Members last week gave initial approval to a manual change that will make it easier for banks to purchase capacity providers’ revenue streams. The Market Implementation Committee approved a change proposed by Citigroup Energy to allow auction-specific transactions to be entered into PJM’s eRPM system after the auction that initiated them.
Under current rules, such transactions cannot be submitted to PJM until after the third incremental auction for a delivery year. The MIC approved changes to Manual 18 by acclamation, sending the issue on to the Markets and Reliability Committee for final approval. (See Stakeholders Look to Expedite Auction-Specific Transactions.)
Despite closing its Wisconsin nuclear plant prematurely last year, Dominion Resources wants to keep its options open in Virginia, where it is considering a third unit at its North Anna nuclear plant.
But it hasn’t done any analysis to compare the risks of a new plant against an increasing reliance on natural gas-fired generation, Virginia State Corporation Commission staff said in a filing last week.
Responding to Dominion Virginia Power’s 2013 Integrated Resource Plan, staff said such an analysis should be included in the company’s next IRP in 2015 in order to determine which option the company should follow in the future.
Dominion “believes that uncertainty associated with the price of natural gas over the long term is a greater risk than the development cost uncertainty of a nuclear unit. However, the company concedes that no analysis has been performed to support this assertion,” SCC staff said. Staff said Dominion has indicated a willingness to conduct the analysis.
Two Plans
In its 2013 IRP, Dominion presented two different plans, one it called the “Base Plan” that calls for the expansion of generating capacity through new natural gas-fired plants, and one it calls the “Fuel Diversity Plan,” which includes low-emission options and does not rely so heavily on natural gas.
Both plans are very similar in the short run, with the major difference being that the latter plan includes the construction of North Anna 3. The company has chosen to follow the Base Plan, the least cost option, but it will also continue to go “forward with reasonable development efforts of additional resources included in the Fuel Diversity Plan,” which “would preserve the company’s ability to implement these alternatives should future conditions warrant,” SCC staff noted.
While natural gas plant projects have low development cost risk, the historically volatile fluctuating fuel price creates the risk of high operating costs. Nuclear plants generally have low operating costs, but their construction is very complicated and prone to cost overruns.
“In other words, there is a risk trade-off of higher operating cost risks with the Base Plan and higher project development cost risks with the Fuel Diversity Plan,” SCC staff said. “Staff was unable to determine whether the Base Plan contains too much operating cost risk, or whether the development cost risk associated with the Fuel Diversity Plan is greater than or less than the reduction in operating cost risk the Fuel Diversity Plan would achieve, because the company did not perform an analysis of this risk trade-off in its IRP.”
Dominion, which applied for Nuclear Regulatory Commission approval of North Anna 3 in 2003, has not committed to building the unit. In its IRP, the company said it would make its final decision once it received a Combined Operating License from the NRC. The unit would be completed no earlier than 2024.
Risky Business
The recent boom in natural gas production, resulting in cheap prices, has not been kind to the nuclear industry. Dominion learned this the hard way last year, when the company was forced to close the 556-MW Kewaunee Power Station, which it had purchased in 2005 for $192 million. After utilities did not renew their power contracts with the Wisconsin plant and Dominion failed to buy other nuclear plants in the region, the company attempted to sell Kewaunee in 2011. When it became apparent there were no buyers, Dominion closed it.
Kewaunee, which opened in 1974, closed a year shy of its 40th birthday, when its license would have needed renewal. Staff at the plant are now beginning the long process of decommissioning it.
With North Anna 3, Dominion seeks to keep all of its options on the table. Mark Kanz, local affairs manager for Kewaunee, recently told Nuclear Power International magazine that the prospect of North Anna 3 “proves that the company sees the benefit of nuclear and is looking forward to continuing that into the future.”
SCC staff also wants the company to compare the costs of building a third unit with the costs of extending the operating licenses of the first two, along with the licenses of the two units at its Surry nuclear plant.
“Given that these units still provide extremely efficient and dependable baseload generation for the company, and given the extremely high costs of constructing new nuclear plants, staff believes that the company should engage in serious discussions with discussions with the NRC to determine whether renewing these licenses is possible.”
