Page 1638 – RTO Insider

April 29, 2014

Ott: Need to Reconsider ARR Allocations

PJM will ask stakeholders to consider changing the historical allocation of Auction Revenue Rights, Executive Vice President for Markets Andy Ott told members last week.

Ott told the Members Committee webinar that the number of facilities resulting in ARR infeasibilities have increased steadily since 2012, largely due to transmission outages (see chart).

ARR Infeasibilities (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

“We’ve seen constraints come up that we haven’t seen before,” Ott said. “… PJM can build its way out of it, but it’s going to take years.”

Ott said PJM will begin discussing Stage 1A ARR allocations at the end of May or early June in hopes of making changes before the next allocation in spring 2015.

ARRs are allocated annually to firm transmission service customers, entitling them to receive a share of the revenues from the annual auction of Financial Transmission Rights. The infeasibilities, in turn, contribute to shortfalls in FTR revenues.

Total ARRs are capped based on historical generation capability and zonal base load. For the 2014/15 allocation, the zonal base load was based on the minimum daily peaks for the year beginning Oct. 22, 2012.

Infeasibilities have increased due in part to uncompensated power flow (loop flow) and additional market-to-market flowgates, but increased transmission outages is the primary factor, Ott said.

Generation retirements — which were not anticipated when the Stage 1A process was designed — also have played a role. More than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices.

The retirements require PJM to remap historical resources to an equivalent generator or create a “dummy” generator for ARR and pricing purposes. This can create additional Stage 1A infeasibilities, PJM says.

“The system seems to be able carry less and less of” the historic, “grandfathered” rights, Ott said. “We really need to take a fresh look at this. The solution is a high-level solution: Change the way things are allocated.”

In June, the Federal Energy Regulatory Commission rejected a complaint (EL13-47) by FirstEnergy Solutions Corp. that sought to bill all transmission users to make up FTR shortfalls. Since then, market participants say, the problem has only gotten worse with cumulative shortfalls exceeding $1.1 billion. (See FTR Holders Seek Shortfall Fix.)

April 29, 2014

Members to Consider Easier Sharing of Real-Time Generator Data

Members agreed to consider an easier method for transmission owners to access real-time generator data, an effort to improve situational awareness and emergency response.

The Markets and Reliability Committee last week approved a problem statement by AEP’s Dana Horton to ease TO access to real-time MW output and MVar data. The data would be used as inputs to the TOs’ state estimators.

Horton said TOs are discouraged from obtaining the information under the current process, which he said is “burdensome and time-consuming.”

The information will improve TOs’ ability to “assess the impacts of external conditions and be able to develop effective plans or implement corrective actions to maintain reliability,” the problem statement said.

Under an issue charge approved by the MRC, the Operating Committee will consider developing new access rules and determine “the appropriate uses, storage and protection of the data.”

The work is expected to take three months.

April 29, 2014

Quick Transmission Fixes Approved by FERC

The Federal Energy Regulatory Commission approved PJM’s plan for selecting transmission projects that can easily and cheaply resolve constraints in Locational Delivery Areas (LDAs).

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 (See Quick Fix Transmission Upgrades Ok’d).

Upgrades that increase the ratio to more than 1.15 would be added to the Regional Transmission Expansion Plan (RTEP) if they cost less than $5 million and can be completed prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.

Such projects are unlikely to be common. PJM told the commission that it had identified no circumstances that would justify such projects in the last three years.

FERC approved the proposal over the objections of Utility Risk Management Corp. (URMC) and NextEra (ER14-456).

URMC said the proposal would hurt merchant transmission developers by allowing PJM to supplant merchant upgrades. NextEra argued that the proposal would disguise price signals and reduce transparency and innovation.

FERC said the narrow scope of these quick-fix projects was enough to alleviate these concerns and ensure consistency with Order 1000.

FERC endorsed PJM’s contention that, in relieving minor constraints that are unlikely to return in future years, it prevent misleading price signals.

As a condition of the approval, FERC required that PJM post an annual list of quick-fix proposals and recommended that the RTO and its stakeholders devise operational procedures in case such a project cannot be completed by June 1 of the relevant delivery year.

April 29, 2014

NERC Draft Rules for Physical Security

Below is a summary of the six requirements included in the draft reliability standard for physical security of the grid.

