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.)
Southern Illinoisans are split over hydraulic fracturing according to a new poll. More than 40% of people who answered the poll by the Paul Simon Public Policy Institute said fracking should be encouraged, with about 39% opposed. About 20% had no opinion. The state recently allowed for the procedure and is currently working out regulations and rules.
Big Rivers Wins $54M Rate Hike to Offset Aluminum Plant Loss
The Public Service Commission awarded Big Rivers Electric Corp. a $54 million rate hike that will boost average rates 16% for residential customers of the company’s Kenergy Corp. distribution cooperative. Big Rivers, which also serves the Meade County Rural Electric Cooperative and the Jackson Purchase Energy Cooperative, had sought a $63 million boost to offset the loss of Kenergy’s largest customer, Century Aluminum.
Century Aluminum has reached an agreement to obtain market-priced power through Big Rivers for its Hawesville smelter. Century expects to seek a similar agreement for its Sebree smelter, the subject of another rate hike request, which the PSC will consider at a hearing Jan. 7. To deal with the loss of its top two customers Big Rivers says it will seek to idle one or two of its generating plants. The shutdowns will be subject to the approval of MISO and the Southwestern Reliability Council.
Gov. Steve Beshear (D) and U.S. Rep. Hal Rogers (R) announced a Dec. 9 summit to seek ideas to improve Eastern Kentucky’s crippled economy. Beshear and Rogers also announced a planning committee of more than 40 people, many from the private and education sectors, to come up with topics and goals for the summit. The region has lost nearly 6,000 coal jobs in the last two years.
While other Appalachian states have been able to offset coal’s decline with increased natural gas production, the shale boom is likely to leave Kentucky behind. The Marcellus shale formation stretches across West Virginia, but stops at the Bluegrass State’s border. Thus West Virginia is producing four times as much gas as Kentucky, and there is little evidence that Kentucky will catch up.
Duke Energy Carolinas asked the South Carolina Public Service Commission for permission to build a 750 MW combined cycle plant at the existing Lee Steam Station in Anderson County, SC. The North Carolina Electric Membership Corporation (NCEMC) will own 100 MWs of the project if constructed.
The Utilities Commission approved Duke Energy’s request to replace its “Save-a-Watt” energy efficiency program with new programs using a shared-savings model. Customers will get 88.5% of the savings realized from efficiency and conservation with Duke earning the remaining 11.5%. The program is the result of a settlement between Duke and environmental groups.
The Public Utility Commission approved the results of an auction to supply Dayton Power and Light Co.’s standard offer customers, which cleared at an average price of $49.32/MWh. The three winners of the auction will supply 10% of DP&L’s standard service offer load for January 2014 through May 2017.
The Public Utility Commission delayed until next year a decision on PPL’s request for a new charge to cover the costs of repairing major storm damage. The proposed fee has drawn opposition from consumer and business groups, as well as the commission’s staff, which suggested a storm damage reserve fund that could be replenished with a fee. The commission opened a new 30-day comment period.
The 3.6 million Pennsylvania utility customers who have not picked a competitive power supplier would have the decision taken out of their hands if legislation promoted by electricity marketing firms is enacted. Customers who don’t shop would be assigned to competitive suppliers through an auction rather than being supplied by their incumbent utility. Suppliers would pay the state $100 per switched customer, an estimated one-time budget boost of $360 million.
Consumer advocates say the proposal would upend a system that has already induced more customers to switch than any state other than Texas, where all customers are required to shop. About 37.5% percent of customers statewide have switched suppliers.
If fracking is to reverse West Virginia’s fortunes, the state will have to learn from its mistakes as a coal producer. Throughout its history, much of West Virginia’s coal has been quickly transported by out of state companies for processing. That left the state benefiting from miners’ wages and coal-extraction taxes but watching corporate profits go elsewhere. The first few years of the fracking boom reveal an uneven record, with anecdotal success stories mixed with troubling similarities from the last energy boom.
