The Planning Committee approved a manual change that will result in PJM identifying potential transmission upgrade requirements earlier in the study process.
In past years, studies identified many reinforcements which were ultimately not needed as projects dropped out of the backlogged transmission interconnection queue. As the backlog has been reduced, however, some projects have cleared the Impact Study phase without any apparent violations, only to have violations indicated when they are evaluated at 100% in the Facilities Study.
As a result, PJM plans to eliminate the 19% probability for Feasibility Studies and replace it with the 53% currently used for Impact Studies. Impact Studies will use the 100% probability. The changes will be incorporated in Manual 14B. (See Transmission Studies to Flag Upgrades Earlier.)
PJM CEO Terry Boston and Federal Energy Regulatory Commissioner Cheryl LaFleur kicked off PJM’s third annual Grid 20/20 conference in Philadelphia last night.
In keeping with the theme of this year’s conference, LaFleur told an audience of about 100 about the need to create a “culture of resiliency.”
“When there is a problem on the grid, very rarely is it the result of one thing. It’s a succession of mistakes where if you had defense in depth it could have been stopped,” she said. “There has to be a line of sight between what people are doing and the bigger issues…These little thing will add up to the big things.”
About 180 people gathered for today’s daylong session at the Sheraton Society Hill.
Carlyle Group closed on its purchase of the 823-MW Red Oak combined-cycle plant in New Jersey from Energy Capital Partners, bringing to 11 the number of plants it has bought since acquiring Cogentrix Energy Power Management late last year. More: Carlyle Group
DTE Shakes Up Senior Management
Steve Kurmas
DTE Energy named five executives to new positions, effective Dec. 30. Steve Kurmas becomes DTE Energy president and COO; Jerry Norcia president and COO of DTE Electric and Gas & Storage Pipelines; Dave Meador, DTE Energy vice chairman and chief administrative officer; Peter Oleksiak DTE Energy senior vice president and CFO; and Mark Stiers president and COO of DTE Gas. More: DTE Energy
Duke Utilities Eye Renewables Business
Having decided its regulated utilities should get much more into renewables, Duke Energy has established a group to determine how they should do it – by building, owning capacity or partnering. Duke’s utilities may take different approaches, says Ron Caldwell, who heads the new group, which is focusing initially on solar. Getting renewables into the utility mix is “the next place for our generation portfolios to evolve to,” Caldwell said. More: Charlotte Business Journal
Riverbend Demolition Set
Riverbend Steam Station (Source: Duke Energy)
Duke Energy will begin dismantling the 84-year-old Riverbend station in North Carolina this fall and level the powerhouse and chimneys in 2016. The company shut the little-used 454-MW plant in April as part of its coal plant-retirement program, and now has outlined permanent closure plans. Environmentalists will watch closely how Duke handles coal ash ponds at the site. More: Charlotte Observer
Exelon Reaps up to $100 Million in PTCs
Exelon continues to take advantage of the production tax credit for wind power even as it protests the PTC as a market distorter, particularly damaging to its giant nuclear fleet’s revenue. A Bloomberg New Energy Finance analyst pegged Exelon’s own wind PTCs for this year at $75 million to $100 million, based on the company’s 1.3 GW of wind projects. To environmentalists’ criticism, Exelon says it has a fiduciary responsibility to its shareholders to take the tax credits, but it opposes all market-distorting subsidies. Although Exelon has suffered this year from low power prices, Morningstar analysts say the company’s prospects are good because its low-carbon nuclear fleet will be valuable for years to come. More: Greenwire; Forbes
FirstEnergy Adds $2.8 Billion to Spending Plan
FirstEnergy’s board approved $2.8 billion for transmission system upgrades, on top of the $700 million it set earlier this year. FE sees most of its growth coming from transmission investment, CEO Anthony Alexander said. The company plans to cut the sales force of FirstEnergy Solutions, its unregulated subsidiary, to further reduce its market risk. More: The Plain Dealer
Seneca Pump Hydro plant in Warren, PA (Source: FirstEnergy)
FE Gets FERC Approval for Hydro Asset Sale
FirstEnergy companies won Federal Energy Regulatory Commission approval to sell 527 MW of hydropower facilities to LS Power Development. The plants include the 451-MW Seneca Pumped Storage facility in Warren, Pa., and assets in Virginia and West Virginia. FirstEnergy said in May that it would sell up to 1,240 MW of unregulated hydro assets. More: Electric Light & Power
NRG to Supply Phila. Convention Center
NRG Energy, which entered the residential retail market in Philadelphia in September, has won a big commercial customer in the city. The Pennsylvania Convention Center will buy its approximately 26.5 million MWh a year of power from NRG Business Solutions beginning next year. A competitive process resulted in choice of the NRG Energy unit, which is to provide 25% of the power from renewable sources. This is the first renewable power buy for the center, which later this month will host the world’s largest conference dedicated to green building. More: MarketWatch
PJM will require all steam generators to adjust their capacity ratings based on summer peak load conditions under manual changes outlined to the Planning and Market Implementation committees last week.
