Coal boosters who hope carbon capture technology will ensure the fuel’s future will find little support in a new report conducted for planners in the Eastern Interconnection.
EPA’s proposed New Source Performance Standards for greenhouse gases will likely make it impossible to permit new coal-fired generation that doesn’t include Carbon Capture and Storage (CCS) technology.
But the report notes that the Department of Energy’s flagship CCS project, FutureGen in Illinois, “has experienced multiple delays and changes of scope and design [and] its prospects remain uncertain.”
Even if CCS becomes economical, the report concludes, the higher capital costs of coal generators means CCS “may be first deployed on natural gas plants before coal-fired plants, if natural gas prices remain low.”
“… Any state-level incentives to support coal mining and encourage the use of coal face an uphill battle in contending with these challenges.”
(Source: EPA)
The report also predicts the retirement of more than 50 GW of current plants between 2013 and 2016, in addition to the approximately 12 GW retired during 2010 through 2012. Of the 269 GW of coal capacity in the Eastern Interconnection, about one-third is located in five states that fall all or partly within PJM: Ohio, Indiana, Pennsylvania, Illinois and West Virginia. The average age of coal units in these states will be nearly 50 years by 2015.
The study, “Current State and Future Direction of Coal-fired Power in the Eastern Interconnection,” was conducted by ICF International for the Eastern Interconnection States’ Planning Council and the National Association of Regulatory Utility Commissioners (NARUC) with funding from DOE.
The Markets and Reliability Committee approved agenda items 2, 4 and 5 unanimously Thursday. Details are below:
2. PJM MANUALS
A. Manual 28: Operating Agreement Accounting
Reason for change: Revises the manual to reflect Tariff changes regarding lost opportunity cost compensation, as approved by FERC in docket ER13-1200.
The changes regard the amount of lost opportunity costs that a generator receives when PJM ordered it to reduce its output to maintain system reliability.
PJM made the changes to ensure that generators were not rewarded for operating units above the Maximum Facility Output specified in their interconnection agreements.
PJM told FERC the change was needed to prevent generators from causing constraints by operating above their Maximum Facility Output and then being rewarded with lost opportunity cost payments when PJM orders them to reduce output.
The new rules limit lost opportunity cost compensation to the lesser of the Maximum Facility Output or Economic Maximum (the highest incremental megawatt output level the unit can achieve while following economic dispatch).
Impacts:
Changes sections 5.2.6 and 5.2.8 (Operating Reserve & Reactive Services Lost Opportunity Cost Credits) to limit lost opportunity cost compensation.
Section 7.2 (Shortage Pricing) amended to incorporate calculation details for non-synchronized reserve market lost opportunity costs.
Modifies section 5.3 (Operating Reserve) to correct errors and provide clarifications on exempting deviations during shortage conditions; adds revisions for associating interfaces to the East or West BOR regions.
Modifies sections: 5.2.3 to incorporate details of Lost Opportunity Cost Credit for Synchronous Condensing; 5.2.6 (Wind Lost Opportunity Cost) to align language with Tariff; 17.3 (Allocation of Annual and Monthly FTR Auction Revenues) to correct section reference.
PJM contact: Stan Williams
B. Manual 14B: PJM Region Transmission Planning Process
Reason for changes:Updates to reflect changes from FERC Order 1000, switch to two-year planning cycle and revised benefit/cost test for Market Efficiency projects.
Impact:
Separates Reliability and Market Efficiency into subsections
Adds a new section (2.1.2) to explain two-year planning cycle on Market Efficiency projects.
Changes to reflect Order 1000.
Changes energy market benefit calculation component of benefit/cost ratio for Market Efficiency projects eligible for regional cost allocation. The change in total energy production cost and change in load energy payments (previously weighted .70/.30) will be equally weighted.
PJM contact: Tim Horger
4. PARAMETER LIMITED SCHEDULES (PLS) REVISIONS
PJM will add new processes for generators seeking exemptions from operating parameters under changes endorsed by the MRC.
The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.