Transmission owners should perform a risk assessment of transmission stations and substations to determine which ones, if disabled or damaged, could result in “widespread instability, uncontrolled separation, or cascading within an Interconnection.” Assessments should be repeated every 30 months if such a vulnerability is identified and every 60 months if not.
Transmission owners should have an unaffiliated third party verify the risk assessment. Such third parties can be a registered planning coordinator, transmission planner or reliability coordinator, or “an entity that has transmission planning or analysis experience.”
Transmission owners with stations or substations identified under Requirements 1 or 2 that are not under their direct control must notify the operator of a primary control center that does control the stations of their critical status.
Operators of stations, substations or primary control centers identified as critical under Requirements 1 through 3 must conduct an evaluation of potential threats and vulnerabilities of those facilities. The evaluation must consider the characteristics of the facilities and any prior history or attack of similar facilities, and incorporate any threat intelligence provided by NERC, law enforcement or other authorities.
Operators of facilities identified during the threat analyses must develop within 120 days a physical security plan for the facilities, incorporating security measures, law enforcement contact information, a timeline for implementing the security plan and ways to conduct ongoing threat evaluations.
Transmission owners and operators must have a third party evaluate the threat analysis in Requirement 4 and the security plan developed in Requirement 5. The evaluation must be completed within 90 days of the security plan completion, and any changes suggested by the third party must be performed within 60 days.

April 29, 2014

Generic Transition Mechanism for Capacity Changes Dropped

PJM last week withdrew a proposal to develop a generic transition mechanism to hold capacity providers harmless for future rule changes.

The RTO’s proposed problem statement and issue charge was withdrawn from the agenda of the Markets and Reliability Committee without explanation. There was no indication why the issue was withdrawn or whether it will be added to a future agenda.

Members had greeted the proposal coolly when PJM announced it at the MRC meeting in March. (See PJM Proposes Generic Transition Rule for Capacity Market Changes.)

The proposal was prompted by the transition mechanism approved by members to protect generators whose installed capacity ratings are reduced by seasonal verification tests.

April 29, 2014

MRC/MC Briefs

The Markets and Reliability Committee approved the following Tariff and Operating Agreement revisions last week:

Clarifications to the Tariff and OA giving generators providing Tier 2 synchronized resources the ability to aggregate these resources in order to avoid retroactive penalties for failure to respond appropriately when called. New language will also be added to Manual 11: Energy & Ancillary Services and Manual 28: Operating Agreement Accounting. Aggregation will not be used in calculating Tier 2 Synchronized Reserve credits; each resource will continue to be credited independently.
Revisions to the Tariff to reflect current PJM practices regarding credit available for virtual transactions. PJM instituted the policy as the result of a FERC Order in 2004 but failed to make accompanying changes to the Tariff. These revisions also correct for changes in credit policy since 2004 (e.g., working credit limit discount is now 25%, not 15%).
Clarifications to the Tariff and OA on regulation shoulder hour lost opportunity costs (LOCs). As a result of a review, PJM discovered that the documents didn’t adequately describe the calculation of the deviation between the regulation set point and the expected output of each regulation resource.
Changes to the Tariff and OA reflecting PJM’s change in mailing address to: PJM Interconnection, L.L.C. 2750 Monroe Blvd., Audubon, PA 19403.

The MRC also approved the following manual changes:

Manual 13: Emergency Operations — The changes will allow declaration of Cold Weather and Hot Weather alerts several days in advance instead of the day before.
Manual 18: PJM Capacity Market — Conforming the manual to recent FERC orders, including seasonal verification testing and Capacity Import Limits effective with the 2017/2018 delivery year. (See related story, FERC Clears Capacity Import Limits.)

The Members Committee endorsed the following consent agenda items last week:

Revisions to PJM’s Tariff and Operating Agreement to clarify agreements and transactions to which PJM Settlement, Inc. is not a party.
Operating Agreement and Tariff revisions to effectuate the eSuite application name changes (i.e., changing eSchedules and EES to InSchedule and ExSchedule, respectively). Proposed improvements to eSuite applications are slated to continue through 2015.

April 29, 2014

Federal Briefs

NRC Gives Exelon’s Limerick Extension for Fukushima Fix

The Nuclear Regulatory Commission granted Exelon’s request for an additional two years to make upgrades to the reactor buildings at its Limerick Nuclear Generating Station. The NRC in 2012 ordered Exelon to take steps to prevent hydrogen buildups similar to what occurred during the Fukushima disaster in Japan in 2011.

