VALLEY FORGE, Pa. — PJM will delay action on manual changes on generator notification and start-up times until the Federal Energy Regulatory Commission rules on the RTO’s Capacity Performance proposal (ER15-623, EL15-29).
The issue stems from a four-year-old problem statement drafted to address reliability and market implications of de-staffing little-used generator units during the spring and fall shoulder months. At the time, some manual changes were endorsed, but others were overlooked, and the issue was mistakenly closed.
Some wanted to re-open the issue because they had not been involved in the original talks; others questioned whether years-old solutions were still appropriate.
“A lot’s changed … and we’ve got this thing called [Capacity Performance] coming that talks specifically to this,” she said. “Let’s get that feedback first and then decide how best to handle the remaining scope.”
PJM asked FERC to rule on the Capacity Performance proposal by April 1.
CTS on Track Despite PJM-MISO Interface Pricing Dispute
Meanwhile, PJM believes that proposal “will misrepresent the impact of interchange on internal PJM constraints,” he said. PJM staff also believes the impact of the modeling issue has been “significantly overstated,” Williams said.
Regardless, the RTOs plan a joint FERC filing outlining the CTS proposal in May, with hopes of launching it by November 2016.
PJM Drafting Proposal on External Capacity Transfer Rights
PJM staff will draft a detailed proposal for allocating capacity transfer rights to historical external resources and present it to stakeholders in April, MIC members were told Wednesday.
In December, PJM stakeholders agreed to review modeling practices that the RTO said might be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market. (See PJM MIC OKs Capacity Transfer Rights Inquiry.)
The issue involves only a few players, said Stu Bresler, vice president of market operations, who presented the MIC with a “conceptual” proposal. Among them is the Illinois Municipal Electric Agency, which uses capacity resources outside of the Commonwealth Edison locational deliverability area to meet its internal resource requirements.
CO2 Emission Rates Steady
Despite retirements of numerous coal-fired generators, PJM has reduced its carbon emissions only modestly in the last five years.
Between 2009 and 2014, PJM’s system average emissions dropped 3% to 1,108 lb/MWh. Marginal on-peak units saw a bigger, 10% drop to 1,646 lb/MWh while off-peak dropped 7% to 1,707 lb/MWh.
The Environmental Protection Agency’s proposed Clean Power Plan would require an overall 30% reduction in power plant carbon dioxide emissions from 2005 levels by 2030.
The burdens will fall unevenly on PJM states, with Kentucky, West Virginia and Indiana — the top-ranked PJM states in 2012 carbon emissions per megawatt-hour — having to cut their emissions by only 20%, while New Jersey, already the least carbon-intensive state in the RTO, having to cut its emissions the most in percentage terms (43%).
PJM’s 2014 system-wide average puts it well above EPA’s proposed targets for New Jersey and four other states but below the targets for eight states. (See Carbon Rule Falls Unevenly on PJM States.)
PJM Releases More Details on Carbon Plan Impact Study
PJM this month released more details on its scenario analyses of the Clean Power Plan with a 129-page study of the economic impacts of adhering to the new carbon rule. The RTO released preliminary results of the study, which was requested by the Organization of PJM States (OPSI), in November.
The study concludes that individual state compliance would be more costly than a regional approach and would increase the capacity at risk for retirement. PJM expanded on the key findings with an appendix providing state-by-state impact.
PJM will use the results of the economic analysis as the foundation for reliability analyses to determine transmission needs resulting from potential generator retirements. (See related item in PJM TEAC Briefs.)
VALLEY FORGE, Pa. — PJM received 118 transmission proposals during the competitive window that closed in February, including 92 market efficiency projects and 26 to address reliability problems.
Nineteen transmission owners and non-incumbent developers submitted proposals, led by ITC Holdings, FirstEnergy, Commonwealth Edison and American Electric Power with at least 10 each.
The market efficiency proposals are intended to relieve congestion in 12 locations, nearly half of the proposals targeting the AP SOUTH and AEP-DOM regional facilities. In addition to 34 transmission owner upgrades ranging from $100,000 to $81 million, there were 58 greenfield proposals projected to cost from $9 million to $433 million. (See PJM TEAC IDs 20 Market Efficiency Candidates.)
PJM’s Tim Horger suggested that the Federal Energy Regulatory Commission’s ruling last month rejecting the RTO’s proposed $30,000 fee on greenfield proposals was a factor in the unexpectedly high number of market efficiency proposals. (See FERC Rejects Fee on Greenfield Transmission Projects.)
Initial analysis of the proposals will require more than 15,000 hours of computing time, assuming 160 hours of base runs for each proposal, Horger told members of the Transmission Expansion Advisory Committee on Thursday. Sensitivity analyses on projects that pass the initial screening will require additional time.
“This will be a challenge, at the least,” Horger said. “I’m confident our guys will get it done.”
Particularly demanding will be the projects proposed for AP SOUTH, he said, as they can impact other interfaces. Those proposals likely will take until the end of the year to review.
The reliability proposals consist of 15 transmission owner upgrades with a cost range of $300,000 to $62 million and 11 greenfield projects estimated from $18 million to $101 million.
PJM Studying Tx Upgrades Needed Under EPA Carbon Rule
PJM is conducting studies to determine transmission upgrades that may be needed to respond to plant retirements resulting from the Environmental Protection Agency’s proposed carbon emission rule.
Preliminary results of a scenario assuming 16 GW of at-risk generation identified voltage and thermal violations. The plant retirements were assumed to be evenly distributed between 2020 and 2029.
The voltage issues affected the PJM West, Southwest MAAC and Dominion locational deliverability areas (LDAs).
