Dominion’s new Pleasant View-Goose Creek 500 kV line will be designated as line number 595.
Dominion is building a 500kV ring bus substation, Goose Greek, to install a 150 MVAR capacitor bank. The Doubs-Pleasant View and Pleasant View-Brambleton circuits will terminate at the Goose Creek station.
The project (PJM baseline upgrade b1799) is designed to correct NERC category C3 N-1-1 voltage violations, with completion targeted for spring 2014.
The Doubs–Goose Creek line will keep the 543 line designation while the Goose Creek–Brambleton (Loudoun) line will keep the 558 identifier.
Unable to resolve the disputes themselves, PJM last week asked the Federal Energy Regulatory Commission to settle its standoffs with MISO and NYISO over cross-border reliability projects.
PJM and MISO parted ways in separate Order 1000 interregional compliance filings. PJM balked at the MISO’s request to remove cross-border Baseline Reliability Projects (BRPs) from the cost allocation provisions of the PJM-MISO Joint Operating Agreement.
PJM also said it was unable to reach agreement with the New York ISO on a process to address cross-border tie-in facilities needed for reliability. As a result, it said, “the RTOs have not fully satisfied their Order 1000 compliance requirements.”
PJM did reach agreement with members of the Southeast Region Transmission Planning region (SERTP) on an “avoided cost” mechanism for funding cross-border reliability projects.
MISO Proposal
MISO told FERC (ER13-1943) says its request to amend the JOA is justified by FERC’s March 22 Order 1000 compliance order, in which the commission accepted MISO’s proposal to remove regional cost allocation for BRPs and assign all BRP costs to the pricing zone where the project is located. The change took effect June 1.
Since BRPs are no longer subject to regional cost allocation, cross-border BRPs cannot be eligible for interregional cost allocation, MISO says.
PJM – MISO Tie Lines (Source: PJM Interconnection, LLC)
Instead, MISO proposes that tie lines between MISO and PJM transmission owners be designated as cross-border BRPs. Ownership and responsibility for any upgrades would be shared by the transmission owners — essentially preserving their rights of first refusal (ROFR) on cross-border reliability projects. According to PJM, there are 83 tie lines ranging from 69kV to 765 kV between the two RTOs.
MISO said reliability problems can be addressed through cross-border Market Efficiency Projects, for which interregional cost allocation would continue.
PJM and its transmission owners referred to the dispute only indirectly in their filings with FERC last week, leaving MISO to provide details. The PJM transmission owners “have informed MISO that they do not agree … [that MISO’s request] would be compliant with the requirements of Order No. 1000,” MISO Vice President for Transmission Jennifer Curran said in written testimony included with MISO’s filing.
In a meeting with MISO stakeholders in January, PJM officials and transmission owners made clear their opposition to MISO’s plan. Craig Glazer, PJM vice president of federal government policy, told MISO stakeholders that their proposal was not consistent with Order 1000. “I don’t think that dog’s gonna hunt,” he said. “…You’re doing this because you want to protect the ROFR rights.”
A MISO representative responded that broad cost allocation of reliability projects was not justified because the benefits of such projects are primarily local. In an earlier filing, MISO told FERC that in 80% of its Baseline Reliability Projects since 2006, at least 75% percent of costs were allocated to the local pricing zone.
PJM: MISO Can’t Unilaterally Change JOA
In its compliance filing last week (ER13-1944), PJM told FERC that it should reject MISO’s proposal because the JOA is a contract which can only be changed by mutual consent of the two RTOs. PJM said it would be “damaging” for FERC to “wrest one provision out of this carefully negotiated integrated agreement.”
The 2008 Joint Operating Agreement allocates the costs of cross-border reliability and market efficiency projects between the two regions based on the benefits each expects to receive. Although the two RTOs have had an interregional cost allocation provisions in force since 2005, no cross-border projects have been approved for cost allocation under the JOA, Curran said.
The Order 1000 dispute is one of several points of friction between the two RTOs. On June 20, the RTO officials appeared before FERC to make their cases in a dispute over the way PJM models cross border transmission deliverability, which MISO says is unfairly limiting its generation from competing in PJM’s capacity market. (See: PJM and MISO: Best of Frenemies)
NYISO
PJM also left it to FERC to sort out a dispute with the NYISO.