Manual 21 currently requires such temperature corrections only for combustion turbines and combined cycle units. The revisions will extend the requirement to coal and nuclear steam units.
About 60% of steam units already perform temperature corrections, with half increasing their capacity ratings and half reducing them, said PJM’s Tom Falin. The average adjustments were 0.5% with the largest adjustment 2%.
PJM also will begin requiring hydropower and pump storage units to perform their annual capacity tests — now allowed to be conducted any time — during the summer.
The adjustments can affect generators’ installed capacity values as well as capacity interconnection rights.
PJM plans to implement the changes after seeking endorsement by the Markets and Reliability Committee in the first quarter of 2014.
The changes will be incorporated in PJM’s planning studies in summer 2014, with a likely transition period before use for markets purposes.
Large-Eddy Simulation results. (Source: Cristina Archer, PhD; University of Delaware)
Stagger Turbines to Raise Output
A University of Delaware researcher says more generous spacing and staggered arrangement of turbines could raise a wind farm’s output by 13% to 33% over conventional arrangements. The issue is pertinent to the state, where offshore wind development is a yet-unrealized goal.
The Chicago Infrastructure Trust has proposed a kind of feed-in tariff to help the municipal buildings use less energy. The trust said its plan could help Commonwealth Edison meet the state’s energy efficiency targets, which the utility said it cannot meet with funds from an existing surcharge.
Coal being loaded into a hopper (Source: James River Coal)
James River Idles More Coal Mines
James River Coal idled four Kentucky mines at its Buckeye complex, eliminating 1.3 million short tons of annual thermal coal production on top of the 3.7 million tons it idled in September. The company might restart the Buckeye production if markets warrant it, but the earlier shutdowns are meant to be indefinite.
The Public Service Commission and Michigan Energy Office have told Gov. Rick Snyder that the state could get 15% of its power from renewables by 2020 and 30% by 2035. The agencies will deliver reports on other power issues later, as part of Snyder’s effort to gather information for possible legislative action.
A big-business coalition has legal standing to oppose the Energy Strong program Public Service Electric & Gas is proposing to storm-proof its grid, the Board of Public Utilities ruled in rejecting a PSE&G challenge to the group. The coalition of large energy users object to the utility’s plan to fund the $3.9 billion program with ratepayer money on an ongoing basis instead of submitting the expenses for scrutiny and reimbursement afterward.
Anti-nuclear activists and industry representatives wrangled over fundamental issues as the Nuclear Regulatory Commission held one of a series of hearings about its “waste confidence rule,” which governs storage of spent fuel. The Charlotte meeting drew a crowd, spurred by proximity to two Duke Energy nuclear plants. The NRC is weighing its rule, which a federal appeals court vacated last year.
Municipalities in Allegheny and Beaver counties have begun to pass solar panel policies to be prepared as interest in installations increases. The municipalities participated last year in a project to develop a model ordinance.
FirstEnergy’s four Pennsylvania utilities sent the Public Utility Commission a proposal for buying default-service supply beginning June 2015. CRA International would run quarterly auctions starting in October 2014 and have a bidding process for supply of renewable energy credits.
Wyoming Republican Sen. John Barrasso has challenged Federal Energy Regulation Commission Chairman Jon Wellinghoff’s plan for recusing himself from decisions involving Stoel Rives law firm clients before he leaves FERC for a position with that firm. Echoing concerns that others have raised, Barrasso asked why the chairman has not recused himself from broader matters that could affect Stoel Rives’ current and future clients.
