Company Briefs

The powerhouse at Duke Energy’s retired Cliffside Steam Station in Mooresboro, N.C., came down in a cloud of dust last week, the latest demolition Duke has conducted to modernize its generation fleet.

The coal-fired station went into service in 1940, and units 1 through 4 were retired in 2011. Units 5 and 6 are coal-fired units equipped with modern scrubber technology and still operate as part of the James E. Rogers Energy Complex.

See a video of the powerhouse implosion here.

More: Duke Energy

Entergy Execs Announce 2016 Exits

Entergy Executive Vice President and Chief Operating Officer Mark Savoff and Executive Vice President and Chief Nuclear Officer Jeff Forbes announced coordinated retirement dates last week.

Both executives plan to shift to advisory roles on Nov. 1 before retiring in 2016’s first quarter. At that time, Tim Mitchell, Entergy’s senior vice president of nuclear operations, will be named acting chief nuclear officer. In an executive restructure, the chief nuclear officer will directly report to Entergy Chairman and CEO Leo Denault. Mitchell will also be a candidate in Entergy’s search for a permanent chief nuclear officer.

Savoff and Forbes joined Entergy in 2003 and oversaw the transition of Entergy’s transmission system to MISO in 2013.

More: Entergy

DTE, GE Working on New Economic BWR Design

DTE Energy is teaming up with GE Hitachi to design a new type of boiling water reactor. While others are working on smaller, modular designs, the two companies are working on advancing the first-ever Economic Simplified Boiling Water Reactor (ESBWR).

The ESBWR incorporates passive safety systems, including a reactor that can cool itself for more than seven days without backup power or any human input. DTE has already received licensing from the Nuclear Regulatory Commission for the ESBWR.

The company said it has no current plans to start construction but said it is “keeping the option open, given the long-term environmental and economic advantages of nuclear power.” Dominion Virginia Power has selected the new design for a possible third reactor at its North Anna site in Virginia.

More: Nuclear Street

Alliant Eyes Boosting Solar Capacity by 50%

Alliant Energy subsidiary Interstate Power & Light in Iowa is planning to increase its total solar energy capacity by 50%, according to a recent request for proposals.

The company said it is looking to develop solar projects of between 1 and 10 MW. It currently purchases about 22 MW of solar capacity from about 1,650 customers in its service territory.

Alliant said the plan is unrelated to an Environmental Protection Agency air emissions settlement that calls for it to spend $6 million on environmental mitigation projects, which could include solar generation.

More: DesMoines Register

Xcel Energy to Accelerate Minnesota Wind, Solar Investments

Xcel Energy says it will reduce its greenhouse gas emissions in Minnesota by increasing wind and solar power investment and replacing two coal-burning generators with a natural gas-fired unit in the mid-2020s.

The plan, submitted to state regulators, would reduce carbon dioxide emissions in the Upper Midwest 60% by 2030 compared with 2005 levels. Until now, Xcel had aimed for a 40% reduction over that period.

Two of the three coal-fired units at Xcel’s Sherco power plant — Xcel’s largest in the region — would be retired in 2023 and 2026 under the plan. The two units, built in the 1970s, would be replaced by a new power plant fueled by natural gas.

More: Minneapolis Star Tribune

PSEG Combined-Cycle Project to Deliver Power by Summer 2018

Construction on PSEG Power’s 540-MW Sewaren 7 combined-cycle project is expected to begin next year at an existing power station site in Woodbridge, N.J.

The $600 million dual-fuel gas-turbine facility is set to deliver power to the PJM market for the summer of 2018.

The project was finalized after clearing the Base Residual Auction in August.

More: Black & Veatch

Line Replacement has Wisconsin Residents Worried

Residents in Onalaska, Wis., are concerned over Dairyland Power Cooperative’s planned replacement of a 65-year-old 161-kV line.

Dairyland, which is based in La Crosse, has been working nearly a decade to replace the 9-mile stretch of line connecting power plants in Alma and Genoa to the grid, and designs are not yet ready, in spite of a late 2016 start date. The cost of the project is calculated between $7 million and $8 million. Other transmission lines in the area have been rebuilt recently or are in the process of replacement.

Residents are worried that the new line, which will carry twice the electricity at the same voltage, will increase exposure to electromagnetic radiation. Dairyland says raising the wires will mitigate exposure.