Reason for change: The change will reduce administrative burdens on members.
Impact: The proposed change would create three types of exemptions:
Temporary Exception: A one-time exception of 30 days or less;
Period Exception: An exception lasting for at least 31 days but no more than one year during the 12 months between June 1 and May 31; and
Persistent Exception: An exception lasting for at least one year.
The changes will require revisions to Attachment K of the OATT, Schedule 1 of the Operating Agreement and section 2.3.4 of Manual 11: Energy & Ancillary Services Market Operations.
Assuming FERC approval, the changes will be effective Oct. 1.
PJM contact: Jacqui Hugee
5. STAKEHOLDER PROCESS ON TRIENNIAL CONE REVIEW
Members will consider changes to the Cost of New Entry (CONE) triennial review process under a problem statement and issue charge approved by the MRC. CONE values are used in PJM’s Reliability Price Model (RPM) to obtain capacity resources.
Reason for problem statement: PJM and members agreed to explore changes in the review process in a settlement approved by the Federal Energy Regulatory Commission in January (Docket No. ER12-513).
Impact: The inquiry will assess the use of the Handy-Whitman Index of public utility construction costs for adjusting CONE and consider other potential changes.
PJM is required to file Tariff changes with FERC in time for the 2014 triennial review or a status report if stakeholders are unable to reach consensus on changes.
Duke Energy agreed to quit burning coal at its share of the Wabash River Station power plant in western Indiana by June 2018 under a settlement with environmental and citizens groups that also calls for the company to increase its investments in renewable energy. The Natural Resources Defense Council ranked the Wabash River Station ninth among 25 coal-fired power plants it says are responsible for half of the mercury pollution in the Great Lakes region.
The settlement ends the activist groups’ challenge of Duke’s state air permit for its new $3.5 billion, coal-gasification plant in Edwardsport that went online this summer.
The Maryland Public Service Commission deferred action for one week on a request from Dan’s Mountain Wind Force LLC that its deadline to start building wind turbines be extended until Dec. 31, 2014. The PSC staff recommended approval of the extension request, saying the company had solved financial problems with an agreement with Exelon Corp. to fund construction and eventually purchase the project.
The U.S. Department of Energy and the state of New Jersey announced plans to design a small electric grid that will serve the state’s transit system and withstand the onslaught of storms like Superstorm Sandy. The micro grid will power the transit system’s rail operations between Newark, Jersey City and Hoboken.
The Chemical Industry Council of New Jersey and the state’s Division of Rate Counsel are balking at the expansion of PSEG’s solar power program, calling it too expensive. Public Service Electric & Gas won state regulatory approval of a plan to expand its “Solar4All” program by putting solar panels on factories, warehouses and landfills.
The chemical trade group says power costs for New Jersey industrial customers are already 59% higher than the national average.
Virtually all the nearly 5,000 comments filed on a proposed settlement of coal-ash lawsuits against Duke Energy opposed the deal or called for hearings on it. North Carolina filed suit in August against 12 Duke Energy coal-fired power plants where it said ash has polluted water.
The actions followed earlier suits against Duke’s Riverbend and Asheville plant, meaning that all 14 of Duke’s North Carolina coal plants are now the targets of state litigation.
Attorney General Roy Cooper said a state Supreme Court ruling should lead to lower utility profits and customer rates. The court backed Cooper’s appeal of Duke Carolinas’ 2011 rate case, which increased rates 7.2%, saying that the state Utilities Commission didn’t fully document the impact to customers of the return on equity granted Duke.
Cooper says state regulators should heed that ruling in reducing ROE in a rate case currently before them.
American Electric Power says there is no basis for an analyst’s report suggesting the company might sell its Ohio power plants. The report, from UBS Investment Research, comes as AEP is changing its structure to make the Ohio plants into a new subsidiary.
An AEP spokeswoman said there are “no current plans to sell that business.” AEP has about 9,000 MW of generation in Ohio, the company’s largest market among the 11 states where it has utility customers.
