The Markets and Reliability Committee approved the following Tariff and Operating Agreement revisions last week:
Clarifications to the Tariff and OA giving generators providing Tier 2 synchronized resources the ability to aggregate these resources in order to avoid retroactive penalties for failure to respond appropriately when called. New language will also be added to Manual 11: Energy & Ancillary Services and Manual 28: Operating Agreement Accounting. Aggregation will not be used in calculating Tier 2 Synchronized Reserve credits; each resource will continue to be credited independently.
Revisions to the Tariff to reflect current PJM practices regarding credit available for virtual transactions. PJM instituted the policy as the result of a FERC Order in 2004 but failed to make accompanying changes to the Tariff. These revisions also correct for changes in credit policy since 2004 (e.g., working credit limit discount is now 25%, not 15%).
Clarifications to the Tariff and OA on regulation shoulder hour lost opportunity costs (LOCs). As a result of a review, PJM discovered that the documents didn’t adequately describe the calculation of the deviation between the regulation set point and the expected output of each regulation resource.
Changes to the Tariff and OA reflecting PJM’s change in mailing address to: PJM Interconnection, L.L.C. 2750 Monroe Blvd., Audubon, PA 19403.
The MRC also approved the following manual changes:
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.
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. (See related story, FERC Clears Capacity Import Limits.)
The Members Committee endorsed the following consent agenda items last week:
Revisions to PJM’s Tariff and Operating Agreement to clarify agreements and transactions to which PJM Settlement, Inc. is not a party.
Operating Agreement and Tariff revisions to effectuate the eSuite application name changes (i.e., changing eSchedules and EES to InSchedule and ExSchedule, respectively). Proposed improvements to eSuite applications are slated to continue through 2015.
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.
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.
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.”
PJM’s scheduling rules aren’t flexible enough to meet the needs of wind and other variable energy resources, the Federal Energy Regulatory Commission ruled last week.
The commission said PJM’s rules failed to meet the requirements of Order 764, which requires transmission providers to offer scheduling at 15-minute intervals. FERC ordered PJM to submit a new compliance filing within 30 days.
Prior to Order 764, the pro forma Open Access Transmission Tariff — developed for generation that could be scheduled with relative precision — included no option for adjusting transmission schedules within the hour.
As a result, variable energy resources could not avoid generator imbalance charges when they knew their generation was likely to change within the hour. Generator imbalance charges pay for energy the transmission provider must purchase when a generator’s output falls short of the amount scheduled.
The revised pro forma OATT requires that transmission providers allow scheduling changes be made within 20 minutes “or a reasonable time that is generally accepted in the region … before the start of the next scheduling interval.” The commission said it wanted to allow generators to adjust their schedules in 15-minute intervals.
PJM proposed amending the firm and non-firm point-to-point transmission service provisions of its Tariff to allow 15-minute schedules. But the commission said it was not compliant with Order 764 because the proposed Tariff required that the changes be made 20 minutes “before the next clock hour,” rather than before each 15-minute interval.
(As a practical matter, PJM said it does not assess imbalance penalties on any generators, because virtually no market participants use point-to-point transmission to serve load.)
Interchange Transactions
FERC also took issue with PJM’s practice of requiring that interchange transactions have a minimum duration of 45 minutes, which the commission said “is inconsistent with Order No. 764 because it does not allow a generator to schedule for less than three consecutive 15-minute intervals.”
PJM said it implemented the 45-minute rule on interchange transactions in 2008 to prevent “market abuses.”
In 2007, MISO and its Independent Market Monitor determined that nearly 60% of intra-hour schedules between MISO and PJM occurred in the final 15 minutes of the hour. PJM said the trading was the result of “market participants’ ability to see price differences between the two RTO markets for the first third of the hour and thereby predict with relative certainty the direction of the price separation between the two RTOs when the hourly integrated prices were calculated.”
PJM said this resulted in interchange spikes of up to 1,000 MW — increasing uplift charges because of the need to call on combustion turbines to balance the generation swings.
“A return to a 15-minute duration rule would cause an increase in imbalance charges [and balancing operating reserve] costs because it is entirely reasonable to expect that market participants would return to the [prior] practices,” PJM said.
Last year, the commission rejected MISO’s proposal to retain an existing requirement that schedules starting at the 30- and 45-minute marks of the hour be made by the beginning of the hour, which MISO said was intended to prevent the problems identified in 2007.
The commission last week granted MISO an extension until June 30, 2015 to fully implement Order 764.
Data Requirements
Order 764 also requires variable resources to provide meteorological and forced outage data to help transmission providers more accurately forecast generation. The commission accepted PJM’s addition of these requirements to its Tariff.
Calpine Corp. is selling six power plants in the Southeast and Midwest to LS Power for $1.57 billion in cash as part of a plan to focus on its electricity sales businesses in the Mid-Atlantic, Texas and California. The plants — representing a combined 3,498 MW — are in Alabama, Oklahoma, Louisiana, Florida and South Carolina.
Calpine spokesman Brett Kerr said the company planned to sell the six power plants for some time. It wanted to sell additional plants in Alabama, Arkansas and Florida but wasn’t able to get the price it needed for those assets. The LS Power deal is expected to close in the second quarter, and Calpine said it plans to use proceeds to pay down debt, buy back shares and possibly buy new generation.
The company operates 77 natural gas-fired power plants across the U.S., including 24 in California, 20 in Mid-Atlantic states and 14 in Texas. Calpine also has geothermal power plants in California.
