A novel project: Energy generated from wind turbines (in Wyoming) powers compressors (in Utah) that inject high-pressure air into salt caverns underground. The compressed air is stored for high-demand hours.
Duke Energy is joining a novel $8 billion project using Wyoming wind energy and Utah salt mines to provide power to Los Angeles.
Duke-American Transmission Co. (DATC) is one of four companies proposing the project, which would be the first time underground compressed-air storage would be used on such a scale in the U.S.
“This project would be the 21st century’s Hoover Dam — a landmark of the clean energy revolution,” said Jeff Meyer of Pathfinder Renewable Wind Energy, one of the four companies involved.
Meeting California Renewable Goals
The project is one of about 200 plans California officials will consider to help it reach its renewable-energy goals. Duke and the other companies said they would be submitting the proposal in early 2015.
The project would start with a $4 billion, 2,100-MW wind farm north of Cheyenne, Wyo., to be built by Pathfinder Renewable Wind Energy. Power from the facility would be sent to an energy storage facility near Delta, Utah, on a $2.6 billion, 525-mile transmission line to be built by DATC.
In Utah, four massive caverns — each a quarter-mile high and 290 feet in diameter — would be carved out of underground salt formations.
At times of low demand, electricity from the wind farm would power compressors that would inject high-pressure air into the caverns.
At times of high demand, the high-pressure air, combined with a little natural gas, would power eight generators. The $1.5 billion facility, to be built by Pathfinder, Magnum Energy and Dresser-Rand, would be rated at 1,200 MW.
An existing 490-mile transmission line would deliver the power through Utah, Nevada and California to Los Angeles.
Intermittent Wind
(Source: Dresser-Rand)
The project is intended to address the challenge of matching wind’s variable output with energy usage patterns.
California’s wind farms tend to generate most of their power in the evening, dropping off when energy demand reaches its peak. Wyoming wind, by comparison, tends to increase later in the day.
Dresser-Rand designed and built the first facility using compressed-air energy storage (CAES) in Alabama; the facility is linked to a coal-fired generating station. The 110-MW unit went into operation in 1991, and boasts a 96.7% reliability record in generation mode. There is one other operating CAES facility in Huntorf, Germany.
If the project goes forward, one of the first jobs will be excavating the caverns, using a process called solution mining. Magnum Energy, which has excavated other storage caverns, said it would inject water into the underground salt formations, dissolving the salt and pumping the salt solution to the surface, where it would be dried. Underground caverns have long been used for oil and natural gas storage.
The project, which is not expected to be completed until 2023, would be subject to numerous state and federal regulatory approvals, none of which has been applied for yet.
Exelon Generation is adding another 2,000 MW of fossil generation to its fleet in Texas, which will bring the company’s total generation in ERCOT to nearly 6,000 MW.
The company announced Monday it was investing more than $500 million in four gas and two steam turbines to build combined-cycle plants at two of their existing sites.
General Electric H-Class Turbine (Source: BusinessWire)
In addition to using the most fuel-efficient technology, the plants will be air-cooled, rather than water-cooled, a big plus in drought-threatened Texas. The turbines will be General Electric H-class models, which GE says will allow more than $8 million in fuel savings per turbine a year.
French company Alstom is providing the heat recovery steam generators. Earlier this year, GE agreed to buy the power arm of Alstom for $16.8 billion.
It will be the first use of the new GE turbines in the U.S.
“What we see is a clean-energy future that includes this kind of new technology, which uses little water and produces few emissions while generating electricity at a very low cost,” said Ken Cornew, president and CEO of Exelon Generation.
The new combined-cycle plants are to be built at Exelon Generation’s Wolf Hollow site in Grandbury, southwest of Fort Worth, and the Colorado Bend plant in Wharton County, southwest of Houston.
Exelon Generation currently has six generating stations in Texas with a combined output of about 3,700 MW. It has wind farms generating an additional 281 MW, for a total of nearly 4,000 MW.
The two new plants will boost that total to nearly 6,000 MW. Exelon said it would start construction of both plants in 2015 and expects both to be in service by 2017.
Exelon needs $580 million in additional revenue annually to keep its Illinois nuclear fleet in operation, Senior Vice President Kathleen Barron told the Illinois Commerce Commission last week.
Exelon has been saying for months that unless pricing for the output of its Illinois nuclear stations improves, it may need to shut them down. Barron said the company figures it needs about $6 more per MWh for continued operation. That would translate to rate increases of about 8% in Chicago and more downstate, where prices are cheaper.
And even that might not do it. “While a $6/MWh payment or even less would be sufficient for some units, $6 may not be enough for others,” the company said in a statement. “Each of our 11 nuclear units in Illinois has a different cost structure and different requirements.”
Barron’s comments are part of a national campaign by Exelon to gain credits for its carbon-free output, and cut or reduce the federal wind production tax credit, to let its plants compete. Company lobbyists and executives have been delivering a consistent message since the spring. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Barron said the result of closing the nuclear stations would be significant for Illinois. “If the units at risk of closing today — representing 43% of the state’s nuclear generation — retire, they cannot be mothballed and later brought back online,” Barron said. “Together, they represent more than 30 million metric tons of avoided carbon emissions, given that they will need to be replaced with fossil generation to provide the around-the-clock electricity needed to serve customers in the state.”
Dominion Virginia Power is starting a $2 billion project that will underground 4,000 miles of outage-prone lines by 2026.
The target represents about 11% of the company’s overhead distribution lines, and placing them underground should result in increased reliability, the company said. About a third of the company’s 58,000 miles of distribution lines are now underground.
It said it will spend about $175 million a year moving the lines. The company is expected to file an application for a rate increase to pay for the project with the Virginia State Corporation Commission by the end of October. The rate increase would go toward the project, it said.
South Carolina Official Upset Duke Hasn’t Removed Ash Yet
A South Carolina Public Service commissioner said he thought Duke Energy was already removing stored coal ash from its sites in the state. He was surprised to learn it hasn’t started yet.
“I think it’s somewhat of a surprise to this commission that no ash is being removed because this has been an ongoing situation that we’ve heard about and talked about,” Commissioner G. O’Neal Hamilton said. “We’ve seen reports of trucks moving in North Carolina and I assumed that was happening here and it’s a little disappointing.”
