Washington, D.C., is the most energy-efficient major city in PJM, followed by Philadelphia and Chicago, according to the American Council for an Energy-Efficient Economy. Boston took the top spot in ACEEE’s inaugural City Energy Efficiency Scorecard, receiving 77 of a possible 100 score.
Washington, D.C. (#7 nationally), Chicago (9) and Philadelphia (10) ranked in the second tier, receiving more than half of possible points. Philadelphia was among the top-scoring cities on community-wide initiatives, with efficiency targets, systems to track progress, strategies for mitigating urban heat islands, and use of distributed-energy systems. Philadelphia also scored high for transportation policies, along with Washington.
(Source: Environment America Research Policy Center)
The 100 most-polluting U.S. power plants are responsible for about half of all power-sector carbon dioxide emissions, according to a new study. Forty-four of the worst 100 polluters are in PJM states, nearly three-quarters of them in West Virginia, Pennsylvania, Ohio, Indiana and Kentucky.
Nearly 40% of U.S. households had smart meters as of July, up from about 33% a year earlier. “The era of pilots is a distant memory,” the Edison Foundation’s Institute for Electric Efficiency concludes in a new report. “The current focus is … on integrating and optimizing information gathered by smart meters and other investments that form the digital grid.”
Bipartisan energy efficiency legislation that has stalled in the Senate may be shoved aside completely this week by debate on a funding bill, leaving the fate of the energy measure highly uncertain. The bill has become ensnared in battles over ObamaCare and other topics.
Methane emissions from fracking well completions are lower than previously estimated while emissions from pneumatic controllers and equipment leaks are higher than Environmental Protection Agency projections, according to a new study. The study, funded by industry and the Environmental Defense Fund, concluded that total emissions from natural gas production are about what EPA has estimated.
Researchers took measurements at 489 wells nationwide, about one-tenth of 1% of all the natural gas wells in the U.S. Some observers said the study may understate total emissions because high-emitting sites, although rare, can cause disproportionate releases.
The Federal Energy Regulatory Commission last week approved a final rule extending reliability standards to generator tie-lines and a Notice of Proposed Rulemaking on standards regarding generator verification.
Generator Requirements at the Transmission Interface (RM12-16)
In a final rule, the commission approved Reliability Standards FAC-001-1 (Facility Connection Requirements), FAC-003-3 (Transmission Vegetation Management), PRC-004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations), and PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing).
Reason for change: The North American Electric Reliability Corp. (NERC) proposed the standards to close a reliability gap for generator interconnection facilities without requiring generators to register as transmission operators.
Impact: The FAC-001 and FAC-003 standards currently in effect are applicable only to transmission owners and operators; the change will extend their applicability to certain generator interconnection facilities.
The current versions of PRC-004 and PRC-005 do apply to generator owners as well as transmission owners. NERC proposed modifications to clarify that their requirements extend not only to protection systems associated with the generator, but also to any protection systems associated with the generator interconnection.
The standards define “generator interconnection facility” as referring to “generator interconnection tie-lines and their associated facilities extending from the secondary (high) side of a generator owner’s step-up transformer(s) to the point of interconnection with the host transmission owner.”
FERC Contacts:
Technical Information — Susan Morris, Office of Electric Reliability, (202) 502-6803, susan.morris@ferc.gov
Legal Information — Julie Greenisen, Office of the General Counsel, (202) 502-6362, julie.greenisen@ferc.gov
The commission approved a Notice of Proposed Rulemaking (NOPR) endorsing NERC’s proposed standards MOD-025-2 (Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability), MOD-026-1 (Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions), MOD-027-1(Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions), PRC-019-1 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection), and PRC-024-1 (Generator Frequency and Voltage Protective Relay Settings).
Reason for change: The standards are designed to reduce the risk of generator trips and provide more accurate models for transmission planners and planning coordinators to develop system models and simulations. Portions of the standards were proposed to comply with FERC Order 693.
Impact: The standards should ensure that generator models accurately reflect generator capabilities and equipment performance.
Standards MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1 are new.
MOD-025-2 consolidates two existing standards, MOD-024-1 (Verification of Generator Gross and Net Real Power Capability) and MOD-025-1 (Verification of Generator Gross and Net Reactive Power Capability), which will be retired.
