PJM Transmission Expansion Advisory Committee 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.

— Suzanne Herel

March 17, 2015January 18, 2024

Company Briefs: March 17, 2015

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.

More: SeeNews Renewables

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.

More: Midwest Energy News

Arkansas Electric Co-op Looking at More Hydro

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.

More: P-14663-000; P-14664-000; P-14665-000

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.

More: NJ.com

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.

More: Jacksonville Business Journal

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.

More: Journal Sentinel

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.

Terms of the purchase were not disclosed.

More: Clean Technica

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.

More: Exelon; San Antonio Business Journal

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.

More: Mainline Media News

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.

More: Chattanooga Times Free Press

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.

More: Wichita Eagle

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.

More: North American Wind Power

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.

More: Zacks

Compiled by Ted Caddell

March 17, 2015June 15, 2023

Monitor: Winter Prices Boosted PJM Prices, Raise Withholding Concerns

By Rich Heidorn Jr.

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%).

“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.”

March 17, 2015

New York Industrials Want Ginna Deal Tossed

By William Opalka

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.

March 17, 2015June 15, 2023

PJM Operating Committee Briefs

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.

Cold Sends PJM to New Winter Record.)

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.

— Suzanne Herel

March 17, 2015June 15, 2023

Eastern RTOs Express Confidence in Meeting Clean Power Plan Compliance

By Rich Heidorn Jr.

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.

March 5, 2015

Exelon ups Merger Offer in Maryland as AG Calls for Rejection – UPDATE

By Suzanne Herel

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.

“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.

In addition to Maryland, the merger must be approved by regulators in D.C. and Delaware. (See DC Consumer Advocate Seeks Delay in Exelon-Pepco Proceedings.)

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.”

— Ted Caddell

March 3, 2015June 15, 2023

MISO Stakeholders Call for Seasonal Resource Construct; Cool to Mandatory Capacity Market

By Rich Heidorn Jr.

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.”

March 3, 2015

New York PSC Bars Utility Ownership of Distributed Energy Resources

By William Opalka and Rich Heidorn Jr.

New York’s overhaul of the electric industry, which seeks increased reliance on distributed energy resources, will largely bar utility ownership of those assets.

The state Public Service Commission on Thursday took another step in its Reforming the Energy Vision process with a 133-page order establishing a “policy framework” for the development of markets for distributed energy resources (14-M-0101).

The framework envisions utilities serving a central role in the transition as distributed system platform (DSP) providers, responsible for integrated system planning and grid and market operations.

In most cases, however, utilities will be barred from owning distributed energy resources (DER): demand response, distributed generation, distributed storage and end-use energy efficiency.

The planning function will be reflected in the utilities’ distributed system implementation plan (DSIP), a multi-year forecast proposing capital and operating expenditures to serve the DSP functions and provide third parties the system information they need to plan for market participation. The first plans will be due Dec. 15 from Central Hudson Gas & Electric, Consolidated Edison of New York, Orange & Rockland Utilities, Rochester Gas & Electric, New York State Electric and Gas and Niagara Mohawk Power. (See related story, Timeline for New York’s ‘Reforming the Energy Vision’.)

Grid Integration

From their place between NYISO wholesale markets and market participants and end-users, the utilities will integrate distributed resources by balancing supply and demand-side resources through real-time load and network monitoring, enhanced fault detection, automated feeder and line switching, and automated voltage and reactive power control.

“It is anticipated that over time, DSPs will increasingly rely on [distributed resources] to maintain reliable system operations during both ‘blue sky’ days and significant system events,” the order said.

Markets

The plan envisions procurement evolving from a near-term approach based on requests for proposals and load-modifying tariffs to “a more sophisticated auction approach.”

Although there will be room for geographically unique products, there will be a standard market platform for the entire state to ensure efficiency for providers and multi-site customers. “This requirement extends beyond the ‘common look and feel’ of customer orientation, into the technical protocols and market rules to which aggregators and service providers must conform,” the PSC said.

NYISO could accept demand reduction bids directly from DER providers, dispatching demand-side reductions in competition with supply-side resources, or accept bids from a utility acting as an “aggregator of aggregators.” Alternatively, utilities could use contracted DER to modify its load shape when it bids into the wholesale market to serve its load.

“Demand is becoming an integral resource in the operation of the grid and we have to change regulation to do that,” PSC Chair Audrey Zibelman said at the commission meeting.

Utility Ownership

To address market power concerns, the commission said that utility ownership of distributed resources “will be the exception rather than the rule.”

“Because of their incumbent advantages, even the potential for utility ownership risks discouraging potential investment from competitive providers,” the order said. “Markets will thrive best where there is both the perception and the reality of a level playing field, and that is best accomplished by restricting the ability of utilities to participate.”

The commission said utility ownership would be permitted under three exceptions:

Energy storage integrated into distribution systems. “Storage technologies integrated into grid architecture can be used for reliability and to enable the optimal deployment of other distributed resources, and we agree with staff that this application of storage technology should be permitted without the need for a market power analysis. REV will support a greater understanding of how storage strategically used on the grid can support greater penetration of intermittent renewable resources without compromise to system reliability. It will be advantageous for utilities to gain this experience and, as part of their DSIP plans and rate plans, utilities should develop information on optimal locations and levels of storage either on the system or behind the customer’s meter.”
Projects enabling low- or moderate-income residential customers to benefit from DER where markets are not likely to satisfy the need. “This potential is particularly acute in the case of rental customers that cannot control improvements to premises.”
Demonstration projects. “We recognize that demonstration partnerships with utilities and third parties can accelerate market understanding and the development of sustainable business models. In limited circumstances, utility investment and ownership of assets to support such demonstrations is warranted.”