The staff noted that it is unknown whether the NRC would grant renewals to the current units. The units would be 60-years-old when their licenses — already extended by 20 years — expired. The NRC expects the first application for an extension beyond 60 years to be filed in 2018 or 2019. Without additional license extensions, the country would face a wave of nuclear plant retirements during the next decade.
Two losing bidders for the Artificial Island transmission project have issued harsh critiques of PJM’s handling of the solicitation, seeking to persuade the Board of Managers to reject planners’ recommendation that the project be awarded to Public Service Electric & Gas.
In letters to the board, Northeast Transmission Development, a unit of LS Power, and Atlantic Grid Development, whose backers include Google, allege the competition was tainted by favoritism and that the PSE&G project will have difficulty winning siting approval. The challengers also contend the technical design of the winning project is inferior to their own proposals.
Atlantic Grid’s proposal failed to make PJM’s list of finalists. LS Power’s project was the low-cost proposal among the 10 finalists until PJM planners revamped the PSE&G proposal and deemed it equal in cost to LS Power’s at $211 million to $257 million. The changes reduced PSE&G’s price tag by $832 million, a 78% reduction. The estimates do not include an additional $80 million for a static VAR compensator, which PJM added to all of the proposals. (See PSE&G Wins $300M Artificial Island Project.)
In his letter, Northeast Transmission President Paul Thessen said PJM’s cost estimate for his company’s project is too high. He said the company estimates its project at $149 million and will cap its recovery at $171 million, a savings of at least $40 million to $90 million over the PSE&G project.
The board is scheduled to consider the staff recommendation at a meeting July 22.
“After careful evaluation, PJM’s staff concluded that ours was the best proposal. We believe that is the correct choice,” PSE&G spokesman Mike Jennings said in a statement. “We have successfully completed transmission projects in environmentally sensitive areas and performed that work on time and on budget. We are committed to doing the same with this project.”
PJM spokesman Ray Dotter declined to comment on the critiques. “We can say in general that our approach, which was made clear all through the development of our Order 1000 filing and reiterated throughout the Artificial Island evaluation process, is that we would look for the most cost-effective transmission solution,” he said.
Unwarranted Preference
Atlantic Grid said PJM planners gave PSE&G an “unwarranted preference” based on its participation in the Lower Delaware Valley Transmission System Agreement (LDV), a 1977 compact that controls right of way along the recommended project path between the Hope Creek nuclear plant and Red Lion, Del. Other signatories are JCP&L, Delmarva Power & Light, Atlantic City Electric and PECO.
Crediting PSE&G for the LDV right of way ignores the fact that about half the route is over federal and state land, where it may be difficult to obtain siting approval, Atlantic Grid said. In addition, the LDV right of way, the route of an existing 500-kV circuit, will need to be widened by as much as 200 feet in some locations.
Atlantic Grid said the PSE&G project “has a high likelihood of being rejected” by state or federal permitting agencies because it crosses wildlife protection areas and about 59 water bodies and may adversely impact endangered or threatened species. As a result, the ultimate fix “will be substantially delayed because PJM has proceeded down a dead end,” wrote Atlantic Grid President Robert L. Mitchell.
The New Jersey Board of Public Utilities (NJBPU) submitted comments raising the same concerns before planners announced their recommendation last month.
Atlantic Grid said PJM and its engineering consultant, GAI Consultants Inc., failed to seek a pre-application review from the New Jersey Department of Environmental Protection, which could have provided an indication of the project’s chances of winning required permits. “If GAI had followed this process its report might well have raised stronger cautions,” Atlantic Grid said.
Reliability of Design
Atlantic Grid also said the planners’ choice does not provide black start support for Artificial Island and ignores Nuclear Regulatory Commission regulations requiring nuclear plant switchyards be served by two physically independent circuits to minimize the likelihood of simultaneous failure. The PSE&G project would add a 500-kV line paralleling LDV’s existing 500-kV circuit.
Home to the Hope Creek and Salem nuclear plants, New Jersey’s Artificial Island is one of the largest nuclear complexes in the country.
26 Proposals
PJM asked for solutions to a stability problem at the complex last year. Five utilities and three independent developers responded with 26 potential solutions ranging from $100 million to $1.5 billion.