Standards MOD-026-1 and MOD-027-1 would exclude units rated below 100 MVA (Eastern and Quebec Interconnections), 75 MVA (Western Interconnection) and 50 MVA (ERCOT Interconnection), potentially excluding about 20% of registered generators from compliance.
MOD-026-1 would allow transmission planners to compel the compliance of generators below the threshold if the generator is deemed to have “technically justified” units.
The commission is seeking comment on whether the higher thresholds limit the effectiveness of the proposed standards and on the exception regarding “technically justified” units.
FERC contacts:
Technical Information — Syed Ahmad, Office of Electric Reliability, (202) 502-8718, syed.ahmad@ferc.gov
Legal Information — Mark Bennett, Office of General Counsel, (202) 502-8524, mark.bennett@ferc.gov
On Laurel Mountain, W.V., AES Corp. installed 32 MW of battery storage to support its 98 MW wind farm. The project provides PJM with regulation service and allows AES to smooth minute-to-minute fluctuations in output from its turbines.
In Hazle Township, Pa., Beacon Power is installing 200 flywheels that will provide PJM 20 MW of frequency response. The company put 4 MW into commercial operation on September 11 and expects the full 20 MW plant operational next year.
In Lyon Station, Pa., batteries housed in what look like large storage sheds are providing 3 MW of frequency regulation to PJM and peak demand management services to Met-Ed.
These are the vanguard of energy storage applications that will change both the economics and operations of the grid — providing quicker, more accurate frequency regulation, aiding in the integration of variable resources, eliminating the need for some grid upgrades, and providing alternatives to natural gas-fired peakers.
PJM members will be asked Thursday to approve an initiative to draft market rules to allow batteries, flywheels and other advanced energy storage devices to participate in the RTO’s capacity market.
This raises the question: Is advanced storage ready to move beyond pilot projects and into day-today operations?
Pumped hydro, a decades-old technology, currently provides virtually all of the grid’s storage capability, with more than 127,000 MW installed worldwide. Compressed air energy storage installations are second, followed by sodium-sulfur batteries. Other technologies total less than 85 MW combined.
Beacon Power flywheels in Hazleton, Pa. (Source: Beacon Power)
Experts say some of the most promising storage applications, such as hydrogen-powered fuel cells that could provide bulk storage, are a decade or more from commercial deployment. But some more mature technologies could take significant roles in the next several years.
“The future is already here — at least the beginning of the future,” said Imre Gyuk, manager of the Department of Energy’s energy storage research program, at a briefing earlier this month in Washington.
Costs
For storage to reach its potential, its costs must come down at the same time that its capability improves.
Storage can provide benefits in regulation, voltage support and power quality and reliability as well as deferring transmission and distribution upgrades and reducing the need for peaking generators. But “even with all those benefits, it’s difficult to make it add up” to exceed costs, Haresh Kamath, energy storage program manager for the Electric Power Research Institute (EPRI), told the briefing.
Most energy storage technologies have higher capital costs than natural gas-fired peakers. Flywheel capital costs are similar to a combined-cycle plants. Sodium sulfur (NaS) batteries, the most economical battery for utility-scale applications, have been estimated at 1.8 to 3.5 times the cost of a combined cycle plant.
The two crucial of measures of storage capability are cycle life (the number of complete charge-discharge cycles before becoming unusable) and round-trip efficiency (the system’s energy output relative to input). Improving these measures will boost storage in comparisons against generation.
(Source: California PUC)
Market Rules
In addition to the cost and technology challenges, market rules are also an obstacle to widespread deployment.
Storage can provide several benefits simultaneously to the wholesale system, electric distribution companies, and end-use customers. “These characteristics, plus the difficulty in monetizing multiple stakeholder benefits, often act as barriers to the widespread deployment of energy storage systems, whose multi-functional characteristics also complicate rules for ownership and operation among various stakeholders,” EPRI said in a 2010 white paper. It concluded policy changes would be needed “to realize the true potential of storage assets.”
Rule Changes Could Quadruple Revenues
Researchers at Energy and Environmental Economics reported in a 2009 paper that storage revenues could be increased by as much as four-fold by reducing minimum size requirements for market participation and permitting bi-directional bidding for regulation.