More: LaCrosse Tribune

NuScale Seeking British Partners for Modular Reactor Design

NuScale Power, a U.S. company developing a small modular reactor with the help of a $217 million Department of Energy grant, is looking for a partner to help make the design a reality in the United Kingdom.

The company, mostly owned by Fluor Corp., is distributing a prospectus in the U.K. seeking a partner in what it says is a chance to get a piece of the $612 billion nuclear market by 2035.

NuScale’s design is on track to come up for U.S. certification next year, and the company says it expects to receive U.S. regulatory approval in the early 2020s. It is currently developing a test model in Idaho, using technology that can be customized for scale, allowing deployment in series, with up to 12 small reactors totaling about 600 MW.

More: Nuclear Street

Indiana’s Rising Power Prices Drive Pushback

Northern Indiana natural gas and electric provider NIPSCO has asked state regulators for an 11.5% hike in residential electric rates. Indiana’s industrial utility customers are protesting the request.

Joseph Hamrock, CEO of NiSource, parent company for NIPSCO and utilities in six other states, said the increases are needed to fund plants, poles and wires that serve as fail-safes even in light of new generating technologies.

More: NWI Times

South Field Energy to Build 1,100-MW Nat Gas Plant in Ohio

South Field Energy announced plans to build a $1.1 billion, 1,100-MW natural gas-fired power plant in Columbiana County, Ohio.

South Field and other companies are taking advantage of the cheap gas being produced at Utica Shale fields in the state. It is the sixth natural gas plant under construction in Ohio, according to the Akron Beacon Journal.

Construction would start in 2017, and the plant should be operational by 2019. South Field is also building an $899 million gas-fired plant in Carroll County.

More: Akron Beacon Journal

Ameren Increases Quarterly Dividend by 3.7%

Ameren increased its quarterly dividend on common stock, from 41 cents/share of common stock to 42.5 cents, an increase of 3.7%. The common share dividend is payable Dec. 31 to shareholders of record at the close of business on Dec. 9. The company’s board of directors also declared quarterly cash dividends to all classes of Ameren Missouri stock and all classes of Ameren Illinois preferred stock.

More: Ameren

October 13, 2015February 14, 2025

APPA: $7.3B Capacity Performance Price Tag Unnecessary

By Rich Heidorn Jr.

A study released last week by the American Public Power Association estimates that PJM’s Capacity Performance rules will increase costs to consumers by $7.3 billion over the 2016-2019 delivery years — a tally in line with PJM’s own estimates.

But while PJM says the increased capacity costs will pay off in improved reliability and reduced energy market prices, APPA says the spending is not justified.

“PJM’s recent changes are an over-reaction to the ‘polar vortex’ and address a problem that was largely already addressed by PJM and market participants through various other measures,” said Joe Nipper, APPA’s senior vice president of regulatory affairs and communications. “As a result, bill-paying consumers will pay a lot more for the same product.”

The report was prepared by James Wilson, who also consults for state consumer advocates in PJM. Wilson said that the transition auctions recently held for the 2016/17 and 2017/18 delivery years resulted in $4 billion in additional costs to upgrade 60% and 70% of “base” capacity to Capacity Performance, respectively.

In addition Wilson estimates that the Base Residual Auction for 2018/19, which cleared at $164.77/MW-day, would have cleared at $124.23/MW-day if not for the requirement that 80% of the resources acquired be CP. That, Wilson said, increased the total BRA cost to $10.9 billion, an increase of $3.3 billion. Wilson’s quantitative findings are in line with PJM’s own calculations.

PJM said the incremental cost of the 2016/17 transition auction was $2.3 billion, slightly below the estimate of $2.5 billion to $3.6 billion PJM and the Independent Market Monitor had predicted in a joint analysis. The increase for 2017/18 was $1.7 billion, PJM said (versus an estimate of $3.1 billion to $4.2 billion).

The RTO said the 2018/19 BRA represented a $3.4 billion increase over the previous year’s auction, an amount that is within the $2 billion to $5 billion range PJM and the Monitor had expected. (See PJM Transition Auction Means Reprieve for Exelon Nukes.)

Different Conclusions

But while Wilson’s math generally agrees with PJM’s, he does not agree with the RTO over what ratepayers are getting for their money.