Atlantic Grid’s proposal, which would have buried an HVDC transmission circuit in public road rights of way between Artificial Island and Cardiff, N.J., appears to have been rejected early in the process. PJM cited its $1.01 billion cost and said it failed stability performance tests.
PSE&G, whose sister company PSEG Nuclear LLC operates the Salem and Hope Creek nuclear plants, submitted 14 alternative solutions, more than any other competitor.
One PSE&G proposal, 7K, envisioned a new New Freedom-Deans 500-kV line and a new Salem-Hope Creek-Red Lion 500-kV line at a cost of $1.066 billion.
The 7K project PJM planners recommended last month included several major changes that PJM says reduced the price by more than three-quarters.
Atlantic Grid criticized planners for modifying proposals that initially failed the technical review to allow them to qualify. “Some proposals were modified more than others, and others were not modified at all, raising significant questions about why PJM discriminated in this manner and the fairness of the process,” Atlantic Grid said.
“It appears that PJM took the proposals and then re-engineered a solution it liked best by mixing and matching pieces from different project proposals. The result is that PJM’s recommended 7K Project looks almost nothing like the original 7K proposal submitted by PSE&G.”
PJM Review
PJM planners began reviewing the proposals in July. In October, planners told the Transmission Expansion Advisory Committee they had narrowed their focus to the lowest-cost projects, which proposed interconnecting with facilities in Delaware. They also said they intended to add static VAR compensators to all proposals to provide reactive support.
By February, the focus had narrowed to proposals using two routes to connect to Delaware: a northern path that would add a 17-mile 500-kV line that parallels the existing 500-kV line from Red Lion to Hope Creek, and a southern crossing using a 230-kV circuit. The northern crossings included PSE&G’s 7K proposal; among the southern crossings was LS Power’s proposal, 5A.
By the March TEAC meeting, PJM planners apparently had decided to eliminate the New Freedom-Deans 500-kV line from the PSE&G proposal, showing its cost as proposed reduced to $297 million.
At a special TEAC meeting in May, planners said they also had eliminated a second tie line between the two nuclear plants from proposals by PSE&G and Dominion Virginia Power.
That reduced the estimated cost of the PSE&G proposal by about $43 million, giving it the same range ($211 million to $257 million) planners had assigned to the LS Power proposal, which had previously had been listed as the lowest cost option.
The elimination of the tie line also improved the performance of the PSE&G proposal in the planners’ rankings of the proposals.
PJM presented a chart summarizing its analyses of the proposals, assigning color codes for each of 25 attributes: green (positive or limited impact); yellow (some impact) and salmon (negative impact). RTO Insider summarized the findings by assigning a score of 1 to green, zero to yellow and -1 to salmon.
PSE&G’s 7K proposal scored a 1 out of a possible 25 in its original form but received a 9 when the second tie line was removed — the best of all 12 proposals analyzed. LS Power’s proposal scored a 7, ranking it third. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.)
LS Power contends PJM planners underestimated the cost of the PSE&G proposal. The company said GAI Consultants estimated the cost of the 500-kV line at $5 million/mile while staff estimated only $3.6 million/mile. The consultants included an adder of $1 million/mile to account for construction in wetlands, which LS Power said PJM staff apparently did not consider.
LS Power also complains that PJM gave its proposal no credit for factors favoring its proposal, including rightofway, route diversity, black start, market efficiency, feasibility and system outage requirements.
Order 1000 Precedent
While LS Power wants PJM to accept its cost-capped proposal, Atlantic Grid asked the board to delay a decision until it evaluates the likelihood of the proposals to receive necessary siting approvals.
The challengers said the selection of PSE&G would set a bad precedent for future solicitations under the Federal Energy Regulatory Commission’s Order 1000, which was intended to open transmission development to competition.
“Unfortunately, if this RFP sets the pattern for the future, PJM will discourage participants from spending time, money and engineering resources to develop innovative, well-engineered RFP responses,” Atlantic Grid said.
Members approved yet another initiative to address reliability concerns over gas-fired generators, agreeing to consider changes to the way such units submit energy and capacity market offers.