The issue arose after environmentalists said that the company’s W.S. Lee Steam Station has coal ash lagoons that are leaking toxins into the surrounding area. Duke said it will present the commission with plans for the removal by the end of the year. Duke is converting the plant to burn natural gas. A Duke spokesman said plans are being made to remove coal ash from a number of sites in North Carolina as well, but they have not yet been implemented.
Ralph Rogers, Tennessee Valley Authority’s top lawyer, is retiring at the end of the year. Rogers started with the federal authority in 1979 and became TVA’s senior litigation attorney and ethics officer. He was the highest paid attorney in TVA history, making $1.9 million last year and $2.5 million the year before. High executive salaries at TVA have drawn fire from former Knoxville Mayor Victor Ashe, who said “most East Tennessee attorneys do not make a quarter of that amount (paid to Rodgers) in one year.”
Under the corporate-like board structure adopted for TVA by Congress in 2006, pay levels for the general counsel and other top officers at TVA have risen significantly over the past decade to more closely align with investor-owned companies rather than the government-level pay grades used by TVA in the past.
Public Service Electric and Gas started construction of a 10-MW solar plant on a former garbage dump in New Jersey, the latest and largest system of solar arrays the company is building. The project will sit atop a capped dump in Bordentown.
It’s part of a state-wide effort to use brownfields and under-used industrial sites to build solar plants to deliver energy to the grid. The company is planning to spend $247 million on this and similar projects. It is eying plans to build an even larger solar plant on another former dump in New Jersey.
Grid operators demonstrated resiliency during January’s polar vortex but more needs to be done to prepare for future cold spells, the North American Electric Reliability Corporation said in a report released today.
All-time Winter Peaks vs. Polar Vortex Loads by Pct. (Source: NERC)
NERC’s Polar Vortex Review noted that only one balancing authority shed load despite the fact that many areas in the Midwest, South Central and East Coast experienced temperatures 20 to 30 degrees below normal. (South Carolina Electric and Gas (SCE&G) dropped less than 300 MW, less than 0.1% of the total load for the Eastern and ERCOT Interconnections.)
Howard Gugel, NERC director of performance analysis, said the industry performed well “under extremely challenging circumstances. Industry owners and operators used all the resources at their disposal to keep the grid reliable.”
Grid operators relied on voltage reductions and demand side management to prevent load sheds. NERC said the performance validated its regular training and drills “as the operators and other [… entities were able to effectively and successfully implement emergency procedures.”
Record Cold
Forty-nine cities set new record lows, with Minneapolis shivering through 62 consecutive hours of temperatures below zero from Jan. 5 to Jan. 7. On Jan. 6, the average daily temperature in the U.S. was 17.9 F, the first time the average dropped below 18 F since 1997. The 17-year run of temperatures above 18 was the longest such span on record and occurred during a period in which an increasing portion of the generating fleet had become fueled by natural gas, NERC noted.
The cold pushed many generators beyond the temperature range for which they were designed.
Nevertheless, an analysis of NERC’s Generating Availability Data System (GADS) found that most generators units performed within the equivalent forced outage rate (EFOR) range expected based on the past five years. The exception was natural gas units, which had a higher-than-expected forced outage rate in January in two regions, the Midwest Reliability Organization and Southeast Reliability Corp.
Demand Records
Eight of 10 areas included in the study — all but ISO-NE and the Florida Reliability Coordinating Council (FRCC) — set all-time winter demand records on Jan. 6 or 7. The VACAR South reliability coordinator, which includes SCE&G, busted its record by almost 18%. (NERC’s review did not include the Western Electric Coordinating Council, which was largely unaffected by the polar vortex.)
Causes
Like PJM, other regions experienced fuel deliverability problems, natural gas pipeline outages and frozen equipment. The report catalogues dozens of cold-weather problems that led to outages, delayed starts or deratings, most of them involving the freezing of water and the gelling of oil and diesel fuel.
NERC’s report makes a number of recommendations but does not call for changes to existing mandatory reliability standards. Many of the recommendations are already being taken in PJM and other regions.
Among the recommendations:
Generators
Review and update power plant weatherization programs, including procedures and staff training.
Continue or consider implementing a program for winter preparation site reviews at generation facilities.
Review the basis for reporting forced and planned outages to ensure appropriate data for unit outages and de-ratings. The review found that planned and forced generation outages in some regions exceeded worst-case scenarios used in seasonal assessments.
Consider where appropriate the temperature design basis for their plants to determine if improvements are needed for the plants to withstand lower winter temperatures without compromising their ability to withstand summer temperatures.
Review internal processes to ensure their ability to secure necessary waivers of winter environmental and/or fuel restrictions.
Oil & Natural Gas
Review natural gas supply and transportation issues, and work with gas suppliers, markets and regulators to develop appropriate actions.
Include in winter assessments reasonable losses of gas-fired generation and considerations of oil burn rates relative to oil replenishment rates to determine fuel needs for continuous operation.
Continue to improve operational awareness of the fuel status and pipeline system conditions for all generators.
Ensure that on-site fuel and fuel ordered for winter is adequately protected from gelling.
NERC will conduct a webinar Thursday to provide a preview of its 2014-15 winter outlook and to discuss cold weather events including the polar vortex and the 2011 Southwest winter outage.
PJM officials said Wednesday they are amending their proposed capacity overhaul in response to dozens of mostly critical stakeholder comments.
“Already, based on the comments, we are making adaptations to our proposal. It’s extremely helpful to get your feedback,” Executive Vice President for Markets Andy Ott said at the beginning of the three-and-a-half-hour question-and-answer session on the proposal.
“We said all along it was a proposal,” Ott said later in the session. “I can’t say it enough. You’re not talking to a wall here. This isn’t a traditional stakeholder process but it is still a stakeholder process.”
On Monday, PJM released more than 300 pages of comments from more than 50 stakeholders. While the comments reflected the traditional load vs. supply divide, there was near universal unease with how quickly PJM is attempting to introduce a new Capacity Performance product and rewrite compensation and penalty policies. (See Something for Everyone to Dislike in Capacity Performance Proposal.)
Although Wednesday’s discussion was the last scheduled stakeholder meeting before PJM issues its final proposal Oct. 7, officials said they would consider one or two additional meetings.