Thermal violations prevented five LDAs from importing their capacity emergency transfer objective (CETO) values in the load deliverability test. The generation deliverability test found multiple 230-kV violations, mostly in Southwest MAAC.
Planners will continue the analysis with scenarios assuming 6 GW and 32 GW of generation at risk.
NRG Yield is buying majority stakes in two Colorado wind farms with a combined capacity of 63 MW. The company also announced it is buying a 1.4-MW fuel cell project in Connecticut.
NRG is buying the wind farm interests from Invenergy. Spring Canyon II and Spring Canyon III, consisting of 35 GE turbines, began operations last year and sell their output to Platte River Power through a 25-year power purchase agreement. NRG is buying the University of Bridgeport Fuel Cell project from Fuel Cell Energy.
The two transactions are valued at about $41 million.
Xcel Asks Minnesota PSC to Limit Large-Scale Solar
Xcel Energy has asked the Minnesota Public Service Commission to limit the aggregation of smaller solar “gardens” that qualify as large-scale projects.
The request is in response to the popularity of the state’s Solar Rewards Community program, which already has attracted proposals totaling 431 MW. Minnesota law restricts smaller, community “garden” solar projects to 1 MW, but allows projects to band together to form larger facilities in order to take advantage of location and transmission connections. Xcel cited one proposal for 50 MW of 1 MW gardens in a suburb near Minneapolis.
Among Xcel’s suggestions: limit co-located applications to 1 MW or less; allow co-located applications from single developers as long as they don’t exceed 1 MW; and limit applications from multiple developers at co-located sites to 1 MW. Xcel said community solar projects are expensive and add 1.5 to 1.8% to ratepayer bills.
Arkansas Electric Cooperative Corp. this month filed preliminary permit applications with the Federal Energy Regulatory Commission for three new hydroelectric generating stations on the Arkansas River with a total capacity of 123.6 MW.
AECC surrendered previous licenses it held for hydro projects at several locks and dams on the river, saying they were uneconomic to develop at the time. But AECC said it has revived interest in the hydro potential of lock and dam Nos. 3, 5 and 6. The licenses for those facilities, held by another entity, expired at the end of February. An Entergy Arkansas transmission line runs close to the proposed stations.
AECC built three other hydropower plants on the river between the late-1980s and 2000 with a total capacity of 167.4 MW.
NRG Plant Likely Customer of Controversial PennEast Pipeline
NRG Energy said it would likely switch its Gilbert Station in New Jersey from burning ultra-low sulfur diesel to natural gas if the controversial PennEast pipeline is built to deliver gas from Pennsylvania’s Marcellus Shale region.
The pipeline is owned by a consortium of companies, including affiliates of four New Jersey utilities serving most of the state’s natural gas customers. Pipeline opponents say that no customers directly on the pipeline route would benefit. The comments from NRG are the first public acknowledgement that a local industrial customer might tap into the PennEast line.
FP&L Buying, then Closing Jax Coal Plant to Get CO2 Credits
Florida Power & Light is paying $520 million for a modern 250-MW coal-fired power plant near Jacksonville, Fla., that it plans to shut down within two to three years.
FP&L has been paying $120 million a year to buy power from the Cedar Bay Generating Plant under a long-term power purchase contract. The utility says it will be able to cut $70 million in annual costs and reduce carbon emissions by a million tons per year if it buys the plant and shuts it down.
FP&L, a subsidiary of Juno, Fla.-based NextEra, filed a request for the acquisition and proposed shuttering of the plant with the state Public Service Commission.
Madison Gas & Electric Bows to Shareholders to Increase Renewables
Madison Electric & Gas agreed to expand its renewables development in response to pressure from shareholders.
The company agreed to work with the shareholder group and a designated consultant to “study adding substantial and measureable amounts of renewable energy” to its supply mix.
A group of MGE Energy shareholders were pushing a proxy proposal calling for the utility to obtain 25 percent of its energy from renewable sources by 2025. The shareholders agreed to drop their proposal after the company made its commitment.
SunEdison Buys into Storage Market, Acquires Solar Grid Storage
SunEdison, a major developer of renewable power projects, announced it has purchased a four-year-old solar generation and storage startup.
With the purchase of Solar Grid Storage, SunEdison is venturing into the energy storage business. Solar Grid Storage specializes in linking solar installations with lithium-ion battery systems. It has completed four such projects and is in the planning stage with three more.
Exelon Seeks Permits for LNG Facility in Brownsville, Texas
Annova LNG, majority owned by Exelon Generation, filed a request with the Federal Energy Regulatory Commission to build a natural gas liquefaction plant and export terminal on 650 acres at the Port of Brownsville, Texas.
For Exelon Generation, best known for operating the nation’s largest nuclear fleet, this will be the first foray into the LNG export business. “The project represents a potential opportunity to diversify Exelon’s role in the energy business in an area that shows strong growth potential: natural gas exports,” Exelon Generation President and CEO Ken Cornew said.
The U.S. Department of Energy recently authorized Annova to export up to 342 billion cubic feet of gas per year to free-trade agreement countries. The company said construction of the $3 billion “mid-scale” terminal would take four years. It will require 26 separate federal, state and local permits and licenses.
Exelon’s Limerick Nuclear Station Gets Additional NRC Inspection
The Nuclear Regulatory Commission has ordered an extra inspection at Exelon’s Limerick Generating Station in Pennsylvania after identifying an unspecified security issue during an inspection last June.
Limerick was notified of the inspection as part of its annual assessment. Post-9/11 security procedures prohibit the agency and the company from providing details about security lapses, but a company spokeswoman said the issue has been fixed.