Dan Utech, White House deputy energy and climate adviser since 2010, has moved up to succeed Heather Zichal, who left her climate adviser position last week. Utech is a former adviser to Sen. Hillary Clinton and aide to the Senate Environment and Public Works Committee.
The Obama administration is taking new comments on its determination of the social cost of carbon, a metric it uses to assess the benefits of greenhouse gas regulations. Industry has attacked the SCC levels set in May for lacking public input. “Minor technical corrections” since then have resulted in a cost of $37/metric ton of carbon dioxide in 2015, down from $38, the White House said in inviting comment on the matter.
ACEEE 2013 Energy Efficiency State Scorecard Rankings Map (Source: aceee.org)
For the first time, Illinois made it into the American Council for an Energy-Efficient Economy’s top 10 states whose policies and programs support energy efficiency. Just above Illinois is Maryland at No. 9. Of other PJM states, Ohio at No. 18 is among a handful of “most improved” states, joined by No. 46 West Virginia. Pennsylvania, at 19, was recognized for “recent concentrated efforts.”
The Department of Energy is investing $84 million in 18 carbon capture and storage R&D projects to reduce costs and improve the efficiency of CCS. Among them are a bench-scale project at Media and Process Technology in Pittsburgh and a pilot-scale project at the Gas Technology Institute in Des Plaines, Ill. The Environmental Protection Agency has called CCS a viable technology for future coal plants to meet the agency’s greenhouse gas regulations.
Coal’s future is much shorter than the 200 years that government predicts, according to a Clean Energy Action study. The group said only 20% of remaining coal reserves will be economically recoverable. Ohio, where coal prices have risen 7.8% annually since 2004, is one of 16 states past their peak production years, according to the study.
Some experts are raining on the natural gas and oil production boom, saying production bonanzas from fracking are coming from only a few “sweet spots” that will play out in the next few years. Other experts disagree strongly, in part because they see technology developing fast.
Firing wood with coal can help power producers cut their carbon dioxide emissions, but it is easier for some companies than for others, and the practice may be a bridge to future reductions instead of a permanent strategy.
The governors of Maryland and Delaware and the mayors of Philadelphia and Hoboken, N.J., are among members of President Obama’s Task Force on Climate Preparedness and Resilience. The group is charged with identifying what governments can do to advance climate-resilient investments.
PJM is changing the way it estimates Tier 1 Synchronized Reserves and is open to lifting the cap on demand response participation in Tier 2, officials told the Operating Committee last week.
A review of more than 40 Synchronous Reserve events since January 2012 found that only 71% of estimated Tier 1 reserves responded when called upon. The response rate drops to 62% when two outlier events — in which there was over-performance — are excluded.
PJM officials decided to take a look at their estimation methods after an SR call during the Sept. 10 heat wave provided only 12% response.
PJM plans to implement several changes in its methodology by the end of the year:
Cap all units used in the Tier 1 estimate at the lesser of Eco Max or Spin Max (by end of year).
Remove all hydropower units – which don’t respond automatically to synch reserve events — from the Tier 1 estimates (already done).
Remove all combined cycles units from the Tier 1 estimate except units that have submitted a Spin Max < Eco Max (done).
Remove units with a manual dispatch instruction from the Tier 1 estimate (by end of year).
During hot or cold weather alerts, the Degree of Generator Performance (DPG) modifier will be used to adjust the Tier 1 response estimate (by end of year).
Tier 2 Synchronous Reserve Response Performance for Events > 10 Minutes (% of Assignment Provided) (Source: PJM Interconnection, LLC)
Units assigned regulation, which are assumed to be able to respond with the MWs outside their regulation band, will remain in the Tier 1 estimate.
Units providing constraint control are expected to respond to a Synch reserve event and will remain in the estimate.
Tier 2 Unchanged
Also unchanged are the Tier 2 calculations. PJM filed new Tier 2 penalty rules for nonperformance Nov. 1 (ER14-297).
The new rules were approved by the Members Committee Oct. 24 in response to concerns that the existing penalties were insufficient to ensure compliance.
Demand response and generation have each provided 59% of requested MWs for Tier 2 events of 10 minutes or longer in 2013, according to a PJM analysis provided last week to the Operating Committee. That was a decline after steady increases in performance from 2009 through 2012.