The Board of Managers will make the ultimate decision on what PJM files with the Federal Energy Regulatory Commission following an Enhanced Liaison Committee meeting with members Nov. 4 in Philadelphia. Although the meeting will be limited to PJM members, representatives of state regulatory commissions will also have a chance to address the board before or after the meeting, officials said.
Ott said officials are targeting a FERC filing by Dec. 1 in order to have the changes in place for the May 2015 Base Residual Auction.
Ott said the board will likely make additional changes in the plan before filing with FERC. “I think there’s a very small chance that [the Oct. 7] proposal will be filed” at FERC, Ott said.
Below are some of the issues that generated discussion Wednesday.
Force Majeure
Mike Borgatti of Gabel Associates said PJM’s proposal for “the outright elimination of force majeure is untenable.”
Borgatti said the rules would allow a coal-fired plant to escape penalties if it were unable to operate because a sinkhole swallowed a nearby substation but not if the hole made the road to the plant impassible for coal deliveries. Another stakeholder observed force majeure would not apply for a gas-fired generator that lost its pipeline to the sinkhole.
Independent Market Monitor Joe Bowring, who opposes PJM’s proposal to add an additional class of capacity, said he supports the tightened force majeure rules. “The market doesn’t care why you’re out [of service]. If you’re not producing energy, you’re not producing energy. That’s all the market cares about. It’s impossible [for the Monitor and PJM] to manage a long list of excuses.”
Ed Tatum of Old Dominion Electric Cooperative said Bowring’s analysis was an inaccurate description of the Reliability Pricing Model. “This is a resource adequacy concept. It’s not a market. … Taking an academic view of what is not a market is not going to get us” improved performance.
Officer Certification
Generators are also balking over requirements that officers certify their plants’ ability to meet the Capacity Performance requirements. Borgatti said it could be impossible to certify that a generator holds a firm gas contract three years into the future.
Another member said the requirement introduced both organizational risk and personal risk to the officer. “You’re asking the officer to certify to an unknown risk that won’t be known until after the fact,” he said. He said PJM should eliminate the requirement or add a “safe harbor” provision.
The IMM says performance incentives will be sufficient to ensure reliability and that officer certifications are unnecessary.
Ott said PJM is aware of the risk of unintended consequences from the requirement. “We certainly heard that” from the comments, he said.
Capacity Performance Requirements
Others said PJM should relax its requirement that Capacity Performance resources be able to run at full output for 16 hours for three consecutive days during weather emergencies, saying it unnecessarily excludes demand response, energy efficiency and storage.
Wil Burns, an attorney representing public interest groups said PJM should broaden its Capacity Performance definition to include resources such as DR, EE and renewables that have no fuel risk and “that can be and have been there when needed.”
PJM’s Adam Keech said the requirement was intended to cover the daily summer peak or the two daily winter peaks. But he suggested PJM might relax the requirement saying, “I don’t want to say anything is etched in stone.”
“You’re getting a sense from us that the last thing we want to do is to discourage resources that can be there,” Ott said. But he said the RTO felt that it needed operational requirements and not “just rely on the economic pressure of a performance penalty. Striking that balance will be very key.”
Despite the appellate court ruling voiding FERC’s authority over DR, “PJM believes there’s a continuing role for demand response in the wholesale market,” Mike Kormos, executive vice president for markets, assured stakeholders. “It may be there in a different format.”
Kormos said PJM would integrate its plans for DR with the capacity market “once it’s clear how FERC wants us to move forward.”
Base Capacity Assumptions
Several speakers challenged PJM’s assumption that no base capacity will be available during the peak winter week. Tatum noted that the RTO uses a probabilistic approach to account for forced outages in its calculation of loss-of-load-expectation (LOLE) and installed reserve margins (IRM).
“Zero seems pretty on-off – kind of a low number to me,” Tatum said. “I think it would be good to have a consistent approach.”
Kormos said that to count on any base capacity during the winter peak “might be overoptimistic.”
“If you look at the number of gas units that never get gas on peak [winter] days,” when generation has to compete against gas demand for heating, “it’s not as draconian as it sounds,” Kormos said.
PJM has proposed that all but 15% of peak winter load be served by the new product. “I don’t think our thinking has changed a lot on that,” agreed PJM’s Tom Falin.
Market Power
Load representatives asked PJM and the Monitor to address market power concerns, saying the new product could be subject to withholding.
Susan Bruce, representing the PJM Industrial Customer Coalition, said “strong market power protection” would be essential to winning her group’s support.
Ott endorsed the Market Monitor’s suggestion of a must-offer requirement that allows generators to submit “coupled” offers with one price for Base Capacity and a higher price for Capacity Performance.
Bowring said the best way to reduce withholding risk is to use a single annual capacity product without the new product. (Bowring also has called for eliminating Limited and Extended Summer DR). Given the higher requirements and penalties on CP, Bowring said, there will be a “very substantial incentive” for generators to withhold.
But Bowring said his staff could review proposed costs for winterization or firm fuel within coupled offers the same way it currently screens offers under the avoidable cost rate (ACR) and avoidable project investment recovery rate (APIR).
“It’s very doable. I don’t want to understate the complexity of it. It’s going to be much more complicated than it is now.”
Cost Recovery
One generator representative said his company is concerned with being able to recover the additional costs to allow its plants to meet the CP standards. “Just because you put those costs in has no bearing on whether you’ll actually see recovery for more than one year,” he said.
Bowring acknowledged capacity revenues have “not been adequately compensatory.”
Ken Carretta of Public Service Enterprise Group said generators would face additional maintenance costs as well as capital expenditures – a disconnect with the current backward-looking ACR mechanism.
“We have to figure out a way to reflect that,” Bowring agreed.
The Federal Energy Regulatory Commission last week approved actions on four standards and policies proposed by the North American Electric Reliability Corp. and the North American Energy Standards Board (NAESB).
Notices of Proposed Rulemaking
Demand and Energy Data Reliability Standard
The NOPR (RM14-12) proposed to accept NERC reliability standard MOD-031-1 (Demand and Energy Data), which governs the collection of demand, energy and related data to support reliability studies. NERC said the proposal clarifies data collection requirements and adds transmission planners as entities that must report demand and energy data. Applicable entities are required to report actual peak hour demand from the previous year for comparison with forecasted values. They also must explain how their peak demand forecasts and demand side management forecasts compare to actual demand and demand side management. (See related story, Brattle: Missing EE Costing PJM Load $433M Annually.)
