Page 1711 – RTO Insider

May 21, 2013

Tx Planning Standard OK’d on Second Try

The Federal Energy Regulatory Commission last week approved a revised transmission planning reliability standard it had previously rejected as “vague and unenforceable.”

The North American Electric Reliability Corp.’s proposed reliability standard TPL-001-2 would have allowed transmission planners to plan for non-consequential load loss following a single contingency as long as the plan was the result of an open and transparent stakeholder process.

The commission said the revised standard TPL-001-4 will improve reliability “by providing a blend of specific quantitative and qualitative parameters for the permissible use of planned non-consequential load loss to address bulk electric system performance issues.” The commission said the new rule defines the stakeholder process and criteria that must be followed and includes safeguards, including a review process to ensure the procedure does not hurt reliability.

The commission’s approval, a Notice of Proposed Rulemaking, will be open for 30 days after its publication in the Federal Register. In a concurring statement, Commissioner John R. Norris praised the rule for balancing the need to protect system reliability and minimize costs.

“NERC’s proposal goes a long way towards empowering local communities to consider the economic tradeoffs between incurring costs to avoid shedding firm load versus planning to shed firm load, while still ensuring that the decision-making process is more open and transparent and building in a safeguard for NERC to review decisions for possible adverse reliability impacts,” Norris said.

May 16, 2013

PJM Chooses Continuity over New Voices for Board – UPDATE

By Rich Heidorn Jr.

WHITE SULPHUR SPRINGS, WV – “I don’t want to put the board on the spot,” said Robert Mork, doing just that at the PJM Board of Managers annual meeting with public interest groups and state regulators Tuesday. “But I think it’s the case that none of you have worked in a consumer advocate’s office or served on a state commission.”

There was an awkward silence in the wood-paneled Eisenhower conference room at the opulent but mostly empty Greenbrier resort here. No one corrected Mork, an attorney in the Indiana Office of Utility Consumer Counselor.

Would the 10-member PJM benefit from the presence of at least one board member with a state ratemaking perspective? It will have to wait at least another year to find out.

The PJM Members Committee this morning approved the re-election of three long-serving members to the PJM Board of Managers: Jean Kinsey, William Mayben and Richard Lahey. Given the absence of any other candidates, reelection was all but certain.

Kinsey, a Ph.D. economist, has served on the board since 2003. She is a Professor Emeritus in the Department of Applied Economics at the University of Minnesota and an expert on food consumption trends, obesity issues, consumer buying behavior, and food industry organization.

Lahey, who has a Ph.D. in mechanical engineering, is an expert on nuclear reactor safety technology, power engineering, and the use of advanced technology in industrial applications. A Professor Emeritus at the Rensselaer Polytechnic Institute, he has served since PJM’s independent board was created in 1997.

Mayben, who joined the board in 2007, worked as a management consultant serving utilities and is former president and CEO of the Nebraska Public Power District. He holds a B.S. in electrical engineering.

The three were selected for new three-year terms by the nominating committee, comprised of Board Chair Howard Schneider; also a member of the original board; board members John McNeely Foster and Susan Riley, and five PJM members. The members represent the Electric Distributor, Generation Owner, Other Supplier, End Use Customer and Transmission Owner sectors.

Lahey and Mayben, who both serve on the board’s reliability committee, told PJM Insider that maintaining the security of the PJM grid against physical and cyber attacks would be among their priorities in their next terms.

“I’m concerned about people getting into our system,” said Mayben, who is also on board’s audit committee.

Lahey also is a member of the human resources and finance committees. He said had he had no specific goals. “It’s hard to predict the future,” he said. “At every meeting there’s some new challenges.”

Kinsey is a member of the competitive markets and audits committees.

She declined to comment on her pending election Wednesday. “I think they [members] know what I’m doing and what I will be doing,” she said.

May 13, 2013

No Changes for Wind BOR, Forecasting Costs

PJM will continue its current methods for calculating wind farms’ operating reserve charges and allocating costs of its wind forecasting tool.

The Intermittent Resources Task Force concluded a six-month review last month without reaching consensus on any proposed changes to the current methods.

The task force’s 2008 charter included an assignment to “recommend methodology for allocating wind production forecasting costs, and potential changes to how operating reserve charges are applied to intermittent resources.”

Balancing Operating Reserves (BOR) are calculated for wind resources the same as for non-intermittent resources: Resources can earn reserve credits by following dispatch instructions; those that fail to do so are ineligible to earn credits and are charged for deviations.

PJM’s wind power forecasting tool, used to ensure scheduling of sufficient generation in the day-ahead market, costs $135,600 annually. The cost is allocated RTO-wide, based on transmission use, through PJM’s monthly Schedule 9-1 charges.

