Mike Kormos, PJM executive vice president for operations
HERSHEY, Pa. — Planners seeking to protect the grid against physical threats should consider transmission alternatives as well as security measures, Mike Kormos, PJM executive vice president for operations, told a conference of state regulators last week.
“You can only harden a substation so much. If someone wants to attack a substation, they will,” Kormos said during a panel discussion at the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference here. “That leads us to the resilience piece. Maybe the best way to make a substation less critical is to build more transmission. A substation is critical basically because we’re pushing too much power through it.”
Kormos said most of PJM avoided the cascading 2003 blackout largely because it had “headroom” — excess capacity — in its system. “It wasn’t operations [that saved PJM]. It happened too fast. It was good planning.”
Kormos said PJM will start ranking its substations by criticality to target needed spending. PJM has begun discussing with state regulators and the Federal Energy Regulatory Commission how it can balance confidentiality concerns with the need for cost oversight and the transparency of the Regional Transmission Expansion Plan (RTEP).
Kormos said PJM will publicly share its criteria for determining criticality “so people are comfortable we’re not simply gold plating the system for the sake of … returns.” The challenge, he said, is creating a process that allows state regulators to validate the need for security spending while “not going so far as putting out a map and putting a big ‘X’ and saying, ‘Plant the bomb here.’”
Transformers’ Vulnerability
Transformers are a tempting target because they are expensive and time-consuming to replace, requiring a lead time of five to 12 months from U.S. manufacturers and six to 16 months from foreign suppliers, according to a newly released congressional report.
Substations containing transformers are easy to identify and generally unguarded, unlike other critical facilities such as generating stations or control rooms.
At a cost of $2 million (230 kV) to $7.5 million (765 kV) — excluding transportation and installation — maintaining a large inventory of spare high-voltage transformers “is prohibitively costly,” the Congressional Research Service report noted. (See related story, Report: Uncertainty over Sabotage Threat Could Lead to Wasteful Spending.)
In 2006, the Edison Electric Institute (EEI) began a Spare Transformer Equipment Program (STEP) to enable the grid to restore operations quickly following a terrorist attack. The program requires participating utilities to maintain a specific number of transformers up to 500 kV to be made available to other utilities in an emergency.
Although the number of spares that grid operators keep on hand is closely guarded, a 2007 news report cited in the congressional study said that PJM maintained 29 spares for 188 transformers on its system rated at 500 kV.
PJM may be better off than some regions, having standardized 500-to-230-kV transformers several years ago, according to Kormos. There are two standard designs, one for the Dominion zone another for the rest of the RTO.
PJM may have to refund millions in transmission costs to Midwest utilities following a federal appellate court ruling last week, but the RTO’s current cost allocation method for regional transmission projects shouldn’t be in jeopardy, PJM officials said yesterday.
The Seventh Circuit Court of Appeals ruled Wednesday that the Federal Energy Regulatory Commission had failed in its second try to demonstrate that the “postage-stamp” cost allocation method formerly used for high-voltage transmission lines in PJM’s eastern region is fair to the RTO’s Midwestern utilities.
In a 2-1 ruling, the court remanded the case to FERC for the second time, ordering it once again to justify why utilities in the Midwest should be billed under the same “socialized” method as utilities in the east for the construction of 500-kV lines that are exclusively in Mid-Atlantic states.
New Hybrid Cost Allocation Formula
The postage-stamp method in dispute was supplanted last year with an Order 1000-compliant hybrid formula that allocates only half of the cost of regional projects using the postage-stamp socialization. For reliability projects, the remainder of the allocation is determined by a solution-based distribution factor (DFAX) analysis. Changes in load energy payments determines the balance for economic projects.
PJM General Counsel Vince Duane said the RTO is waiting to see how FERC responds to the remand before determining the RTO’s next step. “It’s unclear whether FERC will throw the towel in or attempt to justify” the postage-stamp allocation, Duane said.
If FERC concedes, PJM will likely have to rebill its transmission customers for payments received until 2013, when the hybrid formula took effect. PJM Chief Financial Officer Suzanne Daugherty yesterday asked PJM’s billing department to calculate how much money is at stake.
