PJM stakeholders deadlocked for the third time Thursday on changes to the $1,000/MWh energy offer cap, leaving it to the Board of Managers to decide whether to seek Federal Energy Regulatory Commission approval of any changes.
Old Dominion Electric Cooperative’s Ed Tatum withdrew a compromise proposal to raise the cost-based offer cap to $1,800 in the face of opposition from load representatives following a lively Members Committee debate.
Members’ inability to reach consensus means the board would have to make a unilateral Section 206 filing to win FERC approval for any change.
PJM CEO Terry Boston expressed disappointment. “I was hopelessly optimistic that we could get to a [Section] 205 filing,” he said.
“There will be other times” when the cap is exceeded, Boston said. “I really don’t like the idea that we hold in abeyance until we have an emergency. … We don’t want to be in the position that we have to run to FERC and ask for a 24-hour decision.”
In January, FERC granted the RTO’s request for a waiver, allowing make-whole payments for generators with operating costs exceeding $1,000. PJM said the waiver was necessary to allow some gas-fired generators to cover costs above the cap, as spot gas prices spiked as high as $140/MMBtu.
Earlier this month, Calpine Energy Services requested that FERC allow it to recover about $3.3 million it said it spent on expensive gas for two generating units at PJM’s direction and was unable to burn when the RTO cancelled their plants’ dispatches (ER15-376). Calpine’s claim is similar to those filed earlier by Duke Energy, which is seeking $9.8 million for “stranded” gas (EL14-45) and Old Dominion, which is seeking $2.7 million (ER14-2242). (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
In April, PJM members agreed to form a task force to consider changing the cap. The group was unable to reach consensus after nine meetings and has since disbanded.
The proposal presented Thursday resulted from negotiations led by Tatum and Mike Borgatti, of Gabel Associates, who represented generators. It would have allowed cost-based offers between $1,000/MWh and $1,800/MWh to set LMPs. Generation costs above that cap would be recovered through uplift.
Maximum market-based offers would be capped at $1,000 or the cost-based offer.
The majority of members who spoke Thursday strongly opposed the changes. Even those who encouraged the proposal’s passage conceded they supported it only as a better alternative to losing control over the matter to FERC. A 205 filing also would show a cohesiveness among the group, they said.
“This is not a proposal that Old Dominion would have come up with,” Tatum said in making his presentation. But, he said, “I think we’ve gone as far as we can go with this.”
Susan Bruce of the PJM Industrial Customer Coalition said her group opposed the proposal. “There is a lack of evidence of a systemic problem,” she said.
Market Monitor Joe Bowring said fewer than 25 offers breached $1,000 in January. While some of the proposed offers were in the $1,700/MWh range, Bowring said there were no legitimate offers greater than $1,400/ MWh.
Walter Hall, representing the Maryland Public Service Commission, said Tatum’s proposal represented not a “compromise” but a concession to generators’ attempts to profiteer.
“We fear this is a profit-making opportunity [for generators], not a cost-recovery opportunity,” he said. “Why should everyone profit from something of that nature?”
Jim Jablonski of the Public Power Association of New Jersey referred to the Market Monitor’s March 26 report to FERC, which concluded that only $9,118 of $583,774 in additional compensation sought by seven units in three PJM control zones when gas prices peaked in January was legitimate.
And, he said, “that was at the worst of times. I certainly don’t see the justification for above $1,000.”
Carl Johnson, representing the PJM Public Power Coalition, said approving the Tatum-Borgatti proposal would have been preferable to “throwing a jump ball at FERC.”
“It’s not perfect, but it is way better than that outcome,” he said.
J.P. Morgan Ventures Energy’s Bob O’Connell, who had debated Tatum over the issue at the October MC meeting, said he came into Thursday’s forum opposed to the newest proposal. (See Load, Supply Trade Blame over Offer Cap Impasse.)
But, he said, “the deal you see on the table is a deal that can get done. This is not about getting what you want — it’s about not getting what you don’t want.”
State-by-state compliance with the Environmental Protection Agency’s (EPA’s) proposed carbon emission rule would be almost 30% more expensive than a regional approach, according to preliminary results of PJM analyses.
The analyses included eight scenarios requested by the Organization of PJM States (OPSI) and seven proposed by PJM.
One analysis (PJM scenario 4), which included existing fossil resources and planned resources with interconnection service agreements (ISAs) and facility study agreements (FSAs), estimated a 2020 carbon price of $11/ton under state compliance, compared with $2/ton under a regional approach.
PJM determined the CO2 emissions prices based on the price differential needed to ensure the RTO’s economic dispatch displaced enough high-emitting generators with lower-emitting generation to reach the emissions targets.