“Improved generator performance certainly would have resulted in much lower energy costs during the ‘polar vortex’ period of extreme cold in early 2014, when very high forced outage rates caused price spikes in the PJM energy markets,” Wilson wrote. “However, that very extreme period followed 19 winters during which such extreme cold did not occur, capacity was never scarce during winter and winter energy prices remained low in PJM.

“The polar vortex period revealed accumulated fuel and winterization issues at many plants. Apparently, many of these issues were resolved by the winter of 2015, when performance was much improved. The improved performance in winter 2015 reflects numerous steps taken by market participants and PJM following the polar vortex events, and well before Capacity Performance was approved or implemented.

“So it is unclear that CP is likely to have a substantial incremental impact on future energy prices. The expected value of the incremental impact of CP on future annual energy prices is likely an order of magnitude lower than the estimated impact on capacity cost developed in this report.”

“The combination of the changes to the [variable resource requirement] curve and the CP rule changes caused capacity prices in the 2018/2019 BRA to be higher than they otherwise would have been,” PJM said in a statement. “However, PJM is confident that the implementation of Capacity Performance has been the right approach to making the grid more reliable and benefiting consumers, and that consumers will, in fact, enjoy substantial benefits in the form of lower energy prices should extreme weather conditions materialize again as they have in the recent past. The results of the annual and transitional auctions demonstrate the market was ready and prices were competitive.”

While supply stakeholders are upset over CP’s costs, some generators are pushing to relax what they say are unduly harsh non-performance penalties. (See Generators Seek to Reopen PJM Capacity Performance Rules.)

October 8, 2015May 27, 2025

Massachusetts Regulators Endorse Pipeline Contracts

By William Opalka

The Massachusetts Department of Public Utilities has ruled that electric distribution companies can sign contracts for natural gas capacity and pass the costs on to electric ratepayers (15-37).

Proponents of building gas infrastructure to supply electric generation have argued that the increasing reliance on natural gas requires additional pipelines to increase supply and lower high prices in the winter. After an investigation and proceeding, the DPU on Oct. 2 said the Electric Restructuring Act of 1997 did not preclude it from approving such contracts.

“The department finds that an EDC contract for pipeline capacity would be consistent with the Restructuring Act if an EDC is able to demonstrate that entering into a contract would result in cost savings for EDC ratepayers and otherwise satisfies the standard of review for approving EDC gas capacity contracts,” the order states.

The DPU’s order was in response to the state Department of Energy Resources’ April 2 petition requesting an investigation into ways new natural gas capacity could be added. The department sought to determine if there was an “innovative mechanism” for EDCs to add new natural gas capacity into the region to benefit electric ratepayers, and if cost recovery was appropriate.

“An EDC must demonstrate that the proposed contract (1) results in net benefits for the Massachusetts EDCs’ customers at a reasonable cost, and (2) compares favorably to the range of alternative options reasonably available to the EDC at the time of acquisition of the resource or contract negotiation,” the DPU order said.

Kinder Morgan subsidiary Tennessee Gas Pipeline, which is developing the proposed Northeast Energy Direct pipeline, said the order “is an important step in ensuring that electric generators have reliable access to the fuel needed to generate electricity within the ISO-NE transmission grid.” The project is among those that could be funded under the order. (See NH PUC Staff: Northeast Energy Direct Pipeline Would Lower Power Prices.)

A critic of the move, Massachusetts Attorney General Maura Healey, had argued during the proceeding that the restructuring law limited the regulators’ ability to act and questioned their assumptions. “Because of legal concerns with the DPU’s proposal and the risk to ratepayers, throughout this proceeding, our office urged the department to fully and carefully analyze the need for additional gas capacity before moving forward with any proposal that requires customers to bear the risk of a large infrastructure project,” said Chloe Gotsis, spokeswoman for the attorney general.

This is not the last word from Healey’s office. In July she commissioned a study to address the need for additional gas capacity in New England region. The study is expected by the end of the month.

The company producing the study, Boston-based The Analysis Group, has already looked askance at another Massachusetts energy proposal that it says saddles ratepayers with excessive costs. It recently conducted a study for the New England Power Generators Association critical of imported Canadian hydropower. (See New England Generators: State Interventions Risk Market Development.)