The spokesman for Ohio Gov. John Kasich mocked a Democratic legislator who asked the governor to release documents on the sudden resignation of the Ohio EPA’s chief water expert. “If she had her way, we’d all be living on a collective farm cooking organic quinoa over a dung fire,” Kasich’s spokesman said. “So, I think we’ll take her views in context.”
Meanwhile, the Associated Press reported that coal interests have contributed about $50,000 to Kasich and another $170,000 to state lawmakers since 2011.
Dayton Power and Light Co. won’t be offering gimmicky plans to lure customers as its Ohio market opens to retail competition, company officials said. “We’ll try to keep it on the straight and narrow,” CEO Phil Herrington told the Dayton Daily News in an interview.
The state Environmental Quality Board approved a draft regulation that officials said will strengthen environmental performance standards for oil and gas activities.
The proposal includes provisions covering exploration in parks and wildlife areas, spill prevention, waste management and the restoration of well sites after drilling. The rule also includes standards on the construction of gathering lines and temporary pipelines and provisions for identifying and monitoring abandoned wells.
The Department of Environmental Protection is recommending a 60-day public comment period on the new rules, with at least six public hearings across the state.
FirstEnergy Corp. estimated it will cost nearly $1 billion to decommission Three Mile Island Unit 2, which has been idle since its partial meltdown in 1979. The company disclosed the figure at a public hearing in Hershey Aug. 28.
FirstEnergy says it will continue to maintain the facility until Unit 1, operated by Exelon Nuclear, is shut down. Unit 1 has a license to operate until 2034.
The price of electricity for PPL Electric Utilities’ default residential customers will increase slightly while default commercial customers’ rates will drop. The new “price to compare” for residential customers will be 8.5 cents per kWh, up from the current 8.2 cents.
A federal judge threw out a lawsuit by conservation groups to block construction of a high-voltage power line by PPL and PSEG through the Delaware Water Gap National Recreation Area.
PPL agreed to pay a $60,000 fine to settle a complaint that it transferred a repair crew working on a high-priority outage in a 2011 snowstorm to fix a low-priority outage. The switch — a violation of the state utilities code — meant 1,326 customers in the higher-priority area were left in the dark about four hours longer than necessary.
A 14 MW solar project that will be Pennsylvania’s largest has won local land use approvals. Orion Renewable Energy Group, LLC should begin construction in about a year on the 100-acre site near Chambersburg in Franklin County.
In a joint forum on energy issues, Virginia gubernatorial hopefuls Terry McAuliffe and Ken Cuccinelli sparred over McAuliffe’s electric car company and Cuccinelli’s position on climate change and involvement in a dispute over gas royalties.
Natural gas-fired generation is the foundation of Dominion Virginia Power’s updated long-range energy plan, which also includes emissions-free resources to respond to U.S. greenhouse gas regulations.
The State Corporation Commission (SCC) has approved rules allowing Rappahannock Electric Cooperative customers to participate in a voluntary prepaid electric service program, the first offered in the state. The program allows a customer to prepay for electric service and permits the cooperative to suspend service when sufficient funds are not available.
Customers using the prepaid option will pay the same for electricity as those using traditional billing but will avoid having to pay a large deposit, late payment fees, or reconnection charges. The coop serves about 155,000 customers in a rural region from Fredericksburg to Front Royal.
Potomac Edison said it is complying with a West Virginia Public Service Commission investigation into the company’s billing practices, after residents complained about irregular billing and a lack of meter-reading.
The West Virginia Public Service Commission is seeking suggestions for simplifying its application process for homeowners seeking credits for rooftop solar systems.
PJM officials told members Thursday they may seek to lower the price cap on emergency demand response as a result of their review of the July 14-19 heat wave.
The comments came as PJM gave its most detailed explanation yet regarding the heat wave, with a lengthy presentation and answers to 64 questions submitted to officials after earlier presentations last month.