The regional approach sets a single carbon price for all fossil fuel generators in PJM. Under state compliance, each state would have a different carbon price. Indiana and West Virginia would face the highest carbon prices under a state-by-state approach, with prices exceeding $14/ton, while it would cost Maryland and Virginia only about $5/ton.
Under a regional plan, “states have the ability to trade reductions among each other to achieve lower costs of compliance,” explained Chief Economist Paul Sotkiewicz. Sotkiewicz and PJM engineer Muhsin Abdur-Rahman presented the preliminary results of the analyses at the Members Committee webinar last week.
Total compliance costs would near $45 billion in 2020 under the state approach, versus $35 billion using regional compliance.
Mass-to-Rate Conversion
PJM initially did the analyses based on the implied mass-to-rate conversion in the EPA’s June 2 proposed rule. It redid the calculations based on revised guidance the agency provided Nov. 6, which sets a declining mass target over the interim compliance period (2020-2029) and does not credit new renewables and incremental energy efficiency.
Under the revised conversion, most of the scenarios estimated carbon prices of about $5 to $10 per ton in 2020, rising to $20 to $30 per ton in 2029.
One scenario (PJM #8) saw carbon prices starting at about $40/ton in 2020 and rising to almost $60/ton by 2029. The scenario adjusted planned natural gas capacity based on historic commercial probabilities (greater than 70% for projects with ISAs, greater than 50% for those with FSAs), reduced new combined-cycle capacity to not exceed the installed reserve margin target and assumed a 50% increase in gas prices.
The analyses found that a rate-based approach would result in lower LMPs than a mass-based measurement, meaning generators will need to collect more in capacity revenues. There were little or no increases in LMPs for many scenarios.
The Federal Energy Regulatory Commission won’t wait for PJM stakeholders to develop rules to prevent fleet owners from receiving reactive power payments for retired generators.
FERC last week ordered PJM to revise its Tariff to address the issue within 30 days or show cause why it should not be required to do so (EL15-15).
A frustrated Vince Duane, PJM general counsel, told members Thursday that FERC’s action appeared to be prompted by the “fairly contentious” process that preceded the Markets and Reliability Committee’s approval last month of a problem statement to address the issue. “They’re not prepared to wait for this group to go through those issues,” he said.
The problem statement included language suggested by Public Service Enterprise Group, which complained that the original statement assumed that fleet owners are being overpaid if they failed to file revised cost schedules with FERC after plant retirements. PJM officials said they did not know how much ratepayers might be overpaying. (See PJM Members Seek Fix for Payments to Retired Plants.)
Duane said it was not certain whether PJM will file proposed Tariff revisions within 30 days or seek more time. But he added that the issue was “not going to be addressed through the stakeholder community — at least not exclusively.”
The commission said it was acting because PJM’s Tariff lacks explicit provisions to end reactive power payments for generators that are retired or sold.
FERC said it also had asked its Office of Enforcement “for further examination and inquiry as may be appropriate” for owners that may have received payments for retired units. Any refunds resulting from the order will be dated from when the Nov. 20 order is published in the Federal Register.
The commission cited a filing in which FirstEnergy “asserted that the commission and the PJM Tariff are silent about updates to reactive service revenue requirements when units are deactivated or transferred out of a fleet, but that ‘parties may agree among themselves regarding the allocation of revenues with respect to changes in ownership.’”
FERC also cited the Sept. 24 request of Sunbury Generation to terminate the reactive service tariff for its retired 436-MW coal-fired facility in Snyder County, Pa. FERC noted that Sunbury had closed the plant more than two months before its filing. PJM told the commission it was still paying for reactive power on the retired plants.
The commission Thursday approved Sunbury’s cancellation request and required it to refund any payments received for the period after the plant deactivation (ER14-2936).
The Federal Energy Regulatory Commission yesterday approved Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., dismissing concerns from PJM stakeholders of increased market power, adverse effects on competition and increased rates.
With approvals from FERC and the Virginia State Corporation Commission in hand, Exelon still must win approval from regulators in D.C., Maryland, Delaware and New Jersey. “We did consider all of the issues that came in with respect to … the PJM stakeholder process. We felt it met the tests of [the Federal Power Act] with the effects on rates, the effects on regulation and the effects on competition,” FERC Chairman Cheryl LaFleur said after the commission’s monthly meeting yesterday.
FERC did not place any conditions on its approval of the merger, such as requiring that Exelon stay in PJM, as requested by the Independent Market Monitor, or that the companies not be allowed to recover any merger-related costs through rates, as the Delaware Public Service Commission requested.
FERC noted that Exelon committed to staying in PJM for 10 years after its 2012 merger with Constellation Energy Group as a condition of the Maryland Public Service Commission’s approval of that deal. The commission said it would address market power concerns if and when Exelon left PJM after 2022.