“In the limited situation that utilities will be allowed to own DER as a regulated asset, they will be restricted to recovery of their actual costs,” the commission said.

Consumer Protections, Energy Efficiency

To increase penetration of energy efficiency, utilities will also be required to expand their programs — currently based on direct rebates and subsidies — to include third-party companies. “The state’s greenhouse gas reduction goals demand that we achieve significantly more efficiency than is practical to achieve through current ratepayer-funded direct subsidy programs,” the commission said.

The commission said it will protect consumers by requiring certification of any DER provider that requests consumer data, or that furnishes services via DSP or other utility functions. “Warranty and disclosure requirements will also be considered,” the commission said.

The steps are consistent with the draft State Energy Plan, which calls for the use of markets and reformed regulatory techniques to improve system efficiency and customer empowerment and reduce carbon emissions, the PSC said.

“By requiring utilities to modernize their business models and meet evolving customer demands, New York is committed to forging a new path to develop a dynamic, customer-oriented power grid able to drive clean energy markets to scale,” Richard Kauffman, chairman of energy and finance for New York, said in a statement.

Two Tracks

The proceeding was separated into two tracks, with Track One focused on developing distributed resource markets, and Track Two on reforming utility ratemaking.

The PSC’s staff says that utility financial incentives should be structured “to reward utilities for the efficient development of DER on their systems in a manner that either makes them indifferent to ownership, or favors ownership by third parties.” Staff will provide a straw ratemaking proposal by June 1.

In related orders Thursday the PSC also:

Approved the first community choice aggregation pilot program in New York. It will allow Westchester County municipalities to issue solicitations for natural gas or electricity supplies for local residents and small businesses (14-M-0564).
Stayed its December decision that restricted how customers with multiple locations could participate in net metering programs and postponed its rule requiring utilities to file new tariffs to resolve concerns about how such customers are compensated. The ruling, which gives renewable energy developers and utilities more time to transition away from existing net metering rules, means solar projects already under way will be eligible to receive net metering credits (14-E-0151, 14-E-0422).

March 3, 2015June 15, 2023

Year 1 Judged a Success for MISO South; Gains Limited by SPP Dispute

By Rich Heidorn Jr.

NEW ORLEANS — MISO officials last week called Year One of MISO South a success but acknowledged room for improvement in crisis communications and unfulfilled potential because of the ongoing dispute with SPP.

MISO said ratepayers of Entergy and other utilities that joined MISO in December 2013 received $730 million to $954 million in net benefits in 2014, including at least $160 million from more efficient generator commitment and dispatch and at least $570 million from deferred generation investments made possible by the increased footprint diversity.

MISO had estimated the benefits for the Entergy companies alone at $524 million.

The expansion boosted MISO’s high-voltage transmission to almost 66,000 miles from 50,000 and its generation capacity to 177 GW from 133 GW.

Wayne Schug, vice president of strategy and business development, explained how MISO calculated its “value proposition” in a presentation to members last week.

The RTO said the entire footprint saw net benefits of $2.2 billion to $3.1 billion. Schug said the range reflects different assumptions that went into the calculations.

Load Shed, Tornado Highlight Need for Better Coordination

miso south — Entergy Arkansas’ Mayflower substation, one of the three major substations serving the Little Rock area, suffered heavy damage in the April 27, 2014 tornado. The 500-kV high-voltage yard lost all of its switches and breakers.

The southern expansion meant the RTO, accustomed to dealing with winter snow storms, also had to be prepared for extreme summer heat and hurricanes, said Todd Hillman, vice president of MISO South.

While the summer was mild and there were no severe hurricanes, officials said their emergency procedures were tested during several incidents.

On April 23, multiple forced outages led to post-contingent loading of more than 125% of system operating limits, with studies indicating 1,100 MW of load at risk for the next contingency.

MISO treated the situation as a temporary interconnection reliability operating limit (IROL) condition.

After redispatching generation, MISO directed Entergy to shed 150 MW of load. Entergy ultimately shed 163 MW for almost two and a half hours, avoiding a much larger load shed.

Hillman said the incident highlighted a need to improve crisis communication with state commissions. “We could do a much better job of coordinating with the states,” he said.

Four days later, on April 27, a tornado hit Northern Arkansas, cutting a half-mile-wide swath for about 80 miles with winds of more than 136 mph. Multiple 500-kV transmission lines were lost or damaged, and MISO ordered Entergy’s Arkansas Nuclear One offline.

Hillman said the incident demonstrated the need for better coordination with nuclear units following severe weather events.

Another management challenge for MISO is the much larger qualifying facilities in MISO South, with some behind-the-fence industrial generators as large as 1,500 MW.

SPP Dispute

Officials said the ongoing dispute with SPP had limited the benefits of the larger footprint.

“I really hope we can resolve” the SPP dispute, said Director Michael Curran, who said their neighbor could help improve East/West transmission. “If we continue to take hostages … or create toll roads, we’re really just undercutting the economic successes,” he said.

MISO Board Chairman Judy Walsh said she and CEO John Bear attended SPP’s January board meeting at the invitation of SPP Chairman Jim Eckelberger and later dined with the SPP board at Eckelberger’s home. “I think that was a breakthrough of sorts in the relationship,” she said. “The boards have developed a common goal of greater communication and cooperation and working together to make the seams more efficient.”

She said MISO plans to return the invitation to SPP.