Communications Reliability Standards
The NOPR (RM14-13) proposed approval of two revised NERC standards, COM-001-2 (Communications) and COM-002-4 (Operating Personnel Communications Protocols). Among the requirements is the use of a three-part communications process when issuing operating instructions: recipients must repeat the instruction and receive confirmation from the issuer that the response was correct, or request that the issuer reissue the instruction. The standard establishes “zero-tolerance” enforcement for failure to use three-part communications during an emergency.
The commission ordered NERC to modify COM-001-2 or develop a separate standard that ensures that entities maintain adequate internal communications capabilities. It noted that a task force report on the 2003 blackout found that one of the causes of the outage was that FirstEnergy’s control center computer support and operations staff lacked effective internal communications procedures and “lacked procedures to ensure that its operators were continually aware of the functional state of their critical monitoring tools.”
Final Rule
Standards for Business Practices and Communication Protocols for Public Utilities
The final rule (RM05-5-022) incorporates the latest version of NAESB’s Standards for Business Practices and Communication Protocols for Public Utilities into FERC regulations. The revised standards reflect the commission’s Order 890 series of rulings and other orders. They include standards supporting Network Integration Transmission Service on an Open Access Same-Time Information System (OASIS); Service Across Multiple Transmission Systems (SAMTS); and commission policy regarding rollover rights for redirects. Modifications were also made to ensure consistency across the OASIS-related standards.
The rule also includes changes reflecting updates to e-Tag specifications and gas-electric coordination standards to provide consistency between the two markets.
Compliance Filing
Find, Fix, Track and Report (FFT) program
The commission approved NERC’s annual compliance filing on its Find, Fix, Track and Report (FFT) program, as well as two changes to the program. The order (RC11-6-004) approved NERC’s proposal to continue processing some moderate risk violations as FFTs. The commission also approved NERC’s proposal to extend the mitigation period after an FFT is posted from 90 days to one year, but it rejected a proposal to allow some mitigation activities to go beyond a year. “We do not believe that NERC has provided adequate support for the need for this proposal,” the commission said. “Further, we are concerned that mitigation periods of greater than one year could weaken the incentive for entities to expeditiously mitigate possible violations and delay necessary corrections.”
The following issues were approved by stakeholders with little or no opposition Thursday.
Markets and Reliability Committee
Manual Changes
Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines were revised to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.
Manual 14A: Generation and Transmission Interconnection Process was revised with the addition of a new section 1.14 regarding interim deliverability studies.
Manual 14D: Generator Operational Requirements was updated as part of an annual review. It includes changes reflecting North American Electric Reliability Corp. standard MOD-025-2.
FTR/ARR Senior Task Force
Members approved changes in the scope of the Financial Transmission Rights Senior Task Force. The task force was formed to identify ways to improve FTR funding levels. The new scope includes an examination of the role of virtual transactions on revenue adequacy and proposed solutions by the Market Monitor.
One sentence was struck from the revised problem statement as a result of objections by the Market Monitor. The sentence stated that: “With FTR underfunding that has occurred over the last several years, FTRs no longer perform the function of an effective hedge against congestion in the Day-Ahead market.” While PJM officials said it was factually accurate, the Monitor said it wasn’t appropriate for inclusion in the problem statement.
Credit Requirements
The MRC and Member Committee approved the following changes recommended by the Credit Subcommittee:
Risk Documentation Requirements – Removes the requirement that officer certifications be notarized, and allows electronic submissions. Eliminates the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
Virtual and Export Transactions Credit Requirement Timeframe – Reduces the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
Demand Bid Volume Limits – Establishes a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January.
Transition to 30-Minute Demand Response
The MRC and Members Committee approved a transition mechanism related to changes requiring more operational flexibility from demand response providers. The change would allow curtailment service providers to designate previously cleared megawatts as “non-viable” — unable to meet the new 30-minute-lead-time requirement. CSPs would be relieved of their obligations and have their capacity payments reduced. The transition mechanism was developed to comply with the Federal Energy Regulatory Commission’s May 9 ruling on the DR changes (ER14-822). Members also agreed to sunset the Capacity Senior Task Force.
Transparency of TO Calculations
Members voted to close an issue relating to the transparency of the calculations transmission owners use for allocating energy, capacity and transmission costs. PJM has created a webpage listing the methodologies transmission owners use for calculating total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL). The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged. (See TOs Will Disclose Calculation Methodologies.)
Members Committee
Supplemental Transmission Project Definition
Members approved revisions to the Operating Agreement clarifying the definition of supplemental transmission projects as one that is not a state public policy project and is not required for system reliability, operational performance or economic criteria. The change removes a reference to supplemental projects as “Regional RTEP” (Regional Transmission Expansion Plan) projects. It also clarifies that any reliability upgrades required as a result of the supplemental project are considered part of that project and are the responsibility of the entity sponsoring it.
Data Submittal Deadlines
Members endorsed Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes would allow load reconciliation data to be included in the calculation of balancing operation reserve deviation charges.
Members also endorsed Reliability Assurance Agreement revisions to allow EDCs to submit corrections to peak load contribution and network service peak load assignments until noon on the next business day. The changes, which will also be reflected in Manuals 18 and 27, are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)
A massive retired coal-fired generating station on the Delaware River is up for sale and is generating enthusiasm among architecture scholars and developers. Delaware Station, built in 1920, was designed by Philadelphia architect John T. Windrim, who also designed the famous Franklin Institute. The 223,000-square-foot building comes with 10 acres of land and another 6 acres underwater.
The site is near the booming Northern Liberties and Fishtown neighborhoods. Owner Exelon Generation has hired real estate brokerage Binswanger to supervise the sale. Sealed bids are due by Nov. 3.
The plant was the northernmost of three waterfront Philadelphia Electric Co. power stations, each a variation on a classical temple. All three are retired. One has been repurposed as an office.
PPL’s plan to build a 725-mile transmission line across four states to take advantage of power generated from cheap Marcellus Shale gas is attracting opposition.
