Super, an attorney for the group, said last week.
The Obama administration again extended the review period on the Keystone XL pipeline, and its final decision may not come until after the Nov. 4 congressional elections. The State Department said officials need more time to review some of the 2.5 million public comments on the project and investigate the impact of a pending Nebraska lawsuit that could change the route of the pipeline. Officials there did not say when those reviews would be completed.
Supporters of the pipeline denounced the delay. “Here’s the single greatest shovel-ready project in America, one that could create thousands of jobs right away,” Senate Minority Leader Mitch McConnell (R-Ky.) said. “But the president simply isn’t interested. Apparently radical activists carry more weight than Americans desperate to get back on the job.”
Environmentalists called it a sign that the project will be rejected. The latest postponement “confirms, yet again, that this project is not permit-able,” said Rachel Wolf, a spokesperson for a group called the All Risk, No Reward Coalition. “This export pipeline fails the climate test, fails the jobs test, and doesn’t even have a legal route.”
The Nuclear Regulatory Commission will increase its oversight of the Ginna nuclear power plant in Wayne County, N.Y., east of Rochester. The NRC had issued what is called a “white” safety finding — of low to moderate significance — having to do with flood protection at the plant and the threat to backup batteries and other emergency power sources.
Ginna owners made modifications late last year, but the NRC was unhappy with the time it took to make the fixes. “This was one of the primary areas of focus for the NRC after Fukushima back in March 2011, and basically we wanted to make sure that all of the plants were protected to the greatest degree possible, and a lot of that analysis work is still going on,” said NRC spokesman Neil Sheehan.
Exelon said it has faith in the actions taken. “Ginna is a robust, fortified facility designed to withstand the most severe weather related events, including the highest recorded flood levels in the area,” the company said in a statement. “This potential issue was corrected, [and] it did not affect the safe, reliable operation of the plant.”
The U.S. Court of Appeals for the District of Columbia Circuit last week upheld a regulation that limits emissions of mercury and other hazardous pollutants, in a decision that affects mainly coal-fired power plants. The EPA’s Mercury and Air Toxics Standards (MATS) applies to 1,400 of the country’s largest power plants and begin taking effect in 2015.
The regulations are expected to cause a wave of coal plant retirements. U.S. companies have shut or converted more than 22,000 MW of coal-fired power plants since 2009 and have plans to shut or convert more than 42,000 MW in the next decade.
Exelon Corp. owns 1,300 MW of wind generation, a portfolio dwarfed by its 22,000-MW nuclear fleet.
So when company executives decided in 2012 that the interests of wind and nuclear power had diverged over the renewal of wind’s Production Tax Credit, Exelon called on Congress to let the subsidy expire.
The American Wind Energy Association, which spends much of its time lobbying for continuation of the PTC, responded by kicking Exelon out of the trade group. The wounds haven’t healed since.
Last month, AWEA released a study in response to Exelon’s claims that wind farms subsidized by the PTC are responsible for negative prices that are hurting the revenues of the company’s nuclear plants.
At last week’s Federal Energy Regulatory Commission meeting, Commissioner John Norris said the AWEA study provided “very compelling evidence” that “the PTC and negative pricing … are having none or negligible impact on nuclear facilities.”
“If that’s not a factor [in nuclear’s woes], as the AWEA study would seem to indicate, let’s get it out of our rhetoric,” Norris said, calling on Exelon to respond to the analysis.
AWEA’s report is intended to bolster its case for renewal of the PTC, which expired Dec. 31. On April 3, the Senate Finance Committee approved a two-year PTC extension, retroactive to Jan. 1, sending it on to the full Senate.
Exelon has been lobbying Illinois state legislators, warning that the company may shutter as many as three of its six nuclear plants in the state. The company has cited low natural gas prices and flaws in PJM’s capacity market as causes of its plants’ declining revenue. (See Exelon in Lobbying Push to Save Ill. Nukes.)
It also blamed the PTC, which pays wind generators $23/MWh of output, the equivalent of $37/MWh before taxes.
With no fuel cost and with revenue from the PTC and renewable energy credits (RECs), wind farms can profitably generate even when prices are negative.
On that, AWEA and Exelon agree. AWEA, however, takes issue with being blamed for causing negative prices.
The AWEA report, authored by analyst Michael Goggin, says that wind projects have the same impact on real-time and day-ahead prices with or without the PTC.
A generator receiving the PTC and selling RECs would offer at -$20 to -$40 per MWh, says Goggin.