FERC also noted that the companies have committed to hold transmission customers harmless for any merger-related costs for five years after the merger is completed. After that, FERC said, the companies must file a request to recover these costs through rates, at which point “the commission will determine whether applicants have demonstrated offsetting savings to customers served under commission jurisdictional rate schedules such that recovery of merger-related costs would be appropriate.”
In its order approving the deal (EC14-96), FERC largely echoed the two companies’ rebuttals of protests from the Monitor, the Delaware PSC, Southern Maryland Electric Cooperative and other PJM stakeholders. (See Exelon, Pepco Reject Merger Objections.)
In its response to these rebuttals, the Market Monitor had argued in early September that FERC should require from the companies more information and analysis showing how the merger would not adversely affect competition in PJM’s capacity market through their combined demand response resources. It also said the companies did not address vertical market power concerns in their analyses.
FERC disagreed, however, saying that the information provided by the companies was sufficient. It said Pepco’s additional 700 MW of demand resources would be too small to affect competition in PJM’s capacity market, noting that Exelon already controls 26,000 MW of generation, DR and energy efficiency. The commission also pointed to a Sept. 19 filing from the companies in response to the Monitor’s claims, which the commission said “provided additional information regarding the limited ability of Pepco Holdings’ demand response resources to participate in the PJM energy market.”
“While we recognize that the combination of Exelon’s and Pepco Holdings’ capacity market-based demand response resources increases the market share owned by [the companies], we believe that the recent improvements to the dispatch and pricing of capacity market-based demand response resources will encourage competition among providers and lead to more efficient dispatch going forward,” FERC said.
FERC also agreed with the companies’ contention that the deal would not affect vertical competition, as Pepco owns only 17 MW of generation, and the only Pepco utility joining Exelon that distributes natural gas is Delmarva Power & Light, which does not supply any generation facility.
Both the D.C. Office of the People’s Counsel and the Delaware PSC had raised concerns about the potential adverse effects the merger would have on the PJM stakeholder process. The OPC worried that the new company’s subsidiaries would give it an increased influence on stakeholder decisions, while the PSC was concerned that PJM would lose a consistent consumer advocate in discussions (See Pepco to Lose its PJM Voice; Consumers Lose Frequent Ally.)
FERC disagreed, again echoing Exelon and Pepco. “While the commission is aware that Exelon will be a member with more assets after the merger, there is nothing in the record of this proceeding to indicate Exelon will have excessive influence over the stakeholder process or the independence of PJM,” the commission said. It noted that the new company would only have a single vote as a transmission owner in PJM’s senior committees.
The commission did not discuss the merger at its meeting. LaFleur said this was because the commissioners felt that other items on the agenda such asthe North American Electric Reliability Corp. standards and the 2014 Report on Enforcementwould benefit from discussion, while its decision on the merger was sufficiently explained in the order. She added that due to the packed schedule, she feared that the meeting would run late; it lasted an hour and a half after four discussions.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:40)
Members will be asked to endorse the following manual changes:
Manual 3: Transmission Operations — Updates names; clarifies timing for load shed for post-contingency voltage collapse; updates several sections; adds procedures.
Manual 13: Emergency Operations — Clarifies actions taken prior to emergency procedures; adds Min Gen Advisory procedure; updates Cold/Hot Weather Alerts; revises geomagnetic disturbance procedure; condenses and consolidates Attachment A.
Manual 11: Energy & Ancillary Services Market Operations — The changes will allow PJM to relieve demand response resources of their regulation and synchronized reserve responsibilities during Load Management Events. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.
Manual 14B: PJM Regional Transmission Planning Process — Changes made in accordance with North American Electric Reliability Corp. standards PRC-023-3 (Transmission Relay Loadability) and TPL-001-4.
Manual 28: Operating Agreement Accounting — Revised to include Load Reconciliation data in the settlement of emergency load response and emergency energy billing.
Manual 29: Billing — Changes method of reimbursing treatment of underpayments of miscellaneous items and special adjustments to avoid cost shifts.
Manual 13: Emergency Operations — Updates the 2015 day-ahead scheduling reserve requirement to 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%).
The MRC will be asked again to approve PJM’s proposal to limit interchange during emergency conditions. An MRC vote last month on the issue fell just short of a two-thirds approval. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)
The proposal to be voted on includes language to address hoarding and manipulation of interchange “room,” in order to address concerns raised by the Market Monitor.
PJM officials said they intended to recommend operating under the new rules, which require only a manual change, with or without the two-thirds mandate. The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.