Sen. Joe Manchin (D-WV) and Rep. Ed Whitfield (R-KY) introduced legislation to block proposed regulations on greenhouse-gas emissions from new power plants and grant Congress authority to decide when a rule making for existing plants would take effect.
The bill also would require the Environmental Protection Agency to set rules for coal-fired power plants that incorporate “commercially feasible” technologies. EPA in September announced regulations to impose carbon dioxide limits on power plants. The limits would require new coal-fired plants to incorporate expensive and unproven carbon capture and sequestration technology. Several thousand coal industry workers and supporters rallied at the Capitol last Tuesday to protest the EPA rules.
The FutureGen 2.0 carbon-storage project in Illinois should go ahead with support from $1 billion in federal funding, the U.S. Department of Energy concluded in an environmental study. A final decision on whether the $1.65 billion project should proceed could come by the end of the year. The project would store carbon dioxide delivered through a 30-mile pipeline from a former Ameren coal plant at Meredosia on the Illinois River.
Observers say it could take weeks before the White House announces a new candidate to fill the fifth seat at the Federal Energy Regulatory Commission after Ron Binz’s nomination failed amid heavy conservative opposition. Some think the Obama administration won’t announce a new nominee before the New Year.
The Nuclear Energy Institute said the Nuclear Regulatory Commission should keep more of its workers on the job in a future government shutdown, saying the agency’s furlough of 92% percent of its staff during the recent lockout reflected an overly restrictive definition of essential safety functions. In a letter to NRC, the trade group noted that 90% of the NRC’s budget is recovered from licensee fees.
The DC Court of Appeals ordered the Environmental Protection Agency to issue rules within 60 days on how power plants must dispose of coal ash. The waste is currently considered a solid waste, allowing it to be recycled in products such as cement. Reclassification as a hazardous waste could restrict recycling and increase disposal costs.
The issue has taken on urgency as a result of a 2008 incident when a dam burst 40 miles outside of Knoxville, Tennessee, spilling 5.4 million cubic yards of ash spilled into neighborhoods and waterways.
Former CIA director Michael Hayden says there is no way to defend against a geomagnetic disturbance that could cripple the electric grid. “I don’t mean to be so flippant, but there really aren’t any solutions to this, so I would just leave it at that,” Hayden said at a conference. A disturbance could be caused by a nuclear explosion over the U.S. or a very large solar flare.
Sens. Tom Udall (D-NM) and Mark Udall (D-CO) introduced legislation to create a nationwide Renewable Electricity Standard that would require investor-owned utilities to get 6% of their electricity from renewables sources by 2014 and up to 25% by 2025. The two first attempted a national RES in 2002 as members of the House of Representatives, and again in 2007, when their RES amendment cleared the House but failed in the Senate.
The senators plan to attach the bill as an amendment to the energy efficiency bill sponsored by Sens. Jeanne Shaheen (D-NH) and Rob Portman (R-OH). House Energy and Commerce Committee Chairman Fred Upton (R-MI) said his panel will consider the bill if it passes the Senate.
Newly elected Sen. Cory Booker (D-NJ) will serve as a member of the Environment and Public Works Committee. The former Newark mayor also will serve on the Commerce and Small Business committees.
House Democrats want the Obama administration to finalize tough guidance for hydraulic fracturing operations that use diesel fuel. The Environmental Protection Agency sent the proposed guidance to the White House Office of Management and Budget in September for a final interagency review. The top Democrats on the Energy and Commerce Committee and its Oversight subcommittee told the OMB that its decision is long overdue. “Diesel fuel is toxic and should not be used in fracking without careful environmental review under the Safe Drinking Water Act,” the Democrats said in a letter.
Public Service Enterprise Group’s proposed Energy Strong initiative and similar responses to Superstorm Sandy are fighting the last war, says the director of markets and regulation for the World Alliance for Decentralized Energy.
