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December 7, 2025

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FERC Rejects Order 1000 Waiver on SPP-SERTP Seam

By Chris O’Malley

sertpThe Federal Energy Regulatory Commission said last week that SPP must engage in interregional coordination and cost allocation with the Southeastern Regional Transmission Process region (SERTP), rejecting the RTO’s request for a limited waiver of Order 1000 requirements.

FERC’s ruling came in a 94-page order that approved Order 1000 compliance filings by SPP and the SERTP utilities, subject to additional filings (ER13-1939).

SPP had argued its only interconnection to SERTP was via Associated Electric Cooperative Inc. (AECI), which supplies 51 local electric cooperatives in Missouri, Iowa and Oklahoma.

Because AECI is “a non-commission jurisdictional utility” that does not intend to revise its Open Access Transmission Tariff to implement Order 1000, SPP argued, it was impossible for the RTO to comply with Order 1000’s requirements regarding the SERTP seam.

A waiver is also appropriate, SPP argued, because it and AECI already engage in interregional coordination through a joint operating agreement. The two regions have been exploring revisions to the JOA to provide “similar benefits that the requirements of Order No. 1000 intend to provide,” SPP said.

FERC noted, however, that AECI voluntarily enrolled in the SERTP region. “As a result, SPP and SERTP are neighboring transmission planning regions,” the commission said.

Large Number of Interconnections

FERC also said the RTO is connected to AECI “to a greater degree than SPP suggests” because of the large number of interconnections between AECI and 10 SPP members, including Kansas City Power & Light and Westar Energy.

The commission also rejected SPP’s claim that FERC had set a precedent for its request when it granted a waiver to Maine Public Service Co. FERC noted that Maine Public Service is not interconnected to the United States but rather to Canada. That unique situation made it impossible to join a transmission planning region consistent with Order 1000.

The commission accepted interregional cost allocation filings by SERTP members Southern Co., Duke Energy Carolinas, Louisville Gas & Electric, Kentucky Utilities and Ohio Valley Electric Corp. with a few caveats.

FERC ordered the companies to provide identical language in provisions on cost allocation, data exchange and the identification of interregional transmission facilities.

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Protests Continue — on Camera — at FERC

By Rich Heidorn Jr.

WASHINGTON — About 10 protesters were led or carried out of the Federal Energy Regulatory Commission’s open meeting Thursday after defying the commission’s “no interruptions” rule with chants of “Stop construction at Cove Point!”

Last week, the commission issued an order saying it no longer will allow protesters to read statements before its meetings, as Chairman Cheryl LaFleur previously had permitted since the activists began appearing regularly at commission meetings last fall.

The new policy came after protesters — no longer content to read a statement before the session — disrupted January’s open meeting and a February technical conference on the Clean Power Plan. (See FERC Cracks Down on Protesters.)

Last week’s order also ended the commission’s ban on the use of cameras — which meant that the first test of the new policy was captured by photographers, including those from Politico and RTO Insider.

Protester briefly resists security guards attempting to escort him out of FERC meeting.
Ted Glick, national campaign coordinator at the Chesapeake Climate Action Network, briefly resists security guards attempting to escort him out of the FERC meeting.  © RTO Insider

The commission’s secretary began the meeting by reading a summary of the new policy, which also was posted on a large sign outside the meeting room.

Immediately thereafter, two protesters stood up, facing the commissioners, but were confronted by security as they attempted to speak. One of the protesters was Ted Glick, national campaign coordinator at the Chesapeake Climate Action Network. Glick had previously said he did not think the order expressly prohibited unscheduled speakers.

As the two were being ejected, seated protesters — like the others, wearing red T-shirts with slogans such as “FERC Doesn’t Work” — took up the chant and were led from the room.

Finally, a group that had taken seats on the floor in front of the audience were forced to leave.

 

The commission briefly left the meeting room during the episode, which lasted for about four minutes. Security guards said later that the protesters were escorted out of the building. No one was arrested.

Over the past year, FERC has been the target of environmental activists over its approval of natural gas pipelines and export terminals, including Dominion’s Cove Point site on the Chesapeake Bay near Lusby, Md., which is now under construction.

The challenge of dealing with the protesters now falls to Commissioner Norman Bay, who is scheduled to replace LaFleur as chairman on April 15. Beyond Extreme Energy, the organization that has been coordinating the protests, said it is hoping to attract more than 500 demonstrators to FERC in May.

In November, about 100 climate change protesters blockaded FERC headquarters, snarling traffic on First St. N.E.  About 25 were arrested. (See Federal Briefs.)