“We promptly corrected a technical security concern identified last year, and at no time was the security of the facility, our workers or local residents compromised,” Dana Melia said.
Anti-Nuclear Group Calls on NRC to Withhold Watts Bar 2 License
An anti-nuclear group called on the Nuclear Regulatory Commission to hold off on licensing the Tennessee Valley Authority’s new Watts Bar 2 nuclear station until the TVA reviews earthquake and flood risks at the plant. Watts Bar 2 is currently scheduled to go into operation by the end of this year.
The Southern Alliance for Clean Energy said the earthquake and tsunami that destroyed the Fukushima plant in Japan in 2011 underscores risks not currently planned for at Watts Bar 2. The reactor will be the first new commercial unit to come online in 20 years.
“It shocks the conscience that the NRC is preparing to issue an operating license for Watts Bar Unit 2 potentially this June without completing its post-Fukushima review of seismic and flooding risk,” an alliance spokeswoman said. TVA said it made several changes to the plant’s original design, which were approved by the NRC’s Advisory Committee on Reactor Safeguards.
Westar Files for $125 Million Rate Increase in Kansas
Westar Energy requested a $125 million rate increase to pay for environmental upgrades at its coal-fired power plants and for service life extension work at the Wolf Creek nuclear station near Burlington, Kan.
In a filing with the Kansas Corporation Commission, Westar said nearly half of the increase would pay for coal-plant upgrades to meet federal Clean Air Act standards. One-third would go toward improvements at the Wolf Creek nuclear plant, of which Westar owns 47%. The rate increase would boost a residential customer’s bill about $13 a month.
A state consumer advocate agency indicated it would challenge the request.
PPL Issues RFP for 370,000 MWh of Alternative Energy Credits
PPL Electric Utilities is looking to buy more than 370,000 MWh of alternative energy – wind, biomass, solar – in order to meet its Alternative Energy Portfolio Standard requirement in Pennsylvania.
It has hired NERA Economic Consulting to act as RFP manager. The delivery period would start June 1 and run for six years. The bid date for the RFP is April 1.
FirstEnergy Invests $748M in Infrastructure Projects
FirstEnergy’s three Ohio utilities, which last year spent more than $1 billion on “Energizing the Future” upgrades, want to spend $784 million this year to improve the overall efficiency and reliability of its electric system.
Toledo Edison plans to put $120 million toward upgrading infrastructure. Ohio Edison and The Illuminating Company expect to spend $383 million and $281 million, respectively, for reliability programs. The expenditures include more than $475 million for transmission projects owned by FirstEnergy’s American Transmission Systems Inc.
PJM’s markets were generally competitive in 2014, but last winter’s cold resulted in a 37% increase in LMPs and raised concerns about economic withholding, the Independent Market Monitor said in its annual State of the Market report, released Thursday.
Market Monitor Joe Bowring said weather-related demand and higher fuel costs in the first quarter boosted energy prices for 2014 despite lower prices the rest of the year.
Real-time LMPs rose from $38.66/MWh in 2013 to $53.14/MWh last year. Congestion costs increased by $1.2 billion (186%), and uplift jumped 11% to a record $965 million.
As a result, total billings increased by 62% to a record $50 billion, beating the previous record of $35.6 billion set in 2011.
The Monitor said the results show energy prices were generally competitive, meaning they were set by generators offering at, or close to, their marginal costs. The exception was the high demand hours in January 2014, when the behavior of some participants raised concerns about “economic withholding.”
“In particular, there are issues related to the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage,” the report said. “One of the symptoms of these issues was an unprecedented increase in uplift charges in January.”
The adjusted markup component of LMP doubled from $1.16/MWh (3%) to $3.32/MWh (6.2%).
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“There are currently no market power mitigation rules in place that limit the ability to exercise market power when aggregate market conditions are extremely tight,” the Monitor said. “If market-based offer caps are raised, aggregate market power mitigation rules need to be developed.”
The report includes 11 new recommendations (see table above). Only four of the Monitor’s 83 previous recommendations between 2009 and 2014 have been adopted in full, with another seven adopted in part. The remainder (87%) have not been acted on.
Generator Revenues
Thanks to the high prices last winter, average net revenues — a measure of the incentive to invest in new generation — rose sharply for many generators, with an increase of 74% for combustion turbines, 30% percent for combined-cycle plants, 113% for coal, 43% for nuclear, 24% for wind and 7% for solar.
“The impact of a relatively short period of high loads on net revenues illustrates how scarcity pricing can work to address the missing money issue in wholesale power markets,” the report said.
A new combined-cycle plant would have been profitable in 12 of 19 zones in 2014, while a new CT would have been profitable in 10 eastern zones. Despite the increases, however, new coal and nuclear plants would not have been profitable anywhere in PJM last year.
“Coal is still not remotely close to a signal to invest,” Bowring said during a press briefing last week.
The report identified 22 generators totaling almost 7,000 MW as at risk of retirement, 70% of the capacity from coal units with an average age of 46 years. One-quarter of the at-risk capacity are oil- or gas-fired steam units with an average vintage of 35 years.
Falling into this category were units that did not recover avoidable costs from total market revenues or did not clear the 2016/17 or 2017/18 base residual auctions but cleared in previous capacity auctions.
This is in addition to almost 27,000 MW of retirements that occurred or are expected between 2011 and 2019.
Capacity Market
Bowring also continued his campaign against the inclusion of limited demand response in the capacity market. DR and the 2.5% “holdback” to demand reduced capacity revenues by $3.4 billion (31%), Bowring said.