The study looked at potential revenues for a theoretical storage resource located in Allentown, Pa., based on 2007 market clearing prices ($41/MW-day for capacity, $14/MWh for regulation and $34/MWh for energy). It found a system with 1 MW of charge and 2 MWh of energy storage would generate revenues of more than $250,000, most of it from regulation, with additional revenue from capacity and energy arbitrage — storing energy overnight when prices are low and selling during peak hours.
As of the time of the study, PJM capacity rules required a minimum of 12 hours of capacity and a minimum resource size of 0.1 MW.
One key to increasing revenues, the analysis found, was permitting asymmetric bidding in the regulation market — allowing the battery to earn regulation revenue when charging and discharging — in recognition that regulation dispatches over an hour can be energy neutral.
Changing market rules to permit asymmetric bidding and to allow energy storage to offer one hour of regulation with less than one hour of energy storage would increase the net present value of energy storage in PJM from about $1,000 per kWh of energy storage to nearly $3,500.
FERC Order, Stimulus Funding
Storage received a boost from the Federal Energy Regulatory Commission in July with Order 755, which requires PJM and other transmission providers to consider speed and accuracy in acquiring regulation resources. (See FERC Rule Boosts Storage, Renewables.)
Storage also was a prime beneficiary of federal stimulus money under the 2009 American Recovery and Reinvestment Act (ARRA). About $185 million in ARRA funds leveraged $585 million from industry for 16 energy storage projects, not including eight smart grid projects with storage. The goal of the federal spending is to demonstrate the technologies’ technical feasibility, document costs, stimulate regulatory changes and generate follow-on projects. Four of the 16 projects have been completed to date.
Proposed Legislation
To provide additional incentives, Sen. Ron Wyden (D-OR), chairman of Senate Energy and Natural Resources Committee, and Sen. Susan Collins (R-ME) reintroduced legislation in May to create an investment tax credit for energy storage.
California Storage Mandate
With or without federal incentives, a lot more storage will be added over the next few years. On Sept. 3, the California Public Utilities Commission issued a proposed order requiring the California grid to obtain 1.3 GW of storage by 2020, a target that will require utilities to increase their storage by 30% annually.
The order was prompted by Assembly Bill 2514, which barred pump storage projects larger than 50 MW from eligibility in order to enable a “market transformation” for new technologies.
The order would prohibit utilities from owning more than 50% of the storage resources to be procured across the three “grid domains” of transmission, distribution, and customer-located storage.
To address utilities’ concerns that the 2020 goal is too ambitious, it would allow utilities to defer up to 80% of their targets if they can show they can’t procure enough “viable projects to meet the targets.”
EPRI’s Kamath said California’s mandate could do for storage what Germany’s world-leading commitment to solar power did to reduce solar’s “soft” costs, including permitting, inspection, interconnection, financing and customer acquisition.
“It’s going to have effects all across the industry,” said Klamath.
Ron Binz’ nomination to the FERC chairmanship was hanging by a thread late last week after coal-state lawmakers took the former Colorado regulator to task at his confirmation hearing and Sen. Joe Manchin (D., W.V.) announced he would oppose the nominee.
Binz testifies
Binz will need the backing of one Republican and all of the remaining 11 Democrats to win the recommendation of the 22-member Senate Energy and Natural Resources Committee. That will be tough for Democrats to pull off.
Ranking member Lisa Murkowski (R-Alaska) has already stated her opposition and no Republicans spoke in favor of Binz at his confirmation hearing Tuesday. Also in doubt is Sen. Mary Landrieu (D., La.), who has not indicated she will support the nominee.
`War on Coal’ Target
If Binz’ nomination fails, it will be because he became the target for those angry over the Obama administration’s so-called “war on coal.”
Binz would have limited influence over coal’s life or death as FERC chairman: Although FERC policies ensuring transmission access for renewables impacts coal indirectly, the agency has no role in the setting of climate or pollution policy.
But the timing of his confirmation hearing was inauspicious. The War-on-Coal blowback reached a crescendo last week as the EPA issued its long-awaited greenhouse gas limits on new power plants.