Under a problem statement approved by the Market Implementation Committee Wednesday, members will consider ways to reduce the confusion that occurred on the coldest days of last winter, when some gas-fired generators were unable to obtain fuel, some claimed costs above the $1,000/MWh offer cap and others ended up with “stranded” gas after PJM cancelled plans to dispatch them. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
The effort will attempt to design rules that allow generators to submit offers that better reflect often volatile natural gas prices. Among potential changes: allowing generators to change their energy market offers during the operating day and submit differing hourly offers in the real-time market, as the New York ISO allows.
Carl Johnson, representing the PJM Public Power Coalition, expressed concern that stakeholders’ multiple gas-electric coordination initiatives could result in changes whose interactions are not well understood. “We have, at my count, six problem statements … on gas issues,” he said. “I’m concerned as we march forward … how these timelines will work together.”
Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), also expressed concern. “The expectation for compromise gets less and less as you get more and more complex,” he said.
John Horstmann of Dayton Power & Light Co. suggested the issue could be handled by one of the groups already dealing with gas-electric issues. PJM staff agreed to review work assignments and make a recommendation at next month’s MIC meeting, when stakeholders will consider a proposed Issue Charge.
PJM capacity prices would increase sharply but reliability would not be threatened if a recent federal court ruling eliminated demand response from wholesale markets, according to a new report by the Independent Market Monitor.
Market Monitor Joe Bowring said the sensitivity analysis released last week is intended to help stakeholders evaluate the impact of the May 23 ruling by the D.C. Circuit Court of Appeals that sharply restricts the Federal Energy Regulatory Commission’s jurisdiction over demand response compensation. (See DR’s Future Unclear Following Court Ruling.)
Revenue in the May base residual auction would have more than doubled to $16.86 billion from $7.5 billion if no DR or energy efficiency cleared, the analysis found. Cleared resources would have dropped by 3,290 MW, reducing reserves to 2% above the Installed Reserve Margin (IRM) from 4.4%. Bowring said the analysis included energy efficiency as “another form of DR,” which could be vulnerable under the court ruling.
Disruptive Ruling
On July 7, PJM joined FERC in asking the Court of Appeals to reconsider its ruling. “Extricating demand response from markets in which it has had years to integrate will be inherently disruptive and will inevitably raise countless unforeseen complications,” PJM said. While Order No. 745 was limited to economic demand response in daily energy markets, its implications are “potentially boundless.”
PJM’s petition overstates the impact of DR on reliability and understates the ability of PJM markets to respond, Bowring said in an interview Friday.
“If there’s a decision to eliminate [DR and EE] the market will adapt,” Bowring said. “Once you allow for other offers to respond to all this we would expect the prices to equilibrate — balance out — to the cost of new entry.”
Capacity prices doubled for much of the RTO in May’s base residual auction following rule changes that reduced the volume of limited DR and external generation that could clear.
Annual resources cleared at $215/MW-day for the PSEG zone, while the rest of the RTO cleared at $120/MW-day, about one-third of the $351 net cost of new entry (net CONE).
2.5% Holdback
The IMM’s study also looked at the potential impact of Bowring’s recommendation to eliminate a rule that reduces the volume of capacity resources procured in the BRA by 2.5%. Stakeholders last year rejected calls to eliminate the 2.5% holdback, which is intended to be filled by short lead-time resources procured in incremental auctions closer to the delivery year.
Had the holdback been eliminated along with DR and EE for the May BRA, capacity revenues would have more than tripled to $23.87 billion, or $396/MW-day, 13% above net CONE. The quantity of resources acquired would fall but remain sufficient to meet the IRM, the Monitor’s analysis found.
With the removal of DR and EE and the elimination of 2.5% offset “prices would have risen to greater than net CONE but less than the maximum price [1.5 times net CONE] and PJM’s reliability target would have been maintained,” the Monitor said.
The analysis assumed that all other variables are held constant, meaning that the real impact would likely be less because additional generation resources would have cleared the auction. “In the absence of demand side resources, some generating resources that retired in prior years might not have retired, and some new generation resources that did not clear in prior years would have cleared and both would have affected prices in subsequent auctions.”