The case originally involved plans for 18 new projects. Currently at issue are 15 projects: 11 completed, one under construction and three more under study, according to the court.
Among the projects affected are the TrAIL, Susquehanna-Roseland and Carson-Suffolk lines, as well as cancellation costs for the MAPP and PATH lines, according to PJM. The total cost of the affected projects is $2.7 billion, but PJM would have collected only a fraction of that through 2013 because the allocations are collected over the projects’ useful lives.
Rebilling Method in Question
One question yet to be answered is what allocation formula would be used in any rebilling. Dayton Power & Light Co., which was assessed $66 million under the postage-stamp formula, would see its allocation drop to $1 million under a 100% DFAX formula, the company’s attorneys stated in a reply brief earlier this year.
Regardless of how the rebilling issue is settled, Duane said he was confident that the current hybrid formula will survive.
“I think this current method is more defensible. It seems to be more in line with what the court is looking for,” he said.
In addition to reducing the socialized portion of the allocation by half, the new method expands the definition of “regional” projects to include not just lines of 500 kV and above but also double 345-kV circuits, which are more prevalent in western PJM, Duane said.
“We’re not back to square one” on cost allocation, he said.
Order 494
The appellate court case stems from an April 19, 2007 FERC ruling (Order 494) that replaced PJM’s former “license-plate” method with the postage-stamp method, which bills all utilities in proportion to their sales.
The court ruled that FERC had again failed to show how a western utility would benefit as much as an eastern utility from new transmission facilities in the east. The court called FERC’s argument that it was too difficult to quantify the benefits western utilities would receive “a feeble defense.”
“We conclude, with regret given the age of this case, that the commission failed to comply with our order remanding the case to it,” Judge Richard A. Posner wrote for the majority. “It must try again. If it continues to argue that a cost-benefit analysis of the new transmission facilities is infeasible, it must explain why that is so and what the alternatives are.”
The court said that it was unlikely that much electricity will be transmitted from the eastern to the western utilities via the new transmission lines because the west is a net exporter.
Illinois’ Complaint
The Illinois Commerce Commission, which filed the complaint on behalf of Commonwealth Edison, did not dispute that the construction of high-voltage transmission lines in the east would provide some benefit to western utilities. For example, ComEd would be able to reduce its reserves, as the increased transmission capacity in the east would reduce the likelihood of outages there.
“So some of the benefits of the new high-voltage transmission facilities will indeed ‘radiate’ to the western utilities, as the commission said, but ‘some’ is not a number and does not enable even a ballpark estimate of the benefits of the new transmission lines to the western utilities,” Posner wrote. The ability to obtain and deliver electricity and reducing reserve capacity “are not equivalent benefits, though treated by the commission as equivalent. The only explanation for why it did that is that, having failed to conduct a cost-benefit analysis, it had no basis for treating the benefits as other than equivalent.”
Instead of the postage-stamp approach, the ICC argued that the western utilities’ contribution to the costs should be based solely on a DFAX analysis. FERC argued that this approach was an underestimate and the court agreed, calling it “the opposite extreme.”
In his dissent, Judge Richard D. Cudahy called a mathematical solution to the cost-allocation problem a “complete illusion. Despite the frequency with which cost-benefit analysis is used, it does not resolve the difficulty of accurately or meaningfully measuring the costs and benefits involved with these grid strengthening projects. Cost allocation, particularly at these extraordinarily high voltages, is far from a precise science, and there are no mathematical solutions to determining benefits region by region or subregion by subregion.”
The majority acknowledged “that the benefits of the new facilities to the western utilities may prove unquantifiable because they depend on the likelihood and magnitude of outages and other contingencies, and that likelihood and that magnitude may for all we know baffle the best analysts.”
“If the commission after careful consideration concludes that the benefits can’t be quantified even roughly, it can do something like use the western utilities’ estimate of the benefits as a starting point, adjust the estimate to account for the uncertainty in benefit allocation and pronounce the resulting estimate of benefits adequate for regulatory purposes,” Posner wrote. “If best is unattainable, second best will have to do, lest this case drag on forever.”