The more than two-hour presentation, which concluded the Markets and Reliability Committee meeting, seemed to exhaust most members’ questions. The Wilmington meeting room gradually emptied like a baseball stadium late in a lopsided game; by the end of the pre-Labor Day meeting, less than half of the members remained.
Much of the focus of the discussion was on PJM’s actions in the ATSI zone, where officials created a temporary interface July 17 to reflect the actions they were taking to ensure reliability.
(Source: PJM Interconnection, LLC)
PJM deployed emergency demand response in the zone on July 15, 16 and 18. During hours ending 16 through 18 on the 18th, DR set prices at $1,800/MWh, based on PJM rules that cap bids and offers at $1,000/MWh plus two times the reserve penalty factor (currently $400/MWh).
“The offer cap for emergency DR is probably too high at $1,000 when you add the two times the penalty,” said PJM Vice President of Market Operations Stu Bresler. Bresler recommended the limit be reduced to less than $1,000 plus only the primary reserve penalty. The cap “should be just short of [the price of] primary reserves,” Bresler said.
DR also was dispatched in the PJM, PPL and AEP South Canton zones on July 18 but did not set prices there. DR provided 92% to 102% of its obligations, depending on zone, PJM said.
Below is a summary of several key questions and answers. Unless otherwise attributed, direct quotes are from PJM’s written responses to member questions.
ATSI Interface
Q. Why did PJM create the pricing interface for the ATSI zone and not for AEP’s overloaded South Canton transformer? Was the interface necessary for dispatching demand response?
A. PJM created the ATSI Interface because its controlling actions were taken to address multiple post-contingency overloads in the area in addition to reducing load on the South Canton transformer. “Because a zonal action was being taken to limit imports into the zone in aggregate, the ATSI Interface provided the price signal that most appropriately reflected system conditions.”
PJM didn’t need the interface to call on Emergency DR. Without the interface, however, “other transmission constraints may have bound but the price impacts would have likely been inappropriately more localized.”
Some members said PJM should document in its manuals the process for adding localized interfaces in the future. PJM said it acted without giving members prior notice because of the urgency of the situation. But officials said they are “open to discussing a process that allows ample time for stakeholders to be notified of such new interfaces provided that it allows for flexibility for unforeseen system conditions to be priced accurately.”
South Canton Transformer
Q. What was the quantity and general characteristics (size, fuel-type, reason for outage) of the generator outages that resulted in the overload on the South Canton transformer? (Different quantities have been reported in different presentations, leading to some confusion as to the actual amount of generation that was unavailable).
A. PJM said it could not provide specifics on the generator outages, which totaled about 2,700 MW north and east of South Canton. “The response to this request would contain market sensitive information that PJM is not able to provide.”
Q. What is the limit on this transformer? What are the details of the transmission upgrade that will relieve the limit?
A. PJM was using a 95-degree normal rating of 1718 MVA, based on data submitted by AEP in November. The rating was raised to 1852 MVA on July 17 after AEP informed PJM that the rating submitted in November was incorrect. Officials said they don’t know the reason for the error.
AEP is scheduled to replace a disconnect switch on the transformer (RTEP project b1972) by October 4, which will increase the unit’s ratings to 2713 MVA (summer normal)/2922 MVA (summer emergency).
Operations
Q. Why did TVA issue a TLR 5b on July 15?
A. “TVA issued a TLR 5b [transmission loading relief] for a unit trip that caused an overload on their system. Both Firm and non-Firm contracts were curtailed as a result.”
The TLR cut 3,381 MW of imports to PJM, including 29 MW of firm imports.
Marji Philips, of Hess, questioned whether TVA could have avoided the TLR by redispatching its generation but decided against doing so because the TLR was cheaper. “TVA had a reputation for leaning on the system,” she said.
PJM CEO Terry Boston, former executive vice president of system operations for TVA, said that TVA’s problem was caused when a MISO generator that was providing counterflow reduced its output. As soon as the MISO unit returned, TVA’s problem was cured, Boston said. “It did not look like a market issue. It looked like a transmission issue,” Boston said.