Manchin complained at Tuesday’s hearing that Obama’s environmental policies were beating the “living crap” out of his state. On Wednesday, he announced his opposition to Binz, criticizing him for prioritizing “renewables over reliability.
“His approach of demonizing coal and gas has increased electricity costs for consumers,” Manchin said.
Colorado PUC
Binz served as chairman of the Colorado Public Utilities Commission from 2007 through 2011, during which he drew praise from renewable energy advocates and opposition from the coal industry.
Binz participated in the drafting of Colorado’s Clean Air-Clean Jobs Act, which offered utilities incentives for replacing coal-fired power plants with natural gas. The bill, which was opposed by the coal industry, led to the retirement of six coal-fired generators, the addition of pollution controls at two others and the construction of new gas generation at a cost of about $1 billion. See: Who is Ron Binz, And What Will He Do at FERC?
Binz told last week’s hearing he would be “source neutral” and emphasize reliability as FERC chair. He noted that coal provides 40% of Colorado’s electricity, more than any other source. He also acknowledged he had spoken “inartfully” at a forum when he called natural gas a “dead end” fuel.
Norris Allegation
Adding to Binz’ woes last week were comments from FERC Commissioner John Norris, who reported that Senate Majority Leader Harry Reid persuaded President Obama to reject him as FERC chairman because he was too “pro-coal.”
Norris, a Democrat, told TransmissionHub that Reid’s chief of staff cited a vote he made as a member of the Iowa Utilities Board. Reid’s office denied Norris’ account.
Senate Minority Leader Mitch McConnell (R-Ky.) said Thursday that he would actively work against the nomination of what he called the Senate Majority Leader’s “foot soldier in his and this Administration’s War on Coal.”
Duke Energy Corp. is the latest company to end a long-standing practice of insuring its retirees, a cost-saving approach already embraced by IBM, Time Warner, Caterpillar, General Electric and DuPont.
About 14,500 retirees of were informed that the company will no longer provide insurance to supplement Medicare coverage. Instead, Duke will pay retirees an annual stipend toward the cost of insurance.
Almost 75% of the nation’s publicly traded companies are ignoring a three-year-old Securities and Exchange Commission requirement that they inform investors of the risks that climate change may pose to their bottom lines.
The data, culled from the annual reports of 3,895 U.S. public companies listed on major stock exchanges, found that only 27% mentioned “climate change” or “global warming” in their most recent filing. Nearly all of the 179 energy companies reviewed mentioned climate change.
The number of electric generation units at commercial and industrial sites has more than quadrupled since 2006, leading utilities such as AEP to consider getting into the on-site power business.
On-site generation still accounts for less than 5% of U.S. electricity production. But it is gaining momentum because of falling prices for solar panels and natural gas, as well as a fear that power outages caused by major storms will become more common. Wal-Mart, which produces about 4% of the electricity it uses, plans to boost that to 20% by 2020 and expects to be paying as little for solar power as utility power in less than three years.
Exelon Corp. boosted the stock awards for CEO Christopher Crane to $4.2 million in 2012, 25% above his target, thanks to his work lobbying state and federal officials. The company’s board of directors credited Crane for winning approval of the Constellation merger and for influencing new Environmental Protection Agency regulations and deregulation measures in Ohio.
FirstEnergy Corp. announced the election Luis A. Reyes, former administrator of the Nuclear Regulatory Commission’s Atlanta-based Region II, to its board of directors. His term will run until the company’s 2014 annual meeting. Reyes will serve on the board’s Corporate Governance and Nuclear Committees.
The state Pollution Control Board rejected a request by Ameren Corp. to transfer permission to delay pollution controls at five coal-fired plants to Dynegy Inc., which is seeking to acquire the plants. The board said Dynegy could submit a new petition for a waiver, requiring the company to prove that it faces a hardship preventing it from cutting emissions.
Meanwhile, Foresight Energy LLC, the largest coal producer in the state, offered to help Dynegy finance the emissions controls or acquire the plants itself. Its goal: To create a new customer for its southern Illinois coal.
American Electric Power announced it will close the last of its four coal-fired generating units in Lawrenceburg by 2015. AEP previously decided to close the first three of the Tanners Creek units. About 115 employees working at the plant will be affected.