Environmentalists and property owners say PPL’s plan to build a $4 billion to $6 billion, 500-kV line across Pennsylvania to bring power to New Jersey, New York and Maryland will induce more drilling, fracking and power-plant construction in the shale region.
“There are a whole wealth of harms that come from drilling for shale gas,” said Maya K. van Rossum, head of the Delaware Riverkeeper Network. “And the more we invest in fossil fuels, the less money we have to invest in renewable sources.”
Construction on what is billed as the world’s largest post-combustion carbon-capture plant is underway near Houston. While other carbon-capture projects are still in the design phase, or hung up with permitting or financing issues, NRG Energy is going ahead with the Petra Nova Carbon Capture Project. It is being built at the existing W.A. Parish power plant in Fort Bend County.
The plant is designed to capture 90% of the carbon dioxide from flue gas, compress it and transport it by pipeline 80 miles to an oil field, where it will be pumped underground to stimulate oil production. The compressed carbon dioxide is expected to increase the oil field’s yield from 500 barrels a day to 15,000 barrels.
The $1 billion project is being funded by a grant of up to $167 million from the Department of Energy’s Clean Coal Power Initiative, along with $250 million in loans from Japanese banks and $600 million in equity.
An environmental group opposed to Dominion Resources new liquefied natural gas export project in Maryland is taking a new tack: trying to convince potential investors that it’s a bad risk.
The Chesapeake Climate Action Network hired a financial research firm to analyze the project, which is planned for an existing facility on the Chesapeake Bay’s western shore. The firm’s report warns that the project’s success is dependent upon further state and federal approvals. Dominion Midstream Partners is awaiting approval from the Securities and Exchange Commission to raise $400 million to finance the project.
“Investors buying the common units of Dominion Midstream Partners should realize that this company’s cash-flow is purely dependent on the Cove Point Liquefaction Project, for which further delays are expected,” said Jan Willem van Gelder, director of Profundo, the research firm. “In combination with the limited voting power of the unit holders and the dominant position of parent company Dominion Resources, investors are likely to face very uncertain returns.” The report goes on to warn of expected legal challenges facing Cove Point, based on environmental and conflict of interest charges.
Public Service Enterprise Group is partnering with four other companies to build and operate a 105-mile, $1 billion natural gas pipeline.
The New Jersey company will partner with affiliates of UGI, South Jersey Gas, New Jersey Natural Gas and Elizabethtown Gas. PSEG will have a 12% stake in the project, with the other parties each holding 22%. UGI Energy Services would build and operate the project. PSEG said the project would benefit its New Jersey customers, bringing low-cost Marcellus Shale gas to them.
Construction is planned for 2017. The pipeline would run from Luzerne County, Pa., to Trenton, N.J.
Duke Energy announced last week it is buying 278 MW of solar energy from eight utility-scale projects in North Carolina to help meet state renewable-energy mandates. Duke is purchasing three solar farms rated at 128 MW and power-purchase agreements with five projects rated at 150 MW.
“Solar prices are coming down. We can make it work at an attractive price,” said Rob Caldwell, vice president at Duke Distributed Energy Resources. He said the current purchase-power agreements the company is entering into are “about a third” of the $0.11/kWh Duke now pays for rooftop solar.
Duke must derive 12.5% of its power from alternative energy sources by 2021. The acquisitions will make Duke compliant with interim targets in 2015 and 2018, Caldwell said.
An Ohio judge barred FirstEnergy workers from picketing the homes of three company executives after neighbors of FirstEnergy CEO Tony Alexander complained about protesters using bullhorns and air horns in their suburban neighborhood.
Common Pleas Judge Jane M. Davis issued the restraining order against the Utility Workers of America, which is in contract negotiations with FirstEnergy. A tentative pact was reached in July, but workers at 14 units turned it down.
FirstEnergy requested that the protests be limited to no more than five people and that the protesters be prohibited from screaming, yelling or making noise “in a manner intended to disturb.” But the judge prohibited any protesters at all.
FirstEnergy spokesman Todd Schneider said the company’s actions were in response to the large, “inappropriate” demonstration in a residential area.
“Protesting in front of our corporate headquarters is one thing,” he said. “Protesting in a residential neighborhood is a different thing.”
FirstEnergy’s Bruce Mansfield Plant in Shippingport, Pa., and American Electric Power’s General James M. Gavin plant in Cheshire, Ohio, are among the nation’s 10 dirtiest power plants, according to a report by Environment America Research & Policy Center.
The “America’s Dirtiest Power Plants” report ranked the Mansfield plant third and the Gavin plant sixth.
“In 2012, U.S. power plants produced more carbon pollution than the entire economies of Russia, India, Japan or any other nation besides China,” the report said. “In fact, the 50 dirtiest U.S. power plants alone — representing less than 1% of U.S. power plants — produced as much pollution in 2012 as the nation of South Korea (the world’s seventh leading emitter of greenhouse gases).”
Georgia Power’s Scherer plant in Juliette, Ga., was No. 1. Indiana Michigan Power’s Rockport Plant in Rockport, Ind., came in No. 4. The Tennessee Valley Authority’s Paradise plant in Drakesboro, Ky., was No. 10.
The Markets and Reliability Committee heard first read Thursday on proposed rule changes intended to reduce uplift and capture operator actions in LMPs.
The proposal would make changes to day-ahead resource commitment and scheduling reserve requirements, as well as synchronized and primary reserve requirements. It will be brought to a vote at the next MRC meeting Oct. 30.
One change would allow PJM operators to commit long lead resources scheduled for the next operating day — those with a 36-hour notification and start time — in the DA market. Operators would have this option only during emergencies and Hot or Cold Weather Alerts. The change is intended to reduce the mismatch between DA and real-time markets and capture more of the resources meeting system needs in DA LMPs.
‘Heartburn’
A second element would increase the day-ahead scheduling reserve (DASR) requirement on these peak days when forecasted RT load exceeds submitted fixed demand.
The change is intended to ensure that PJM schedules enough capacity to meet RT load while also scheduling enough reserves to meet the average load forecast error (LFE) and forced outage rate (FOR), as well as its normal 10-minute reserve requirements. The current 6.27% DASR requirement covers only the LFE and FOR. How costs of the additional reserves would be allocated is still under discussion.