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Exelon, Pepco Ink Deal with Md. Counties, but Critics Stand Firm – UPDATE

By Suzanne Herel

Two key Maryland counties have agreed to support Exelon’s controversial takeover of Pepco Holdings Inc. in return for promises to fund customer bill credits, grid reliability improvements, renewable energy projects, energy efficiency programs and help for low-income consumers.

Montgomery and Prince George’s counties, suburbs of D.C., represent three-quarters of Pepco’s customers in Maryland, where Attorney General Brian Frosh, consumer advocacy groups and environmentalists have been urging the Public Service Commission to reject the $6.8 billion deal. (See Exelon ups Merger Offer in Maryland as AG Calls for Rejection.)

The acquisition, which would give Exelon control of more than 80% of the state’s electricity customers, also faces opposition from detractors in D.C. (See Exelon Sweetens the Deal for DC in Pepco Takeover.)

“We believe the agreement is significant because it was signed by a large consortium of low-income consumer advocates and recreational interest groups, in addition to Montgomery and Prince George’s counties,” Exelon spokesman Paul Adams told RTO Insider.

The agreements, filed with the PSC, bring with them a delay in a decision while the public is given time to weigh in.

The parties involved can submit testimony on the settlement until March 30. This is also the deadline for testimony on another settlement with The Alliance for Solar Choice filed March 2. Written public comments may be submitted through April 9.

Hearings Set for April

Evidentiary hearings are set for April 7-9. The PSC had planned to issue its decision on April 8; now it is shooting for April 29.

In a statement announcing the new schedule, the PSC said, “According to the request, the joint applicants have entered into two settlement agreements that they believe resolve all contested issues in this proceeding.”

The Maryland Office of People’s Counsel, however, continues to urge the PSC to reject the deal.

“Generally, we disagree with that,” People’s Counsel Paula Carmody told RTO Insider on Tuesday. “Our perspective is that the transaction is not good for our state, not good for ratepayers and not in the public interest.”

Carmody noted the number of parties yet to be won over — among them the Maryland Energy Administration, the staff of the PSC and groups including the Coalition for Utility Reform.

That organization’s counsel, Montgomery County Councilmember Roger Berliner, submitted a filing March 3 asking the PSC to require Exelon to increase its commitment to reliability, renewable energy and distributed generation.

“Exelon is trying to pick folks off, but appreciate the dynamic they face,” Berliner said in an interview, echoing Carmody’s list of critics.

In a brief filed with the PSC, the OPC said, “Nothing in the revised commitments or in the joint applicants’ initial brief overcomes the substantial harms and risk that will result if the subject acquisition is approved.”

It added, “The joint applicants’ commitments that supposedly provide benefits — those concerning reliability, the Customer Investment Fund and low-income assistance — also provide little, if any, value.”

The proposed conditions, OPC said, don’t address what Maryland stakeholders will lose: “the ability and right to compare the policy proposals and performance of two investor-owned utilities serving customers in Maryland that are subject to the same laws and regulations.”

“The concern about Exelon is that it will favor its nuclear power plants at the expense of renewable energy. In the absence of Exelon making a commitment to renewable and distributed energy in Maryland, I don’t think this merger will be found in the public interest.”

‘Necessary but not Sufficient’

Berliner commended some of the settlement’s aspects, in particular Exelon’s agreement to pay $500,000 for the PSC to retain a consultant to study how to transform the electric grid; a commitment to improve reliability by 2018; and the creation of a $50 million “Green Sustainability Fund” to stimulate investment in solar, energy storage and other distributed generation.

“There are good things in the settlement with the counties,” Berliner said. “But to use legal terminology, they are necessary but not sufficient. The bar is a little higher for this merger to be found in the public interest.

“I think they need to do more.”

In the meantime, Gov. Larry Hogan has delayed the appointment of two new members of the PSC until after the five-member board rules on the Exelon deal. The governor has nominated Michael L. Higgs Jr., a telecommunications attorney, and Jeannette M. Mills, former chief customer service officer for Exelon’s Baltimore Gas and Electric.

DC Opposition

Meanwhile, three members of the D.C. Council have penned a letter to the District’s PSC urging the commission to reject the deal, saying that it is not in the public interest, as required by law.

Mary Cheh, Elissa Silverman and Charles Allen said the transaction creates a conflict of interest between Exelon, a producer of electricity, and Pepco, which buys electricity and distributes it.

“A producer looks for the highest prices for its product, but a buyer looks for the lowest prices,” they said.