PJM said the Northeastern ISO/RTO Planning Coordination Protocol, which outlines its relationship with NYISO and ISO-NE, does not provide a mechanism for one region to link to its neighbor’s transmission facilities to solve one region’s reliability need. “These tie-ins are especially critical given the highly intertwined nature of the NYISO and PJM regions, and the unique nature of the NYISO/PJM seam,” PJM told FERC (ER13-1947).
PJM rejected NYISO’s proposal that PJM be subject to the NYISO tariff as a merchant transmission developer or a NYISO transmission owner under the NYISO Transmission Expansion Process. PJM said NYISO’s proposal was unworkable because those market-based processes don’t apply to baseline reliability facilities and would violate commission precedent that coordination between RTOs “should be done at the RTO level.”
PJM asked FERC to order the two RTOs to amend their JOA to add provisions for reliability transmission tie-ins. “Such a directive would help end what has been unproductive debate as to the relationship of this issue to Order No. 1000’s requirements,” PJM said.
SERTP
In a separate filing (ER13-1927), the PJM transmission owners said they reached agreement with the members of the Southeast Region Transmission Planning region (SERTP) to add a new schedule to the PJM Tariff governing cost allocation for interregional transmission expansions. Signing the agreement on behalf of SERTP were Duke Energy, Louisville Gas & Electric/Kentucky Utilities, Ohio Valley Electric Corp. and Southern Co.
The proposal calculates the benefits of an interregional project based on avoided costs — “the cost savings achieved by replacing higher cost regionally-planned transmission projects with the more efficient and cost-effective proposed interregional project,” the PJM transmission owners said.
They acknowledged that the commission previously ruled that the avoided cost methodology does account for economic or public policy benefits of transmission projects. However, they noted, “Order No. 1000 does not require the consideration of public policy or economic benefits at the interregional level.”
The Market Implementation Committee last week soundly rejected a proposal to change the modeling assumptions used in long-term auctions of Financial Transmission Rights (FTR).
The proposal — which would have reduced capability in long-term FTR auctions from 100% to 50% of available capability after reserving Auction Revenue Right (ARR) capability — received support from only 36% of MIC voters.
Bruce Bleiweis, director of market affairs for DC Energy, LLC, said the proposal would hurt the ability of market participants to engage in long-term hedging while providing only small improvements to FTR funding shortfalls. “It will result in a lot less liquidity, a lot less price discovery,” he said.
In May, the MIC gave near-unanimous support to two other modeling changes also intended to reduce the risk of FTR funding shortfalls by reducing or eliminating infeasibilities in the FTR model so that increased counterflow FTRs clear. (“MIC OKs Options to Reduce FTR Shortfalls”)
MIC rejected another proposed change and deferred a vote on the long-term auction proposal pending a ruling on FirstEnergy Corp.’s complaint to the Federal Energy Regulatory Commission over FTR underfunding (EL13-47). FERC rejected the complaint June 5, saying FirstEnergy had not proven PJM’s current practices are unjust and unreasonable. The commission urged the RTO to continue its efforts to address the causes of underfunding.
The Planning Committee voted last week to continue using a load model based on the period 1998-2006 in its calculation of Installed Reserve Margin (IRM) requirements.
The 2013 Installed Reserve Margin (IRM) study will set IRM requirements for base capacity auctions for delivery years 2014 through 2017. The 1998-2006 load model selected by the committee is the same one used in the 2011 and 2012 IRM studies.
The committee is expected to receive the study results in September and vote on the new IRM requirements in October.
Seeking its third base rate increase in four years, Potomac Electric Power Co. won approval from Maryland regulators Friday for a $28 million increase in distribution rates and a $24 million surcharge to accelerate the hardening of feeder lines.
Pepco had asked the Maryland Public Service Commission for almost $61 million in additional distribution rates and an increase in its return on equity (ROE) to 10.25%. The commission accepted a staff recommendation for an ROE of 9.36%, a slight boost from the current 9.31%. The changes will add $2.41 monthly to the average residential bill, effective July 12, 2013.
Pepco also requested a $192 million Grid Resiliency Charge, including $17 million for accelerated vegetation management; $151 million to move portions of six feeders underground and $24 million to accelerate the hardening of 24 feeders that are prone to outages during major storms.
The commission approved only the work on the 24 feeders, saying it needed more information on the undergrounding proposal. The commission said the company’s plan for accelerating vegetation management in 2014 “has no impact on the amount of tree trimming required for subsequent years and provides no cost savings in the future.”
