The Market Implementation Committee next month will consider proposals to allow network load customers more frequent opportunities to switch to nodal pricing.
Current rules allow network customers to make such switch requests annually, effective June 1st. A stakeholder group formed under a problem statement approved at the request of retail marketer Direct Energy proposed two alternatives to allow such switches monthly. The annual switching rules don’t allow retail marketers to provide innovative products, Direct Energy said.
Both proposals would limit intra-year switches to 5% of the electric distribution company (EDC) network service peak load. The differences between the two proposals are the additional caps on the number of customers per EDC: either five or 50 customers per EDC.
Marji Philips, of Hess Corp., said the intra-year switches could hurt Financial Transmission Rights holders. “If five large industrial customers switch to nodal in the middle of the year, your [FTR] holdings could be seriously impacted,” she said.
David Pratzon, of GT Power Group, questioned the breadth of support for the proposed changes, saying only a small number of stakeholders worked on the problem statement.
The proposals would phase in implementation of intra-year requests with quarterly switches allowed in the first year and monthly switches permitted in the following years. The first switches would be available effective June 1, 2014.
Customers would be required to provide 60 days’ notice before the switch becomes effective, a deadline that could be extended to up to 150 days for complex cases.
As under current rules, customers would be barred from switching from nodal back to zonal.
The MIC is expected to vote on the proposals at its next meeting.
Dominion and PPL will remove three Special Protection Schemes (SPS) while Dominion will add one, PJM told the Planning Committee last week.
Dominion will operate an SPS to control stability at its Bath County pump storage facility to continue operation during the Dooms – Lexington rebuilding project.
The pump storage facility has six generating and pumping units totaling about 3,000 MW. An existing Bath County/Cloverdale SPS is designed to trip either one or two Bath County pumps if the flows on the Cloverdale 6A/6B transformers exceed their temperature-adjusted emergency ratings.
The Dooms – Lexington 500 kV line will be taken out of service about September 2014 for a wreck and rebuild baseline project (b1908). Existing stability restrictions would restrict generation and pumping at Bath to two units, removing about 2000 MW of capacity. The new SPS (PJM Baseline Project b2281) will allow operation of up to five units.
The SPS will not be armed if there are any other 500 kV outages in the vicinity. PJM will determine how many units at Bath will be armed for the SPS based on the operating status of the Bath units (i.e., pumping, generating or condensing).
The target date for completion of the rebuilding project, and removal of the SPS, is June 1, 2016.
The three SPSs being removed are:
Dominion Harmony Village SPS: The SPS was installed in 2007 to prevent an overload on line #65 during loss of towers carrying lines #2016 and #85. The completion of a new 230 kV line (#2122) from Hayes to Yorktown (B0779) in December 2012 eliminates the need for the scheme.
Dominion Virginia Beach SPS: The SPS was installed in 2007 to prevent line #27 from overloading as the only feed to Virginia Beach due to loss of two other feeds. The completion of a 230 kV line (#2118) from Landstown to Virginia Beach (S0375) in December 2012 eliminates the need for scheme.
PPL West Shore 230 KV Automatic Load Shedding SPS: SPS B0718 was installed in 2010 to alleviate an N-1-1 summer peak overload condition at the Steelton Tap on the Hummelstown-Middletown Junction #2 230 kV line. A second Brunner Island – West Shore 230 KV line (B0717) went in-service recently, eliminating the need for the SPS.
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.