More than 100 environmental and community groups have formed a coalition to fight Dominion’s proposed liquefied natural gas (LNG) export facility at Cove Point. The groups asked Gov. Martin O’Malley to oppose the export complex, which they say would accelerate fracking in the region and emit more carbon pollution than most of the coal-burning power plants in the state.
Customers who say “no” to a new smart electric meter could end up paying for it. The Public Service Commission staff recommended that utilities charge customers who keep their existing meters about $75 upfront as well as a monthly fee.
Maryland’s Office of People’s Counsel also supports charges to cover meter reading and other costs incurred by customers who choose to keep their old devices.
The Carlyle Group will buy the Red Oak power plant, an 823 MW combined cycle facility in Sayreville, from Energy Capital Partners.
Carlyle is purchasing Red Oak and five California plants through its affiliate Cogentrix Energy Power Management. Carlyle, an asset manager, has purchased $1.2 billion in generation assets since acquiring Cogentrix in late 2012.
American Electric Power asked the Public Utilities Commission for a $290 million rate hike to expand its smart meter program to 900,000 customers. AEP has deployed smart meters to 110,000 customers to date.
The Bowling Green City Council banned fracking and disposal of fracking waste fluids while Niles City Council unanimously repealed its own ban on oil and gas drilling.
Niles reversed the “Community Bill of Rights” it enacted in August in a meeting packed with anti-drilling advocates pleading to keep the ban and labor unions encouraging its repeal. Opponents of the ban said the law might not withstand a legal challenge because the state Department of Natural Resources claims only it can license drilling.
But Bowling Green’s attorney said his city’s ban is part of the city’s criminal code, not its zoning code. The city is an unlikely target for drilling because of a high water table and unsuitable geology.
The Sierra Club launched an advertising campaign urging Ohioans to boycott FirstEnergy Corp. to protest what it says are efforts by the company to undercut Ohio’s renewable energy and efficiency standards. The target of the boycott is FE’s retail arm, FirstEnergy Solutions.
The environmental group paid for an electronic billboard across from the Statehouse, where lawmakers may soon revisit Ohio’s 2008 law requiring utilities to find at least 25% of their power from renewable or advanced technology sources by 2025. A FirstEnergy spokesman called the campaign “misleading.”
FirstEnergy’s Hatfield’s Ferry and Mitchell power plants can shut down Oct. 9 without affecting grid reliability, an analysis by PJM has concluded. PJM told FirstEnergy of its conclusions in a letter dated Sept. 19, saying that the impact of the closures “can be handled by transmission upgrades and the implementation of temporary operating measures.”
FirstEnergy said it’s shutting down the plants because they’re losing money. The move will displace 380 workers.
Met-Ed is suspending its energy-saving Easygreen program while it awaits the result of a Public Utility Commission cost/benefit analysis. Last year, about 20,000 Met-Ed customers participated in the program, which allows the utility to remotely control their air conditioners and pool pumps when demand for power peaks.
The PUC expects to complete the study on the programs of Med-Ed and other Pennsylvania utilities this summer.
87% of electric distribution company customers reported they were either somewhat or very satisfied with the overall quality of service they received from their providers in 2012, down slightly from 89% in 2010 and 2011. PPL and Penn Power led the rankings with a 90% satisfaction rating; Peco had the lowest overall score at 84%.
The state’s voluntary donation fund to make loans for solar energy projects has attracted virtually no interest and made no loans. Through April 26, contributions to the fund amounted to $319.54, but the monthly transaction fees to accept online donations totaled $319.00, leaving a balance of 54 cents.
The State Corporation Commission began a public hearing on a proposal from Dominion Virginia Power that would keep base rates flat for at least two years. Customers may still see increases for the costs of fuel, constructing new plants and environmental compliance. Regulators have until November to decide.
WASHINGTON – The Federal Energy Regulatory Commission today rejected settlements by FirstEnergy and Duke Energy affiliates over their moves to PJM, ruling that the companies unfairly imposed transition costs on transmission customers who were not party to the agreements.
The orders involve FirstEnergy’s American Transmission Systems Inc. (ATSI), which moved from MISO to PJM in June 2011, and Duke Energy’s Ohio and Kentucky utilities, which moved to PJM in May 2010.