“A wind project that does not receive the PTC will offer into power markets at just above $0/MWh, based on wind’s zero fuel cost and very low variable O&M [operation and maintenance] costs,” the study says. “This offer will always be lower than almost all other offers.”
Northbridge Group analyst Aaron Patterson, co-author of a 2012 Exelon-sponsored report critical of the PTC, does not question AWEA’s data but does disagree with the conclusions.
Wind “may set the price in certain hours. It has a much broader effect in all hours of pushing the dispatch curve out,” Patterson said in an interview. “That manifests itself in some hours in negative prices but in other hours in positive prices that are lower than what they would otherwise be.”
“We can work with AWEA on a clean energy future but we can’t deny the truth,” said Joe Dominguez, Exelon’s senior vice president for governmental and regulatory affairs and public policy, in an interview. “We didn’t pick a fight with the wind industry for the fun of it. We’re trying to save plants and jobs.”
Below is a summary of the major points of the AWEA report and Exelon/Northbridge’s response.
PTC Corrects for “Market Distortion”
AWEA: “The PTC is correcting for market externalities that are not currently accounted for, such as the cost of carbon emissions and the other major environmental and human health costs of fossil fuel consumption. As a result, the PTC is actually countering the market distortion that occurs on an ongoing basis because market pricing does not account for these factors.”
Exelon has complained that zero-emission nuclear power also gets no credit for its contribution to meeting climate change goals.
But Patterson notes that the PTC subsidy typically represents more than half of the per-MWh revenue of wind plants.
“I think it’s fair to say that to the extent that carbon reduction is a goal that it’s more efficient to price carbon rather than selectively subsidizing some sources and not others,” he said.
Pretax carbon prices in California and the Regional Greenhouse Gas Initiative range from $4 to $12 per ton, equivalent to $2 to $6/MWh, Patterson said. “$37 [per MWh] doesn’t strike me as an appropriate level of compensation given the carbon markets we have today,” he said.
As wind’s growth has depended on the PTC, nuclear power has benefited from the Price Anderson Act, which limits nuclear plant liability in an accident.
But that’s different, Patterson said. “It’s not production-based. It doesn’t affect how nuclear units operate in the market,” he said. “In my view, it’s not a distortionary subsidy.”
Negative Prices Overstated
AWEA: “Exelon has grossly overstated the frequency of negative prices at its nuclear plants, by a factor of at least 10 in most cases, and in some by a factor of 20 or more.”
AWEA cites a February 2013 statement by Exelon CEO Christopher Crane that the company’s Byron nuclear plant sees negative prices 16% of the time. In May 2013, Crane was quoted as saying that the Clinton nuclear power plant and the rest of the company’s nuclear plants face negative prices about 14% of the time.
Between 2009 and 2013, Exelon says real-time and day-ahead prices at its Quad Cities nuclear plant were about $6/MWh less than at the Northern Illinois hub because of competition from subsidized wind. In 2012, the differential totaled $130 million. “That’s huge,” said Exelon’s Joe Dominguez.
AWEA says real-time prices at the Byron and Clinton plants were below zero only 2 to 5.5% of the hours between 2011 and 2013. In the day-ahead market, negative prices occurred in only 0.8 to 2.4% of hours over the same period, AWEA says.
Dominguez said Crane’s comments referred to only off-peak hours.
“In the off-peak hours wind tends to produce most of its output and it is also coincident with when our consumers use the least amount of electricity. And the combination of those two factors and transmission congestion leads to negative prices,” Dominguez said. “It’s an upside-down argument to criticize nuclear plants because they can’t ramp when windmills unpredictably run.”
Real-Time vs. Day-Ahead Prices
AWEA: “Merchant nuclear plants almost exclusively sell their energy into day-ahead markets, so day-ahead data captures the true impact of negative prices on Exelon’s nuclear plants.”
Patterson responded: “To say that negative prices don’t matter because Exelon or any other nuclear generator sells their output in [forward markets] is not correct. Those prices are lower than they would otherwise be because of negative prices in the real-time market.”
Wind’s Blame for Negative Prices
AWEA: “Market price data and wind plant output data show that most instances of negative prices occurred when wind plant output was very low. … If Exelon were correct, and wind plants were the factor causing these negative prices, one would expect to only see negative prices during hours when wind plants were producing at nearly full capacity.”
Three incidents that appear to have involved localized transmission outages were responsible for most of the negative prices affecting the LaSalle, Braidwood, Byron, Quad Cities and Clinton plants in 2013, Goggin said.