PJM officials said they don’t know the reason for the fall off in performance. “There’s nothing that jumped out” as a cause, said PJM’s Tom Hauske.
DR Cap
Although the cap on DR participation was raised to 33% last fall, it provided only 224 of the 925 MW (24%), with generation providing the remainder.
DR typically offered between 200 and 250 MWs per hour into the market. Mike Bryson, executive director of system operations, said the decline in SR prices affected the volume of DR bidding into the market, rendering the cap moot.
Asked by EnergyConnect’s Bruce Campbell whether PJM still sees a need for a limit on DR participation, Bryson responded: “I think it’s certainly worth discussing.”
Adam Keech, director of wholesale market operations, said that PJM would need to improve its data collection before considering a change in the cap. About 9% of MWs assigned to DR failed to provide PJM with data in 2013, down from 46% in 2012.
Officials said one concern with removing the cap would be the operational impacts because of differences in the ramp rate of DR versus generation in the first 10 minutes of spin events.
The Operating and Planning committees last week endorsed an updated Transmission Owner/Transmission Operator matrix of shared and assigned tasks. The matrix, an index between NERC reliability standards and PJM manuals, is used as an audit tool.
Reason for changes: Update to reflect reliability standards enacted since the last revision in April.
Impact: Adds standards becoming effective in January 2014 and revisions to existing standards. Key changes:
EOP-001-0.1b — TOs shall develop and maintain a set of plans to mitigate operating emergencies for insufficient generating capacity.
EOP-005-2 R2 — Restoration Plans should be submitted by eDART instead of PERCS website.
EOP-008-1 R5.1 — Fixed errors regarding submittal of backup functionality plans through PERCS website.
PRC-001-1 R2.2, R3.2, R4 — Align with PRC-001 Compliance Bulletin. Requires TOs to report all protection system failures and protection system outages on EHV facilities (345 kV and above) through eDart. Also requires TOs to report to PJM Operations any protection system failures and outages on any other Reportable Facilities requiring PJM to modify PJM EMS Network Application Contingencies.
EOP-004-2 (effective Jan. 1, 2014) — Requires TOs experiencing a disturbance to supply sufficient information to allow PJM to meet its 24-hour reporting requirement.
VAR-001-3 (effective Jan. 1, 2014) — Adds more specific PJM Manual references in R1.
Compliance is expected upon TOA-AC approval. TOs must provide evidence of compliance back to their last PJM TO/TOP audit.
PJM contact: Mark Kuras
Winter Reserve Target Cut to 27%
The committee endorsed a minimum winter reserve target of 27%, down from 28% a year ago. The target is revised annually to maintain the one in 10-year loss of load expectation (LOLE). The target is based on unit summer ratings and is expressed as a percentage of the forecasted weekly peak load.
PJM contact: Tom Falin
MANUAL CHANGES
Manual 13: Emergency Operations
Reason for changes: Annual review of load forecast error and forced outage rate components of day-ahead scheduling reserve: (effective Jan. 1, 2014); updates to comply with revised NERC standards.
Load forecast error (LFE) changed from 2.13% to 2.12%. Forced outage rate changed from 4.66% to 4.28%. The day-ahead scheduling reserve for RFC and EKPC regions of PJM is changed from 6.91% to 6.41% times peak load forecast.
References to ILR (interruptible load for reliability) — no longer a valid term — are removed.
Revised order of emergency procedures so that curtailment of non-essential plant and building load is curtailed prior to issuing a manual load dump warning and voltage reduction.
Updates to the min gen and max gen alerts process to include posting to the RCIS.
Hot and cold weather alert unavailability numbers updated to include East Kentucky Power Cooperative.
Clarifies section 5.4 post contingency local load relief warning (PCLLRW)
References to transmission emergency alerts (TEA) and security emergency alerts (SEA) deleted due to retirement of the terms.
Section 4: Replaced “CIP” reference for Event Reporting with reference to “EOP-004-2.”
Section 6: Updated to reference revised Attachment J, (PJM operating plan for compliance with EOP-004-2). Attachment J almost entirely rewritten to support EOP-004-2 compliance.
Manual 41: Managing Interchange
Reason for changes: Manual 41 and Section 2 of the Regional Practices cover the same material regarding managing interchange.