Total payments for DR rose almost 44% to $676 million in 2014 thanks largely to a $195 million increase in capacity revenues.
The Monitor said DR should be used to offset demand rather than treated as supply.
“A successful redesign of the PJM capacity market to address its identified flaws is the most critical initiative currently being considered by PJM stakeholders,” the report said. PJM’s Capacity Performance proposal, which would address some of the Monitor’s concerns, is pending before the Federal Energy Regulatory Commission.
Auction Revenue Rights & Financial Transmission Rights
Auction revenue rights and financial transmission rights revenues offset almost 91% of total congestion costs in the day-ahead energy market and the balancing energy market for the first seven months of the 2014/15 planning period, nearing full funding “for the first time in quite some time,” Bowring said.
The improvement resulted from a reduction in ARR allocations. “We don’t think it should have been done that way,” Bowring said. “And we think the underlying problems with FTR funding remain.”
The report cites a market design that it said “incorporates widespread cross subsidies.”
Uplift
Uplift rose $96 million to almost $965 million, although uplift as a share of total billings fell to 1.9% from 2.6%. Balancing charges increased $407 million, partially offset by a $282 million reduction in reactive services.
The recipients of uplift payments remained “remarkably concentrated,” Bowring said, with 10 units responsible for more than one-third of the total.
Bowring repeated his call for a change in confidentiality rules that would allow him to identify the units so that competitors could propose new generation or transmission to address the need for the out-of-market payments.
The lack of transparency “means there’s no competitive pressure on them,” Bowring said. “It’s not possible to compete that away.”
A group of large electric customers asked federal regulators to reject an agreement to keep a nuclear power plant in western New York operating.
The group said the Federal Energy Regulatory Commission should reject a reliability support services agreement ordered by the New York Public Services Commission to keep the 580-MW R.E. Ginna plant financially viable to serve customers of Rochester Gas & Electric (ER15-1047).
The utility and NYISO said the plant is needed to maintain system reliability until a transmission project that would bring additional energy into the Rochester area is completed in late 2018. An agreement filed with the PSC on Feb. 13 guarantees annual payments of about $210 million, minus some adjustments for support services. (See Ginna Nuclear Plant Wins Contract to Keep Operating).
The interveners — 60 large industrial, commercial and institutional energy consumers — say the out-of-market payments would distort NYISO’s wholesale electricity markets and result in “potentially staggering rate impacts to RG&E’s retail electric customers.”
RG&E estimated an average residential customer would see bills rise about 4.2% while costs for large primary customers would increase 6%. The exact amount will depend on the monthly output of the plant and changes in wholesale energy and capacity market prices.
The group says RG&E’s estimates understate the impact of the increases because they are averaged over the life of the 3.5-year agreement and are based on the total bill, including commodity costs unaffected by the deal. Primary customers would see increases of 9.05% in 2015. “On a delivery-rate-only basis, the RSSA apparently would result in increases of over 20% to retail customers,” the protest says.
Exelon unit Constellation Energy Nuclear Group said it has lost $100 million over the last three years operating the plant. It said it would mothball the plant without an agreement.
However, opponents to the deal have previously said no formal proceeding to shutter the plant has been started, and the move by CENG is an attempt to sidestep the lengthy and costly process to formally retire a nuclear plant. The interveners say reliability-must-run contracts should only be allowed when there is concrete evidence the plant would otherwise retire.
VALLEY FORGE, Pa. — PJM generators performed much better during this winter’s cold than a year ago, with forced outage rates limited to 12.3% on Feb. 20, when PJM set a new record winter peak load of 143,826 MW. About 22,800 MW of generation was unavailable due to forced outages.
Compared with last year, this winter saw some areas with colder temperatures, and they extended farther south, dispatch manager Chris Pilong told the Operating Committee last week.
About 22% of the outages Feb. 20 were due to gas issues. PJM lost 17,500 MW to forced outages the night before the record was set, of which one-third were gas-related.
No emergency procedures were required, and no demand response was dispatched, during the cold snap. There were no major transmission constraints.
SynchroPhasor Error Rates Greatly Improved
SynchroPhasor error rates have been trending downward in the past few months. In January, five of the 12 companies met the 0.2% error goal, and four others were below 1%.
The phasor measurement unit (PMU) technology is not currently considered a “critical” cyber asset but could become so in about a year. Critical assets are defined as those whose failure would, within 15 minutes, adversely impact systems in a way that would affect the reliable operation of the bulk electric system.
PJM expects the technology to become critical once it is used in solutions by the state estimator or becomes crucial to interconnection reliability operating limit (IROL) determinations.
Emergency Tool Refresh Underway
A revamped emergency procedures tool, which has been in testing since Feb. 19, is expected to go live March 30. Phase 2 enhancements are expected to be rolled out in June.
Fuel Type Posting Rule Takes Effect April 1
Generation operators will be required to enter fields for energy fuel type (and sub type) and start-up fuel (and sub type) in eMKT beginning April 1. Offers lacking the information will be rejected.
The rule change follows the Feb. 23 introduction of new functionality allowing generators to make intraday cost schedule changes in eMKT. The manual process for such changes is no longer being used.
WASHINGTON — Representatives of PJM, ISO-NE and NYISO told the Federal Energy Regulatory Commission last week that they are prepared to implement their states’ plans for complying with the Environmental Protection Agency’s carbon emission rule but that the agency’s deadlines should be flexible to account for delays in building new gas pipelines and electric transmission.
PJM officials also told FERC in the third of four technical conferences on the Clean Power Plan that states that rebuff regional efforts to price CO2 emissions could overwhelm the RTO’s economic dispatch software, undermining reliability.