Officials said they are working to improve their coordination with TVA. They said the incident raised questions about PJM’s control over external resources that are block scheduled and not pseudo-tied.
“We don’t have authority to reduce the output of external resources to relieve constraints,” Bryson said. The plants could keep running and sell their energy to other customers, he said.
Price Formation
Q. Was Shortage Pricing invoked? If not, why considering that a Maximum Emergency Generation was invoked?
A. “In this case, a Shortage event did not occur; reserves are not monitored in individual transmission zones such as the ATSI zone, and actual primary reserves were not less than the reserve requirement in either Mid-Atlantic and Dominion (MAD) or RTO. In real-time, hot weather procedures, including alerts of reserve shortages, are communicated to the market via Emergency Procedure messages.”
Demand Response
Q. Does Operations have any biases about using DR? Don’t want to use it? Want to use it? Want to use it to get practice? Feel DR is cumbersome so don’t like to use it?
A. “There are operational characteristics of the current DR products (2 hour lead time, majority only available in emergency, etc.) that make DR difficult for the operators to use efficiently and PJM has initiated stakeholder discussions to adjust these characteristics. The vast majority of Emergency DR is long lead.”
Reserve Sharing Agreements
Q. What actions will PJM take to support a neighboring RTO that is short of its reserves and how does this action impact PJM LMPs and charges (for instance, would PJM curtail DR/load Max Emergency Generation to support a neighboring RTO)?
A. PJM has reserve sharing agreements with the Northeast Power Coordinating Council (including NYISO and ISO-NE) and with Virginia-Carolinas (VACAR) (including Duke Energy Carolinas, Progress and South Carolina Electric & Gas).
“The nature of these agreements are `good utility practice.’ They are not requirements to provide reserves at all times. A company may elect to not respond if they cannot provide. Because responding to a request is not required, PJM does not rely on shared reserves and does not include them in reserve calculations for scheduling and dispatch.”
Bryson added: “We cover our needs from the ancillary markets. When our internal markets are not sufficient we can call on external reserves. We don’t rely on external reserves to meet NERC compliance requirements.”
Financial Transmission Rights (FTRs)
Q. What happened to balancing congestion and Financial Transmission Rights revenues on July 18?
A. Balancing Congestion costs for more than three hours totaled about $238,000, approximately 0.2% of total of FTR revenue inadequacy in July. “It wasn’t huge but it wasn’t insignificant,” said Bresler.
During the three hours of congestion, the day-ahead market flow averaged 8% higher than real-time. “Day-ahead congestion on [the] South Canton transformer and lower load resulted in reduced flows into the ATSI zone in the Day-ahead market, although not completely down to the Real-time level.”
Forecasting
(Source: PJM Interconnection)
Q. How did peak loads compare with PJM’s forecasts?
A. PJM’s hourly integrated peak load during the July 2013 heat wave was 158,156 MW, which occurred on July 18 for hour ending 17. The Day-Ahead Load Forecast for that hour was 157,033 MW (99.2% of actual load).
The 50/50 Projected Seasonal Peak Load Forecast from the January 2013 Load Forecast Report was 155,553 MW (98.3% of actual).
PJM would create rules allowing batteries, flywheels and other advanced energy storage technologies to participate in its capacity market under a problem statement presented to the Markets and Reliability Commission on first reading Thursday.
The proposal was introduced by Janette Kessler Dudley of Demansys Energy, which aggregates commercial and industrial customers for participation in the regulation market.
Dudley said the purpose of the problem statement is to establish enrollment procedures. Because advanced storage technologies — which also include thermal storage and compressed air — are still being developed, rules should not be limited to current products, she said.
In its second performance assessment of PJM’s capacity market, The Brattle Group recommended the RTO develop such rules: “Although the primary driver behind the development of these devices is to provide additional ancillary services to balance the grid, these resources could also participate in RPM.”
To do so, Brattle said, PJM will have to incorporate different ways for calculating capacity values. “Storage devices may be able to provide two types of capacity products: (1) an annual product, for devices that can sustain their capacity value for at least 10 hours; and (2) a limited product for devices that can sustain their capacity value for at least 6 but less than 10 hours.”