4. GAS UNIT COMMITMENT (10:00-10:20)
Beginning in January, gas generators will be able to change their offers to reflect fluctuating fuel prices, under a proposal being brought to the MRC. The proposal would allow generators to lock in their fuel prices three hours in advance of the operating hour.
The option would be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released. (See PJM Members Approve Intraday Updates to Generator Cost Schedules.)
5. SELLER CREDIT (10:20-10:40)
Members will be asked to endorse PJM’s plan to eliminate the “seller credit” provision from its credit policy, which RTO officials said was unnecessary. The provision was enacted when PJM still used monthly billing, to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit, PJM said.
6. RESIDENTIAL DEMAND RESPONSE: PARTICIPATION IN THE PJM SYNCHRONIZED RESERVE MARKET & MEASUREMENT AND VERIFICATION FOR ENERGY AND LOAD MANAGEMENT (10:40-10:55)
The committee will be asked to endorse a proposal that PJM begin measuring the demand response performance of some residential customers through sampling of interval-meter data. (See Operating Committee Briefs, Nov.11.)
7. DEFINITIONS IN GOVERNING DOCUMENTS (10:55-11:10)
Members will vote on non-substantive revisions to definitions in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35: Definitions and Acronyms. The changes are intended to align the documents.
Members Committee
2. CONSENT AGENDA (1:20-1:25)
The committee will be asked to approve the following:
Operating Agreement (OA) revisions to ease Transmission Owners’ access to generator data feeds.
Updated Installed Reserve Margins and related metrics for 2015/16 through 2018/19 delivery years.
Approve/endorse proposed non-substantive revisions to definitions in the Tariff and OA, aimed at providing alignment of definitions between the documents.
3. ELECTIONS (1:25-1:30)
The committee will elect members to the 2015 Finance Committee and sector whips, and the Members Committee vice chair.
PJM has identified 20 candidates for “market efficiency” projects in the competitive window that opened Oct. 30.
The candidates, which were presented to the Transmission Expansion Advisory Committee this morning, were based on annual simulated congestion frequency of at least 25 hours in the 2019 and 2022 study years.
They include 17 lower voltage facilities with a minimum of $1 million congestion in the study years and two regional facilities — AP SOUTH Interface l/o Black Oak-Bedington and AEP-DOM Interface l/o Black Oak-Bedington — with at least $10 million in congestion.
PJM said facilities below the thresholds were not likely to pass the minimum 1.25:1 benefit-cost criteria.
The RTO will also accept proposals to address capacity import limitations and thermal overloads on the Roseland-Cedar Grove-Clifton 230-kV corridor.
Artificial Island Update
PJM staff plans to announce its revised recommendation on the Artificial Island stability project at the Jan. 8 TEAC meeting, prior to a February recommendation to the Board of Managers. PJM will allow the four finalists to make presentations at a special TEAC meeting to be scheduled the week of Dec. 8. (See Two of 4 Artificial Island Finalists Offer Cost Caps.)
PJM and NYISO last week successfully launched Coordinated Transaction Scheduling (CTS), an effort to reduce uneconomic interchange flows. “So far it’s going well,” PJM’s Stan Williams told the Market Implementation Committee last week.
The new product allows traders to submit bids that clear only when the price difference between New York and PJM exceeds a threshold set by the bidder.
CTS began Nov. 4, a day after PJM began implementing credit checks for all exports. Williams said 57 CTS transactions were consummated Nov. 4 and the volume has grown since. PJM said as much as one-third of exports from PJM to New York occur when PJM prices are higher. (See NYISO Scheduling Product Wins FERC OK.)
PJM will continue discussions on a similar product with MISO at today’s Joint Stakeholder meeting at MISO headquarters.
PJM, Members to Discuss Earlier Notice on Pricing Interfaces
Stakeholders agreed Thursday to consider whether PJM should be required to provide more notice to the market before introducing “closed loop” interfaces to capture operator actions in pricing.
The MIC approved a problem statement by DC Energy’s Bruce Bleiweis to consider if such pricing interfaces should be barred from taking effect until they are announced before the monthly Financial Transmission Rights or Balance of Planning Period FTR auction.
In the last year, PJM has created closed loop interfaces in at least four locations so that operator actions — such as sub-zonal dispatch of demand response — are captured in LMPs rather than uplift. PJM said it must use the interfaces to set prices because its modeling software can only set prices for thermal constraints, not voltage problems.
Bleiweis’ initiative follows objections he raised at the August MIC, in which he said PJM’s efforts to reduce uplift were exacerbating FTR underfunding. (See PJM: Can’t Delay Interface Postings for FTR Auctions.)
On Thursday, PJM’s Joe Ciabattoni said that PJM will attempt to provide one-day notice for subzonal DR but that such notice may not be available for pricing interfaces needed for other reasons. “The potential exists for [pricing interfaces] at all of the 6,000 active constraints,” he said.