HERSHEY, Pa. — As PJM’s chief operating officer, Audrey Zibelman helped design PJM’s Reliability Pricing Model. Now the chair of the New York Public Service Commission, Zibelman says she has a “different prism” for viewing capacity markets.
Audrey Zibelman, NY PSC
“Centralized procurement may not be good for everything we want to do as states,” she told the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference last week.
Zibelman criticized rules that restrict states’ ability to contract for capacity, such as buyer-side mitigation constructs that she said force ratepayers to pay twice for the same resource.
“That’s frankly absurd. That’s saying the rules of the market are form over substance,” Zibelman said. “We need to sit with [the Federal Energy Regulatory Commission] as partners and say ‘We have a whole issue about how procurement’s going to happen, particularly post-111(d) [the Environmental Protection Agency’s proposed rule to cut carbon emissions].’
“It’s a complex issue and there isn’t a single solution but it’s got to start with a good conversation between us and FERC.”
Officials from Maryland and New Jersey, who have been frustrated by court rulings in their attempts to contract for generating capacity, also called for changes.
Dianne Solomon, NJ BPU
Dianne Solomon, chair of the New Jersey Board of Public Utilities, vowed, “We’re going to continue to flex our state’s rights.” The BPU has filed for rehearing of an appellate court ruling that invalidated contracts it ordered utilities to sign with a natural gas-fired generator. (See Rebuffed by Courts, CPV Seeks FERC End-Around.)
Maryland Commissioner Lawrence Brenner said he has also seen the capacity issue from two vantage points, having helped negotiate a settlement over PJM’s RPM while an administrative law judge for FERC (ER05-1410).
“The capacity market tried to adjust for bilateral contracts and self-supply but there was a balance sought so as not to sink the basic capacity market,” Brenner said. “And it turned out that some of those balancing mechanisms were a little too creaky to work.”
FERC Commissioner Philip Moeller suggested state rule changes could relieve some of the pressure on the capacity markets, which were designed to ensure sufficient supply for peak loads and provide the so-called “missing money” needed to supplement energy and ancillary services revenues.
“I’d like to see my colleagues at the state level consider real-time pricing,” Moeller said. During high load periods, he said, “you can’t expect people to act altruistically for more than a couple of days.”
Robert Powers, chief operating officer of American Electric Power, called Moeller’s real-time pricing suggestion “interesting.” But he asked “how much tolerance is there to send these [price] signals?”
Pennsylvania Public Utility Commission Chair Robert Powelson said that he supports the capacity market, which he said sends appropriate market signals.
But he said his state is concerned about the lack of stability in market rules. Consumer advocates and demand response providers have also grown weary of the rule changes. (See Consumer Advocates to PJM: No More Changes, Please.)
“Mike Kormos, Terry Boston and Andy Ott — very bright guys — but I think in my state we’ve reached a bit of a fatigue level with: What’s the next iteration of the BRA [base residual auction]?” Powelson said. “What’s going to happen next?”
Members narrowed the scope of a task force created to improve funding of financial transmission rights (FTR) Thursday, agreeing to eliminate consideration of balancing congestion.
The Markets and Reliability Committee approved the narrowed scope after first rejecting a proposed charter for the FTR/ARR Senior Task Force.
The MRC approved the charter on a second vote, which called for removing from the charter and issue charge a reference to “enhancing the mechanism by which balancing congestion is allocated.”
The MRC had approved the task force on first reading May 29 after PJM officials said they wanted to fast-track the issue in order to have a solution in place before next year’s FTR auction. (See New Task Force to Target FTR Underfunding.)
PJM said it had suggested an altered allocation of balancing congestion as a potential transition mechanism for any rule changes.
At the task force’s first meeting, however, Market Monitor Joe Bowring objected to the inclusion of the balancing congestion issue. Bowring told the MRC Thursday that the task force’s work would be “bogged down” by including the issue, which has been the subject of litigation and has eluded previous stakeholder attempts at consensus. Bowring said members could craft a transition without it.