Impact: PJM merged M41 into Regional Practices document and will retire M41. Other changes include:
Chapter 2, Section 1.2.6 – Added clarifying language around PJM’s default ± 1000 MW ramp limit
Chapter 2, Section 1.2.6 – Added clarifying language around NYISO interface ramp limit
Chapter 2, Section 4 – Removed reference to pre-schedule checkout
PJM contact: Mary Mason
GRID OPERATIONS
New 500 kV Lauschtown Substation
PPL is building a new Lauschtown 500 kV substation as part of a baseline upgrade (b2006.1).
Impact: Existing TMI‐Hosensack 500 kV line will terminate at the Lauschtown substation and keep the 5026 line designation. Proposed designation for the Lauschtown‐Hosensack 500 kV line is 5066.
Target completion date: Spring 2017.
Belmont SPS Revised
FirstEnergy Corp.’s Belmont special protection scheme (SPS) will be revised Dec. 1 as a result of the retirement of the Willow Island generator.
The Belmont substation is surrounded by a pocket of generation and has only two extra high voltage paths out of the area. The loss of either line creates potential stability and thermal overload issues that puts the second line at risk.
Existing procedure: The SPS is armed upon loss of the Belmont-Harrison 500 kV line (528 ) followed by loss of the Belmont No.5 765/500 kV Autotransformer or the Kammer-Belmont-Mountaineer 765 kV line. The SPS trips both Oak Grove combustion turbines and a selected Pleasants unit upon the loss of the other second facility.
Revised procedure: The retirement of the Willow Island generator eliminates the need to trip either Oak Grove unit. The revised procedure limits the output of one of the Pleasants units to a maximum of 520 MW and arms-to-trip the other Pleasants unit. Oak Grove units will not be affected.
Target implementation date: Dec. 1, following a 90-day lead time to review changes with RFC.
Brandon Shores SPS Removed
The Brandon Shores SPS in the BGE zone will be removed in February because of the cancellation of the underlying transmission upgrade.
Background: Constellation Energy Commodities Group, Inc. submitted a merchant interconnection request (W3-122) for physical upgrades to the Brandon Shores –Riverside circuits 2344 and 2345 (ratings increase). A temporary SPS (W3-123) was designed to operate during the upgrade work to address a contingency analysis that indicated that a loss of one Brandon Shores – Riverside 230kV circuit may overload the other parallel circuit. Agreement W3-122 was cancelled in September
Existing procedure: The SPS was armed when a contingency analysis showed the Brandon Shores –Riverside (2344/2345) 230kV circuit is loaded up to 100% of its LTE rating. The SPS initiated a trip of either Brandon Shores Unit 1 or Brandon Shores Unit 2 when the Brandon Shores–Riverside 2344/2345 is lost and current on opposite circuit exceeds the setting for 30 seconds.
Impact: Minimal: The SPS was armed only once in the past year. The SPS will be removed from service Feb. 28, 2014.
PJM will reduce the volume of imports that clear in next year’s Base Residual Auction – potentially increasing capacity prices – under methodology approved by the Planning Committee yesterday.
The committee approved revised methodology that will create five import zones and limit external resources in next year’s BRA to 6,200 MW – a 17% drop from the 7,483 MW that cleared in May for delivery year 2016/17.
That’s good news for generators in PJM, who have been bemoaning the fall in capacity prices resulting from competition from both imports and demand response. But there’s no guarantee that it will increase clearing prices.
While cleared imports more than doubled in this year’s BRA, demand response offers dropped 27% from the 2012 auction. A rebound in DR offers next year could reduce upward pressure on prices.
Another unknown yesterday was how the impact of an exemption for external generators with firm transmission that commit to providing capacity in future auctions and have pseudo-ties allowing PJM to control their dispatch.
PJM planning staffers who presented the methodology yesterday could not say how much of the imports that cleared in May would be exempt from the limits. No one from PJM’s markets staff attended the meeting or was made available for questions from stakeholders.
About 64% of the imports that cleared in May (4,788 MW) had confirmed firm transmission service from the resource into PJM. The remainder was under study.
Five Zones
The new methodology sets both an overall limit and individual limits for five “external source zones.” Generators in the five zones will compete against each other until the individual caps or the overall limit is hit. The zones and limits are:
North (New York ISO & ISO New England): 1,598 MW.