They cited the commission’s 1999 approval of Pepco’s proposed divestment of its generation assets as being in the public interest and yielding “non-monetary, but no less important, benefits to District ratepayers.”

“With Pepco substantially out of the generation business,” the PSC wrote at the time, “there will be less motivation for the company to act as an inhibitor to the development of a competitive generation market in the District.”

The councilmembers concluded that “the only real beneficiaries of the takeover will be Pepco shareholders (Exelon is buying them out at a more than 24% premium over market value) and Exelon Corp. (which will capture a steady, reliable stream of revenue to offset its riskier generation assets).”

The D.C. Office of People’s Counsel, who also is critical of the proposed deal, said last week that it was too early to tell if the settlement proposed in Maryland would benefit D.C. consumers.

“At this time, the Office of People’s Counsel is focused on the evidentiary hearings” set for March 30 through April 8, People’s Counsel Sandra Mattavous-Frye said. “There may be terms in the Maryland settlement proposal that may be of benefit to District consumers, but I still need more time to carefully examine the details and to determine whether any of these have value to the District of Columbia.”

The acquisition has been approved by the staff of the Delaware PSC, 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.

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Inhofe Decries EPA ‘Power Grab’

By Ted Caddell

inhofe
Sen. Jim Inhofe (R-Okla.) opened a hearing last week by displaying a map identifying the 32 states he said are opposing EPA’s proposed carbon emission rule, which he called a “selfish power grab.” The Natural Resources Defense Council said Inhofe’s map “radically overstates state opposition.”

There’s no mistaking where Sen. Jim Inhofe (R-Okla.) stands on global warming and the Environmental Protection Agency’s plans for addressing it.

In February, the chairman of the U.S. Senate Environment and Public Works Committee brought a snowball onto the Senate floor to underscore his skepticism of climate science. Last week, he kicked off a committee hearing by displaying a map identifying the 32 states he said are opposing EPA’s proposed carbon emission rule, which he called a “selfish power grab.”

“The proposal undermines the longstanding concept of cooperative federalism and the Clean Air Act, where the federal government is meant to work in partnership with the states to achieve the underlying goals,” Inhofe said. “Instead, the rule forces states to redesign the way they generate, manage and use electricity in a manner that satisfies President Obama’s extreme climate agenda.”

In a two-hour hearing, the committee heard from officials from Wyoming, Wisconsin and Indiana, who said the rule would harm their states’ economies, and representatives from California and New York, who insisted it is necessary and achievable.

“You can significantly reduce these emissions in a way that grows your economy,” said Michael J. Myers, chair of the litigation section of New York’s Environmental Protection Bureau. “The time is now for state leadership. So take the wheel.”

Todd Parfitt, director of the Wyoming Department of Environmental Quality, said EPA’s “timelines are problematic if not unrealistic.” A major problem for his state and others in the Midwest, he said, is that EPA would give credit for wind power to consuming states rather than producers. He said that 85% of wind energy generated in Wyoming is consumed outside the state.

Under the Clean Power Plan, states will first be asked to come up with their own ways to implement the emissions reductions rules, but the federal government would step in and impose rules if they don’t.

The Natural Resources Defense Council said after the hearing that Inhofe’s map “radically overstates state opposition” by including any state where a state official or agency has raised concerns.

Indiana is among the 12 states that are challenging EPA’s authority to issue and enforce the carbon rule. Oral arguments in the case are scheduled for next month before the D.C. Circuit Court of Appeals.

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PJM MIC Briefs

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.

Chantal Hendrzak, PJM general manager of applied solutions, told the Market Implementation Committee on Wednesday that many stakeholders had provided feedback since the issue was resurrected in February. (See Members Dispute PJM, IMM on Unfinished Changes to Notification, Start-Up Times.)

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

The dispute between MISO and PJM over interface pricing is not expected to derail the Coordinated Transaction Scheduling product intended to reduce uneconomic power flows between the RTOs, PJM officials told the MIC. In presenting the interregional coordination update, Stan Williams told the committee that MISO believes its Independent Market Monitor’s pricing proposal is superior to PJM’s. (See Patton Asks FERC to Set Deadline on 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

pjmDespite 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.)

(Prior coverage PJM: EE, Renewables Could Save Some Coal Plants under Carbon Rule.)

— Suzanne Herel

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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.

pjmNineteen 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

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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

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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.

pjm

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%).

pjm
(Click to zoom.)

“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.”

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New York Industrials Want Ginna Deal Tossed

By William Opalka

ginnaA 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.

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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