John Brodbeck, of Pepco, said he agreed PJM should consider the issue. “But we’re busy and here it is August. I don’t think there should be any changes” expected before the next base capacity auction in April, he said.
Energy storage received a boost from the Federal Energy Regulatory Commission in July with an order requiring PJM and other transmission providers to consider speed and accuracy in acquiring regulation resources. The order will make batteries, flywheels and other emerging technologies more competitive against slower-responding gas- and coal-fired generators in the regulation market. (See FERC Rule Boosts Storage, Renewables.)
Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal the MRC endorsed Thursday after a lengthy discussion. The proposal was approved over the objections of five members.
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.
Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
Roy Shanker, representing NextEra and LS Power, said the proposal could result in PJM spending millions on upgrades that produced inconsequential improvements to the system. Shanker said the 1.15 trigger could result in spending to relieve theoretical constraints that don’t actually result in price separation in the auction.
“Where else do we allow spending of $5 million with no evaluation of benefits, the potential for zero benefits, and guaranteed returns to [transmission owners]?” Shanker asked in a presentation analyzing the change.
Marji Philips, of Hess, said Shanker had identified a flaw in the proposal. “I don’t want to pay for something if there’s no benefit.” Philips later voted in favor of the change, however.
Walter Hall, of the Maryland Public Service Commission, said the issue should be sent to the Capacity Senior Task Force for further debate.
Others were not persuaded by Shanker’s argument. “We did not find it compelling and we don’t agree with the math,” said Ed Tatum, of Old Dominion Electric Cooperative.
Bill Schofield, representing the New Jersey Public Power Coalition, noted the volatility of CETL calculations. “We understand that the upgrade might have no immediate impact. But the probability is that it would provide value over its life,” he said. “We weighed the risk… We judged that this is a valid way to save load — consumers — a significant amount of dollars.”
Susan Bruce, representing the PJM industrial Customer Coalition, agreed with Schofield. “We think that the benefit certainly outweighs the cost.”
“This isn’t to block transmission from getting built” but to ensure it’s needed, Shanker responded. He suggested PJM first run the auction and if the results showed a constraint, it re-run the auction assuming a transmission upgrade.
Jason Barker, of Exelon, said his company was “agnostic” until seeing Shanker’s presentation. He suggested PJM conduct a risk-adjusted analysis before approving such upgrades.
PJM officials said those suggestions were not workable.
“We can’t do a cost benefit analysis,” said PJM Executive Vice President for Operations Mike Kormos. “That’s the problem.”
PJM Executive Vice President for Markets Andy Ott said adding the two-step process would extend the auction by at least a week. “It’s just the nature of the complexity of the auction.”
“$5 million is a very small number. [Shanker’s proposal is] so far from practical that we said, `Thanks for your comment. Let’s move on.’”
Panda Power Funds, a Texas-based private equity fund, last week announced two big investments in PJM, proposing a 859 MW natural gas-fired power plant in southern Maryland and purchasing rights to a planned 829 MW natural gas generator in rural northern Pennsylvania.
Planned Liberty Power Plant (Source: Panda Power)
The fund announced Aug. 22 that it had completed the acquisition and financing of Moxie Energy’s planned Liberty combined-cycle generating station in Bradford County, Pa. The fund said it is the first new generator developed to take advantage of its proximity to the Marcellus Shale gas formation. Construction will begin immediately, and commercial operations are scheduled to begin by early 2016, the company said.
The announcement came a day after the fund announced plans for the 859 MW Mattawoman generator in Prince George’s County, Md., a suburb of Washington, D.C.
Founded in 2010, the fund has invested in three combined-cycle power plants currently under construction in Texas, and a 20 MW photovoltaic solar farm in Pilesgrove Township, N.J., which was completed in 2011.