Bleiweis said that he wants PJM to formalize its notification procedures in its manuals.
Path Set for Query on Synch Reserve Payments
The MIC agreed to host the initial education session on the Independent Market Monitor’s effort to change compensation for Tier 1 synchronized reserves. The MIC endorsed an issue charge that scheduled the first session as part of the regular MIC meeting and defers a decision on whether to create a subgroup to complete the inquiry.
The MIC approved Market Monitor Joe Bowring’s problem statement last month.
Tier 1 synchronized reserves — all on‐line resources following economic dispatch and able to ramp up at PJM’s request — are paid the Tier 2 synchronized reserve market clearing price whenever the non-synchronized reserve price is more than zero. Bowring said it’s wasteful to pay Tier 1 the same price as Tier 2, because only Tier 2 are subject to penalties for non-performance.
PJM officials said they will likely oppose Bowring’s proposed change, which they said could upset the balance of the RTO’s scarcity pricing scheme. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
Initiative on Replacement Capacity Transactions Set for January
Members approved an issue charge deferring until January the first meeting to discuss Citigroup Energy’s request to change rules regarding the timing for recording replacement capacity transactions. Citigroup’s Barry Trayers said the current procedures, which don’t allow recording of the transactions until after the third incremental auction, create administrative headaches.
PJM will relieve DR resources of their regulation and synchronized reserve responsibilities during Load Management Events under a change to Manual 11 endorsed by the MIC. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.
Monthly Seller Credit Eliminated
Members endorsed PJM’s plan to eliminate the “seller credit” provision from its credit policy, which RTO officials said was unnecessary. The provision was begun under monthly billing to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, PJM said the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit.
AEP Asks to Split Zone into 4 Settlement Areas
The proposed change does not affect Wheeling Power or Kingsport Power. (Click to zoom.)
American Electric Power asked PJM to split its zone into four energy settlement areas, a change that will affect demand response pricing, real-time load, InSchedule load contracts and auction revenue rights (ARRs).
New aggregates representing the four operating company energy settlement areas will be created.
Hub and interface definitions will not be impacted and the AEP physical transmission zone pricing point will still exist. Capacity and network transmission service will continue to settle at the AEP zone.
AEP has not provided a list of buses defining each of the proposed settlement areas but is required to do so by Dec. 1.
PJM said the following changes will result:
InSchedule load contracts will need to be created identifying the new settlement area.
Any real-time load currently priced at the AEP physical transmission zone will shift to being priced at the applicable operating company load aggregate.
Effective with the 2015/2016 ARR Allocation, load serving entities (LSEs) in the AEP zone will be assigned into one of the four new operating companies based on the location of their load unless the LSE sinks at a nodal location. Each LSE will be assigned a pro-rata amount of capability from each historical generation resource based on its proportion of peak load in the AEP zone. ARR allocations for LSEs not sinking at a nodal location will be assigned as follows: Load in the Indiana Michigan Power, Kentucky Power and Appalachian Power areas will sink at their respective aggregates. Load in the Ohio Power area will sink at the Ohio Power aggregate for Stage 2 only. In Stage 1, load at Ohio Power area will sink at the Ohio Power without MON POWER and the MON POWER Aggregates. The Stage 1 configuration is needed to maintain ARR requests from historical generation for the AEP zone corresponding to the AEP integration reference year (2004).
PJM will begin measuring the demand response performance of some residential customers through sampling of interval-meter data under a rule change approved by the Operating Committee Wednesday.
The new procedure will apply to residential customers on non-interval meters and under direct load control of a curtailment service provider. The measurements will be used to evaluate the performance of resources participating in synchronized reserve, economic energy and load management programs.
The sampling would replace outdated studies dating back to 2001. Sampling is a way to improve accuracy without the cost of installing one-minute meters on every participating household, PJM said. The rule would take effect June 1, 2015, with a transition mechanism for resources that cannot meet new requirements for delivery years 2016 through 2018. (See MIC Briefs, Sept. 9.)
The OC approved the proposal with 14 abstentions and 19 objections, 15 from FirstEnergy. FE’s Jim Benchek said PJM shouldn’t take action on the issue given the uncertainty over DR’s role in wholesale markets as a result of the EPSA ruling and FE’s complaint seeking to prevent DR from clearing in capacity markets. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)
Benchek said the change represents a “carve out” for residences while generators must use interval meters. “If we make an exception here, where does it stop?” he asked. “They should have interval metering like anyone else if they want to sell synchronized reserves.”
