Capacity imports could clear at lower prices than internal resources under proposed import limits being considered by PJM.
PJM officials are planning to create an RTO-wide import limit as well as individual limits for PJM interfaces with the North, South and West, Stu Bresler, vice president of market operations, told the Market Implementation Committee last week.
If the external limit is not reached, the “rest of RTO” and “outside RTO” regions would clear together at the same price. Once the cap is reached, however, the marginal external resource would set the price for the “outside RTO” region while the marginal internal resource would set the price for the “rest of RTO” region.
If there is price separation, internal resources will clear at a higher price than imports, just as resources east of PJM’s west-to-east constraints are often priced higher, Bresler said.
An alternate approach being considered by PJM is to require that resources have firm transmission as a condition for allowing them to offer into the auction.
PJM said last month that its initial analysis indicated the RTO should be able to absorb the more than 7,400 MW of imports that cleared in May’s capacity auction for 2016-17.
Officials said that their initial review found PJM can import 11,000 to 12,000 MW simultaneously. That would allow at least 7,500 MW of imports to clear in the capacity auction, with an additional 3,500 MW reserved for the RTO’s Capacity Benefit Margin — a set aside to be used in emergencies. (See Current Capacity Imports OK: Study)
However, PJM’s Mark Sims told the Planning Committee last week that the estimate may be overly optimistic because it assumes redispatch of almost 10,000 MWs. “We know in real-time that these kinds of adjustments … haven’t happened,” he said.
Capacity Price Curve With Import Cap (Source: PJM Interconnection, LLC)
Sims said staff will conduct a revised analysis that puts more “realistic” limits on redispatch. The new analysis also will set a threshold distribution factor of 3% rather than the 1% factor used in the original analysis. “We don’t want to consider distribution facilities in Florida,” he said.
The Planning Committee approved a problem statement on a proposed cap last month in response to the May capacity auction, in which cleared imports increased by more than 3,000 MW.
Officials plan to seek Planning Committee approval of the import caps next month. PJM wants to implement the new rules prior to posting the planning parameters for the next Base Residual Auction.
PJM will perform a cost-benefit analysis before proceeding with a combined-cycle bidding model expected to cost up to $1 million.
Combined Cycle Plant Diagram (Source: General Electric Company)
PJM’s Tom Hauske told the Operating Committee that incorporating the Alstom model — chosen by the OC to ensure more consistency among offers — will be more complicated and costly than initially expected. Hauske said the changes will affect more than eMKT and scheduling and won’t be implemented until 2015 instead of June 2014.
Given the new cost estimate of between $750,000 and $1 million, Hauske said, “We have to be able to justify it” for inclusion in PJM’s budget.
All 53 combined-cycle units in PJM, which can now offer as steam units or combustion turbines, would be required to use the new model. Sellers will have to offer the new combined cycle configurations for at least three months. All units would be aggregated under one unit ID.
Maryland officials aren’t saying what their next move is in the wake of a federal court ruling that voided the state’s contract with developers of a 725 MW combined cycle plant in St. Charles.
Judge Marvin Garbis
U.S. District Judge Marvin J. Garbis ruled that the “contract for differences” the state Public Service Commission negotiated with Competitive Power Ventures unconstitutionally interfered with the Federal Energy Regulatory Commission’s jurisdiction over interstate wholesale energy sales.
“Because states have no authority, either traditional or otherwise, to set wholesale rates, the compensation received by CPV for its wholesale energy and capacity sales is exclusively subject to the regulation of FERC,” the judge wrote in a 149-page order.
The ruling invalidates the PSC’s April 2012 order directing Baltimore Gas and Electric Co., Potomac Electric Power Co., and Delmarva Power & Light Co. to enter into contracts that guaranteed CPV Maryland LLC an income stream so that it could finance construction of the Charles County facility.
Robert J. Grey, general counsel for PPL Corp., one of the companies that challenged the CPV deal, said the ruling “upholds the integrity of competitive generation markets.” PSEG Power LLC and Essential Power LLC were the other plaintiffs.
An appeal is likely, although Regina L. Davis, spokeswoman for the PSC said Friday that the agency was reviewing the ruling and had no immediate comment.
Charles County Commissioner Ken Robinson said the county remained “cautiously optimistic” that the project will proceed.
Merchant Option?
CPV officials did not respond to requests for comment. Last month, the company announced that it would build a 700-MW combined cycle plant in Woodbridge, New Jersey as a merchant facility because of uncertainties created by legal challenges to state-sponsored contracts there.