In both cases, the commission ruled that the settlements improperly reinstated transition costs that the commission previously ruled should be borne by the utilities, unfairly leaving non-settling parties liable.
The cases originated from the companies’ filings of revised transmission tariffs that reflected their revenue requirements as PJM members. American Municipal Power Inc. (AMP) challenged both Duke and ATSI’s rate filings.
Duke Settlement
In February 2013, Duke Energy Ohio and Duke Energy Kentucky filed a settlement agreeing to reimburse AMP for any transition costs resulting from Duke’s move to PJM. The companies also agreed to reimburse AMP for 75% of “legacy” transmission expansion costs — Duke’s share of MISO transmission projects approved before the company joined PJM. Duke estimated the transition costs and legacy costs at $518 million.
The settlement also reduced the return on equity included in Duke’s wholesale rates from 12.38% to 10.88% percent (plus 50 basis points for its membership in a regional transmission organization). AMP — which buys transmission from Duke on behalf of Hamilton and Lebanon, Ohio and Williamstown, Ky. — agreed not to seek a lower ROE before 2016.
In today’s order (docket # ER12-91), the commission ruled that Duke had “not shown why it is not unduly discriminatory for AMP, but not other customers, to be exempted from paying” the transition costs.
ATSI Settlement
ATSI’s rate filing sought recovery of $38 million in transition costs while agreeing to forgo recovery of $360 million in legacy transmission expansion charges.
The company’s settlement, filed in December 2012, exempted AMP and Buckeye Power Inc., from paying any costs of the utility’s move to PJM but left it to the Ohio Public Utility Commission to determine what costs would be passed on to retail customers served by other distribution companies.
Buckeye Power is a generation and transmission cooperative owned by 25 electric distribution cooperatives in Ohio.
“While other wholesale customers may not have objected to the [AMP, Buckeye] settlement, these customers are largely served by ATSI’s distribution affiliates,” the commission ruled (docket # ER11-2814). “Thus, the lack of objection from these affiliates … has no bearing on the justness and reasonableness” of the agreement.”
The ruling was a victory for the Ohio Consumers’ Counsel (OCC), the lone challenger to the ATSI settlement.
OCC contended that ATSI was seeking to use the settlement as an “end-run” to include in its transmission rates charges prohibited by FERC in a May 2011 order.
Next Steps
The commission said ATSI and Duke could attempt to recover their transition costs through section 205 filings. Those filings would have to demonstrate that the benefits received by the companies’ customers as a result of the move to PJM exceeded the transition costs assigned to them.
FERC also remanded the issue of Duke’s ROE for further hearing and settlement judge procedures. The commission said that although the reduced ROE provisions “appear just and reasonable,” it was unable to accept them because of a “non-severability” clause in the settlement.
Ameren Corp. and Dynegy Inc. will face off with environmental groups next week in a hearing that could decide the future of some of Illinois’ largest coal-fired power plants. The companies are seeking a waiver from the Illinois Pollution Control Board that would provide five additional years to meet stricter air pollution limits for Ameren’s coal plant fleet in central and Southern Illinois.
Commonwealth Edison’s smart grid program created more than 1,000 direct full-time equivalent jobs at the utility and its contractors, in the second quarter, the utility reported to the Illinois Commerce Commission. “Grid modernization is proving to be an even stronger economic engine than we anticipated,” the company’s CEO said.
Indiana’s top utility regulator said his agency won’t solicit or accept money from utility trade groups to help fund a conference of energy regulators from 14 states next year. The announcement came after The Indianapolis Star reported details of the effort by the Indiana Utility Regulatory Commission to raise tens of thousands of dollars from the nation’s largest utility trade groups.
At issue is who should pay for the Mid-America Regulatory Conference in Indianapolis next June. At last year’s conference in Little Rock, Ark., industry groups contributed about $50,000 toward the total cost of $73,000.
The Sierra Club and several citizens asked the Indiana Court of Appeals to overturn Indiana Utility Regulatory Commission (IURC) orders that raised electricity rates to pay for construction of Duke Energy’s Edwardsport coal gasification power plant.
The Public Service Commission awarded Delmarva Power a 3.6% increase in delivery rates. A residential customer using 1,000 kWh will see their monthly bill increase from $140 to $145.