October 6, 2015

D.C. Mayor Announces Deal on Exelon-Pepco Merger

By Suzanne Herel

D.C. Mayor Muriel Bowser and Exelon CEO Chris Crane announced Tuesday that Exelon would invest $78 million in the district and protect consumers from rate hikes for three years under a settlement they hope will persuade the Public Service Commission to approve the company’s $6.8 billion acquisition of Pepco Holdings Inc.

“I believe this proposal is good for our economy and environment, and I’m asking the PSC to support the merger,” Bowser said in an afternoon press conference that also featured two former critics of the merger: People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine.

“My sole objective has been to assure all consumers receive tangible and measureable benefits. … The applicants came back and took us seriously — they made major concessions,” Mattavous-Frye said. “The bottom line is: This is a good deal.”

Racine, who had filed a 40-point critique of the merger with the PSC and went on to be part of the negotiating team, also gave his support.

“We believe we’ve got a good deal that does look out for the ratepayers on Day 1,” Racine said. “I’m satisfied that we’ve pushed Pepco-Exelon to do the right thing.”

Bowser said the joint applicants are awaiting guidance from the PSC on what form the filing should take — a new application or an amendment to the existing case.

One of the main concerns dogging the deal has been a perceived conflict of interest between Exelon’s commitment to its nuclear fleet and pursuing the district’s goal of renewable energy.

Mattavous-Frye said the concern would be addressed with “checks and balances” included in the settlement.

“We have provisions that require the company to implement specific environmental and sustainability policies,” she said, including the strengthening of “ring-fencing” protections separating PHI’s finances from that of Exelon’s nuclear fleet and its other affiliates.

Anya Schoolman, president of solar power advocate group DC SUN, said the settlement “does nothing to change the fundamental conflict of interest identified by the Public Service Commission.”

“Allowing Exelon to take over Pepco will take money out of the pockets of D.C. ratepayers while providing them no tangible benefit,” Schoolman said. “It will also harm the ability of D.C. residents to develop their own clean, cost-effective energy. The token renewable energy provisions in the Exelon settlement are a smokescreen that will allow the company to dismantle the progress the district has made to develop renewable energy.”

The $78 million investment is five times more than Exelon’s initial pledge of $14 million and would go toward promoting sustainability, increasing reliability and supporting low-income residents, Bowser said.

Of that, $17 million would be put toward conserving natural resources and the environment and promoting energy efficiency. The merger, she said, will improve reliability, in part by allowing microgrids to connect to the grid.

Exelon also would set aside $25 million to offset rate increases through March 2019, and within 60 days of the merger it would disburse $14 million to customers — a one-time credit of about $50.

Exelon and PHI have committed to moving 100 jobs to the district from elsewhere and hiring at least 102 union employees within two years, meanwhile dedicating $5.2 million in workforce training for district residents, Bowser said.

“I believe this settlement is in the best interest of the district now and in our future,” said the mayor, saying that it reflects the “fresh approach to energy” she has brought to the district.

Said Mattavous-Frye: “My goal has been to ensure all customers, but particularly residential customers, got the best deal possible. … I could not, without abrogating my statutory responsibility, not take into account how consumers would benefit. I will do everything in my ability to make sure these commitments are followed through.”

Exelon’s Crane also spoke briefly. “We really do appreciate the responsibility of serving the nation’s capital,” Crane said, adding, “The last 30 days has been very beneficial for us.

“Our enhanced local presence will continue to drive our focus on what the needs are in the community.”

The merger already has been approved by FERC and regulators in Delaware, New Jersey, Maryland and Virginia. The state deals contain a “most favored nation” status, which means the companies may have to revisit those agreements to achieve parity with the concessions being offered the district.

“We will have to sit down and determine what effect this will have on Delaware’s settlement,” said Dallas Winslow, chair of the Delaware Public Service Commission. Winslow said he could not comment further because the issue will come before him and the commission.

Pepco shares rose Tuesday afternoon as word of the settlement circulated, with shares rising as high as $26.49 in after-hours trading, up more than $1 on the day. Exelon shares, which also rose earlier in the afternoon, fell after the details became clear, closing down 9 cents to $30.21 and falling further after hours.