The Limerick reactors share some design similarities with the Japanese units. The NRC ordered installation of a “hardened wetwell vent” system to extract combustible gas from building up and possibly exploding. “The installation of such vents is one of our post-Fukushima requirements,” said NRC spokesman Neil Sheehan. Exelon will have until the end of a refueling outage in spring 2018 to complete the work at Unit 1 and until the end of a refueling outage in spring 2017 to complete the work at Unit 2, the NRC said.

More: The Times Herald

NRC: Higher Cooling Water Temps OK for Millstone

The higher water temperatures of Long Island Sound aren’t too high for the Millstone nuclear plant to use, according to the Nuclear Regulatory Commission. The NRC granted Dominion’s Millstone Unit 2 a license amendment to allow operation if its cooling water, drawn from the Sound, rose in temperature to 80 degrees. Unit 2 was forced offline for 12 days in 2012 when Sound water temperatures rose above the then 75-degree limit. The NRC is considering a similar amendment request for Millstone Unit 3.

“We’ve seen a long-term trend over the last 40 years of Long Island Sound temperatures steadily increasing,” Millstone Spokesman Ken Holt said. In 2012, the average temperature in the Sound near the Unit 2 intake pipe was about 77 degrees, he said. The company believes the five-degree margin will be sufficient to allow it to continue operations without costly unplanned shutdowns, he said. “We think we can stay well within the limit,” he said.

More: Nuclear Street

FERC Approves NG Pipeline To Southeast Markets

Additional natural gas pipeline capacity is coming to the Southeast with the Federal Regulatory Commission’s approval of an application for the construction of Transco’s Mobile Bay South III Expansion project. Williams Partners LLP said the project is expected to be completed by spring 2015.

More: Market Watch

April 29, 2014

Members Split Over Change in Reserve Procedures

Stakeholders split last week over a PJM proposal to change how the RTO captures the cost of deploying additional reserves during extreme weather.

PJM’s Lisa Morelli presented a first read of the proposal — which is intended to capture operators’ reliability actions in Locational Marginal Prices rather than uplift — at last week’s Markets and Reliability Committee meeting.

Stakeholders representing generation expressed support for the proposal while those representing load said they feared it could lead to unduly conservative operations and higher overall costs.

It would increase day-ahead and real-time reserve requirements when hot- or cold-weather alerts or max emergency generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.

“On a day like this there’s a ton of uncertainty,” said PJM Executive Vice President for Operations Mike Kormos, citing generator performance and forecasts for weather, load and interchange. “We can’t roll the dice and hope things go away.”

The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion (MAD) synchronized reserve requirement of 1,300 MW.

The increases would be implemented only if operators believe the additional resources can be scheduled without causing operational problems. The real-time adder would be reduced to 50% of the MAD synchronized reserve requirement or lower if the higher amount becomes problematic.

The increased reserves would be reflected in market clearing engines, ensuring that the costs go into LMPs and not uplift.

It is the first proposal to result from a problem statement approved by members in November. (See MIC to Consider Real-Time Pricing Changes.)

“This has been a long time coming,” said PJM Vice President for Market Operations Stu Bresler. “… This is very important to us.” Bresler said the best solution — changing reserves in real time — would be more complex and less transparent.

Ed Tatum, of Old Dominion Electric Cooperative, called the proposal “reactionary.”

“Sixteen years and 24 days into this LMP business … we keep on doing non-market things,” he said. “… We are moving further and further away from the concept of a market. We’re taking it more into an administrative construct.”

David “Scarp” Scarpignato, of Direct Energy, said the proposal could lead to overly conservative operations and increase costs to load. PJM already carries reserves equal to 150% of the largest single contingency, while other regions use only 100%, he said.

“We have very big problems with this,” he said. “PJM already has more conservative synchronized and primary reserve targets than other areas.”

Jason Barker, of Exelon, said Scarp had mischaracterized the PJM proposal. Last July, Barker said, PJM dispatched demand response at $1,800/MWh and Exelon’s peaking generators at “hundreds of dollars” at a time when LMPs were only about $60/MWh. “All of these [costs] were paid through uplift,” he said.

PJM, which wants to implement the changes in time for this summer, will bring the proposal to votes at the MRC and Market Implementation Committee next month. It was developed during meetings of an MIC subgroup on Energy/Reserve Pricing & Interchange Volatility.

At a meeting of the subgroup yesterday, PJM officials said that logistical problems prevented them from producing simulations to gauge the impact of the changes.

April 29, 2014

Effort to Lift Offer Cap Advances After Debate

By David Jwanier and Rich Heidorn Jr.