Others, including Susan Bruce of the PJM Industrial Customer Coalition agreed, calling Bowring’s observation “a cautionary tale on approving things on first read.”
Pamela Quinlan of Rockland Electric said she agreed with Bruce’s concern over approving matters on first read. “People walked away with different understandings of what this group is actually going to work on,” she said.
Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), said that including balancing congestion in the charter suggested the task force had already decided on a solution.
ARRs ‘Sacred Cow’
Steve Lieberman of Old Dominion Electric Cooperative, however, opposed the narrowed scope. “We agreed to the problem statement with the understanding that it would be a broad discussion,” he said.
“We’re very sensitive to focusing only on ARRs [auction revenue rights]” as a solution to the underfunding, Lieberman said, calling ARRs the “sacred cow” for load-serving entities.
PJM Executive Vice President for Markets Andy Ott said the task force would be hamstrung with the narrowed scope. “I don’t know how you talk about an expanding set of causes” without considering balancing congestion, he said.
Jason Barker of Exelon agreed, noting that PJM told the task force meeting June 25 that balancing congestion represented almost $420 million in revenue inadequacy for 2013/14, nearly two-thirds of the total. “We’re interested in discussing all of revenue inadequacy, not one-third of it,” he said.
Bowring had proposed eight changes that he said would improve funding adequacy to 91% from the current 72%. “Either do ARRs only or consider everything,” Bowring said, calling PJM’s original scope a “half-measure.”
In his 2013 State of the Market report, the Monitor rejected suggestions that load subsidize payments to FTR holders by ignoring balancing congestion when calculating total congestion dollars available to fund FTRs.
“This approach would ignore the fact that loads must pay both day-ahead and balancing congestion,” the Monitor said. “To eliminate balancing congestion from the FTR revenue calculation would require load to pay twice for congestion. Load would have to continue paying for the physical transmission system as a hedge against congestion and pay for balancing congestion in order to increase the payout to holders of FTRs who are not loads.”
Growing Shortfall
PJM told the task force Wednesday that the shortfall could be narrowed by allowing proration of Stage 1A allocations. PJM said it would improve FTR funding by removing infeasibilities and improve confidence in FTR values with a “minimal impact” on ARR revenues.
A second alternative proposed by PJM would remove Stage 1 historical resources when they physically retire. PJM said transmission system rights are not necessary for generators that do not exist.
PJM says more than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices since the ARR allocation process was designed.
Below is a summary of issues discussed and voted on at the Markets and Reliability and Members committees on Thursday June 26.
MEASURES REJECTED
RPM Supply Curve Change Rejected
The Markets and Reliability and Members committees rejected a proposal to create more informative supply curves from capacity auctions. The proposal won only 40% support after Market Monitor Joe Bowring warned that “We continue to think this is an extremely bad idea.”
Stakeholders had approved a problem statement by Exelon on the issue without opposition last June. But support for the change eroded after Bowring signaled his opposition, saying it could reveal sensitive data about price-quantity offers and cause collusion among generators. Load representatives opposing the change cited Bowring’s concerns and news reports indicating Exelon had helped boost clearing prices in the May auction by offering 4,255 MW of nuclear capacity at the maximum price allowed. (See Load Balks at Supply Curve Fix in Response to Auction Strategies.)
The proposal won support of three-quarters of Transmission and Generation owners but less than half of Other Suppliers and virtually none of End Use Customers and Electric Distributors.
Cost Development Subcommittee to ‘Hibernate’
PJM withdrew a proposal to sunset the Cost Development Subcommittee after members and the Market Monitor predicted the panel would be needed in the future.
The subcommittee was created to develop standard procedures for calculating the costs of products or services provided to PJM when those products or services are required to be provided at a cost-based rate. It has been dormant since October.
“It strikes us as inevitable” that the committee will be needed again, Exelon’s Jason Barker said.
Dominion’s Louis Slade said it might take as long as two months to reestablish the committee, which is comprised of technical experts, if it were disbanded.