PJM officials told the Operating Committee last week that they are considering increased penalties to eliminate the current economic incentives for generators and demand response providers that fail to perform when called on to provide spinning reserve.
Providers of Tier 2 synchronized reserve are paid per MWH of reserves offered but are only called on to provide reserves for about three spinning events per month, most of them less than 20 minutes long.
“The result is that it is possible to provide the service profitably with a very low level of compliance,” the Market Monitor said in the 2011 State of the Market Report. “This behavior does exist in this market.”
The monitor repeated its call for increased penalties in the 2012 report with some additional observations: “Sometimes units do not achieve the ramp rate they have bid, sometimes units fail to follow PJM dispatch, sometimes system conditions change rapidly during the hour between a market solution and the actual hour.” The monitor noted that non-compliance “has never caused a reliability problem at PJM.”
Tom Blair, of Monitoring Analytics, told the Operating Committee that the market monitor studied three spinning events of more than 10 minutes in 2013 and compliance by demand response resources was “not good.”
David Pratzon, who represents generators at GT Power Source, supported the call for increased penalties. “Tier 2 resources can clear for hundreds of hours before they are called even once. There is a risk that someone can take the money and run.” The weighted average market price for synchronized reserve was $8 per MW last year.
However, Pratzon and representatives of other generators said the rules shouldn’t be so strict that they penalize providers that are doing their best to comply. For example, Pratzon said gas generators can hit “dead bands” during duct firing, and coal plants may underperform if their fuel is damp or of lower quality.
Pratzon, AEP, Exelon and Exelon joined to propose an alternative set of penalties that would not apply unless providers fall below 90% of their promised reserves. Blair said the market monitor also supports the 90% threshold.
Brock Ondayko, of AEP, said although the PJM dispatch system has improved, it still does not accurately model the behavior of coal-fired units.
He added that PJM should ensure that changes to the synchronized reserve rules do not have unintended consequences. “Adjusting ramp rates also impacts the amount of energy we’re awarded during the day,” he said.
PJM staffer Kim Warshel asked participants to submit proposed alternate solutions by July 16, in time for consideration at the next special meeting of the Operating Committee to discuss the issue, set for July 18.
A proposed new scheduling option for transactions into the New York ISO faces an uncertain future after a first reading at the Market Implementation Committee meeting last week.
PJM said it plans to seek an MIC endorsement in August of the Coordinated Transaction Scheduling (CTS) proposal, which is designed to improve interchange scheduling efficiency between NYISO and PJM.
The proposal would create an additional scheduling product, intra-hour evaluations of CTS interface bids and offers. CTS Interface Bids would have as many as four bid curves and up to 11 $/MW pairs. The option would be in addition to current hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers.
PJM says the new product should increase forward price transparency and price convergence between PJM and NYISO.
A cost benefit analysis found that the change could reduce production costs by as much as $26 million, but PJM’s Rebecca Carroll said the RTO had not analyzed how much of those savings would be offset by make-whole payments to generators.
CTS Interface bids would be scheduled based on the projected price difference between PJM and NYISO at the interface. It would use PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application, which has a two hour look-ahead capability. The application correctly predicted prices within $5 about 60% of the time. “We definitely see there’s room for improvement here,” said Carroll.
PJM initially proposed that the trades be exempt from Balancing Operating Reserve (BOR) charges because they provide economic benefits to both NYISO and PJM and will be cleared and scheduled based on near-term projected operating conditions.
But the RTO dropped that proposal after stakeholders said the transactions should be treated the same as real-time dispatchable transactions.
“Because this is a real-time product, it is going to have an impact on balancing congestion,” said one stakeholder, whose identity is being withheld at his request, per PJM’s code of conduct. He said Financial Transmission Rights (FTR) holders should not be penalized for such impacts.
PJM also proposed 15-minute settlements for all interchange transactions — the same interval for which they flow — rather than being integrated in the current hourly settlement processes. PJM said the change would require a longer transition process than using 15-minute settlements for CTS trades alone.
Credit requirements on the new scheduling option would be based on the higher of the 97th percentile historical (prior year) hourly price for the node or the 15-minute IT SCED price forecast for the node.
Stephanie Staska, of Twin Cities Power, LLC, said the credit requirement should apply to all export transactions if such a screen is initiated for CTS transactions.