“We wouldn’t have a need for this tool but for the wind technology and the issues it creates for the rest of the system,” said one member in a Market Implementation Committee discussion of the task force’s findings last week.

The task force concluded, however, that because accurate forecasts improve system reliability, the costs should continue to be spread among all market participants. A proposal to assess the costs solely to wind projects, with offsets in operating reserve charges, won support of only 10% of the task force.

Another member noted that the RTO-wide cost allocation is consistent with how PJM pays for its hydropower scheduling software.

Editor’s Note: PJM Insider is withholding the names and organizations of the speakers in accordance with the PJM Code of Conduct (Section 4.5 of Manual 34). The code prohibits quoting members by name or organization without their approval for all meetings other than those of the Markets and Reliability and Members committees.

May 13, 2013

Model Changes May Cut Reserve Prices in PJM East

Reserve market prices in eastern PJM are likely to drop in June as PJM implements a new model for calculating interface transfer capabilities.

Adam Keech, PJM director of wholesale market operations, said that the new model will allow resources in western PJM to deliver up to six times more synchronized and primary reserves to eastern PJM than in the current “overly conservative” model.

Fewer eastern reserves will be called on as more reserves from the west — which has a surplus — are delivered to the east. As a result, Keech told the Operating Committee last week, “The market value of reserves in the Mid-Atlantic and Dominion zone is likely to be reduced.”

Until PJM implemented Shortage Pricing last October, markets were cleared an hour ahead of the operating hour, causing operators to use conservative assumptions on interface congestion. With reserve market clearing now done in real-time, the old models are sometimes falsely predicting shortages in the Mid-Atlantic zone, Keech said.

“At times, [operators] are doing what the software says. At times they don’t because they know it doesn’t make sense.”

Because some operators follow the software more closely than others, Keech later told the Market Implementation Committee, “it’s tough to gauge what the impact [of the change is] going to be.”

The limiting reserve interface between west and east is usually Bedington-Black Oak or AP-South. Cases run by PJM on AP-South indicate that it has a distribution factor of only 17%, meaning that 6 MW can be loaded in the west for every 1 MW available on the interface. The current model assumed a distribution factor of 100% — as if AP South were the only line connecting the west and east regions.

Because the distribution factor depends on the location of the generators providing reserves and the load served, it will change with system conditions.

The transition is expected to begin by early June. Keech said PJM will phase in the switch, starting with a distribution factor of about 50% to test the new assumptions. “We’re not going to step all the way off the cliff in one fell swoop,” he said. “We want to be careful we don’t create any operational problems.”

May 13, 2013

PJM Opens Capacity Auction

PJM opened its annual capacity auction yesterday, with bids and offers accepted through Friday, May 17. Results of the Reliability Pricing Model auction, which seeks resources for the 2016-2017 planning year, will be posted after 4 p.m. May 24.

Clearing prices in last year’s Base Residual Auction, for 2015-2016, ranged from a low of $136/MW-day in APS to a high of $357 in ATSI. The weighted average cost was $148.33/MW-day, up 19% over the prior year.

Wherever prices clear in this year’s auction, they will not be the result of a competitive market. Transmission congestion, combined with concentrated generation ownership and inelastic demand means the market “is unlikely ever to approach a competitive market structure in the absence of a substantial and unlikely structural change that results in much more diversity of ownership,” the Market Monitor wrote in the 2012 State of the Market Report.

Generation Concentration

In all but three of PJM’s nine RPM markets, one generation owner owns about half or more of all resources. In four zones — PSEG, PSEG North, Pepco and ATSI — the top generation owner controls more than three-quarters of resources. (See map.)

For almost all auctions held since 2007, the PJM region failed the Three Pivotal Supplier Test (TPS). Any supplier that owns more capacity than the difference between supply and demand is pivotal: that is, has market power.

Market Power Mitigation

Market power mitigation is applied when a capacity market seller fails the market power test, the sell offer exceeds the defined offer cap, and the submitted offer would otherwise increase the market clearing price.

Such rules are also applied to prevent demand side market power, when a capacity market seller submits an offer for a new resource or uprate that is below the Minimum Offer Price Rule (MOPR) threshold. (See “Split Decision on MOPR.”)

PJM’s total capacity costs for have nearly tripled over the last four auctions — to nearly $10 billion for 2015-16 — while capacity obligations have more than doubled. The increase in capacity needs reflect the integration of the Duke Energy Ohio and Kentucky (DEOK) and American Transmission Systems, Inc. (ATSI) zones and the addition of the Duquesne zone. This year’s auction will see an additional increase in capacity needs, following the addition of the East Kentucky Power Cooperative.

May 13, 2013

Manual Changes

The Operating Committee approved changes to the following two manuals on May 7.

Manual 03: Transmission Operations

Reason for changes: Semi-annual update.