Market Monitor Joe Bowring said the committee may be needed soon to consider the costs of batteries used in energy storage. “There will soon enough be additional work” for the committee, Bowring said.
The subcommittee will remain standing but will hold no meetings until it receives another assignment.
Members Balk at ‘Deferring’ Issues
Leaders of the Members Committee backed off from a proposal that it “defer” action on four initiatives after receiving push-back from members last week.
Vice Chair Jim Jablonski outlined a proposal to delay further action on four initiatives so that members could concentrate their efforts on several other items that have early fall deadlines for completion. MC Secretary Dave Anders said further meetings on the deferred items would be delayed until about October.
But when members raised objections to delaying two of the four issues, Anders and Jablonski said they would reconsider the proposal.
MEASURES APPROVED
The Markets and Reliability and Members Committees approved the following by acclamation Thursday following little discussion or debate:
Markets and Reliability Committee
PJM Manuals
Members endorsed revisions to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements that incorporate requirements for installation of SynchroPhasor Measurement Units (PMU) at new generation interconnections. Related Tariff changes were approved by members last June and approved by the Federal Energy Regulatory Commission in February. The requirements apply to interconnection customers entering the new services queue on or after Oct. 1, 2012 with facilities with a maximum output of 100 MW or greater. (See Members Approve PMU Requirement.)
Members endorsed changes to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements governing rules for members wishing to purchase access to the PJMNet data feed. (See Final OK for Membership Inquiry, PJMNet.)
Designated Entity and Interconnection Coordination Agreements
The MRC and MC approved the Designated Entity Agreement (DEA) and Interconnection Coordination Agreement (ICA) developed by the Regional Planning Process Task Force (RPPTF).
The documents define the obligations of companies designated to build and operate transmission projects awarded under the competitive rules of FERC Order 1000. They include project scope, planning criteria, development schedules, project milestones and terms and conditions.
FERC ordered PJM to file the DEA for commission approval by July 14. (See: 147 FERC ¶61,128).
Coordinated Transaction Schedule
The MRC gave PJM final approval to implement the Coordinated Transaction Schedule (CTS) product for trading between PJM and the New York ISO.
Last week’s vote endorsed the accuracy of the PJM scheduling tool that will be used to optimize the cross-border transactions. PJM officials told members in March that the Intermediate Term Security Constrained Economic Dispatch (IT SCED) tool is accurate within $5/MWh more than two-thirds of the time. (See PJM Price Forecasts: Close Enough for Power Trading?)
CTS, which is intended to reduce uneconomic power flows between the two regions, is scheduled to be implemented as soon as November.
Transmission Owner Data Feed
Members approved a revised issue charge for the Transmission Owner Data Feed Task Force to include consideration of generator real-time reactive capability data. Members approved creation of the task force in April to consider an easier method for transmission owners to access real-time generator data, an effort intended to improve situational awareness and emergency response.
During initial task force discussions, stakeholders shared concerns about TOs having access to generator-characteristic data in addition to real-time telemetry. Exelon responded that generator real-time reactive capability data is necessary for accurate state estimator and contingency analyses. (See Members to Consider Easier Sharing of Real-Time Generator Data.)
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.”
Shares of NiSource Inc., parent company of Northern Indiana Public Service Co. (NIPSCO), rose 60 cents (1.5%) last week after news that it has been engaged in “soft” merger talks with Dominion Resources. Citing industry sources, The Deal reported that NiSource and Dominion have been talking for months, but that pricing has prevented an agreement. One source said that the two companies have “chatted” but talks have not turned serious and NiSource is not working with a financial adviser.
The report said Duke Energy Corp., Exelon Corp., Southern Co. and American Electric Power Co. have been approached by industry bankers trying to assemble a deal to acquire NiSource. The company owns 15,700 miles of interstate gas pipelines and gas distribution operations in seven states in addition to NIPSCO, which provides power to 450,000 customers in 20 counties in northern Indiana.