Consultant Tom Rutigliano of Achieving Equilibrium said the committee’s action will have no impact on the ultimate fate of DR in wholesale markets, which may be decided by the Supreme Court. To avoid legal problems, PJM has proposed eliminating DR as a capacity supply resource, suggesting load-serving entities instead offer DR and energy efficiency to reduce their capacity obligations.
“This is still just a good measurement technique, no matter who’s doing DR,” Rutigliano said.
Day-Ahead Scheduling Reserve Set at 5.93%; Winter Reserve: 27%
The OC endorsed PJM’s recommendation to set the 2015 day-ahead scheduling reserve requirement at 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%). The changes will be reflected in Manual 13: Emergency Operations.
The committee also endorsed PJM’s proposed 2014/15 winter reserve target of 27%, unchanged from last winter. The 27% target, a percentage of the forecasted weekly peak load, is based on unit summer ratings.
PJM’s Tom Falin said the target does not include data from January 2014. “When we get to extreme conditions, I don’t know how binding this is anyway,” Falin said, noting that PJM would cancel maintenance outages if it anticipated a generation shortage. He said there were about 1,000 MW on maintenance on PJM’s all-time winter peak day in January.
TOs Asked to Update Load Dump Ratings
PJM is asking transmission owners to revise their ratings methodology to address facilities for which the long-term emergency (LTE) ratings are equal to the load dump (LD) measures.
TOs that are unable to make the changes through PJM’s rating methodology guideline should reduce the LTE rating by 3% of the LD rating. PJM wants the changes made by Dec. 1 so that it can determine their impacts on markets and planning before the revised ratings take effect June 1.
Concern over facilities with identical ratings arose as a result of the September 2013 hot-weather event, when PJM discovered that the normal, emergency and LD ratings on the Industrial-Summit 138-kV line were the same. “The impact of all the ratings being the same is there is no time for the dispatcher to perform anything but the most extreme action that must be taken once the load dump rating is reached,” PJM said in its heat wave analysis.
No Votes Gained on Interchange Volatility
A working group meeting last week failed to win any converts to PJM’s plans to limit interchange volatility, OC Chairman Mike Bryson said.
The Energy and Reserve Pricing & Interchange Volatility Sub-Group met on the issue last Tuesday in an attempt to reach consensus. “We tried to beat some votes out of people, but it didn’t really work,” Bryson said.
PJM officials said they intended to recommend operating under the new rules, which require only a manual change, with or without the two-thirds mandate. The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.
Judge Rules Energy Future Can Auction its Oncor Holdings
A state bankruptcy court judge has ruled that Energy Future Holdings can begin accepting bids for its majority stake in Texas transmission company Oncor.
Energy Future, which has declared bankruptcy, is selling off its 80% share in Oncor, which has 120,000 miles of transmission lines and 3 million residential customers in Texas. The winning bidder will then have the right to own that equity when Energy Future exits bankruptcy.
According to Reuters, expected bidders include NextEra Energy, Hunt Consolidated of Dallas and CenterPoint Energy, also of Dallas. Energy Future’s stake is estimated to be worth about $18 billion.
Fracking Rules to be Unveiled Soon, Permit Rush Expected to Follow
The Joint Committee on Administrative Rules last week took a final step toward setting rules to govern fracking in the state.
The committee approved the regulations after months of public hearings, comments and committee work. The exact rules are expected to be released to the public Nov. 15. Until then, outside parties — environmental groups, energy companies and local governments — are in the dark.
“We don’t know if our concerns have been taken into account because we don’t know what changes were made,” said Jack Darin, director of the state chapter of the Sierra Club. The rules are likely to face legal challenges.
Unveiling the rules is expected to spur initial permit applications, local public hearings and test well drilling. The Department of Natural Resources has hired 32 people to help with the initial application process.
Commissioners Get Answers on IPL’s August Blasts, Blackout
Indianapolis Power and Light officials told state regulators last week that the utility will spend $15 million in the next three to five years to replace 137 aging underground circuit breakers that were linked to a network failure in August.
At a hearing held by the Utility Regulatory Commission, the utility said the sounds of a series of underground network disruptions that shook Indianapolis in August were not explosions but the sound of tripping circuit breakers. Those circuit breakers, some dating to the 1950s, were identified as a problem in 2011. Since then, IPL has replaced 10 of the 58 aging breakers that were shown to be susceptible to corrosion.
IPL said that within 30 days it would submit a plan to the IURC to replace 137 vulnerable breakers.
Proposed Law Would Protect Large Wind Farm Operators
The state Senate is considering two bills that would limit nuisance lawsuits against operators of industrial wind turbines by exempting operations that are in compliance with state and local regulations. One measure would impose a “loser pay” requirement on plaintiffs who do not prevail.