Opinion: Investors Ignoring `Carbon Bubble,’ Gore Says
Al Gore
Former Vice President Al Gore writes that investors risk being stuck with “stranded carbon assets” by not addressing climate change risks in their portfolios. “When investors mislabel risk as uncertainty, they become vulnerable to the assumption that since it cannot be measured, they might as well ignore it,” Gore says.
Direct Energy Business LLC last week closed its purchase of Hess Corp.’s New Jersey-based energy marketing business, making the combined company the largest business gas supplier on the East Coast and the second largest business power supplier in competitive U.S. retail markets. Direct, a subsidiary of Centrica plc, paid $731 million in cash plus net working capital, estimated at approximately $300 million.
Hess’ energy marketing business had revenues of over $6 billion in 2012 and is expected to deliver around $200 million of EBITDA in 2013. Its assets include purchase agreements with Marcellus shale gas producers, gas storage and pipeline capacity, and gas and power supply agreements. It also has a tolling arrangement on the Bayonne Energy Center gas-fired power plant, to supply power to customers in New York.
Maura Clark, who headed Direct Energy’s commercial and industrial business prior to the acquisition, will be president of the combined company.
Drawing of planned Exelong HQ in Baltimore (Source: BHC Architects)
Exelon Corp.’s plans for a corporate office building in Baltimore took a step forward as the city’s design panel recommended approval of a plan to add 103 apartments where office space was originally planned. The 23-story building — part of a $250 million first phase of the city’s Harbor Point development – will also include a 70,000-square-foot trading floor.
#2 Panel Maker Boosts Capacity as Solar Industry Slump Ends
SunPower Corp., the second-largest U.S. solar-panel maker, plans to boost manufacturing capacity by 25% in a signal that the industry is emerging from a two-year slump triggered by a global oversupply. Bloomberg Industries’ Large Solar Energy Index, which fell 87% between February 2011 and November 2012, has regained 55% of its value in the past year with SunPower shares quintupling.
Local 102 of the Utility Workers Union of America is picketing FirstEnergy’s Potomac Edison office in Frederick, Maryland, to pressure the company for a new contract to replace a deal that expired April 30. The employees have continued to work while picketing weekly. Local 102 represents about 680 linemen, substation workers, meter readers and technicians, and support personnel of Potomac Edison and West Penn Power, as well as 86 corporate employees.
After two marathon committee meetings failed to narrow choices, members will vote beginning today on more than a dozen proposals to make demand response more flexible and eliminate arbitrage opportunities in capacity auctions.
Facing a tight deadline for action, members of the Capacity Senior Task Force met in daylong sessions last week and yesterday in a so-far fruitless effort to reach consensus. As a result, members will be voting on six proposals to change the way DR is dispatched and 12 proposals to prevent speculation in the capacity auctions.
The CSTF votes, which will close Nov. 12, are intended to identify which proposals will be brought to a vote of the Markets and Reliability Committee Nov. 21. Voters will be asked to vote on whether or not they can support each of the proposals, with the one prop with the most support in each issue becoming the primary motion to be considered by the MRC.
Multiple Sponsors
Representatives of retailer Direct Energy and independent developer LS Power withdrew their demand response proposals in response to CSTF Chair Scott Baker’s entreaties to prune the unwieldy list. But a late addition from Exelon left the number of proposals at six, including others from PJM, the Independent Market Monitor, DR aggregator EnerNOC and the Maryland Public Service Commission.
PJM, Monitoring Analytics and EnerNOC also were among those proposing changes to the auction, along with industrial consumers and Old Dominion Electric Cooperative (ODEC). Although Calpine withdrew its proposal, EnerNOC posted two, including one that combined its original with that of ODEC.
Tight Deadline
Stakeholder panels often use informal polls to narrow their choices before taking formal votes. That option wasn’t available in this case because of PJM’s desire to enact the changes – which will require the approval of the Federal Energy Regulatory Commission — in time for the 2014 Base Residual Auction.