Patterson agrees with AWEA that transmission outages play a role in negative prices — along with, he says, unexpectedly low load or unexpectedly high wind production. “Disentangling the specific cause for a specific negative price is very hard,” he said.
But he said the frequency of negative prices has grown since 2008, “which coincides with the expansion of wind capacity in Iowa and Illinois and surrounding regions. The nuclear plants were there [before]. The transmission was what it was. The load is what is was. What changed? The wind.”
Tx Upgrades Reducing Negative Prices
AWEA: “Instances of negative prices have rapidly dropped to near zero in all regions of the country. … Negative prices are being eliminated as long-needed transmission upgrades are completed and grid operating procedures are modernized.”
AWEA cites data showing the frequency of negative prices peaking in Illinois in 2009 and 2010 and falling since, consistent with the Northbridge report.
“It’s too early to tell whether we’re going to see a trend of reduced negative pricing,” responded Exelon’s Dominguez. “Transmission [expansions are] always trying play catch-up to the introduction of subsidized generation. The reality is we have seen many years of negative pricing. We can’t claim victory simply because one season it didn’t show up.”
PTC Discourages Investment in Conventional Generation
AWEA has noted the boom-and-bust cycle of wind capacity additions in response to cancellation and resumption of the PTC.
Northbridge says the PTC also discourages investments in conventional generation needed to maintain reliability. “In recent years, about 85% of total wind capacity has not operated during the peak hours on the highest demand days of the year, on average,” the Northbridge report says. “Controllable conventional generation is thus needed to backstop wind and ensure the lights stay on.”
Goggin said wind also contributes to reliability, noting it provided PJM more than 3,000 MW of generation during the polar vortex, when many coal- and gas-fired generators suffered forced outages.
“No resource is 100% reliable. This past winter was a very good example of that,” he said. “Every resource is backed up by all other resources.”
PJM’s newest hydropower project will be barely large enough to power nine homes. But if some visionaries have their way, it will be the start of a trend that could add up to a substantial new power source.
The North Wales Water Authority in suburban Philadelphia won Federal Energy Regulatory Commission approval last month for an 11-kW turbine and generator to capture the energy from a 12-inch water line.
North Wales’ project is among 19 projects approved by FERC since September under legislation enacted last year that a Department of Energy study says could unlock 12 GW of capacity at existing non-powered dams and manmade water conduits, including about 1.5 GW in PJM.
The Hydropower Regulatory Efficiency Act (H.R. 267) amends the Public Utility Regulatory Policies Act of 1978 (PURPA) to exempt dams up to 10 MW from FERC licensing requirements (up from 5 MW).
The law also amends the Federal Power Act to relax regulations on conduit hydropower facilities — tunnels, canals, pipelines or other “manmade water conveyance” used in distributing water for agricultural, municipal or industrial consumption — of up to 40 MW.
A second law, the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act (H.R. 678), authorizes the U.S. Bureau of Reclamation to develop small hydropower projects at existing canals, pipelines and other man-made waterways.
Only 3% of the 80,000 dams in the United States generate electricity. An addition of 12 GW would boost U.S. hydropower resources — 2,500 dams generating 78 GW — by 15%. (See PJM Small Hydro Potential: 1.5 GW.)
Three Projects in PJM
The North Wales project is one of three approved thus far in PJM.
Ellwood City, a town 40 miles north of Pittsburgh, won approval for a 10-kW turbine on a 24-inch wastewater pipe that discharges 1.7 million gallons of water daily. The Pelton wheel turbine would use the momentum of the 50-foot “head” — or drop in elevation — in the 340-foot pipe.
Another project that won approval is a 250-kW project by Oak Lawn, Ill., a Chicago suburb, which will install a turbine in a drinking water pumping station.
Oak Lawn buys water from Chicago’s purification plant, storing it in eight reinforced concrete reservoirs. Water must be delivered to the reservoirs through an air gap to prevent backflow into the Chicago delivery system.
Oak Lawn had been using butterfly valves to create the air gap and reduce the 45 pounds per square inch pressure. When the town began planning a major overhaul of the water system, engineers decided to replace the valves with a turbine. “Why not recapture what [energy] they can?” explained Randy Rogers, an engineer with CDM Smith Inc., which is designing the project.
The turbine and generator, about the size of a side-by-side washer and dryer, will save the town more than $160,000 annually in electricity, about 15% of what it spends powering the pumps that deliver water to its customers.