“There are a number of lawsuits being filed and families being paid damages,” said state Sen. Howard Walker, author of the bills. “When that happens, the additional costs are passed on to the ratepayers. To me, this is a property rights issue. If someone is complying with local ordinances and state law, I believe they have the right to harvest wind energy on their property.”
Some wind opponents were displeased. “Wind development is becoming much harder to sell to rural communities,” said Kevon Martis of the Interstate Informed Citizens Coalition. “Turbines are no longer a novelty. They are pervasive and wind developers are having a much harder time convincing people that 50- or 60-story tall turbines are scarcely noticeable in our quiet farming communities.”
Pipeline Company Threatens to Sue Homeowners Who Deny Access
A company planning to build a petroleum products pipeline through the state’s north is threatening property owners who deny access to surveyors, but some environmental groups say that Pilgrim Pipeline doesn’t have that right.
A homeowner in Parsippany received a letter from Pilgrim saying their representatives had the right to go on the property for surveys, and if refused access, Pilgrim would go to court to force the issue. The letter said that Pilgrim is a “pipeline company established under New Jersey law” with the “power to condemn private property.” Because of that, Pilgrim’s consultants have “the ability to enter on private land to perform surveys and investigations,” the letter read.
Not so fast, say environmental groups. “It’s wrong legally, it’s wrong factually,” said Aaron Kleinbaum, legal director of the Eastern Environmental Law Center. “They do not have the right to go onto private property without permission.” Pilgrim has proposed a 178-mile pipeline to carry refined products such as gasoline, diesel and heating oil from the New York Harbor to upstate New York.
Tricia Caliguire, a former energy and environmental policy advisor to Gov. Chris Christie and the chief counsel for the Board of Public Utilities, is leaving government and returning to private law practice.
Caliguire, who has been with the BPU since 2012, will specialize in energy, utility and environmental matters as special counsel in McCarter & English’s Newark office. She started her law career with McCarter & English in 1987.
A state Mining and Energy Commission report proposes allowing unannounced inspections at oil and gas drilling sites. It was just one of the recommendations culled from nearly 220,000 public comments on draft rules. The surprise inspection rule was developed to remove language that would have mandated notice to site operators.
The report, prepared by three of the 14 commission members, also suggested a minimum setback of 1,500 feet to each oil or gas well, tank, tank battery, pit or production facility from the edge of any waterway that leads to a drinking water supply.
The proposals will go to the full commission for a vote and then to the legislature during its January session.
Recycling Plant Partner in Default on Construction Payments
A private developer building a project to remove recyclable material from trash and to produce energy from landfill waste has defaulted on payments, putting the project in jeopardy.
The Solid Waste Authority of Central Ohio said Florida-based Team Gemini, which was to build a recyclables sorting and recovery facility at the Franklin County landfill, is more than $1.1 million behind in construction payments and hasn’t paid its $342,850 rent.
Team Gemini is under contract to complete the facility by June 2016. The plant would be powered by a generation station fueled by the landfill’s organic waste. The authority can pull out of the project if Team Gemini doesn’t come up with the payments within 60 days.
Voters in three of four towns rejected anti-fracking measures on their ballots in last week’s election.
About 58% of voters in Youngstown rejected a measure to ban oil and gas drilling, the fourth time an anti-fracking measure was rejected in the northeast city. The towns of Kent and Gates Mills also rejected anti-drilling measures.
Only voters in Athens, home of Ohio University, supported a measure prohibiting fracking for shale gas and oil. The “Community Bill of Rights and Water Supply Protection Ordinance” passed with 78% of the vote. (See related story, GOP Majority Unlikely to Thwart EPA Carbon Plan.)
PGW Sale to UIL Holdings May Still be Alive, Mayor Says
Philadelphia Mayor Michael Nutter’s administration is still campaigning to keep alive a $1.86 billion sale of the city’s gas utility to UIL Holdings, despite the city council’s refusal to take up the measure.
“The mayor is ever an optimist and is hopeful that before the end of the year, we will have had a bill introduced, hearings and a vote from City Council on PGW [Philadelphia Gas Works] and the sale to UIL,” said Mark McDonald, Nutter’s press secretary. Council President Darrell L. Clarke announced abruptly on Oct. 27 that the city’s legislative body would not consider the proposal.
The mayor’s office released a document last week offering a point-by-point rebuttal of criticisms of the privatization. The deal expires by year’s end if not approved by council.
The Public Utility Commission will hold a hearing to discuss PGW’s future this week, and UIL CEO James P. Torgerson said his company will decide soon whether it will continue to pursue the deal, on which it has already spent $21.3 million. “We’re going to see how things go over the next few days, and then we’ll make some decisions on that,” he said during an analysts call.