“This is a piece that really gives us heartburn,” said Susan Bruce, representing the PJM Industrial Customer Coalition. Bruce said the proposed change would work against customers that seek to keep their actual loads in line with their demand bids to avoid deviation charges.
PJM is also proposing changing the calculation of eligible reserves to more accurately reflect the dispatch capability of resources if they are needed in real time. Operators would clear reserves up to resources’ economic max rather than emergency max. They would also adjust assumptions for offline units to recognize startup and notification times. Unlike the previous changes, which are limited to emergencies and weather-related peaks, these changes would apply at all times.
Synchronized, Primary Reserve Requirements
The RTO is proposing a flexible solution for increasing synchronized and primary reserves during emergency conditions. Instead of adding 1,300 MW, as under the temporary solution approved by stakeholders May 29, PJM would increase the reserves by the additional scheduled capacity. (See PJM Reserve Proposal Gets OK for Trial Run.) Shortage pricing would be implemented through a second, lower step on the synchronized and primary reserve demand curves.
Interchange Cap
In addition to the reserve changes, members also will be asked to consider a cap on hourly interchange transactions to prevent unexpected imports from displacing scheduled resources and generating uplift.
The cap would apply during emergency conditions when operators have made firm resource commitments and anticipated interchange schedules are sufficient to meet projected load.
It would block additional spot imports and hourly non-firm point-to-point transactions once net interchange reaches the cap. Schedules with firm or network designated transmission service would not be blocked. The cap value — based on operator expectations plus a margin of 700 MW — would be implemented one to two hours before the operating hour.
Price Impact Uncertain
Lisa Morelli, who moderated the special sessions of the Market Implementation Committee that led to the proposals, said PJM has been unable to conduct a simulation to predict precisely the impact of the changes.
She said PJM had rerun some day-ahead cases under the proposed rules and found that the changes resulted in increased DASR reserve prices and small increases in day-ahead LMPs during peak hours. “Obviously it would also decrease uplift,” said Andy Ott, executive vice president for markets.
Timeline
If approved, the changes would take effect as early as this winter. Changes requiring Tariff modifications would be effective next spring.
Carl Johnson, representing the PJM Public Power Coalition, praised PJM’s crafting of proposed solutions. “PJM has really listened to our concerns,” he said.
PJM’s Capacity Performance proposal has done the near impossible: unite the RTO’s stakeholders.
Virtually all of the more than 50 stakeholders who commented on the RTO’s revamp of the capacity market agreed that it goes too far, creates too much risk and is being rushed through the stakeholder process too quickly.
For suppliers, its nonperformance penalties are out of balance with its incentives and threaten to bankrupt individual generators.
For load, it represents an unwarranted increase in capacity costs and increased risk of market power.
Both sides agree that it has been insufficiently vetted and may not improve reliability.
PJM staff won’t publish their final proposal until Oct. 7, after receiving additional feedback from stakeholders in a meeting tomorrow.
But based on an initial review of the comments, it’s unlikely the PJM Board of Managers will seek Federal Energy Regulatory Commission approval for the original plan under the original timeline (see table).
All who commented said they shared PJM’s concern over the high forced outage rate during January’s polar vortex. But only a handful said they largely supported PJM’s plan. (See PJM: New Capacity Product Needed for Reliability.)
Many said PJM should try more targeted, incremental changes, rather than a fundamental overhaul of the capacity market that includes a new product and major changes to both compensation and penalties.
RTO Insider reviewed all 45 comments, totaling more than 300 pages, after their release yesterday. (Several of the filings came from multiple stakeholders.) Below is a representative sampling of the most frequently cited complaints.
STAKEHOLDER PROCESS
Pepco Holdings Inc. decried what it called the “hyper-accelerated time line.”
“We now face the immediate prospect of an abrupt major change in critical PJM market rules that took over four years of discussion in the stakeholder process to develop, plus three months of intensive negotiations at FERC to finalize and which have continued to be tweaked ever since. PJM is now seeking to change these rules after only four or five half-day stakeholder meetings.”
The Public Utilities Commission of Ohio said the proposal includes “significant improvements,” including addressing the need for winter- and summer-peaking products and an acknowledgement that “Out of Management Control” is not a legitimate exemption from performance requirements.
Without changes, however, PUCO said it will have “negative, unintended consequences.”
“By rolling out a new capacity tier before the dust has even settled on recent demand response reforms, and before FERC has even seen filings from PJM’s [variable resource requirement]/Triennial Review, PJM casts a cloud of uncertainty over how these related proceedings, taken in a vacuum, will ultimately affect reliability and capacity prices.”
Maryland Public Service Commission: “Compared to the roughly eight to nine weeks devoted to this matter under PJM’s schedule, both NYISO and ISO-NE conducted a roughly one-year stakeholder proceeding to formulate their recent market performance proposals.”
LS Power Group: “While all markets tend to evolve over time, drastic market redesigns such as the proposal often bring about unintended consequences and can shake market confidence.”
Topaz Power Management, which manages competitive power portfolios owned by affiliates of Riverstone Holdings, said the proposal is “unnecessarily complex and unlikely to resolve the root cause of the January cold-weather events. It introduces additional reliability and market risk that could harm both load and supply.”
Targeted Approach Urged
Several commenters called for a change in the day-ahead market schedule to better align it with gas pipeline operations. Others said PJM should consider an interim winter reliability program such as what FERC approved for ISO-NE.
Delaware Public Service Commission: PJM’s proposal “is an overly broad cannon blast to the entire [Reliability Pricing Model and Base Residual Auction] processes rather than focused rifle shots to specifically address identified generator performance issues.”
Dominion Resources suggested splitting the RPM into summer and winter markets “that are separately cleared using the current RPM construct.”
Old Dominion Electric Cooperative and Southern Maryland Electric Cooperative urged PJM “to return to energy and ancillary market solutions rather than add additional requirements to an already cumbersome administrative construct.”
LS Power: “PJM should avoid shoe-horning an entirely new capacity product designed to address winter reliability issues within a structure predicated on meeting PJM’s peak capacity needs in the summer. Instead, the winter reliability issues can be best addressed through combining a few targeted enhancements to the current capacity construct included in the proposal along with establishing a new targeted winter reliability program. This approach would redress certain market flaws that have been identified, and at the same time creating [sic] incentives for generators to qualify for a separate winter-focused product.”