On Oct. 11, a federal court judge threw out New Jersey’s contracts, also on constitutional grounds, with CPV, Hess Corp. and NRG Energy. The three were selected through a solicitation by the New Jersey Board of Public Utilities for construction of 2,000 MW of generation.
Despite the ruling, the CPV and Hess plants are being built. Hess, which began construction late last year on its 655 MW plant in Newark, said it expects to complete the plant in 2015. CPV said it expects construction on the $842 million Woodbridge project to begin within weeks. NRG cancelled its project after failing to clear in two consecutive capacity market auctions.
CPV said in 2009 that it needed state backing to secure long-term financing to build in Maryland. In the interim, however, low natural gas prices and retirements of coal-fired plants have led to a spurt of unsubsidized generation in PJM. CPV said the debt syndication for its New Jersey plant was oversubscribed “reflecting the project’s strong fundamentals.”
Panda Power Funds in July proposed an unsubsidized 859-MW combined cycle plant in the Washington suburb of Prince George’s County, Md. LS Power Group, which had earlier sought subsidies to build in New Jersey, is building a plant in West Deptford without state backing.
Contract for Differences
Under the Maryland contract, CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices are higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices are higher than the contract, CPV would make payments to the EDCs.
Boston Pacific Co., a consultant hired by the PSC, estimated the contract would save residential ratepayers $0.32 to $0.49 per month over the life of the 20-year contract. However, PSC General Counsel Robert Erwin told FERC’s technical conference Sept. 25: “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.” (See Capacity Market Attracts Praise, Criticism at FERC).
PJM Capacity Market ‘Failed’
The PSC took its action to spur new generation after concluding that the state faced “a critical shortage of electricity capacity” because it is a net importer and is subject to higher prices because of transmission congestion.
The PSC said that PJM’s capacity market “has failed to attract new generation” to the Southwest Mid-Atlantic Area Council (SWMAAC), which encompasses most of Maryland.
“Since its inception in 2007, RPM has brought no new generation to Maryland, in spite of the fact that clearing prices for capacity in the SWMAAC have averaged almost double those of the non-constrained portions of PJM,” the PSC said. Existing generators had no incentive to build more capacity, regulators said, because increasing supply would reduce prices.
Request for Proposals
Aerial map of CPV St. Charles location
CPV was selected over two other bidders that responded to the state’s request for proposals (RFP).
The contract for differences required CPV’s plant to clear in PJM’s annual Base Residual Auction. New generators participating in the auction are subject to the Minimum Offer Price Rule (MOPR), which sets a minimum offer price based on the net Cost of New Entry (net CONE), a measure to prevent buyer-side market power.
In the 2012 capacity auction, PJM approved a MOPR bid floor of $96.13/MW-day for the CPV plant. Prices in SWMAAC and MAAC cleared at $167.46/MW-day in SWMAAC and MAAC, although a PJM sensitivity analysis found prices in SWMAAC would have been almost $30 higher had the bid capacity been 750 MW lower.
MD Argument ‘Unpersuasive’
Garbis said he found “unpersuasive” Maryland’s argument that the contract price is a competitive market price because CPV initially proposed it as part of the RFP. He noted that the PSC had reserved the right to select none of the proposed contract prices. “Accordingly, although it was proposed by CPV, the contract price in the CfD is a price ‘set’ or ‘determined’ by the PSC,” the judge ruled.
Garbis also rejected the state’s contention that the contract was a “mere financing arrangement outside the jurisdiction of FERC.”
“While there exist legitimate ways in which states may secure the development of generation facilities, states may not do so by dictating the ultimate price received by the generation facility for its actual wholesale energy and capacity sales in the PJM Markets without running afoul of the Supremacy Clause,” he wrote.
‘Win’ for Consumers?
The COMPETE Coalition, an organization that represents generators and others, called the ruling “an important win for electricity consumers,” saying subsidized development would “needlessly shift the financial risk of new construction from power plant developers to consumers.”
The Maryland Office of People’s Counsel, which represents residential utility customers, was less sanguine. “If the order stands, it could restrict the state’s ability to address reliability problems within the state,” People’s Counsel Paula M. Carmody told The Baltimore Sun.
PJM officials said they are pleased with the response to their request for additional black start resources, as more than 50 generators responded with offers.
“There appears to be a large pool of viable units, both proposed and existing,” said Mike Kormos, PJM executive vice president for operations.
Officials said it will take months to select their fleet of black start resources from among current resources and the new bidders. Locational needs and costs will be the determining factors.
Black start units must be capable of starting without an outside electrical supply, maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.