West 1 (MISO East, MISO West & Ohio Valley Electric Corp.): 2,301 MW.
West 2 (MISO Central + MISO South): 767 MW.
South 1 (Tennessee Valley Authority & LG&E Energy Transmission Services): 1,278 MW.
South 2 (VACAR — non-PJM): 2,493.
Based on current assumptions for 2018, PJM’s First Contingency Incremental Transfer Capability (FCITC) is 9,700 MW. Because 3,500 MW of the import capability must be reserved for the Capacity Benefit Margin, the cap on imports clearing in the BRA would be 6,200.
The limits will be adjusted yearly based on changes in load and generation, in the same way that Capacity Emergency Transfer Limits (CETL) — which govern transmission into Locational Deliverability Areas (LDAs) — are modified.
“We’re approving the methodology, not the [cap] numbers,” explained Steve Herling, PJM vice president of planning.
One utility representative said PJM was moving too quickly to adopt the new rules, noting that the RTO had not done a “backcast” to determine how the new rules would have affected the May auction. “It seems like it would be pretty unfair to make us vote until we understand the impact on prices,” she said.
But PJM staff insisted stakeholders push the initiative forward to allow the new rules to take effect with next year’s auction.
That was enough for most stakeholders. “The methodology is sound. Let’s vote,” said one generation owner representative. The committee approved the methodology acclimation, with only four stakeholders voting no.
Market Impact
Questions about the market impact of the changes will be taken up by the Markets and Reliability Committee, which will be asked to approve the measure in a special meeting next Thursday.
The fact that the cap is below 7,400 MW raises the question of whether “the imports that cleared in May are unreliable,” Herling acknowledged. But he said, “We have not made any such conclusion.”
Another representative questioned the planners’ method for reducing each of the five regional caps by a share of PJM’s 3,500 MW Capacity Benefit Margin (CBM). CBM, reserved to import capacity from neighboring areas in emergencies, allows PJM to reduce its installed generating capacity below that which may have otherwise been required.
Herling said that planners used a “vanilla, pro rata” apportionment of CBM among the regions. They could not optimize CBM among the regions, he said, because “we never know where the help is going to come from if we have a CBM emergency.”
Imports Doubled
The new methodology is the result of a problem statement requested by PJM officials, who said they feared imports in this year’s auction “may have approached, or even exceeded, the amount that can be reliably supported during actual emergency conditions.” (See PJM Considers Limit on Capacity Imports.)
PJM officials were particularly concerned because the majority of the imports were from MISO and other points west, with very little from the north or south. West of PJM imports nearly doubled to 7,081 MW over last year’s auction, 4,723 MW of it from MISO and areas that will be integrated into MISO by the 2016/2017 Delivery Year.
Refining the Methodology
On Sept. 27, PJM staff brief the Planning Committee on a methodology that they said suggested PJM could import 11,000 to 12,000 MW. (See Current Capacity Imports OK: Study.)
At the Oct. 18 meeting, however, PJM’s Mark Sims told members that the limit will be “slightly lower” than 11,000 and closer to the 8,347 MWs imported on July 16, 2013, the highest import observed in an analysis of three years of historical data. (See Import Cap Likely to Settle About 9,000 MW.)
The Sept. 27 results used a 1% distribution factor (DFAX) — which PJM decided was overly conservative — and assumed unlimited redispatch to maximize imports, which officials said was overly optimistic.
The Oct. 18 results assumed more limited redispatch but raised the outage transfer distribution factor (OTDF) to 3%, meaning the model only addressed transmission facilities that carried 3% or more of a projected generator’s output. The two changes “have a tendency to act in opposite directions,” Herling said.
FERC Scrutiny
PJM wants to include the new limit in February when it posts the planning parameters for the 2014 base auction.
To meet that schedule, officials called a special MRC meeting Thursday to vote on the changes. The committee also will be considering other changes that could limit the volume of DR that clears in the auction. (See States, LSEs on Collision Course with PJM over DR Changes.)
Both initiatives will require the approval of the Federal Energy Regulatory Commission. Also watching closely will be MISO officials, who have complained to FERC that PJM’s modeling of cross border transmission deliverability is unfairly limiting its generation from competing in PJM. (See FERC Likely to Increase Pressure on PJM-MISO Joint Market Talks.)