That’s not an issue for New York and the six New England states, which are members of the Regional Greenhouse Gas Initiative (along with Maryland and Delaware in PJM). Officials of those states see RGGI’s cap-and-trade program as central to their states’ compliance.
Robert Ethier, vice president of market development for ISO-NE, said the RTO’s LMP energy market and forward capacity market, combined with RGGI, gives the region the tools it needs to comply “efficiently.”
RGGI the Right Tool
“RGGI seems like exactly the right mechanism to resolve this issue,” Ethier said.
Andy Ott, PJM’s executive vice president for markets, said the RTO’s regional dispatch can help reduce emissions either through an explicit carbon price or through run-time limitations on generators.
But Ott said PJM officials are concerned that if too many states choose run-time limits, it would result in “discontinuities” in the regional market that could threaten operating reliability.
“If a lot of states decide to put in physical limitations, it could actually create a situation where, more often than not, we can’t solve [dispatch] economically anymore, so then we have to go into … emergency dispatch. … That could affect reliability.”
Despite their concerns, RTO and state officials expressed far more confidence than state and utility officials from the Southeast, who also testified at the hearing. They also were more sanguine than several of the state officials who testified before a U.S. Senate hearing the same day. (See related stories, Debate over Cost, Impact of EPA Plan in Southeast and FERC Seeking Its Role on Carbon Rule ‘Safety Valve’.)
Flexibility on Deadlines
In addition to RGGI, New England will also depend increasingly on wind and Canadian hydropower to comply with the EPA rule, said Steve Rourke, ISO-NE’s vice present of planning. Of the 11,000 MW on the RTO’s generator interconnection queues, 42% is wind and virtually all of the remainder is gas.
Such a change in the generation mix will require a “significant transmission build out,” Rourke said. He noted the combined solicitation planned by Connecticut, Massachusetts and Rhode Island for more than 2,300 GWh of renewable energy annually and transmission to deliver it. (See New England States Combine on Clean Energy Procurement.)
The region’s best wind assets are in Maine and elsewhere in northern New England, many of them 100 miles from the existing transmission network, he said.
“We’re sort of far down the road toward meeting the requirements of the Clean Power Plan, but when you look forward there may be a few speed bumps in the road,” Rourke said.
Among those concerns, he said, are retirements of oil- and coal-fired generation, which will create a need for more gas pipeline and storage capacity. He also said the retirement of the Vermont Yankee nuclear plant raises questions about the viability of the region’s four remaining nuclear plants, which produce about one-quarter of its energy. “That’s a big question mark going forward,” he said.
Unrealistic Emission Rate
Rana Mukerji, NYISO’s senior vice president for market structures, said New York’s markets “are well structured to comply” with the rule but that EPA needs to provide the state “a more realistic emission rate.”
Mukerji said EPA’s proposed 549 lb/MWh rate is about half that of neighboring Pennsylvania (1,052 lb/MWh) and the limit on new combined-cycle gas turbines (1,000 lb/MWh).
That is not achievable in downstate New York, particularly New York City, which he said relies on dual fuel fossil units to meet needs on peak days. In 2012, Mukerji said, the city needed dual-fuel units for more than 14 peak days; EPA’s proposed rule envisions such units being called on only three times a year, he said.
Maryland Attorney General Brian Frosh called on state regulators to reject Exelon’s acquisition of Pepco Holdings Inc., while the companies more than doubled their offer of ratepayer incentives.
Frosh told the Public Service Commission the $6.8 billion deal was unlikely to improve reliability and would harm competition.
Maryland Attorney General Brian Frosh
“Post-merger, Exelon will control service to 80% of the state’s ratepayers,” Frosh said. “Internal documents show that Exelon plans to operate its distribution utilities to protect the company’s massive, multi-billion dollar investment in unregulated generation (including its economically challenged nuclear plants) by seeking to control the pace of distributed energy resource penetration in retail service territories.”
Frosh said the deal would only benefit the companies’ shareholders and executives, not ratepayers.
At the same time, the Coalition for Utility Reform and the city of Gaithersburg asked the PSC to require Exelon to up its commitment to renewable energy, energy efficiency and distributed generation. The March 3 filing was made by the coalition’s counsel, energy attorney and Montgomery County Councilmember Roger Berliner, a long-time Pepco critic.
“If the commission chooses to allow one energy company to control 85% of the Maryland market, a company hostile to renewables, distributed energy and energy efficiency among other things, then the commission must insist on a precondition that the merged entity adopt the very best practices in the Pepco service territory as a ‘pilot’ for the rest of the state, practices that simultaneously address the threat to the public interest and are, at the same time, generally recognized as the cornerstone of utilities of the future,” the coalition said.
Increased Rate Credits
Exelon outlined its new offer in a filing March 3 with the PSC.
With Pepco’s agreement, Exelon boosted a reserve that will pay for benefits such as rate credits, energy efficiency and help for low-income customers from $40 million to $94.4 million.
The use of the fund would be at the discretion of the PSC, whose staff had recommended $167 million in credits. Maryland’s consumer advocate, the Office of People’s Counsel, has urged the PSC to turn down the original deal, calling the benefits Exelon offered “either non-existent or woefully deficient.”
Exelon also increased its commitment to reliability, saying performance will be measured on an annual basis beginning next year instead of by a three-year average from 2018 to 2020.
Exelon also said it will offer a one-time amnesty for qualifying low-income families, eliminating unpaid bills that are more than three years past due.