PSEG’s Izzo Frustrated Over Opposition to “Energy Strong”
Ralph Izzo (Source: PSEG)
A frustrated Public Service Enterprise Group chief executive Ralph Izzo last week renewed his call for the state to approve a multibillion-dollar infrastructure-hardening project the company proposed shortly after Hurricane Sandy. In comments following PSEG’s annual shareholder meeting in Newark, Izzo questioned how the project’s opponents could maintain what he believes are two competing objections: that it costs too much and that it won’t help enough customers.
“The only way to reconcile those two is by saying, OK, we’re not proposing to spend the money in an optimal way,” Izzo said in an interview. “In which case, I say, we’re an open book. Tell us a better way to do it. And the reality is, there isn’t a better way to do it.”
Izzo said part of the planned 10-year, $3.9 billion “Energy Strong” project calls for strengthening facilities that were damaged by Sandy and Tropical Storm Irene. Newark-based Public Service Electric & Gas — PSEG’s largest subsidiary — filed Energy Strong with the state Board of Public Utilities in February 2013, four months after Sandy. While the utility maintains the project would improve reliability and help prevent the kind of massive power outages Irene and Sandy caused, opponents have pushed back against its price tag. The state Division of Rate Counsel, AARP New Jersey and a coalition of large energy users have also questioned the project’s stated effectiveness and the utility’s insistence on receiving approval for the money before starting construction.
As Stock Slides, Exelon’s Crane Gets 70% Raise in 2013
Christopher Crane (Source: Exelon)
Even as the company’s stock slid nearly 8% last year, Exelon Corp. CEO Christopher Crane was rewarded with a 70% raise, making more than $17 million in 2013. Crane’s total compensation in cash, stock and benefits topped out at $17.2 million, up from $10.2 million the year before. Crane’s compensation moved to a new performance-pay system that ties rewards over a three-year period rather than year-by-year. The company also eliminated stock options and moved its stock-based compensation to restricted shares and performance shares.
Exelon said it raised Crane’s pay to make it comparable to the median for peer CEOs. Before 2013, his pay was targeted at 20% less than the median. Exelon has suffered from falling wholesale power prices as its nuclear plants have grown less profitable. Increases at its regulated utilities — particularly ComEd, which is collecting annual delivery rate hikes per a state law authorizing $2.6 billion in local grid upgrades — have partially offset the declines at the power plants. But the 8% stock slide last year followed a 31% drop in 2012.
Duke Shareholders Urged To Oust Board Members Over Ash
Two of Duke Energy’s major institutional investors are urging fellow shareholders to vote out four directors at the May 1 shareholders meeting over the company’s ongoing coal ash problems. The California Public Employees’ Retirement System (CalPERS) and the New York City Pension Funds wrote shareholders last week, asking that they not reelect four board members responsible for environmental safety and health compliance.
Ash Spill (Source: Duke Energy)
The letter cites the Feb. 2 ash spill into the Dan River, saying Duke had “forewarning of the public risk” from environmental groups that had intended to sue Duke over ash contamination. None of the committee members named — Alex Bernhardt, James Hyler, James Rhodes and Carlos Saladrigas — has coal industry or other relevant experience, CalPERS and New York City comptroller Scott Stringer wrote. “In light of the serious failures of oversight, scale of impact on the company’s risk profile and the poor response to shareowner enquiry thus far, we urge our fellow investors to hold the relevant board members accountable.”
Duke said last week it has spent $15 million so far cleaning up the spill but said the costs would not be “material” to the company. Duke CEO Lynn Good has said Duke will pay for cleaning up the 70-mile trail of ash in the Dan River, but that it will ask the North Carolina regulators to approve ratepayer funding of costs associated with closing 33 ash basins at Duke sites across the state.
Duke had no immediate comment on the stakeholders’ action. CalPERS owned $140 million in Duke stock in 2013. The New York City funds have $62 billion in U.S. stocks, although it’s unclear how much of that is Duke stock.
PPL Generation, Trading Sale Rumors Fuel Stock Rise
PPL Corp. stock is trading near the top of its 52-week range amid continued speculation that the company may spin off its generation and energy marketing business. PPL shares closed Friday at $33.14, close to its 52-week high of $33.55. The rise came after the International Strategy and Investment Group raised its target price for PPL, citing the strength of its regulated utilities and the potential benefit if it spun off its generation. The report also cited the potential upside for PPL if it merged its power plants with another company’s.
A trade publication earlier this year published a report saying PPL hired Morgan Stanley and Citibank to conduct an internal review of PPL Energy Supply, the business arm that includes PPL’s generation and energy trading and marketing businesses. That report pointed at Dynegy as a possible buyer. PPL declined comment on any sale or spinoff rumors.
Dominion Virginia Power will conduct an earthquake risk assessment for its North Anna nuclear generating station but doesn’t expect the study to point to any significant modifications. The plant’s two 980-MW reactors were knocked offline by a 5.8-magnitude earthquake that shook central Virginia in August 2011. Although the temblor caused no significant damage, the station remained out of service for three months while the company and the Nuclear Regulatory Commission conducted a thorough safety check.
“These plants have so much design margin on the seismic side, I have no concerns about this whatsoever,” said David A. Heacock, president and chief nuclear officer of the parent company’s Dominion Nuclear operating group, said last week. “We verified our plant can withstand a stronger earthquake” than it was designed for.
In 2012, the U.S. Department of Energy, the Electric Power Research Institute and the NRC updated the seismic model for the central and eastern U.S., reflecting a greater seismic hazard at some nuclear plants than previously thought. Forty-seven plants will have to conduct additional studies to determine whether their designs protect them from earthquake hazards. Once the assessments are complete, the NRC will decide if plants require upgrades.