The Monitor made no predictions on where prices would settle.
Concerns over Court Ruling
The D.C. Circuit ruled 2-1 that FERC’s Order 745, which requires PJM and other RTOs to pay DR full locational marginal prices (LMP), violates state ratemaking authority.
In its petition seeking a rehearing, PJM cited “the considerable uncertainty this decision has engendered” for PJM, which has used DR since 2000. Although PJM opposes Order 745’s equal-compensation mandate, General Counsel Vince Duane said the RTO sought rehearing because of concerns over the loss of DR.
PJM said the ruling appears to “forbid any compensation (regardless of the level) to economic demand response from the wholesale daily energy markets, not just the compensation change addressed by Order No. 745.”
“PJM does not have good options for replacing demand response capacity commitments on very short notice for the current summer, and replacing demand response capacity commitments for the next three summers (to the extent they even can be fully replaced) would likely be very costly,” PJM said.
The filing cited DR’s role in maintaining reliability during last September’s unexpected heat wave, when PJM was forced to shed load in some areas and during the arctic cold in January, when it “received more megawatts as load reductions than it could obtain as generation from all but the very largest generating stations.”
The RTO called for load reductions on 13 days in 2013. DR providers are committed to provide more than 8,000 MW of load reduction this summer and more than 10,000 MW for the summers of 2015-2017.
PJM said the loss of the wholesale markets might result in the elimination of many DR resources because the retail market cannot compensate DR for providing regulation, spinning reserves and day-ahead scheduled reserves, as PJM does.
In addition, it is unclear how DR procured through state-run retail processes could compete on price with generation procure in wholesale markets, PJM said. “There should be no mistake that pulling voluntary demand resource offers out of the grid operators’ single-clearing price markets will significantly reduce competition in those markets.”
This would contradict Congress’ direction in the 2005 Energy Policy Act to encourage demand response and eliminate “unnecessary barriers to demand response participation in energy, capacity, and ancillary service markets,” PJM said.
PJM officials said last week they have acquired sufficient new black start capacity to replace coal-fired units that will retire over the next year due to environmental rules.
PJM’s black start capacity will decline to 8,070 MW (150 units) from 8,720 MW (195 units), PJM’s Dave Schweizer told the Market Implementation Committee Wednesday.
Schweizer said PJM will have adequate supplies despite the reduction because of a redefinition of “critical load” and a rule change allowing units in one zone to provide service to others.
The redefinition — which will include units with hot start times of four hours or less — will increase the number of critical load units to 600 from 475 while reducing the total capacity to 2,910 MW from 4,780 MW.
PJM’s black start costs for 2016-17 will total more than $72 million, a 1.8% increase over 2015-16, according to an analysis by the Independent Market Monitor. Some zones, such as Dominion (+39%) and DPL (+27%), will see large increases, while others, such as Commonwealth Edison (-30%), will see sharp drops.
The RTO completed a solicitation for new black start resources because the Environmental Protection Agency’s Mercury and Air Toxics rule (MATs), which takes effect next year, will result in the shuttering of dozens of coal-fired plants.
PJM will attempt to win stakeholder approval for limited changes to the compensation rules for black start units and for a plan for selecting “backstop” resources for regions that fail to secure service through competitive solicitations.
In February, stakeholders rejected two proposals that would have boosted payments to existing black start units by at least 40%. On July 31, the Markets and Reliability Committee will consider smaller compensation changes. (See PJM to Seek Smaller Black Start Changes.)
PJM officials are considering boosting the RTO’s installed reserve margin (IRM) for winter as a result of its experience in January, when it narrowly avoided shedding load amid frigid temperatures and high outage rates.
PJM’s Tom Falin told the Planning Committee last week that a winter IRM is among the responses officials are considering based on a loss-of-load analysis that highlighted the winter risks.
PJM’s current IRM requirement is based on its summer peak demand and the assumption that generator-forced outages occur randomly at a constant rate under all load and temperature conditions.
In early January, however, PJM saw outage rates three times the assumed 7.35%, with many generators unable to start or obtain fuel due to the cold.
As a result, PJM recently conducted a loss-of-load analysis for the winters of 2014/15 and beyond to determine the risk of the RTO having insufficient resources to meet load.