Several MIC members said it was premature to schedule a vote next month given the level of detail PJM had provided them to date. “I don’t know if we understand this issue well enough to vote knowledgeably,” said Jung Suh,of Noble Americas Energy Solutions LLC.
Dave Pratzon, of GT Power Group, said stakeholders should explore the impact of the change on balancing congestion and the implications of using 15-minute settlements.
The issue has been under discussion with NYISO since November 2012. The new scheduling product would require approval of the Federal Energy Regulatory Commission.
PJM expects to open a proposal window for market efficiency transmission projects later this year, PJM officials told members last week.
Steve Herling, PJM vice president of planning, said the window would allow transmission developers to propose cost-saving solutions to congestion issues identified by PJM staff. PJM officials said the window would be opened after PJM staff completes its analysis of public policy transmission needs.
“We may not open a window for another month and a half,” Herling told the Transmission Expansion Advisory Committee. “That doesn’t mean you can’t start working now.”
In an earlier meeting with the Planning Committee, Herling said that the window “will be less focused than” that opened earlier this year to address stability problems at Artificial Island in New Jersey. (See related article.)
Location of High Voltage Problems Identified by PJM (Source: PJM Interconnection, LLC; p. 11, RTEP Reliability Analysis, TEAC 7-10-13)
In 2012, PJM identified $718.6 million in gross congestion, $347 million of which was unhedgeable, a reduction from the $998 million in market congestion for 2011. (See Table.)
Fifteen monitored facilities were responsible for at least $10 million each in gross congestion, led by APSOUTH with $126 million of gross congestion, almost one-fifth of the total.
Proposals must meet or exceed a 1.25 benefit-to-cost threshold to be considered by the Board of Managers for inclusion in the Regional Transmission Expansion Plan.
The Market Efficiency case files are available to those with a Ventyx database license and clearance to view Critical Energy Infrastructure Information (CEII).
In a related matter, Herling said PJM has completed its review of applications from most of the 12 companies that sought prequalification as transmission developers under FERC Order 1000, which reduced transmission owners’ historic Rights of First Refusal and opened transmission projects to competition. PJM will post the results of its reviews within two weeks, Herling said.
The Operating Committee last week approved changes to manuals 1 and 12, while the Planning Committee received a presentation on proposed changes to Manual 21 and the Market Implementation Committee heard a first reading on changes to Manual 28.
Manual 1: Control Center and Data Exchange Requirements
Reason for change: New rules for access to PJM Energy Management System (EMS).
Impacts:
Added new section 2.5.7 detailing rules for transmission owner read-only access to PJM’s EMS. No screen scraping is allowed.
Modified section 3.2.3 to clarify procedures for data communication outages.
Modified section 4.2.4 to clarify repeating of All Call messages.
Adds details to Information Access Matrix in Attachment A.
Next Step: Vote by Markets and Reliability Committee.
Manual 12: Balancing Operations
Reason for change: PJM is changing the regulation requirement to align it with operational needs and address volatility in light load periods.
Impacts:
Changes On-peak (05:00-23:59) requirement to 700 effective MW, a decrease in the requirement for 52% of days, an increase for 48% of days. Net daily decrease of about 60 MW (section 4.4.3).
Changes Off-peak (00:00-04:59) requirement to 525 effective MW, an increase for 66% of days and a decrease for 34% of days. Net daily increase of about 20 MW (section 4.4.3).
Changes regulation scoring methods:
Performance scoring for small regulation allocation: Historical performance scores will be used if the control signal has an average absolute value less than 1% of the regulation assignment (section 4.5.6)
Performance scores when data is not available: Historical performance scores will be used if data is not available and for intervals less than 15 contiguous minutes (adds section 4.5.9)
Regulation Assignments: Scoring will be suspended for 10 minutes after assignment to allow time to ramp into position (adds section 4.5.10).
Next Step: Vote by Markets and Reliability Committee.
PJM contact: Rus Ogborn
Manual 21: Rules and Procedures for Determination of Generating Capability
Reason for change: Clarifying ambiguous language, updating terms.
Impacts:
Clarifies that intermittent resources (wind, solar) are not required to perform seasonal verification tests because their capacity credit calculation is used in place of a ratings test.
Clarifies that all generators, except hydro, pumped storage and diesel units, are required to adjust rating test results for expected cooling water and ambient air conditions.
Hydro and pumped storage units must perform their annual ratings test during the summer verification window and are not required to perform a winter test.