Impact: Incorporates procedure changes (e.g., updates voltage limits, adds ComEd interface).

Manual 03A: Energy Management System (EMS) Model Updates and Quality Assurance

Reason for changes: Updates and clarity.

Impact: Numerous changes including:

New section 1.7 discussing Transmission Service Agreements and data requirements; specifies that updates must come from both transmission and generation owners.
Section 3.3: defines emergency ratings as capability up to 4 hours and load dump ratings as capability up to 15 minutes; eliminated statement that 3% separation is required between emergency & load dump.
New section 4.4 detailing tie line cut-in process.

May 13, 2013

Manual, Tariff Changes: Residual Zones, EKPC, Loss of Internet, Regulation Market

The Market Implementation Committee approved changes to implement Residual Zone Pricing, the integration of the East Kentucky Power Cooperative and market procedures to be used if the RTO loses Internet service.

Residual Zone Pricing

Residual Zone Pricing will replace physical zone LMPs for real-time load effective June 1, 2015. A Residual Zone is an aggregate of all load buses in the physical zone, excluding load priced at nodal locations.

Reason for Changes: Manual revisions are required to implement Residual Zone Pricing, which was endorsed by the Members Committee in February 2012 and approved by FERC in Docket ER13-347.

Impact: The following manuals will be changed: M6: ARR/FTR election language (sections 3 and 4); M11: Energy & Ancillary Services Market Operations (section 2); M27: Open Access Transmission Tariff Accounting (section 5), and M28: Operating Agreement Accounting (sections 3, 8.3, 9.3 and 11).

Residual Metered Load aggregate definitions used for ARR/FTR purposes are fixed for the planning period.

PJM Contact: Suzanne Coyne

EKPC Integration

Reason for Changes: Adds the East Kentucky Power Cooperative zone into PJM markets manuals as a result of the coop’s integration into PJM effective June 1.

Impact: Changes to the following manuals: M11: Energy & Ancillary Services Market Operations (sections 2.13 and 10.4.2); M18: PJM Capacity Market (sections 2.3.1 and 3.3.1); M27: Open Access Transmission Tariff Accounting (sections 2.2, 5.3, 8.1 and 8.1.1), and M28: Operating Agreement Accounting (section 5.3).

PJM Contact: Brigid Cummings

Suspension of Day-Ahead Market for Loss of Internet

Reason for Changes: PJM has no procedures for responding to an extraordinary event, such as an Internet failure, that disables the RTO’s eMKT application. Tariff revisions are required to implement a procedure for suspending the day-ahead market when loss of the Internet or other extraordinary circumstances prevents market clearing. (See “PJM Working on Contingency Plan for Loss of Internet”)

Impact: All market settlements would be done in real time if PJM loses Internet service. The procedure requires changes to sections 1.10.8 and 1.10.9 of the Open Access Transmission Tariff, including clarification that the rebid period will be from 4:00 PM to 6:00 p.m. but may be revised by PJM if the clearing of the day-ahead energy market is significantly delayed.

PJM Contact: Ray Fernandez

Regulation Market

Reason for Changes: New rules implemented in October require regulation offers to include capability (cost, in $/MWh to reserve a resource for regulation) and performance (costs of tracking the regulation signal in miles/MW). Previous rules, as defined in Manual 15, did not include performance costs.

Impact: Inserts regulation cost information in M15: Cost Development Guidelines (sections 2.8 and 11.8) and removes it from M11 – Energy & Ancillary Services Market Operations (sub-section 3.2.1).

Also updates the example of a regulation cost offer calculation (section 2.8) and redefines energy storage losses (section 11.8) in M15 and removes heat rate process information from M11 (section 3.2.1) and moves it to eMKT User Guide.

PJM contact: Jeff Schmidt

May 13, 2013

MIC OKs Options to Reduce FTR Shortfalls

The Market Implementation Committee gave preliminary approval Wednesday to two proposals for lowering the risk of FTR revenue shortfalls.

The two proposals from the Financial Transmission Rights Task Force (FTRTF) received near-unanimous support, while a third option failed with less than 40% support and a vote on a fourth option was postponed.

All of the proposals were designed to eliminate modeling differences between the energy and Financial Transmission Rights (FTR) markets that contribute to FTR funding shortfalls.

The two proposals approved for consideration by the Markets and Reliability Committee reduce or remove infeasibilities in the FTR model and may allow increased counter flow FTRs to clear.

The four proposals were whittled down from more than 20 options the task force considered in eight meetings since October.

PJM’s Tim Horger said an analysis for one constraint found more than a $15 million improvement in FTR adequacy. However, he added, “we’re not guaranteeing anything with this.”

Under the first option (FTR Task Force option 2J), PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.”