The analysis found that on a 90/10 peak day next winter (90th percentile of winter loads), there is a “virtual certainty” of load shedding if 18% of generation is lost to weather outages and maintenance in addition to the year-round 7.35% outage rate, Falin said.
The situation could be more dire in 2015/16 as a result of retirements resulting from the Environmental Protection Agency’s Mercury and Air Toxics rule. The analysis finds a 90% chance of load sheds on a 90/10 winter peak day with only 12.5% in additional outages.
Falin said the results indicate that only 7.4% of PJM’s generation can be “at risk” of winter-related outages to remain in compliance with the “one day in 10 years” loss-of-load expectation on which PJM’s IRM is based.
As a result, he said, PJM is considering proposing either a winter IRM or ensuring that no more than 7.4% of the resources clearing in the capacity market are at risk of cold-related outages.
James Wilson, a consultant to state consumer advocates, said the analysis was conservative and misleading because, among other assumptions, it ignored energy efficiency and assumed no demand response available in the winter.
Falin said the assumption was justified, noting only 43 MW of annual DR cleared for the upcoming winter.
Wilson noted that the threshold identified by PJM was based on preventing any non-zero increase in LOLE, which might lead to costly policies to limit at risk units. He suggested a threshold be applied, as PJM has done in other contexts.
Members OK Load Model for IRM
In related news, the Planning Committee last week approved a PJM staff recommendation to use an eight-year load model (2004-2011) for this year’s reserve requirement study.
Planners chose the model from among 36 candidates ranging in length from seven to 14 years. They said it did well in two coincident peak analyses and was a more recent time period than the other alternatives.
The load model will be used in resetting Installed Reserve Margins for 2015/16, 2016/17 and 2017/18, as well as establishing the initial IRM for 2018/19.
Despite losing out on a $487 million, four-year Department of Energy grant, the developers of a proposed Lake Erie wind farm say they will proceed with the project. The Lake Erie Energy Development Corp. (LEEDCo) will still get a $3 million federal grant for engineering and other studies, in addition to the $4 million it received in 2012. The planned Icebreaker project is to be built near Cleveland, seven miles off shore. LEEDCo President Lorry Wagner said that “the fundamentals of the project are as strong, if not stronger” than ever. “People want locally grown green energy.”
Nuclear Regulatory Commissioner George Apostolakis announced last week that he would retire at the end of his term on June 30. He became the second NRC commissioner to announce his departure in a month. William Magwood announced two weeks ago that he was leaving in September. If neither is replaced immediately, three of the commission’s five seats will be vacant. Apostolakis became a member of the NRC in April 2010. Before that, he was a professor of nuclear science and engineering and a professor of engineering systems at Massachusetts Institute of Technology.
NRC: Entergy Plant Still has ‘Chilled Work Environment’
The Palisades Nuclear Power Plant in Michigan still presents a “chilled work environment” for its security workers despite Entergy Corp.’s commitment to improve, the Nuclear Regulatory Commission said in a letter sent to plant management on June 20. Entergy’s efforts “did not demonstrate a strong commitment to effectively improve” the culture at the plant, the NRC said.
“We concluded that the quality of the actions implemented have been insufficient to assess and understand the cause of the chilled work environment within the Security Department,” according to the letter. Security employees at the plant continue to be afraid to point out problems, the commission said.
But it did note that Entergy continues to work to improve the situation. “Because the first step in any 12-step recovery program involves identifying and admitting the problem, Palisades has clearly passed this step,” the NRC said.
The University of Delaware received a $12 million grant from the Department of Energy to help conduct energy research. Dionisios Vlachos, director of the university’s Catalysis Center for Energy Innovation, said the money will let researchers continue work researching widely abundant plant biomass to be used for renewable chemicals and fuels. The university was one of 32 “Energy Frontier Research Centers” across the country to share $100 million in research grants.
Other winners included the Carnegie Institution of Washington (accelerating the discovery and synthesis of kinetically stabilized energy-relevant materials using extreme pressures), the University of Maryland at College Park (nanostructures for electrical energy storage) and Pennsylvania State University (developing a detailed nano- to meso-scale understanding of plant cell wall structure and its mechanism of assembly to provide a basis for improved methods of converting biomass into fuels).