PJM officials called for changes to the design and dispatch of DR after heat waves in July and September, which they said illustrated the need to make quicker and more targeted use of the resources.
The changes under consideration could reduce DR’s minimum lead and maximum run times as well as allowing subzonal dispatch and eliminating the need to declare an emergency before dispatch.
A proposal outlined yesterday by Market Monitor Joe Bowring would eliminate the six-hour maximum dispatch and the cap of 10 dispatches per year, essentially ending the limited and extended summer DR products.
`Mass Market’ DR Programs at Risk?
Empower Maryland Program Ad (Source: Pepco)
Walter Hall, of the Maryland PSC, proposed an alternative that would protect programs for residential and small business customers of the state’s three investor-owned utilities and one cooperative.
Hall said the commissioners and staff believe some of the changes being contemplated would threaten the “mass market” programs, which are responsible for more than 600 MW of demand reduction. (See States, LSEs on Collision Course with PJM over DR Changes)
Hall said the programs may not be able to respond on a subzonal level as PJM desires.
Bowring, however, was unmoved. “I don’t think there’s any reason to exempt anyone from subzonal dispatch,” he said. The monitor’s proposal would seek to go even further, to nodal dispatch.
While Pepco has expressed concerns about the proposed changes, Hall acknowledged Baltimore Gas & Electric has told the commission it believes the utility’s program can adjust to the changes sought by PJM.
Auction Arbitrage
(Source: Monitoring Analytics)
DR providers also would be affected by proposed changes to capacity auctions. Because clearing prices in Incremental Auctions (IAs) are usually lower than those in the Base Residual Auction (BRA), participants can profit by over-committing in the BRA and buying out their commitments in the IAs. (See MIC to Investigate Arbitrage in Capacity Market)
The PJM Industrial Customer Coalition introduced a proposal that it said could reduce procurements in future BRAs by more than 6,000 MW by correcting overly bullish load forecasts. The IMM’s proposal would bar PJM from selling any excess capacity in the Incremental Auctions.
Facing continued skepticism from Wall Street, Exelon Corp. CEO Christopher Crane said last week that the company would begin shutting down unprofitable power plants if energy prices don’t rebound within a year.
Crane made his comments Wednesday, after the company announced third-quarter operating earnings and a week after Jefferies & Co. downgraded the company to “underperform.”
The company, the largest nuclear power generator in the country, has seen its stock drop more than 20% in the last six months due to weak capacity prices and margins pinched by low natural gas prices and demand growth.
Three Mile Island Nuclear Facility in 2013 (view from Goldsboro, PA; source: Wikimedia Commons)
Exelon executives have been counseling patience, saying energy prices will revive with the planned retirements of 11,000 MW of coal-fired generation in PJM. Crane said last week there was a limit to the company’s own patience.
“We continue to take a hard look at our assets and determine their economic viability,” Crane said on an analysts call. We will shut down facilities that we do not see on a path to a long-term, sustainable profitability.”
Exelon’s stock rose 1.8% to $28.55 per share following Crane’s comments. It closed yesterday at $28.61.
Analysts say the nuclear plants most at risk of being shuttered are Three Mile Island in Pennsylvania, Clinton in Illinois, Oyster Creek in New Jersey and R.E. Ginna in New York.
Exelon reported operating earnings of $667 million, beating analysts’ estimates. The company was boosted by Commonwealth Edison, which generated operating earnings of $127 million, up 41% percent, as it benefited from Illinois’ 2011 Energy Infrastructure Modernization Act, which provides faster and more frequent returns on utility investments.
At the same time, earnings at Exelon Generation, the company’s merchant business, dropped 10 percent from last year, to $411 million.