Todd W. Carter, president and senior partner, said the Liberty project was one of several opportunities the fund considered in PJM. The Liberty plant will use Siemens’ H-class gas turbines, which claim operating efficiencies of 60% and will be cooled by air rather than water. Panda Power will be the majority owner of the project with Moxie Energy retaining a minority share.
Drawing of Planned Mattawoman Plant (Source: Panda Power)
The Mattawoman plant will use recycled municipal waste water for cooling. Pending approval of the Maryland Public Service Commission, the fund hopes to begin construction by early 2015 with completion by mid-2017.
Energy prices and coal generation rebounded in the first half of 2013 as natural gas costs increased, PJM’s Market Monitor reported in its mid-year report.
The load-weighted average LMP was $37.96 per MWh, up nearly 22% from the first half of 2012 as natural gas in eastern PJM briefly spiked at more than $6/MMBtu.
(Source: Monitoring Analytics LLC)
While LMPs were up compared with 2012, and also higher than 2009, they remained lower than 2008, 2010 or 2011.
Fuel Mix
Coal prices were flat in the first half of the year, leading to an 11% increase in generation by coal-fired units and an 18% drop in generation from gas units. Coal units provided 44% of total generation with nuclear units responsible for 35% and gas units almost 16%.
Coal represented 58% of real-time marginal resources in the first half of the year, a slight drop from 2012, while natural gas represented almost one-third of marginal resources, up from 30% in the first six months of 2012. Wind, which was not on the margin in the first two quarters of 2012, represented almost 6% of marginal resources in 2013.
Load
Average real-time load increased by about 2% from the first six months of 2012 while average day-ahead load, increased by almost 12%, driven by the continued growth of up-to congestion transactions.
(Source: Monitoring Analytics LLC)
Virtual bids dropped by one-quarter year-over-year. Physical companies — utilities and customers which primarily take physical positions in PJM markets — increased their share to 75.5%, up from less than 64% in 2012.
Market Competiveness
The monitor’s evaluation of market fundamentals was unchanged from the 2012 report, with only the regulation market results not judged competitive.
The monitor judged the regulation market results “indeterminate.” It found the market structure not competitive because one or more pivotal suppliers failed the three pivotal supplier test in 90% of the hours for the first six months. However, participant behavior was considered competitive due to PJM rules that require competitive offers when the three pivotal supplier test is failed.
PJM made several changes to the regulation market in 2012, including new optimization methods.
“It is too early to reach a definitive conclusion about performance under the new market design because important parts of the design are inefficient and because there is not yet enough information on performance,” the monitor said.
In its response to the 2012 report, released in May, PJM took issue with the monitor’s criticism of the market.
“PJM believes there is ample evidence of competitive market behavior in the regulation market and the IMM conclusion is based on the IMM’s disagreement with opportunity cost calculation rules that were endorsed by members and approved by the FERC.”
Recommendations
In addition to summarizing changes in prices and other metrics, the monitor’s new report called for increased transparency and added several new recommendations on the energy market, operating reserves, demand response, ancillary services and Financial Transmission Rights. (See Market Monitor Recommendations)
The monitor called for additional transparency regarding constraints affecting energy prices, and on unit retirements, “in order to permit new entrants to address reliability issues.”
It also said the market needs better information about the reasons for operating reserve charges. “Data on the units receiving operating reserve credits and the reasons for those credits should be made publicly available to permit better understanding of operating reserve levels and to facilitate competition for providing the same services,” the monitor said.
The monitor also called for action to address what it called the failure of capacity market prices to reflect fundamentals, including “better [Locational Deliverability Definitions], the effectiveness of the transmission.
Who says Congress can’t pass energy legislation? Two bills approved with bipartisan support and signed by President Obama this month may open PJM to new generation from a renewable energy source many thought was fully exploited: hydropower.
(Source: US Department of Energy)
The legislation streamlines regulations on small hydropower sites, which advocates say could unlock 12 GW of capacity at existing, non-powered, dams — about 1.5 GW of it in PJM.
A 2012 Department of Energy report identified the powering of non-powered dams as low-hanging fruit that could increase current U.S. hydropower capacity — 2,500 dams generating 78 GW — by 15%.