The second option (option 3G), would allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”

The other two options would attempt to reduce FTR funding deficits by lowering capability in FTR auctions rather than reducing infeasibilities.

The rejected proposal (option 2K) would have allowed PJM to “reduce capability, if possible, on facilities that have historically caused FTR underfunding in FTR auctions.”

MIC voted to table consideration of the fourth proposal (Long Term Auction Option) until the Federal Energy Regulatory Commission rules on FirstEnergy’s complaint over FTR underfunding (EL12-19-000). That proposal would have reduced “capability in Long Term FTR Auctions … from 100% to 50% of available capability after reserving ARR capability.”

All the proposals would guarantee ARR target allocations and ensure that self-scheduled FTRs are not impacted.

May 13, 2013

MIC OKs UTC Credit Requirement

The Market Implementation Committee endorsed a first-ever credit requirement for up-to-congestion transactions. The new rule, a consensus resulting from 12 Credit Subcommittee meetings since December 2011, will be brought before the Markets and Reliability Committee May 30.

Reason for Change:

UTC trading volumes have grown dramatically since 2010 but there are no credit requirements to protect market participants against defaults.

Impact: Bid screen and cleared portfolio credit requirements are based on a percentile of the difference between each member’s bid or cleared price and the two-month rolling average of real-time value per path.

Bid Screen Credit:

Prevailing flow paths: 70^th percentile
Counterflow paths: 80^th percentile

Cleared Portfolio Credit:

Prevailing flow paths: 70^th percentile
Counterflow paths: 95^th percentile

Minimum Financial Participation Requirements — the same minimum requirements as for increment and decrement transactions:

tangible net worth of at least $500,000 or
tangible assets of at least $5 million, or
posting $200,000 of financial security against which the member may not trade, plus a 10% reduction in additional collateral.

PJM analyzed the impact of the proposals against trading results for April 2011, July 2012, and Jan. 2013 to evaluate shoulder, summer and winter periods. It also looked at how they fared against the largest losses in the 10-month period between Jan. 1 and Oct. 31, 2012.

The proposal covered 95% or more of bid exposure for each scenario except for January 2013, when it covered 82%. Excess collateral ranged from a low of $1.9 million (January 2012) to a high of $8 million (July 2012). Excess collateral is concentrated in members with high bid volumes. (See chart.)

May 13, 2013December 12, 2023

Substation Sabotage Raises Concerns over NERC Alerts

NERC’s delayed and muted response to the sabotage of a Pacific Gas & Electric Co. substation April 16 has some electric industry officials concerned.

One or more gunmen breached a security fence and shot and damaged seven of eight transformers at PG&E’s Metcalf substation near San Jose about 2 a.m. The shooting prompted the California Independent System Operator to issue an alert asking residents in the region to cut their electricity use.

But the seriousness of the sabotage was slow to spread elsewhere in the electric industry. PJM didn’t receive an alert from the North American Electric Reliability Corp. until two days later, Mike Bryson, executive director of system operations, told the Operating Committee last week. The incident “was a lot worse than it appeared to be when we got the alert,” Bryson said.

Bryson said the NERC official who authored the alert believed “it went out later than he would like and didn’t get the reaction it should have.” An alert sent the following day by the SERC Reliability Corp. made clear the seriousness of the incident, Bryson said.

NERC and SERC told PJM Insider the alerts are confidential and would not be made public. The shooting occurred minutes after someone cut underground fiber optic cables a half mile from the substation, briefly knocking out phone and 911 service in the area. Law enforcement officials believe the two incidents are related.

Bryson said the industry gets more than 10 reports annually of shootings at transmission lines but most incidents are far less serious than the April 16 event.

The incident underscored a risk raised last year by Jon Wellinghoff, chairman of the Federal Energy Regulatory Commission. Wellinghoff told Bloomberg News that he feared saboteurs with guns could target transformers. Transformers, which are usually protected only by chain-link fences, are often custom built and can take 18 to 36 months to replace, Wellinghoff said.

An attacker “could get 200 yards away with a .22 rifle and take the whole thing out,” Wellinghoff said. The physical security of the grid “is an equal if not greater issue” than cybersecurity, he added.

Cyber Threat Raised

Separately, the Department of Homeland Security warned last week of a heightened risk of a cyber attack on water and electric utilities.

DHS’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT) reported “increasing hostility” against “U.S. critical infrastructure organizations,” The Washington Post reported, quoting from the alert. “Adversary intent extends beyond intellectual property theft to include the use of cyber to disrupt … control processes.”

The alert included indicators that companies can use to detect attacks and recommended countermeasures. Industry officials told the Post that the level of detail in the alert was evidence that President Obama’s February executive order — which directed the executive branch to increase information sharing with industry — was having an impact.