The acquisition would combine Exelon’s electric and gas utilities — Baltimore Gas and Electric, Commonwealth Edison and PECO — with PHI’s Atlantic City Electric, Delmarva Power & Light and PEPCO.
The staff of the Delaware PSC has approved the transaction, as has the New Jersey Board of Public Utilities, the Federal Energy Regulatory Commission and the Virginia State Corporation Commission.
Exelon hopes to close the deal in the second or third quarter of this year.
Environmentalists Say Most Marylanders Against Exelon-Pepco Merger
The Chesapeake Climate Action Network (CCAN) last week released the results of a poll it commissioned that shows 61% of Marylanders share the group’s opposition to Exelon’s acquisition of Pepco Holdings Inc.
The telephone poll, conducted by Annapolis-based research firm OpinionWorks, sampled 594 randomly selected registered Maryland voters from Feb. 26 through March 8. It shows only 22% expressing approval, with 17% unsure. It has a margin of error of ± 4%, according to OpinionWorks.
Opposition was strongest in Baltimore City, where 73% opposed the merger. CCAN noted that Baltimore ratepayers have seen four rate hikes in the three years since Exelon acquired Baltimore Gas and Electric.
The pollsters prefaced the question with a statement noting that the Maryland Energy Administration “is opposed to the merger, saying it would create a large monopoly that would be costly for consumers.”
“We now know that this merger is not only a bad deal for Marylanders, but a highly unpopular one as well,” CCAN Director Mike Tidwell said in a statement. “… This deal would harm ratepayers and harm our future ability to generate local, renewable energy.”
On March 3, CCAN and the Sierra Club filed a joint brief with the Maryland Public Service Commission opposing the merger.
Exelon spokesman Paul Elsberg called the poll “fundamentally flawed.”
“The poll was conducted for a group that opposes the merger, not for an unbiased organization. Many of the respondents are not even customers of BGE or Pepco Holdings utilities,” he said. “Testimony provided at community hearings and directly to the PSC shows that there is broad support for the merger in the community.”
NEW ORLEANS — MISO stakeholders last week indicated widespread support for moving to a seasonal measurement of resource adequacy, with supporters saying it would improve reliability and efficiency.
MISO currently assesses resource adequacy annually, based on meeting the summer peak. But in a “hot topic” discussion at last week’s Advisory Committee meeting, all sectors except the Power Marketers and Independent Power Producers indicated support in adopting, or at least studying, a change to allow seasonal products.
“Under the current annual construct, seasonal demand is unaccounted for, seasonal resource capability and availability (most notably gas) is not recognized and seasonal transmission differences are not taken into consideration,” Manitoba Hydro, representing the Coordinating Sector, said in its written comments.
Flexibility
“An annual construct may result in reliance on resources when they are unlikely to be available and may underestimate the risk of loss of load other than at summer peak,” the company continued. “In addition, lack of flexibility for load to procure capacity (or be forced to over-procure for all months of the year) to meet variable seasonal demand is simply less efficient and cost effective.”
The company called not for a summer-winter construct but one that used four seasons, which it said would align with commercial contracts, financial transmission rights auctions and quarterly data submittals to the North American Electric Reliability Corp.
Steve Dahlke of the Great Plains Institute, representing the Environmental sector, said a seasonal construct would add more “granularity,” capturing, for example, wind’s increased production in the winter.
“We’ve seen wind resources helping out during this winter’s events,” he said, noting that wind generation set an all-time record Jan. 8, the peak demand day for the RTO this winter. He said it would also capture demand response not available in the summer.
The Transmission Dependent Utilities said a seasonal construct is “the most significant improvement” MISO could make to improve resource adequacy and urged MISO to implement it as soon as the 2016/17 planning year.
“The concept of a seasonal construct has been raised in a number of different forums over the past few years; however, MISO’s commitment to explore and pursue a seasonal construct still remains unclear,” it said. “… Stakeholders in the Supply Adequacy Working Group (SAWG) are still waiting for MISO’s views on this topic after formal discussions related to a seasonal construct began in early 2014.”
No Immediate Help
The IPP sector, however, said that such a change would not help MISO address expected capacity shortages in MISO North and Central next year. It noted that MISO has indicated a transition to a seasonal product could not happen before the 2017/18 planning year.
The IPPs said they were reserving judgment on the concept and that no discussion should occur until MISO publishes a promised white paper examining potential risks and opportunities.
“The IPP sector remains concerned that MISO has already pre-committed publically to state regulators to moving to a seasonal resource adequacy construct and without a fully vetted stakeholder process,” it said. “Such a process could prove lengthy, as already demonstrated when the current resource adequacy construct evolved from a monthly to an annual process. The MISO stakeholder process and regulatory process at [the Federal Energy Regulatory Commission] took almost four years before changes were accepted.”
“I don’t think it’s a forgone conclusion that we should move to a seasonal construct,” Dynegy’s Mark Volpe, representing the IPPs, told the committee.
The Power Marketers, meanwhile, said the idea was a solution in search of a problem. “Resource adequacy must be achieved every day, so having less capacity committed to the footprint on any given day will only serve to reduce reliability,” they said. “Subsequently, the economic efficiency of the energy market will suffer by reducing the number of resources that are available to be committed on a day-ahead and real-time basis.”
Opposition to Mandatory Capacity Market
There was almost as much consensus among stakeholders in opposition to a move to a mandatory capacity market such as PJM’s.
“MISO is not PJM,” said Justin Joiner of Vectren. “The concerns there do not exist in MISO.”
Alcoa and other members of the End-Use Customers sector also rejected the idea, also noting the differences between MISO, PJM, NYISO and ISO-NE.