The state Department of Environmental Protection has revised a rule it proposed in April to limit emissions from coal-fired power plants that was widely criticized by environmental groups and deemed “too lax” by federal environmental regulators.
The new proposed final rule requires the state’s more than two dozen coal-fired power plants to install and operate Reasonably Available Control Technology to reduce emissions of nitrogen oxides and volatile organic compounds.
Critics said DEP’s April proposal would have allowed many of the power plants to operate without turning those controls on and emit up to 40% more pollutants.
Gov. Earl Ray Tomblin picked state Sen. Brooks McCabe, who did not run for re-election this year, to one of three seats on the Public Service Commission.
McCabe, a Democrat, fills a vacancy on the three-member commission created when Ryan Palmer departed to join the Federal Communications Commission. McCabe must resign his Senate seat before joining the commission Nov. 15.
A veteran of the commercial and investment real estate industry, McCabe pursued economic growth and development for the state. He has served on the Senate Committees on Finance, Economic Development, Pensions, Banking and Insurance and Government Organization.
PSC Approves 83% Fixed Charge Increase for Wisconsin Public Service Customers
The Public Service Commission allowed Wisconsin Public Service to nearly double its fixed monthly customer fee, approving an approach that utilities are pursuing to get low-usage customers like those with solar panels to pay more of the costs of maintaining the distribution system.
The measure, approved by a 2-1 vote, will raise the fixed charge from $10.40 to $19 a month. The increase in the fixed charge is offset by a decrease in the energy charge, resulting in an overall hike of about 3%. Fixed charges go toward paying for a company’s fixed costs, such as poles, wires and substations.Consumer advocates and solar supporters criticized the PSC’s vote. “The decision takes the step that most helps utilities at the expense of customers,” said Kira Loehr, executive director of the Citizens Utility Board. “Increasing fixed charges hurts our most vulnerable low and fixed income households and frustrates residential and small business customers’ ability to lower their bills by using less energy.”
The commission has yet to rule on similar requests from other utilities. We Energies wants a 75% increase and Madison Gas & Electric is seeking an 82% jump.
The revised methodology (blue line) results in a reduction from the current forecast (green line).
PJM is testing a new load forecasting model to reverse a marked “degradation” in forecast accuracy.
The model being tested accounts for factors such as appliance saturation and energy efficiency that were previously not included, PJM’s Andrew Gledhill told the Planning Committee last week.
The new model’s “equipment indices” improved near-term forecast accuracy but caused an increase in instability because the forecasts of appliance saturation and efficiency change over time. The forecasts are made by Itron based on data from the Energy Information Administration. “The understanding of where we’ve been and where we’re going has had a tendency to change over time,” Gledhill said.
Officials said it was difficult to determine the model’s long-term forecast accuracy because of data limitations.
PJM is investigating incorporating the equipment indices into its peak-load model. One concern: Will accounting for these trends in the peak model result in an overlap with energy efficiency as a capacity market resource?
PJM previously considered shortening the estimation period but found that it created anomalies. The current forecast uses an estimation period of 1998 to the previous August. PJM found that while a three-year-ahead forecast resulted in a 0.6% reduction for the RTO, some zones increased by as much as 9% while others dropped 6% or more.
PSEG Seeks Injection Rights for PARs
The Planning Committee Tuesday approved PSEG Energy Resources & Trade’s problem statement to consider awarding firm withdrawal and injection rights to transmission projects employing phase angle regulators (PARs).
PJM awards withdrawal and injection rights to controllable AC and DC merchant transmission facilities using only variable frequency technology, which excludes PARs.
PSEG said PJM’s interpretation “creates an impediment to the development of a class of controllable merchant transmission projects that could efficiently address seams issues between PJM” and neighboring regions. Because PAR projects are not awarded rights, “it will be difficult if not impossible for PARs-based projects to be deemed deliverable” for sales of capacity or energy, PSEG said.
GMD Reliability Standard Struggling to Win Support
The North American Electric Reliability Corp. is struggling to win support for its reliability standard on geomagnetic disturbances, PJM’s Frank Koza told the PC last week. Two rounds of voting have failed to gain the two-thirds support needed to endorse the standard for review by the Federal Energy Regulatory Commission.
The most recent vote won support of only 58% of stakeholders, and a third vote will be taken this month, Koza said. “We need to turn about 25 votes around,” he said.
The standard requires reliability coordinators and some transmission operators to institute operational procedures to mitigate the effect of GMDs.
NERC is working on stage two of the standard, in which it must determine what severity GMD will constitute a “benchmark” GMD event. Covered entities will be required to assess the potential impact of such benchmark events on their equipment and systems. FERC required NERC to complete the standard by January. (See FERC OKs GMD, Training Standards; Proposes Modeling Rule Change.)