The Public Service Commission ordered Baltimore Gas & Electric to improve service or risk penalties. BGE’s work plan includes more vegetation trimming, burying some lines and installing more automatic switching to keep power flowing when outages occur.
The commission can fine the company up to $25,000 a day for failing to comply.
Coal-industry officials repeatedly complained about new water-pollution limits to Gov. John Kasich before the governor allegedly forced out a top regulator, documents obtained by The Columbus Dispatch show.
Duke Energy agreed with environmental and consumer groups on a five-year efficiency plan that will exceed the energy savings required by state law. The company filed a plan with the Public Utility Commission pledging to reduce customers’ electricity use 5.7% by the end of 2018, above the state standard of 4.9%.
FirstEnergy Corp. is looking to purchase 265,000 Renewable Energy Credits (RECs) and 6,600 Solar Renewable Energy Credits (SRECs). FirstEnergy need the credits to meet state renewable energy targets for its Ohio Edison, Cleveland Electric Illuminating and Toledo Edison utilities.
Attorney General Kathleen Kane’s decision to prosecute Exxon Mobil’s XTO Energy Inc. for a 2010 wastewater spill angered industry officials, who said the case creates a hostile business environment. Environmentalists called the prosecution a welcome change from the lenient treatment they say the industry has received from state regulators.
Kane filed charges against XTO Energy for discharging more than 50,000 gallons of toxic wastewater from storage tanks at a gas-well site in Lycoming County. XTO settled federal civil charges over the incident in July by agreeing to pay a $100,000 fine and deploy a plan to improve wastewater-management practices.
The State Corporation Commission approved the conversion of Dominion Virginia Power’s Bremo coal plant to a 227 MW natural gas generator. Opened in 1931, it is Dominion’s oldest coal-fired power plant. The conversion is expected to cost more than $50 million.
Generator start and notification rules will be implemented in eMKT beginning Sept. 26, PJM told the Market Implementation Committee last week. The Operating Committee last week endorsed related changes to Manual 14D: Generator Operational Requirements.
Reason for change: The changes were approved in 2012, following a January 2011 problem statement by PJM and the Market Monitor that noted there were no rules governing unit start and notification times. This made scheduling more difficult for PJM staff, left units unavailable for lengthy periods and permitted the exercise of market power, officials said.
Impact:
During the Peak Period (Jan., Feb., June, July and Aug.) the notification plus startup time must not exceed six days. Units will be in forced outage status until they can operate within the six-day limit.
During Off Peak months (March, April, May, Sept., Oct., Nov. and Dec.) units may offer extended notification times that accurately reflect the physical time to bring the unit to the beginning of the startup sequence.
Manual 14D: Generator Operational Requirements was revised: Added applicability for individual generating units greater than 20 MVA; replaced outdated reference to NERC Guidelines with reference to NERC Reliability Standards; Added requirement for generators operating or scheduled to operate for PJM to notify PJM prior to attempting a restart following a trip or failure to start.
More information: Members can review a summary of the changes in the eMKT Enhancements section and test the changes in the “sandbox” environment prior to implementation.
Additional information can be found in the Issue Tracking section of PJM.com. PJM will answer questions through the PJM Markets Hotline and via phone at 610-666-8998.
Three special protection schemes (SPS) are being removed from the PPL and Dominion zones, the Market Implementation Committee was told Wednesday:
Dominion Harmony Village: The SPS was installed in 2007 to prevent overloads on line #65 during the loss of a tower carrying lines #2016 and #85. The SPS is no longer needed as a result of the completion of a new 230 kV line #2122 from Hayes to Yorktown (B0779).
Dominion Virginia Beach: The SPS was installed in 2007 to prevent line #27 from overloading due to the loss of two other feeds to Virginia Beach. The SPS is no longer needed due to the completion of a new 230 kV line #2118 from Landstown to Virginia Beach (S0375).
PPL West Shore 230 KV Automatic Load Shedding SPS: The SPS was installed in 2010 to alleviate an N-1-1 summer peak overload at the Steelton Tap on the Hummelstown-Middletown Junction #2 230 kV line. The SPS is no longer needed due to the energization of a second Brunner Island–West Shore 230 KV line (B0717).