The report identified 80,000 non-powered dams (NPDs) including canal locks and those used to provide water supplies. The top 100 sites could add 8 GW of capacity with the top 10 facilities responsible for 3 GW.
PJM has nearly 150 non-powered dams with potential of at least 1 MW. The top 10 prospects total nearly 500 MW, one-third of PJM’s potential; seven of the top 10 are on the Ohio and Allegheny Rivers in Pennsylvania (see chart below).
(Source: US Department of Energy)
“Many of the monetary costs and environmental impacts of dam construction have already been incurred at NPDs, so adding power to the existing dam structure can often be achieved at lower cost, with less risk, and in a shorter timeframe than development requiring new dam construction,” said the report, done for DOE by the Oak Ridge National Laboratory.
The report did not consider the economic feasibility of developing each site, but added, “The abundance, cost, and environmental favorability of NPDs, combined with the reliability and predictability of hydropower, make these dams a highly attractive source for expanding the nation’s renewable energy supply.”
Two bills signed by President Obama Aug. 9 should make it easier to develop the potential of these sites.
The Hydropower Regulatory Efficiency Act (H.R. 267), amends the Public Utility Regulatory Policies Act of 1978 (PURPA) to exempt dams up to 10 MW from the licensing requirements of the Federal Energy Regulatory Commission (up from 5 MW). It also amends the Federal Power Act to relax regulations on conduit hydropower facilities — manmade water conveyances used for agricultural, municipal, or industrial consumption — of up to 40 MW.
Also under the law, DOE will study ways that existing pumped storage facilities can be upgraded to support intermittent generators and enhance grid reliability.
The second bill, the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act (H.R. 678), authorizes the U.S. Bureau of Reclamation to develop small hydropower projects at existing canals, pipelines and other manmade waterways.
Duke Energy Carolinas reached a settlement with stakeholders on a revised energy efficiency plan that will add programs for multifamily housing and commercial customers.
The agreement with the Environmental Defense Fund and the North Carolina Utilities Commission’s consumer advocates includes a $400,000 bonus if the company increases energy savings by more than 1% in any year.
Under the old program, Duke recovered the costs of the energy savings program as though they were an investment in a power plant. The new plan will use a shared-savings mechanism similar to that used by Dominion North Carolina Power and Duke Energy Progress.
The new offerings will be available in January if the commission, which held a hearing on the proposal Aug. 19, approves.
Duke Energy Renewables has acquired the 4.5 MW Sunset Reservoir Solar Power Project from developer Recurrent Energy. The system’s almost 24,000 solar panels, mounted above the Sunset Reservoir, provides power for municipal facilities through a 25-year power purchase agreement with the San Francisco Public Utilities Commission (SFPUC).
The U.S. Nuclear Regulatory Commission met with Duke Energy Aug. 19 to discuss an October 2012 incident in which the failure of radiator fan belts caused a shutdown of the Robinson nuclear plant’s shutdown diesel generator.
An NRC spokesman said the poorly maintained fan belts could have meant the generator was not available during a loss of offsite power at the plant in Hartsville, S.C. The agency said it will announce any penalties over the incident at a later time.
NRG Energy Inc. must defend a lawsuit claiming that ash and contaminants from its coal-fired power plant in Springdale, Pa., damaged nearby properties, an appeals court ruled. The U.S. Appeals Court in Philadelphia reversed a lower-court decision dismissing the suit, rejecting NRG’s claims that the federal Clean Air Act pre-empts state law claims by property owners.
The residents claim that odors produced by the plant, 18 miles northeast of Pittsburgh, made them “prisoners in their own homes” while ash and unburned byproducts settled on their properties.
Covanta Holding Corp. announced Aug. 19 it has purchased a 21 MW waste to energy plant in Camden, N.J. from a subsidiary of Foster Wheeler AG. The acquisition increased Covanta’s holdings in PJM to 15 generators totaling about 569 MW.