Rumors of a NiSource-Dominion deal date back to at least December, when Mergermarket reported that Dominion was attempting to raise more than $10 billion in debt to acquire an unidentified Midwest utility. One analyst said Dominion was NiSource’s most likely acquirer because it is already involved in the interstate pipeline business and is interested in the Marcellus shale play, where NiSource has pipelines and storage.
Operators at PPL’s Susquehanna nuclear generating station shut down Unit 2 last week to check for cracked turbine blades. Equipment that monitors the turbines for excessive vibration indicated that some of the finely balanced turbine blades in the steam generator may have developed small cracks.
“We have been monitoring turbine performance closely for the last several years and continue to work with the manufacturer to address conditions that are associated with cracks developing,” said Timothy S. Rausch, PPL’s chief nuclear officer. “That’s why we decided to shut down Unit 2 now to inspect blades and replace any that are found to have developed cracks.”
Workers replaced turbine blades at Unit 1 during a refueling outage in May. After the Unit 2 inspection, PPL will install new blades during the 2015 refueling outage, Rausch said.
Atlantic City Electric, Union Reach Pact Through 2018
Atlantic City Electric Co. and the International Brotherhood of Electrical Workers Local 210 reached a labor agreement last week that lasts through 2018. Local 1238, which represents workers at the company’s Carneys Point call center, also agreed to extend its collective bargaining agreement to 2020.
Atlantic City Electric’s parent company, Pepco Holdings Inc., announced in April that it was merging with Exelon, who said it will honor all union contracts and not issue any merger-related layoffs for at least two years after the merger.
Two former New York state regulators are opening a public utility consulting firm in Albany, N.Y. Maureen Harris, who served on the New York State Public Service Commission between 2006 and 2013, and Tom Dvorsky, former senior advisor to the commission, call their new firm Claritas Energy Advisors LLC.
Hess Corp. said it is selling its 50% stake in the Newark Energy Center to private equity firm Energy Investors Funds (EIF) for an undisclosed amount. The 705-MW natural gas-fired plant, currently under construction, is slated to go operational in May 2015. The transaction will make EIF the sole owner of the project. The plant is located on a 23-acre brownfield site adjacent to the Hess Newark petroleum storage terminal.
An Indiana developer is building a $7 million, 3-MW plant at a former gravel mine to turn cow manure to power. Brian Furrer said Green Cow Power should be running by September and will be the largest manure-fed power plant in the U.S. “We’re going to use less dirty coal in this country,” Furrer said. “That is just a fundamental fact of life. We’re going to do it through many different mechanisms. This is one mechanism that’s going to help.”
The plant will pump cow manure into tanks, where bacteria breaks it down and generates methane gas to produce power. Leftover solids are reused as bedding for cow barns, while leftover liquids are treated and spread on farm fields. The electricity will be sold to Northern Indiana Public Service Co. (NIPSCO).
The Federal Energy Regulatory Commission gave final approval last week to the first phase of rules to protect the grid from geomagnetic disturbances. It also finalized a standard regarding personnel training opposed by PJM and gave preliminary approval to a standard on capacity modeling.
Geomagnetic Disturbances – EOP-010-1
The commission approved the North American Electric Reliability Corp.’s Reliability Standard EOP-010-1, NERC’s initial response to the commission’s July order calling for rules to close the “reliability gap” regarding geomagnetic disturbances (GMDs) caused by solar events. Geomagnetically induced currents can flow through transformers and transmission lines, leading to increased reactive power consumption and disruptive harmonics that can cause system collapse.
Artist’s depiction of solar winds shaping earth’s magnetosphere. The magnetic field keeps earth’s atmosphere from being blown away by solar wind. But when it is disturbed by solar storms, problems with the electric grid can result. (Source: NASA)
The standard requires reliability coordinators and some transmission operators to institute operational procedures to mitigate the effect of GMDs. The rule applies to transmission with a “transformer with a high side wye-grounded winding with terminal voltage greater than 200 kV.”
FERC approved the rule without changes, rejecting comments by the Foundation for Resilient Societies and others that the rule should apply to transmission operators with systems less than 200 kV. The Foundation noted that during a March 1989 solar storm cited by FERC, utilities reported effects on static VAR compensators and other reactive power equipment operating between 100 kV and 200 kV.