The solicitation was one of the recommendations of the System Restoration Strategy Task Force, which also increased the pool of potential resources.
PJM expects to lose some existing black start capacity by 2015 due to coal plant retirements.
The PJM Board of Managers last week approved $1.2 billion in transmission reliability projects.
CEO Terry Boston said the projects in the 2013 Regional Transmission Expansion Plan (RTEP) will enhance grid resiliency and respond to the shift of generation from coal to natural gas.
PJM has approved more than $24.2 billion in transmission additions and upgrades since the first RTEP in 2000.
The plan includes upgrades and improvements to transformers, substations and other facilities.
The approved projects can commence as soon as the transmission developers receive required state and local regulatory approvals, said PJM Chief Financial Officer Suzanne Daugherty.
The following issues were approved by the Markets and Reliability and Members committees Thursday with little discussion. Each item is listed by agenda number, followed by a summary of the issue and links to prior coverage in RTO Insider.
Markets and Reliability Committee
2. PJM MANUALS
Members endorsed manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.
Members endorsed changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.
3. COORDINATED TRANSACTION SCHEDULING
Members approved a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.
The Market Implementation Committee on Sept. 11 approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based.
The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.
The committee approved a proposal introduced by Dave Pratzon, of GT Power Group, (Package B) after the Operating Committee selected it over a proposal from PJM and the Market Monitor (Package A).
Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.
Members approved new rules to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.
The MRC selected Alternative 2 under which state estimator data would be used to interpolate output for each five-minute period with curtailments.
6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS
Members approved two proposals to streamline the demand response registration process.
Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.
The MRC approved the following changes:
Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.
The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.
7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) CHARTER
Members approved the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.
PJM said the changes were needed to reduce growing uplift costs resulting from Operating Reserves, “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss.
Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal approved by the MC.
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.
Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes endorsed by the MC.
The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.
A proposal to allow intra-year switching to nodal pricing failed at the Members Committee Thursday, falling just short of the two-thirds vote needed for approval.
The proposal by retail marketer Direct Energy, which would have allowed a limited number of such switches monthly, was opposed by members who said it would create administrative problems for electric distribution companies (EDCs) and potential losses for Financial Transmission Rights holders. The sector-weighted vote was 3.3 in favor and 1.7 against, short of the 3.34 total needed for passage.
David Scarpignato, head of PJM regulatory affairs for Direct Energy, said the changes would allow retail marketers to offer more innovative products. He said it would not have significant impact on EDCs or other market participants because it would cap switches at to 5% of the EDC network service peak load.
The Members Committee in 2005 unanimously endorsed a Tariff change allowing the switch to nodal pricing. But after more than seven years under the new rules, all but 15% of PJM load is still using zonal pricing.
The rules give customers one chance a year to switch to nodal pricing, effective June 1 in alignment with the planning year. Customers must provide notice of their intention to switch by October or January depending on type of service.
Scarpignato said the annual window for switching has limited retail marketers’ ability to provide innovative products such as price responsive demand, which he said is most attractive to those with nodal pricing.
The current rules mean it can take a customer up to 17 months to make the switch after deciding to do so — “major barrier” to adoption, Scarpignato said.
Scarpignato said the change would also help reduce congestion costs across PJM and assist PJM operations, which has said it would like more “granular” dispatch of demand response resources. Under the current zonal dispatch, Scarpignato said, “some of the DR in that zone is actually hurting” PJM’s attempts to relieve constraints.
Scarpignato’s argument won support from representatives for Old Dominion Electric Cooperative and Dominion, as well as from Howard Haas of Monitoring Analytics, PJM’s independent Market Monitor. “Nodal pricing is the way to go,” Haas said. “Unequivocally it is the way to go.”
Representatives from Exelon Corp. and Pepco Holdings spoke in opposition.
Jason Barker, of Exelon, said his company saw little “utility” to allowing intra-year switching and significant financial risk to the remaining zonal customers, who could see their costs increase.
“As the operator of three EDCs we do see substantial downside,” he said. “We’re disappointed that it’s come before the Members Committee after being roundly defeated at the MIC.”
Gloria Godson, of Pepco, said the change would be a “significant burden” on EDCs. “We will have to add additional staff to manage this.”
Scarpignato said the intra-year switches would have minimal financial impact on FTR holders and others in the zone. He said new customers connect to the grid year-round without major impacts.
In answer to a question from Godson, PJM’s Tom Zadlo said the change could impact FTRS. “It is potentially possible that there are some impacts on FTRs but it’s impossible to quantify.” The impact would depend on the size of the loads that switched, he said.