Village Manager Larry Deetjen said the hydro project was an easy sell in the environmentally conscious town, which runs an electronic waste center and was an early adopter of the switch to more efficient LED street lights.
The cost of the turbine, generator and related electrical equipment will be about $1 million, with a payback period of 10 to 12 years, Rogers said.
“I can see this being used wherever you burn head” (move from high pressure to low pressure water flow), he said. “I expect there to be a lot of interest in this.”
$10 Billion Market?
The North Wales hydropower project will install a “reverse pump” on a 12-inch water pipe to replace a pressure-reducing valve at a water transfer station. The station serves a role akin to an electrical substation that steps down voltage from transmission lines to the distribution system.
North Wales is using the valve to reduce the water pressure by about 30 psi. “In doing so, it becomes wasted energy,” said Frank Zammataro, CEO of Rentricity Inc., a New York City-based startup that won a $300,000 grant from the New York State Energy Research and Development Authority to build the project. Pending regulatory approvals, the company hopes to begin construction within two months and have the generator running by summer.
There are about 23,000 locations in the U.S. with such pressure-reducing valves, said Zammataro, a former Merrill Lynch banker. That represents a $2.4 billion market for potable water systems in the U.S.
Industrial uses — food processors, mines, chemical and pharmaceutical manufacturers, and the pulp and paper industry — boost the market size by another $1 billion in the U.S., he said, with worldwide potential of more than $17 billion.
Improving Cost Effectiveness
Current hydropower technology is only cost-effective at scale of 30 kW or more, Zammataro said. But for every 30-kW opportunity there are 10 to 20 opportunities of 5 kW to 30 kW.
Thus Rentricity set out to find cheaper technology that could make the small projects viable. The turbine in the North Wales project will be a modified version of a pump by Xylem Inc., the second-largest pump maker in the world. Rentricity also has a distribution deal with manufacturer Cornell Pump Co.
“The equipment is getting very cookie-cutter, very plug-and-play,” which is essential to reducing cost, Zammataro said.
Workers install Rentricity’s turbine and generator at a pump station for the Municipal Authority of Westmoreland County near Pittsburgh. The “behind-the-meter” 21-kW installation powers two of four large horsepower pumps that send water up hill to a treatment plant 2,500 feet away. (Source: Rentricity Inc.)
Reducing regulatory costs and delays are also key to making small projects viable. Zammataro said it formerly took six months or longer to win a Federal Power Act licensing exemption from FERC. Under the new legislation, the agency is now approving exemptions in about 50 days. “This is, in my opinion, a big breakthrough at FERC,” Zammataro said.
He said state regulators in New England also are on board and allow such projects to qualify for renewable energy credits under state renewable portfolio standards. Not so in Pennsylvania, which he complains is “behind the curve.”
Earlier this month, he was informed that the Pennsylvania Public Utility Commission had rejected “in-pipe micro hydro generation” from being qualified as an “Alternative Energy” resource under state law. The PUC said the technology is not listed among the sources identified by the state’s Alternative Energy Portfolio Standards law and doesn’t qualify as “low-impact hydropower.”
Without such certification, the project cannot qualify for net metering, which provides a higher value for the power than it would be able to obtain though a purchase power agreement. Zammataro said he plans to file a challenge.
Because of its topology, Pennsylvania is “a prime target within the PJM region,” he said. “There’s a lot of hills and mountains they’re moving water over.”
Smaller Footprint than Wind, Solar
To date, Rentricity has completed about a half-dozen projects.
Two turbines at Keene, N.H. water treatment plant, the first energy-neutral water treatment plant powered by its own in flow of water in the U.S. (Source: Rentricity Inc.)
In Keene, N.H., the company installed a 62-kW generator, creating what he says is the “first energy-neutral water treatment plant in the country.”
The company’s largest project is a 325-kW generator installed at the California Water Services Co. The generator is in a 20-foot by 20-foot vault, a much smaller footprint than wind or solar for an equivalent output. “This form of hydropower is very efficient and very compact,” he said.
Zammataro says all new water pipeline projects should be required to investigate the opportunities for energy recovery. In addition to offsetting water utilities’ electric bills — typically 30 to 35% of utilities’ budgets — it can provide remote power sources to run sensors to monitor flow and pressure data and identify the leaks that waste an estimated 20% of water.
“We have a relatively dumb electric grid. We have an even dumber water grid,” he said. “When you replace it you ought to replace it with smart technology.”