But FERC said that transformers operating at 200 kV or less “are likely to have a limited impact” on the grid during a GMD event.
The commission also rejected criticism from George H. Baker, a U.S. Defense Department consultant on GMD threats, who said the standard will be ineffective. Baker said failures of equipment and disruptions to communications networks will inhibit grid operators’ ability to respond to a GMD event and that they will be reluctant to shed load.
The commission acknowledged that the operational procedures spelled out in this first-stage response “are not a complete solution to the risks posed by a GMD event.
“While we recognize the concerns in the comments of Baker and others regarding the efficacy of operational procedures, Order No. 779 weighed those concerns in ultimately directing NERC to develop operational procedures in the First Stage GMD Reliability Standards and more comprehensive protections in the Second Stage GMD Reliability Standards,” FERC said in its ruling.
In stage two, NERC must determine what severity of GMD will constitute a “benchmark” GMD event. Covered entities will be required to assess the potential impact of such benchmark events on their equipment and systems.
PJM already has GMD operational procedures, which are detailed in section 3.7 of Manual 13.
Personnel Training – PER-005-2
The commission also approved an expansion of NERC’s personnel training standard to include operations support personnel, as well as employees of transmission owners and generator operators who support real-time grid operations (RD14-7).
The new training requirements will apply to:
System operators for reliability coordinators, balancing authorities and transmission operators, defined as “[p]ersonnel, excluding field switching personnel, who can act independently to operate or direct the operation of the Transmission Owner’s Bulk Electric System transmission Facilities in Real-time”;
Operations support personnel for reliability coordinators, balancing authorities and transmission operators, who perform current day or next-day outage coordination or assessments, or who determine system operating limits (SOL), interconnection reliability operating limits (IROL) or operating nomograms in support of real-time operations; and
Dispatch personnel of generator operators at centrally located dispatch centers who receive direction from Reliability Coordinators, Balancing Authorities, Transmission Operators or Transmission Owners.
The revised standard will eliminate a requirement that all system operators receive at least 32 hours of emergency operations training annually regardless of the entity’s characteristics or reliability risk.
Solar wind shapes the planet’s magnetosphere – the region in which charged particles are controlled by the planet’s magnetic field. Bursts of solar wind warp the magnetosphere causing geomagnetic disturbances. (Soure: Wikipedia)
The proposed standard was endorsed by the California ISO, ERCOT, ISO New England, MISO, NYISO and SPP. But PJM called it “an unnecessary and a potentially ineffective means to address an otherwise straightforward requirement; namely to train appropriate personnel.”
PJM said that program accreditation would be more effective because it would place “the emphasis on the training program itself, and associated controls,” rather than on “applicable individuals, their personal training and performance records, individual pieces of training content, and other administrative documentation.”
FERC said an accreditation-based training program is not precluded “as an alternative means of compliance” if it otherwise meets the NERC standard.
Modeling, Data, and Analysis Reliability Standard MOD-001-2
The commission issued a Notice of Proposed Rulemaking (RM14-7) to revise NERC’s standards on the calculation of available transfer capability (ATC) and available flowgate capability (AFC).
ATC and AFC calculations, which dictate the amount of transmission capacity that a transmission service provider will sell to third parties, also raise reliability concerns, the commission noted, because transmission providers need “to know of its neighbors’ system conditions affecting its own ATC values.”
The proposed standard would require documentation of the methodologies for determining ATC and AFC, total transfer capability, total flowgate capacity, capacity benefit margin and transmission reliability margin. It also sets requirements for sharing the methodology and data inputs with registered entities with a “demonstrated reliability need.”
It would also eliminate from current standards requirements that NERC said may be necessary for market or commercial purposes. NERC asked the North American Energy Standards Board (NAESB) to consider whether any of the retired requirements should be incorporated into its Wholesale Electric Quadrant (WEQ) Standards to maintain a non-discriminatory market for transmission service.