Marji Philips, representing Hess Corp., said economists’ preference for nodal pricing is similar to their support for energy–only markets in lieu of a capacity market. “It’s good in theory. As a practical reality it stinks.”
Philips said that PJM’s hedging tools are based on zones and hubs. If many customers switch to nodal pricing in mid-year, she said, it could create “ghettos” where customers will have to pay more of a risk premium because suppliers can’t hedge their loads.
Fourteen of 16 public power members voting supported the change along with three-quarters of 20 other suppliers and all eight end use customers. Transmission companies voted 7-2 against while generation owners split 5-5.
Scarpignato said after the meeting that his company was not giving up. “It was an extremely close vote,” he said. “We’re considering our options.”
The volume of data generated by the smart grid threatens to drown utilities, who have yet to figure out what to do with the information or how to store it, according to industry experts. “It’s generating terabytes of data,” said a representative of the Electric Power Research Institute at a panel discussion at the Illinois Institute of Technology.
NorthWestern Energy will buy 11 hydroelectric plants from PPL Montana – the same power-producing dams that NorthWestern’s predecessor, Montana Power Co., sold in the wake of deregulation almost 15 years ago. NorthWestern said it agreed to buy the 11 dams along five separate Montana rivers for $900 million, subject to approval by state and federal regulators.
FirstEnergy Corp. plans to spend several hundred million dollars to replace the steam generator and reactor vessel head at its Beaver Valley Unit 2 reactor, in Pennsylvania, in 2017. It also plans to replace the two steam generators at its Davis-Besse plant in Ohio in February during a longer-than-normal refueling outage.
Pepco Holdings Inc. named former Dayton Power and Light Co. CEO Paul M. Barbas to its board of directors. Barbas is also a former chief operating officer of Chesapeake Utilities Corp. and executive vice president of Allegheny Power.
Members agreed Thursday to consider new rules to allow batteries, flywheels and other advanced storage technologies to bid in the capacity market.
The Market and Reliability Committee approved a problem statement and issue charge with only two no votes despite some wariness from some members.
The proposal was sponsored by Demansys Energy LLC, which aggregates commercial and industrial customers for participation in the regulation market.
Janette Kessler Dudley, vice president of business development and regulatory affairs, noted that PJM currently has no rules allowing batteries or other advanced storage resources to participate in the Reliability Pricing Model. “What my company is interested in is parity,” she said.
Steve Lieberman, of Old Dominion Electric Cooperative, said he was not convinced storage is compatible with other capacity resources.
He said the issue should receive a lower priority than those currently before the Capacity Senior Task Force. “We should proceed carefully as far as expectations go,” he said.
Members ultimately decided the move the issue from the CSTF to the Planning Committee.
Gloria Godson, of Pepco, said she supported the inquiry but that PJM shouldn’t approve new rules until it fully understands the technologies. She noted the amount of “retooling” the RTO has done to address problems with the integration of demand response.
Raghu Sudhakara, of Rockland Electric Co., noted that NYISO already allows four hour resources to participate in its capacity market. “There’s no reason PJM, being as sophisticated as it is, can’t accommodate new technologies,” he said.
PJM currently has about 56 MW of non-pump storage.
PJM should be able to absorb the more than 7,400 MW of imports that cleared in May’s capacity auction for 2016-17, officials told a special meeting of the Planning Committee Friday.
Officials said that their initial review found PJM can import 11,000 to 12,000 MW. “We may have gotten close to what our limit would be, but we haven’t gotten to it yet,” said Stu Bresler, PJM vice president of market operations.
Officials cautioned that their results were preliminary and subject to change with further analysis.
Friday’s meeting was prompted by a problem statement approved by the Planning Committee Sept. 12.
The committee will seek to adopt a methodology for determining an RTO import limit that can be applied in the PJM planning process as well as included in next year’s Base Residual Auction. “It would function much like a CETL (Capacity Emergency Transfer Limit) for the entire RTO,” Bresler told the Markets and Reliability Committee in a brief discussion Thursday.
In addition to ensuring space for capacity, PJM must account for long term transmission contracts and 3,500 MW for the RTO’s Capacity Benefit Margin, which is reserved for importing capacity from external areas in emergencies.
Officials said their initial review identified a 500/230 kV transformer in the Duke Energy Carolinas zone as the limiting facility.
Bresler said PJM likely will propose a combination of path-specific limits with an overall RTO import cap. “The sum of the path-by-path limits could exceed what an overall limit would be,” he said.
Officials were unable to say Friday how much of the RTO’s total import capacity is to PJM’s west, the source of most of the imports that cleared in the May auction.