“There has been a vibrant bilateral capacity market in place within the MISO footprint that has allowed end-use customers in MISO that do have retail choice (as well as municipal and cooperative electric utilities) the ability to contract for capacity at fixed prices at least three years into the future at reasonable prices significantly lower than in these other ISOs and RTOs,” it said.
The Organization of MISO States said it opposed imposition of a downward sloping demand curve or a minimum offer price rule, or the elimination of fixed resource adequacy plans.
No ‘Missing Money’ Problem
“To the extent there is a ‘missing money problem’ in MISO it is negligible and addressing the supposed problem will provide little benefit to the vast majority of the footprint,” OMS wrote. “For the majority of MISO generation — traditional, vertically-integrated, state-regulated generation — there is no missing money problem.”
OMS also said it opposed a mandatory resource adequacy construct. “If the [Planning Resource Auction] were mandatory, it would be the sole arbiter of MISO capacity prices, not state and local regulators.”
The IPPs called for both a sloped demand curve and a three-year forward commitment, saying that without them the “reliability of the grid is threatened.”
“MISO neither has an efficient capacity market, nor has enough capacity to meet reserve requirements,” they said. “This is not a coincidence.”
Story on ComEd Contributions Spurs Call for Investigation
A state senator called for an investigation of Commonwealth Edison after the Chicago Tribune reported that the utility spent $60 million in ratepayer money over seven years on politically influential charities.
“The allegations in the Tribune article are serious and call for immediate action,” state Sen. Dan Duffy said in a letter to Attorney General Lisa Madigan. “ComEd should be required to disclose these contributions to ratepayers. At best, ComEd shareholders, not ratepayers, should bear the burden of funding these contributions.”
A 1987 law allows ComEd, the state’s largest utility, to pass on the cost of its charitable contributions to ratepayers. The Tribune article listed instances where some charities that received ComEd assistance were in the position to aid it.
County Emergency Management Agency Uses Dresden’s Cooling Pond Water to Battle Ice
Warm water from Dresden nuclear plant is being used to melt down ice flows on the Kankakee River to prevent flooding and damage to homes and docks.
The Will County Emergency Management Agency has devised a system to siphon the 70 F water into the Kankakee River. “The warm water from Dresden’s pond helps break up the ice so it can flow freely downstream,” said Harold Damron, the agency’s director.
Challenges to NIPSCO’s $1.1 Billion Modernization Plan Heard in Court
In a case before the state Court of Appeals, the Office of Utility Consumer Counselor and a group of industrial customers are challenging Northern Indiana Public Service Co.’s $1.1 billion electric modernization plan as too costly.
“These plans can cost ratepayers hundreds of millions, even billions, of dollars,” said Utility Consumer Counselor David Stippler. The Utility Regulatory Commission approved the plan in 2013, which would be funded by yearly rate increases that will total 4.9% by 2020.
A NIPSCO attorney said the improvements are necessary. “The commission determined the plan is beneficial to consumers, and no one has disputed that,” said Brian Paul. The court decision could affect improvement plans proposed by other state utilities.
Kentucky Power Appeals PSC Ruling on ‘Unreasonable’ Fuel Costs
Kentucky Power is appealing a Public Service Commission order requiring it to refund $13 million to customers after the commission determined some of its fuel costs last year were unreasonable.
The American Electric Power subsidiary says the commission disallowed charges associated with having both the Mitchell power plant and Big Sandy Unit 2 in operation simultaneously. Kentucky Power said it was necessary to run both units in Louisa to maintain system reliability and to meet demand, especially during last winter’s polar vortex.
Big Sandy Unit 2 is being retired later this year.
City Upset That DTE Rate Hikes Would Kill LED Lighting Incentive
The city of Ypsilanti says a proposed DTE Energy rate increase for LED street lighting, combined with a cut in charges for conventional sodium-vapor streetlights, would undermine the incentives that prompted the city to spend $500,000 last year to convert its streetlights to the more efficient LED technology.DTE’s proposal would increase the cost of powering a 65-W LED bulb from $138 to $154 a year, while the cost of running a 100-W sodium bulb would drop from $184 to $129. “If this rate hike happens, we’ll really feel like this was a bait and switch,” said Ypsilanti City Council Member Brian Robb.
The utility said the old LED rate was experimental. “As we gained more experience with LED technology, we changed the pricing to reflect a more complete understanding of the costs associated with it,” said DTE spokesman Scott Simons.
University Report IDs Ways State Could Improve Fracking Oversight
A University of Michigan report suggested the state take a number of steps to strengthen its oversight of hydraulic fracturing, including better monitoring of surface and groundwater and mandating more emergency planning by natural gas exploration companies.
The recommendations were included in a 277-page report compiled by scientists, lawyers and other University of Michigan faculty. “The purpose of the study is to pull together a massive amount of information and analyze the options in a way that is clear, so the state can look at these options and decide which if any they might want to adopt,” said Sara Gosman, one of the report’s authors.
More than 12,000 fracked wells have been drilled in Michigan since the late 1940s, but high-volume fracking of deep shale deposits is a new phenomenon. Michigan has 13 producing wells in the Utica-Collingwood shale formation, but drilling companies have leased hundreds of other sites.
Mississippi Power’s CEO Warns Kemper Ruling Could Result in Rate Hikes of 35%
Mississippi Power CEO Ed Holland said a state Supreme Court ruling that orders the company to refund customers $271 million for plant construction costs will almost certainly lead to higher rates.