PJM will attempt to win stakeholder approval for limited changes to the compensation rules for black start units and a plan for selecting “backstop” resources for regions that fail to secure service through competitive solicitations.
The changes that will be considered by the Markets and Reliability Committee July 31 would make relatively minor changes to compensation rules, allowing:
Compensation for storage of propane and liquefied natural gas. Current rules permit compensation only for oil storage.
Compensation for energy-only resources.
Recovery of the costs of complying with the rules of the North American Electric Reliability Corp. (NERC) for automatic load rejection (ALR) units.
The changes received only 58% support in a poll of the System Restoration Strategy Task Force, well below the two-thirds vote it will need to clear at the MRC.
The task force unanimously approved a second proposal for selecting black start resources for zones that are unable to obtain black start services through PJM’s requests for proposals (RFPs). The “backstop” provision would be triggered by a failure of an RTO-wide RFP and two incremental RFPs. It would apply to zones that cannot be serviced by generation in another zone or through transmission upgrades to improve their cranking path.
Under the proposal, the host transmission owner would be responsible for obtaining black start service either through its generation affiliate or by contracting with a third-party generator. The unit providing black start capability under the scenario would be prevented from offering into the energy or ancillary services markets.
The alternative, explained PJM’s Chantal Hendrzak, “is to wait for another part of the system to come up” to jump start the zone.
Delmarva Power & Light Co. will accept applications for a Solar Renewable Energy Credit (SREC) Spot Market Auction through July 7. SRECs let renewable energy producers sell credits to Delmarva to help it meet its renewable mandates set by the state. Delmarva intends to buy 2,000 to 6,000 SRECs to help it meet its 2013-2014 renewable portfolio standards set by the state.
Public Service Commission staff said Delmarva Power & Light Co.’s planned reliability investments may shoot too high and suggested the company scale back some of the projects.
Delmarva proposed spending $397 million over the next five years upgrading its system and replacing aging infrastructure. But in a recently released report, PSC staff said they found that much of the Delmarva distribution system “is relatively young in terms of asset life” and that the company hadn’t shown “that its customers are dissatisfied with the current level of system reliability.”
The staff thinks Delmarva should limit its five-year investment plan to $200 million “until a more detailed annual review process can be completed.”
Chicago Mayor Rahm Emanuel’s deal with Integrys Energy Services to provide electricity to city homes and businesses could end up costing more than if customers had stayed with Commonwealth Edison, according Crain’s Chicago Business. A credit on ComEd bills for the months of June and July will lower electricity costs to less than 7.1 cents per kilowatt-hour. Prices negotiated for the 720,000 residences and businesses under Emanuel’s deal vary depending upon consumption. Under the Integrys plan, apartment dwellers would pay 8 cents per kilowatt-hour. The average homeowner would pay 9 cents in June and 7.8 cents in July. But the city has said that it could renegotiate terms if power prices turned out to be higher than ComEd’s.
Quinn, Clean Energy Trust Start $4.6 Million Renewable Fund
The Clean Energy Trust and Gov. Pat Quinn last week announced the creation of a revolving equity fund to stimulate investment in clean energy businesses in the state. “Illinois is a national leader in embracing green energy through innovation, and this fund will help us do even more,” Quinn said. The state Department of Commerce and Economic Opportunity is putting up $2.3 million from federal funds, and the Clean Energy Trust is matching that.
The new fund will award convertible notes ranging from $100,000 to $500,000 to startups working on renewable energy, energy efficiency, smart grids or other energy-related projects. Any returns from the resulting projects will be re-invested into additional businesses. A panel of judges will listen to project pitches and award the grants.
The Bowie City Council accepted a $92,000 grant from the Maryland Energy Administration on June 16 to help the city cut energy consumption and to develop a renewable energy policy. The award, part of the Maryland Smart Energy Community program, will help the city develop policies for a 15% cut in energy consumption within five years and meet a goal of using 20% renewable energy for government-owned buildings by 2022.