Members agreed to consider changing the $1,000/MWh offer cap last week following a debate over whether unusually high gas and electric prices during January were a fluke or a sign of winters to come.

The Markets and Reliability Committee approved PJM’s proposed problem statement, which says stakeholders should consider lifting the cap because this winter’s extreme conditions had for the first time put the limit at odds with rules requiring capacity resources to offer their output into the day-ahead energy market. The accompanying issue charge was also approved.

The initiative passed with 27 abstentions and 11 “no” votes. Susan Bruce cast 10 of the no votes and four abstentions on behalf of the PJM Industrial Customer Coalition. Bruce said the coalition had never voted against a problem statement before.

“We are perhaps rushing to judgment,” she said, noting that PJM had not released all of the results of its analysis of the winter. “… As I sit here today, I don’t know what I don’t know.”

The measures were amended to include an Oct. 31 target date for completion, in order to facilitate a Federal Energy Regulatory Commission order by the end of the year. Also added was the Market Monitor’s request to clarify the offer cap’s application to incremental, startup and no-load costs.

FERC Orders

On Jan. 24, FERC granted the RTO’s request for a waiver allowing make-whole payments for generators with operating costs above the $1,000 cap. PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked to $140/mmBtu.

The January order allowed PJM to fund the make-whole payments through uplift charges. On Feb. 11, FERC granted a second waiver eliminating the cap through March 31, allowing high-cost generators to set Locational Marginal Prices.

FERC lifted the cap over the objections of consumer advocates, state regulators and others, who said allowing the RTO’s most inefficient generators to set clearing prices would provide a windfall to the vast majority of generators with costs well below $1,000. (See Stakeholders Preview Offer-Cap Debate.)

The proposal to consider changing the cap appeared to have the support of generators. Jason Cox, of Dynegy, praised PJM for being “proactive.”

But most of the comments came from those representing load.

Will High Prices Repeat?

“It’s not exactly clear to us that this sort of issue is going to happen over and over again,” said Raghu Sudhakara, of Rockland Electric Co.

“If the purpose is to pull the wool over the eyes of people … and finagle something through without us understanding it, I have a problem with that,” said Gloria Godson, of Pepco Holdings Inc., who insisted the stakeholder process include an examination of high gas prices. PHI abstained on the vote.

Carl Johnson, who said he considered voting no, ultimately cast 15 abstentions on behalf of the PJM Public Power Coalition. “It’s seems [PJM] is taking everything in the FERC order and trying to put it into the Tariff,” he said. “We don’t think having to get a waiver is always a bad thing.”

He also said that the actual impact of the FERC waivers — which yielded about $9,000 in make-whole payments to generators whose production costs went above the offer cap — might not warrant months of prickly debate.

Walter Hall, of the Maryland Public Service Commission, said he was concerned that PJM was “somewhat telegraphing the result you are expecting.”

Not Hypothetical

Bob O’Connell, of J.P. Morgan Ventures Energy Corp., warned members that a no vote would not end efforts to lift the cap.

An MRC rejection “doesn’t prevent members from creating a user group and rushing this through an alternative stakeholder process that may disenfranchise certain members,” O’Connell said. “I suspect there are [at least] five members sitting at this table today that would want to move this forward.”

Steve Lieberman, of Old Dominion Electric Cooperative, said ODEC would have voted no but feared rejection of the measure would lead PJM to make a unilateral section 205 filing with FERC to lift the cap.

Executive Vice President for Markets Andy Ott indicated Lieberman’s concern was well founded, saying PJM needs to act.

“This is not theoretical; this is an issue where we had [generator] costs over $1,000,” Ott said. “No matter what happens at FERC [with relation to future gas prices], we could have gas prices where the $1,000 offer cap doesn’t work. We feel it needs to be addressed by next winter.”

ODEC’s Ed Tatum lamented that efforts to lift the offer cap were the latest of recent PJM initiatives — following changes to limit imports and demand response in the capacity market — that could increase prices for load.

In a discussion over which stakeholder group should address the issue, Tatum argued in favor of the MRC, noting that it involves reliability. He expressed reservations about the Capacity Senior Task Force, which he said had not been a friendly venue for load.

“This RPM [Reliability Pricing Model] stuff has not worked out well for the left side of the room,” he said, referring to where representatives of cooperatives, industrial customers and public power were seated. “We’re not getting a lot of love.”

The committee voted to assign the issue to a new task force reporting to the MRC.

April 29, 2014

Grid Security Rules Win NERC Stakeholder OK Despite Criticism

By Ted Caddell

Stakeholders last week approved draft regulations to protect the electric grid from physical threats even as many criticized the rules as rushed and poorly defined.