Brookfield Energy Marketing: “In our view, for the most part, the PJM capacity markets are currently functioning relatively well. As a result, the current PJM capacity construct does not need to be totally re-constructed as contemplated in the proposal, but instead can be altered with appropriate rule changes that provide the needed performance incentives that PJM is purportedly seeking to address.”
GENERATORS
Suppliers said the proposed penalties could bankrupt individual generators after a single peak-day outage and could lead to accelerated retirement of steam units.
Penalties Unduly Harsh
Generators were unanimous in calling for a reduction in the proposed penalties and in their opposition to the elimination of current force majeure provisions.
Public Service Enterprise Group: “The proposal leans too heavily on the ‘stick’ and fails to provide an adequate ‘carrot.’”
American Electric Power, Dayton Power and Light, FirstEnergy, East Kentucky Power Cooperative and Duke Energy Ohio: “The size and likelihood of increased penalties under the current proposal, matched with continued uncertainty in the capacity price, could easily result in a net revenue decrease for steam generation units, which could further spur premature retirements.”
NRG Energy: “The exclusion of force majeure is inappropriate and could lead one to believe PJM wants every generator to make investments to be hardened for hurricanes and all conceivable natural disasters. This cannot be accurate. Likewise, if a generator has firm natural gas service, and that service is disrupted by an outage on the interstate pipeline system, that is a classic force majeure and the generator should not be penalized for events that are truly outside of its control.
“The proposed penalty is so high (up to 2.5 times a resource’s total annual capacity payments) that it could bankrupt an otherwise viable resource after only one unpredictable outage that should be considered out of the control of the generator. A more appropriate penalty design would place no more than 100% of a Delivery Year’s capacity credits at risk (as opposed to the 250% in the proposal) for any single unit.”
Competitive Power Ventures, which is building combined-cycle plants in Maryland and New Jersey, said the proposed penalties for nonperformance by a 600-MW Capacity Performance generator could total $110 million.
“Assuming a $100/MW-day clearing price, the financial risk imposed on a 600-MW Capacity Performance resource is $55 million, of which about $22 million reflects a full forfeiture of RPM revenues for the year. If the clearing price were $200/MW-day, which occurs frequently in constrained [locational deliverability areas], this would result in a financial exposure of $110 million for this same project. … This penalty structure is unnecessarily punitive and could jeopardize the financial viability of a generation resource.”
Dynegy and Invenergy faulted PJM’s “unrealistic expectations” of generator performance and provided a list of what they called the RTO’s for “faulty assumptions.” Among those assumptions: that all risk should flow to the generator; that dual-fuel capability or fuel on the ground is a panacea; that all gas-fired generators have equal access to fuel-firming products; and that gas-fired generators should maintain the same flexibility during “critical days” on the pipeline as regular days.
EquiPower Resource Corp., which owns 3,600 MW of PJM generation, also criticized the RTO for what it said was a lack of understanding of gas-electric issues. “It appears that some parties have told PJM that no-notice service is readily available as long as generators are willing to pay for it. This is a fallacy. If some no-notice service exists at a few locations inside PJM, we doubt that it is adequate to fuel more than a few generators, never mind the entire PJM gas-only fleet.”
PSEG: “The commercial viability of many resources with higher than average EFORd [equivalent demand forced outage rate] levels will be greatly challenged by this structure. Further, imposing a construct that forces serviceable facilities out of the market because they do not meet highly idealized standards of performance and flexibility is inefficient and will impose unnecessary costs on consumers. Indeed, because many of the most affected units will be older coal and oil units, an unintended consequence of the CP proposal could be to actually decrease reliability by undermining fuel diversity.”
Shell Energy North America said “it may make more sense to offer capacity that we control into the capacity auctions as a Base Capacity Product, rather than as CP, as we are concerned that the current proposal does not provide a reasonable opportunity to earn a return on investments we may make in such resources, nor does it compensate us for the risks we will face with the CP as proposed.”
PJM Power Providers Group (P3): “P3 is struggling to see how the enormous additional risks that will be forced upon generators will be appropriately compensated, year after year, with corresponding revenues.”
Capacity Performance Requirements Too Restrictive
Several commenters complained about the 6,000 run-hour threshold requirement.
NRG called the new product “poorly defined and hastily proposed.”
“The current proposal is discriminatory and likely to have unintended and adverse consequences by excluding substantial quantities of reliable, fuel-diverse resources from the premium capacity product. Many baseload resources with substantial on-site fuel storage will not qualify as Capacity Performance resources because they do not satisfy the required 6,000 run-hour qualification or the greater than 18-hour minimum run time requirement for the Base Load Asset Class. A facility’s run time is based purely on energy market economics and has nothing to do with investment surrounding fuel certainty.”
LOAD
Overly Conservative
Consumer advocates from Delaware, Maryland, New Jersey, Illinois, West Virginia, Pennsylvania, Indiana and D.C.: PJM’s proposal “goes far beyond what is necessary, … is likely to be unacceptably costly and poses a grave potential for resource owners to exercise market power. … PJM proposes to identify the quantity of the new CP product that it will procure through a new reliability study that will focus on winter peak needs. However, the new methodology apparently suggests PJM will require 85 to 90% of all capacity to be CP. We are concerned that the proposed study will rely upon extremely conservative and unrealistic assumptions.”
NextEra Energy Resources: “If PJM were to procure the 85% CP resource level for the 2015/16 delivery year at a clearing price near $190/MW-day, [load-serving entities] would bear roughly $10 billion in additional capacity payments relative to the projection from the most recent incremental auction.”
American Municipal Power (AMP) said PJM has chosen a “radical solution.”
“There has been no clear demonstration by PJM that its proposal has investigated the impact on customers or even whether it will provide superior reliability, particularly during the winter months about which PJM has claimed it is most concerned. While there is no denying or diminishing the magnitude of the ferocity of last winter and the polar vortexes, PJM must remember that it has determined that the winter event was a one-in-10-year event. If the system wasn’t close to the edge during the extreme winter events, it would have meant that the system was over-engineered and inefficient.”
New Jersey Board of Public Utilitiesstaff: The proposal is “a complex and, in certain critical areas, undeveloped set of unnecessary market changes designed to solve near-term reliability concerns that could be addressed far more simply and effectively. The proposal would, moreover, impose significant, but not as yet precisely quantified, capacity-cost increases on end-use customers. The reliability issues that faced PJM this past January were principally occasioned by generator performance failures and were not the direct consequence of market design failure.”