The state attorney general filed felony racketeering charges last week against Chesapeake Energy Corp. related to what the state says was a fraudulent land lease scheme. Attorney General Bill Schuette said Chesapeake’s leasing agents entered into gas leases with landowners, and then backed out of the leases by falsely claiming that mortgages on the properties were a legitimate basis for cancellation.
Chesapeake, the second-largest natural gas producer in the U.S., allegedly entered into the gas leases in order to keep other gas producers from obtaining drilling rights during the state’s recent fracking boom. Chesapeake spokesman Gordon Pennoyer said all charges facing the company are “baseless allegations” and pledged to battle them in court.
In March, Schuette accused Chesapeake and rival Encana Corp of colluding to keep oil and gas lease prices artificially low in Michigan during the oil and gas rush in its Collingwood Shale region in 2010.
The Board of Public Utilities is considering a change in tax policy that would align the state with most others, to the benefit of utilities. The issue concerns utility holding companies that file consolidated taxes not only for their utilities but also for other unregulated subsidiaries.
Consolidated income tax returns allow members of the company to take advantage of tax losses incurred by other businesses owned by the parent. Under current practice, customers received 100% less certain adjustments, making New Jersey one of only four states that allow losses to be returned to ratepayers.
Under the proposed change, 75% of any savings from consolidated filings would be returned to the companies, with only 25% going to ratepayers. Rate Counsel Director Stefanie Brand, however, is concerned with the proposed change in tax laws. “You want to share more with ratepayers, not less,” she said. “It could be where it’s going to get down to where ratepayers get very little, or nothing.”
Duke Residential Customers to Pay More for Renewables
Duke Energy Progress wants to charge residential customers more for solar and other renewable energy than it would charge business customers, the company told the state Utilities Commission last week. Residential customers currently pay 20 cents per month for renewable energy – primarily from solar farms – but Duke wants to push that up to 83 cents per month beginning in December. The charge goes toward subsidies to independent power producers to cover the higher cost of that type of energy that Duke must buy under state-mandated standards.
While the cost to residential customers would go up under Duke’s plan, the cost to businesses would drop from $8.08 a month to $6.11 a month and from $29.68 a month to $24.56 a month for industrial customers. The cost changes are tied to annual caps set by state law. The annual caps for business and industrial customers stay the same for 2015, but the cap for residential customers will rise from $12 a year to $34 a year.
AEP Energy, American Electric Power’s competitive electric service provider, announced last week that it will begin offering natural gas in the state. AEP joins several other competitive natural gas suppliers in the Columbia Gas of Ohio service territory. “By offering natural gas together with electricity, AEP Energy now can provide Ohio residents with a full-service energy solution,” said Scott Slisher, an AEP executive.
Ohio State University and the engineering firm of Babcock & Wilcox are working together to develop a coal-fired power plant that incorporates carbon-capture technology. Funded by a $2.5 million federal grant, the team is planning to use a chemical process to capture carbon dioxide waste during the combustion process. The university’s College of Engineering has already constructed a pilot plant, which generates about 25 kW of thermal energy. It has already run for 680 hours. The planned unit will produce 550 MW.
Public Utility Commission Chairman Robert F. Powelson was sworn in as president of the Mid-Atlantic Conference of Regulatory Utilities Commissioners last week. “I’m thrilled to expand my role with MACRUC and continue to work toward advancement and uniformity of public utility regulation throughout the Mid-Atlantic region,” Powelson said. Powelson was appointed to the PUC in 2008 by then-Gov. Edward G. Rendell. He also is a member of the Marcellus Shale Advisory Commission and is former president of the Chester County Chamber of Business & Industry.
A former GOP strategist who is facing Sen. Mark Warner in November’s Senate election has proposed an energy plan that would eliminate the recent EPA emissions rules, allow more offshore oil and gas leases and push through the Keystone XL Pipeline, all in the name in economic growth. “Virginia should be a model for the rest of the nation in promoting ‘all-of-the-above’ energy policies,” GOP candidate Ed Gillespie said last week. “Technologies that have enabled the shale gas boom have unleashed enormous possibilities for the future, and the nation is positioned to become energy-independent for the first time ever. All that is lacking is national leadership.”