Next Step: Vote at next Planning Committee meeting.
PJM contact: Tom Falin
Manual 28: Operating Agreement Accounting
Reason for change: Incorporating changes to lost opportunity cost compensation as approved by FERC.
Impacts:
Changes sections 5.2.6 and 5.2.8 (Operating Reserve & Reactive Services Lost Opportunity Cost Credits) to limit lost opportunity cost compensation to the lesser of a unit’s economic maximum or maximum facility output as approved in FERC Docket ER13-1200.
Section 7.2 (Shortage Pricing) amended to incorporate calculation details for non-synchronized reserve market lost opportunity costs.
Modifies section 5.3 (Operating Reserve) to correct errors and provide clarifications on exempting deviations during shortage conditions and revisions for associating interfaces to the East or West BOR regions.
Modifies sections: 5.2.3 to incorporate details of Lost Opportunity Cost Credit for Synchronous Condensing; 5.2.6 (Wind Lost Opportunity Cost) to align language with Tariff; 17.3 (Allocation of Annual and Monthly FTR Auction Revenues) to correct section reference.
PJM transmission planners have identified more than $800 million in reliability upgrades for inclusion in the Regional Transmission Expansion Plan (RTEP), officials told members last week. Costs are likely to exceed $1 billion once all projects are tallied.
The upgrades, outlined to the Transmission Expansion Advisory Committee Thursday, include 26 projects to address high voltage problems, 10 to fix load deliverability problems and four areas with short circuit problems.
Short Circuit Upgrades
The biggest single reliability project is likely to be one addressing the short circuit problem in the PSE&G transmission zone outside New York City.
The 2012 PJM RTEP identified several buses in the PSEG zone where the fault currents exceed 80 kA. Potential solutions include upgrading stations to 90 kA and installing current limiting reactors.
Another possible solution being reviewed by PJM is to isolate the Hudson 230 kV from the 138 kV at Marion and 345 kV at Farragut. The 138 kV buses and transmission facilities on the path from Linden to Bergen would be converted to double circuit 230 kV or 345 kV lines. The 345 kV proposal is estimated to cost $1.1 billion but eliminates the need for $588 million of approved RTEP projects, resulting in a net cost of $515 million.
Also under consideration is a proposal to build parallel 700 MW high voltage DC converter stations, estimated at $800 million to $1.1 billion.
One member said PJM should open a proposal window to solve the issue. But PJM officials said they were unlikely to do so — meaning PSEG would have the right to construct the solution — because of the urgency of the problem.
“We will be hard pressed to get any solution by 2015,” said Paul McGlynn, general manager of system planning. “It doesn’t really lend itself to a proposal window.”
“The board has been concerned that this [problem] has been hanging on for quite a while,” added Steve Herling, PJM vice president for planning.
PJM staff is refining its cost analyses and performing additional load flow analyses. Any solution will have to accommodate PJM’s contract with NYISO for the so-called Consolidated Edison “wheel.” The wheel funnels 1000 MW from NYISO through PSEG and into New York City.
In addition to the PSEG short circuit project planners also identified “overstressed” circuit breakers in the Duke Energy Ohio and Kentucky (cost to be determined), Duquesne Light (cost TBD) and Jersey Central Power and Light Co. transmission areas (estimated cost $360,000).
High Voltage
Location of High Voltage Problems Identified by PJM (Source: PJM Interconnection, LLC; p. 11, RTEP Reliability Analysis, TEAC 7-10-13)
PSEG also figures prominently in upgrades to fix high voltage problems, with 13 projects with a total cost of $122 million. AEP had five projects totaling $17 million while AEC had two projects totaling almost $30 million. PEPCO, PPL, Jersey Central Power and Light, Allegheny Power System and PECO had upgrades ranging from $16 million to $4 million.
PJM’s Board of Managers will be asked to approve the high voltage projects in October, PJM officials said.
Load Deliverability
Twenty-five of 27 Locational Deliverability Areas (LDAs) passed the load deliverability test with no thermal or voltage issues while voltage violations were identified in the Penelec transmission zone resulting from the Penelec and Western MAAC load deliverability tests.
Planners identified 10 projects to solve the problems. One in PPL is estimated at $84.5 million and another in Atlantic City Electric Co. at $11.2 million. Costs of the remaining projects, one in Delmarva Power and Light and seven in PEPCO, have not been estimated.