PJM Industrial Customer Coalition: “PJMICC and its members have fundamental questions whether the PJM Problem Statement on PJM Capacity Performance Definition (‘PJM Problem Statement’) accurately captures the reliability concerns. Even assuming that it does, however, PJMICC has serious concerns that the CP Proposal is not a proportionate response and, in fact, may not effectively target the gas‐electric coordination issues that appear to be the root of the reliability problem. If that is in fact the case, the CP initiative may have devastating impacts on energy‐intensive businesses in the PJM footprint.”
Market Power
AMP: “Based on the limited information provided thus far, it appears that PJM’s proposed measures to retain the mandatory capacity markets while breaking out the capacity product into separate categories will substantially increase market complexity and pose the potential for gaming at best.”
NJ BPU: The proposal “appears to open up a distinct new opportunity for strategic withholding. The bifurcation of existing annual capacity resources into Capacity Performance and Base Capacity categories would, absent an explicit set of additional provisions that stakeholders have yet to see, invite generation fleet entities to withhold Capacity Performance capacity and bid such capacity in as Base Capacity in an effort to drive up the Capacity Performance clearing price. There is nothing evident in the Proposal that would prevent such strategic behavior.”
MARKET MONITOR
The Independent Market Monitor called the proposal “an ambitious and timely effort to address some of the significant issues with the current RPM capacity construct” and said it “appropriately focuses substantially on performance issues.”
But the Monitor said the creation of multiple classes of capacity is unwise. “The capacity market should include a single capacity product with one set of performance incentives. There is no reason to have multiple products. With well-designed performance incentives, all sources of capacity can determine how to offer the single capacity product consistent with the physical limits of the resource and the reliability needs of the PJM system. Creating multiple products is the first step towards micromanaging the mix of capacity resources and attempting to substitute the judgment of the planner for market choices.”
The Monitor said its sensitivity scenarios found that coupling offers for resources that cannot currently meet Capacity Performance requirements decreases the price separation between Base Capacity and Capacity Performance prices.
Reducing the maximum amount of Base Capacity resources increases the Capacity Performance price and the price separation between Base Capacity and Capacity Performance products. A requirement for firm gas transportation would have a larger impact on clearing prices than a requirement for dual-fuel capability.
The Monitor reiterated its call for eliminating the 2.5% demand adjustment as well as the Limited and Extended Summer demand response products.
“The capacity market should no longer include any demand side resources on the supply side of the market, including energy efficiency resources (EE). Demand side resources should be on the demand side of the market where they can and should be a very significant component of the capacity market. … Load that does not want to pay for capacity, and is willing to interrupt its use of capacity when that capacity is needed by those who do pay for it, should be able to avoid paying for capacity. That is the demand side of the market as it should work and can work.”
The IMM said its recommendations share PJM’s goals but seeks to accomplish them differently:
“The IMM proposal includes a mechanism to ensure that market prices reflect the net revenue shortfall or missing money, which is to set the offer cap at net [cost of new entry]. The PJM proposal does not include such a mechanism.”
“The IMM proposal includes performance incentives which are solely a function of the provision of energy and reserves during high load hours and which apply equally to all capacity resources. … The PJM proposal imposes high and difficult-to-predict risks on generators as a result of including both quantity and price (LMP) risk in the performance incentives.”
“The IMM proposal does not provide for exceptions to the performance incentives. … PJM’s proposal includes exemptions for units that are not committed by PJM or dispatched down by PJM for providing ancillary services or because of transmission constraints.”
“The IMM proposal includes a must-offer requirement for all capacity resources, which includes the ability of unit owners to incorporate the costs of being a capacity resource in such offers. The PJM proposal does not appear to include an explicit must-offer requirement.”
RETAIL MARKETERS
Consolidated Edison Energy and Consolidated Edison Solutions said PJM’s proposed implementation schedule is unfair to LSEs.
“All market participants have come to rely on the cost and regulatory certainty of the three-year forward mechanism. This allows retail suppliers like CES to account for future capacity costs in their retail contracts with customers, and modifying this capacity market construct without the typical three-year forward lead time would result in unpredictable and potentially unrecoverable costs for retail LSEs.”
DR, STORAGE, RENEWABLES
Brookfield: “Historically, hydro resources have been considered a reliable capacity resource, and PJM can depend on that type of performance going forward. In general, these resources do not depend on a third party to sell a fuel commodity and ensure transportation to the site. … Hydro should be given the option to offer into RPM as a ‘Capacity Performance’ product if the resource is prepared to take on the risk of hourly non-performance penalties.”
NextEra: The proposal “effectively precludes participation by wind resources and non-pumped storage resources.”
The Mid-Atlantic Renewable Energy Coalition said the proposal “would in effect value the capacity benefits of wind at zero.”
Consumer advocates said the proposal “will have a substantially negative impact on the ability for demand response to meaningfully participate in PJM’s capacity market despite the fact that DR compensated for faulty generators during January 2014.”
The Energy Storage Association said PJM’s proposal that Capacity Performance resources be required to provide their full installed capacity (ICAP) for 16 hours per day for three consecutive days is an “unnecessary barrier to storage participation in RPM.”
“Over the course of three days, a Capacity Performance resource must be able to discharge for 48 hours with only 16 hours for recharging. This limited time for recharging means that most facilities will not be able to fully recharge each day, further reducing capacity value. For example, the 30,931-MWh, 3,003-MW Bath County Pumped Storage Station would only have a capacity value of 1,391 MW under proposed Capacity Performance rules. The ESA believes that this dramatically undervalues the contribution modern energy storage can make to system reliability.”
ENERGY EFFICIENCY
EMC2 said PJM has “large amounts of winter energy efficiency that has up to now been invisible to RPM. With the new emphasis on winter reliability, we suggest that RPM would be improved by recognizing the value of these resources.”
“Valuing EE measures at the minimum of their summer and winter reductions undervalues these resources. Instead, we propose that EE measures that have a higher summer value than winter value be credited for their winter value as Base or Capacity Performance, with any excess summer reductions credited as Summer Extended.”