The draft regulations, drawn up by a North American Electric Reliability Corp. working group of 11, are now being considered by the NERC board. NERC must submit proposed regulations to the Federal Energy Regulatory Commission in June. FERC has scheduled a technical conference June 10 to discuss “policy issues related to the reliability of the Bulk-Power System” at which the NERC filing is likely to be a centerpiece.

The plan won 82% approval in polling of NERC members last week. Among PJM members, Duke Energy, Exelon, FirstEnergy and Dominion all said they support the draft standards, while AEP voted no.

“Are we being overly reactive?” a stakeholder from AEP asked, according to a summary of feedback to the draft regulations that was compiled by NERC. “Poorly executed, these standards could carry astronomical … costs.”

“We need to spend time to get this right and not rush something through,” a stakeholder from the Nebraska Public Power District wrote. “This expedited standard development has the potential to derail our entire NERC standard development process.”

The regulations are in response to concerns resulting from the sabotage of a PG&E Corp. substation last year. Under pressure from Congress, FERC on March 7 ordered NERC to develop standards to address physical attacks within 90 days. (See FERC Orders Rules on Grid’s Physical Security.)

Critical Substations

Dominion substation security - simulated view (Source: Dominion Resources) — Dominion Virginia Power plans to spend as much as $500 million to upgrade security at its substations, including the installation of anti-climb fences, as in the simulation above. (Source: Dominion)

The NERC draft calls for utilities to provide protection for “critical” substations, but it allows each utility to determine what substations are critical. The rules call for third-party review of critical facilities but would allow utilities to act as each other’s third party. (See related story, NERC Draft Rules for Physical Security.)

The draft rules don’t require hardening critical substation sites with blast barriers or other defenses, as some critics have suggested.

Several stakeholders were critical of the short time FERC gave NERC to comply. Others said the standards should apply not just to transmission owners and operators but also to transmission planners, reliability coordinators and generation owners and operators.

Still others said the standards were too loosely defined. “As described, the objective of protecting critical facilities of the [Bulk Electric System] is stated too broadly and it is not apparent what countermeasures would be considered adequate or sufficient,” wrote the Bonneville Power Administration.

Brightline Criteria

Colorado Springs Utilities recommended a “brightline criteria” for the facilities covered by the standards, “based on either the Transmission Planning Standard TPL-004a [System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements] or identification of the largest single contingency for each interconnection. If we need a single number, [include] only facilities that provide or control over 3,000 MW of generation or transmission operating at 300 kV and above.”

AEP also questioned the proposed definition of critical facilities. “FERC and NERC have implied that the number of critical facilities identified in this process will be relatively small — fewer than 100 of the 55,000 transmission stations dispersed throughout the country. However, for previous `critical asset’ determinations requested by NERC, AEP has already identified almost that many just on our own system. This would indicate we are starting over with the definition of critical facilities, which is counter-intuitive if not counter-productive.”

One member, from the Southwest Power Pool, noted that NERC’s existing definition of Critical Assets is scheduled to be retired in 2016. “How does one then determine the list of ‘critical’ facilities if that definition no longer exists?” that member said.

Several stakeholders referred to a 2013 FERC power flow analysis on the 30 most critical substations nationwide. The analysis, which was leaked to The Wall Street Journal in March, reportedly concluded that the Eastern and Western Interconnections and ERCOT could be shut down for weeks or months if only nine of the substations were sabotaged.

“If a list of the most critical substations exists, why are we trying to develop a new process to determine the list?” a stakeholder from the Nebraska Public Power District asked. “I feel we have been blindfolded and put into a room and told to hit a small target with a dart and we don’t even know which wall or direction to throw the dart.”

Cost Concerns

AEP echoed concerns about the cost of the rules. The new standards, AEP wrote, “could result in massive changes, bringing excessive additional costs with no guarantee of desired outcomes … While we need to make whatever investment is necessary to adequately protect the grid, we also need to be responsible stewards of the grid and our ratepayers’ pocket books.”

In response to criticism of the draft rules cited in a Journal article April 17, NERC issued a statement defending the regulations and the process used to develop them.

“Standards are one piece of this complex, dynamic endeavor of providing a comprehensive approach to reliability,” NERC said. “NERC also has various other tools to fulfill this mission, including guidelines, training, assessments and alerts. This multi-pronged approach has resulted in a secure and reliable bulk power system for North America.”