Jefferies analyst Paul Freemont cited the unit’s lackluster performance in concluding that the company’s should trade at a discount to the group average price/earnings valuation. “Additionally, the high cash spending of Exelon on nuclear fuel and maintenance results in very little free cash flow generated by the company,” Freemont wrote.
PSEG, PPL Earnings
Also reporting earnings last week were PPL Corp. (PPL), which missed analysts’ expectations, and Public Service Enterprise Group Inc. (PEG), whose results were in line with expectations.
PPL reported quarterly earnings of $410 million, up $55 million, or 15% from a year ago. For the first nine months of 2013, PPL earned $1.9 billion, versus $2 billion for the first nine months of 2012.
Weakness in the company’s supply, corporate and other segments were partially offset by improvements from its regulated utilities in Kentucky, Pennsylvania and the United Kingdom.
Public Service’s results were mixed, with earnings of 77 cents a share meeting analyst expectations and revenues, $2.55 billion, exceeding them.
Earnings Upcoming
Other PJM utilities will be holding calls to discuss their earnings this week:
PJM could get 30% of its generation capacity from wind and solar power without harming reliability and while reducing prices, a preliminary study released last week concludes.
But owners of coal and combined cycle generators would face reduced run times and even lower prices than currently – even as their units suffer increased wear and tear from cycling to support renewables’ intermittency.
GE Energy Management, which conducted the study, outlined the preliminary results during a conference call last week. “Even at 30% penetration, results indicate that the PJM system can handle the additional renewable integration with sufficient reserves and transmission build out,” GE said. “…All the simulations of challenging days revealed successful operation of the PJM real-time market.”
Multiple Scenarios
PRIS Scenario Definitions (Source: GE Energy Consulting)
The study looked at multiple scenarios for integrating increased wind and solar generation to the PJM grid. GE was charged with examining the operational, planning, and market effects of a large-scale integration of renewable power as well as what PJM will have to do to absorb it.
Current state requirements are expected to increase renewable generation to 14% of capacity, up from the current 2%.
The study estimated that increasing renewable capacity to 20% would require 820 miles of new transmission lines at a cost of $3.8 billion. Electric production costs would be cut by $9 billion annually, a 25% reduction, while carbon pollution would be cut by 80 million tons.
A 30% renewables goal would require 1,182 to 2,946 miles of new transmission costing $5 to $14 billion. Production costs would decrease by $13 billion (35%) per year and carbon emissions would decline by 140 to 200 million tons annually.
Increased Cycling, Reduced Revenue
LMP by PRIS Scenario (Source: GE Energy Consulting)
GE predicts coal and combined cycle generation starts will increase and hours online will decrease, resulting in reduced net revenue and increased forced outage rates.
Combined cycle units perform most of the on/off cycling, seeing a 35% displacement relative to the business as usual scenario. Coal units perform load follow cycling, suffering an 18% displacement. The cost impacts would fall most heavily on combined cycle and supercritical units.
For examples, cycling costs for supercritical coal would increase from $0.66/MWh under the 14% RPS scenario to $2.22/MWh in the 30% “Low Offshore + Best Onshore” scenario, which envisions 228 GWh of wind and 48 GWh of solar.
Although on/off cycling and load-following ramps do increase emissions over steady state levels, emission levels do not change dramatically with higher levels of renewable generation.
Operational Impacts
Net Effect on Cycling Damage by PRIS Scenario (Source: GE Energy Consulting)
The study found that higher penetrations of renewable energy would create significantly different operational patterns. “Although there were occasionally periods of reserve shortfalls and new patterns of combustion turbine usage, there were no instances of un-served load,” GE said.
Maximum regulation would increase from 2,000 MW for load only to approximately 3,000 to 4,000 MW in the 30% scenarios when 100,000 MW of new renewable capacity was added.
Diminishing Returns
The analysts concluded that expanding from 20% to 30% renewables “does not appear to be economically attractive.” GE will meet with PJM stakeholders to discuss the final report on Dec. 5.