Holland, in a Sun Herald op-ed, said the court’s ruling effectively voids a plan the company and the Public Service Commission developed to keep down rate hikes associated with construction of the Kemper County integrated gasification combined-cycle plant. “If the court’s opinion stays in place and the refund is required, we will have little choice but to seek at least the original estimated amount of approximately 35% in rate increases,” he wrote.
The court threw out a PSC decision to allow $281 million in rate recovery for costs associated with the plant’s construction. The court said the PSC never found that the funds were “prudently incurred,” a requirement for recovery. Mississippi Power is challenging the court ruling.
PSC Approves Ameren’s Efficiency Plan Allowing 2013 Recovery Calculations
The Public Service Commission approved a settlement that determined Ameren Missouri’s energy efficiency programs saved 347 GWh in 2013. The amount will determine how much money the utility can recover from ratepayers.
Ameren had claimed that its program saved nearly 400 GWh. The Office of the Public Counsel estimated the savings at 300 GWh. They settled on 347 GWh.
2nd State Judge Signs Injunction Against Keystone XL Eminent Domain Actions
A York County District Court judge became the second state judge to grant an injunction halting TransCanada’s use of eminent domain to secure a route for its controversial $8 billion Keystone XL Pipeline.
The judge ruled in favor of a group of landowners who are challenging a state law that gave TransCanada eminent domain powers to build its crude-oil pipeline to Gulf Coast refineries and terminals.
“I know the war is not won yet, but it’s a start,” property owner Susan Dunavan said after the ruling.
JCP&L Planning $267 Million on System Improvements; Rate Counsel Endorses $107 Million Rate Cut
Jersey Central Power & Light said it will spend $267 million on transmission and distribution improvements this year, including a new transmission line in Middlesex County.
Among the projects planned are nearly $6 million in distribution circuit upgrades, $24 million in tree trimming, and money for planning and constructing a 230-kV transmission line in Monmouth County.
JCP&L’s reliability record has been a recent target of regulators and consumers. The Division of Rate Counsel last month endorsed a decision by an administrative law judge that would force the company to cut rates by $107 million, saying that the utility’s reliability record is poor.
The Rate Counsel argued that the company had earned profits in excess of the amount allowed by the Board of Public Utilities. About 90% of its customers were left without power after Hurricane Sandy.
“JCP&L customers have suffered poor reliability too long and should be provided a remedy immediately,’’ the Rate Counsel argued.
Hearing Scheduled for New Power Plant near Williston
The Public Service Commission will hold a hearing this week on the proposed $161 million expansion of the Pioneer Generation Station near Williston to meet growing electricity demands from the state’s oil and gas industry.
Basin Electric said the proposed expansion is needed to meet a forecasted 1,600-MW increase in load by 2035. The company wants to add 12 reciprocating gas-fired internal combustion engines generating up to 111 MW.
PUCO Rejects AEP’s Guaranteed Income Plan for Coal Plants
The Public Utilities Commission last week rejected American Electric Power’s request for a guaranteed income for two of its coal-fired plants, saying the proposal wasn’t in the best interest of ratepayers.
While PUCO rejected the proposal, it ruled that the power purchase agreement was legal. That gave AEP a kernel upon which to press forward with a similar request for other plants. It has argued that customers would benefit from supply stability if the plants received a guaranteed rate. Critics say its proposal would represent a retreat from market-rate pricing.
“Further delays in deciding this issue will postpone our customers’ ability to take advantage of the financial benefits of what we proposed,” AEP Ohio President Pablo Vegas said in a statement. “We will work with the PUCO to address their outstanding issues with our problems.”
Rumors Surround Porter’s Move to PUCO, Johnson’s Tenure
Porter
Gov. John Kasich’s choice of Andre Porter, the state commerce director, to fill a vacancy on the Public Utilities Commission has sparked speculation that Chairman Tom Johnson’s reign may be ending.
Some observers wonder why Porter, who served previously on the commission, would want to make the move back to PUCO if he wasn’t angling for the chair. Johnson, who has been the commission’s chair for less than a year, has faced several controversial issues, including proposals to guarantee prices for merchant power and a legislative proposal to freeze the state’s renewable and energy efficiency standards.
The governor’s office did not comment on his plans for the commission.
PUC Orders FirstEnergy’s Pa. Companies to Give More Details on Improvement Plan
The Public Utilities Commission ordered FirstEnergy’s four companies in the state — Met-Ed, Penelec, Penn Power and West Penn Power — to provide more details on how they intend to address issues raised in a PUC management audit.
The PUC’s Bureau of Audits identified 28 areas of improvement in the companies’ management practices that could produce one-time efficiency savings of $19.2 million and annual savings of up to $3.8 million. The PUC said FirstEnergy’s response was short on specifics and directed the company to devise a more detailed implementation plan.
“Because we have received similar responses to previous audit recommendations in the past with little meaningful improvement, it is imperative that FirstEnergy develop more robust responses to these recommendations,” Commissioner James H. Cawley said in a motion approved by the commission.
Tomblin Vetoes Net Metering Bill, Solar Advocates Applaud
Gov. Earl Ray Tomblin vetoed a bill that would have prohibited utilities from subsidizing solar customers by charging other ratepayers for costs associated with installing and administering solar net-metering systems.
Solar advocates said the bill would have allowed utilities to raise costs for owners of solar installations, reducing incentives for renewable power.
“This bill was fatally flawed,” said Rhone Resch, president and CEO of the Solar Energy Industries Association. “Did it end up that way for political reasons? Or was it a case of sloppy drafting? Whichever the case, Gov. Tomblin did the right thing by vetoing the bill and sending it back to the drawing board.”
Despite retirements of numerous coal-fired generators, PJM has reduced its carbon emissions only modestly in the last five years.