Last week, Exelon asked the agency to reconsider its decision, taking issue in a 43-page filing with the PSC’s findings that the deal would not be in the public interest and it would not be in the public interest to identify additional conditions that could make it so. The filing came at the same time the mayor confirmed her office was discussing a settlement. (See Exelon Appeals DC PSC Decision; DC Mayor Confirms Negotiations.)

October 6, 2015

PJM Markets and Reliability Committee Briefs

VALLEY FORGE, Pa. — PJM is proposing a Tariff change that would allow it to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auctions for the 2016/17 and 2017/18 delivery years.

The RTO uses its incremental auctions to sell excess capacity, or purchase more to replace shortfalls, based on changes to its load forecast. But PJM’s Tariff does not allow for such adjustments based on the additional capacity obtained in the transition auctions.

PJM obtained 4,246 MW of Capacity Performance for 2016/17 and 10,017 MW for 2017/18 in the transition auctions held in August and September.

The Tariff change, which will be brought to a Markets and Reliability Committee vote Oct. 22, would be effective for the third incremental auction for 2016/17 in February.

Independent Market Monitor Joe Bowring took issue with PJM Assistant General Counsel Jen Tribulski calling the amendment a “minor change.”

“This is a substantive change,” he said. “Why buy excess and sell it back? Why do you think that makes sense for the market?”

Stu Bresler, PJM senior vice president for markets, said that when PJM executed the transition auctions for Capacity Performance, it didn’t know what mix of Base and Capacity Performance resources would result.

“This was our intent all along, if we had a case where we had resources committed that weren’t previously committed,” he said. (See PJM Transition Auction Capacity not Included in Incremental Auction.)

In order for the Tariff change to be in place for the February auction, it needs to be filed with FERC by December.

New Methodology Would Decrease Projected Load

The MRC got a look at proposed changes to PJM’s load forecast methodology, which would mean a 2.6% drop in projected peak load for summer 2018.

Among the changes in methodology are the addition of an energy efficiency and saturation variable, a weather history shortened to 20 years and the addition of weather “splines,” which capture the relationship between weather and load, PJM staff said.

“The impact of energy efficiency has finally gotten to the magnitude that it will make a difference in our model,” PJM’s Tom Falin said.

The new methodology is predicted to reduce error rates from 6.6% to 1.5% on a three-year-out basis. (See “New Methodology Could Lower Summer 2018 Forecast by 2.6%; Winter Down 1.8%” in PJM Planning Committee Briefs.)

Members will be asked to endorse the final forecast in November, following the addition of updated economic data, equipment index trends and other data.

While the load forecast is expected to drop, PJM is recommending increasing the installed reserve margin (IRM) to 16.5% from 15.7%.

The proposed increase in the IRM came as a surprise to some members, who expected it to drop as a result of the implementation of Capacity Performance rules. (See “Proposed Increase in Reserve Margin Sparks Opposition from Load” in PJM Planning Committee Briefs.)

But staff said the increase resulted from changes in 2015 capacity and load models, as well as a decline in the capacity benefit of ties (CBOT) — expected capacity imports. The CBOT was reduced because the “rest of world” peak demand is becoming more coincident with the PJM peak.

Staff stressed that changes in the IRM may not have that much impact on the forecast pool requirement (FPR), which determines the amount of capacity procured in the annual Base Residual Auction.

Solution, Task Force Proposed to Curtail RegD Resources

PJM staff presented a provisional solution to address modeling problems that are causing PJM’s regulation market to purchase too much RegD megawatts at times.

They also proposed a charter for the Regulation Market Issues Senior Task Force, which will be assigned to track the issue.

The solution, which will be brought to a vote Oct. 22, would move the benefits factor curve to the left so that it is at zero at 40%. A cap of 26.2% also would be implemented during identified excursion hours — hours when dispatch frequently moves the regulation signal manually.

In addition, the group proposes a tie-breaker logic to rank RegD self-schedules or zero-cost offers. (See “Proposal Would Curtail RegD Resources in Regulation Market” in PJM Operating Committee Briefs.)

The changes to the curve and the tiebreaker would be evaluated quarterly and may be changed depending on the findings of the task force.

Manual Changes Approved

The MRC endorsed changes to the following manuals at its meeting last week:

Manual 40: Certification and Training Requirements. Edited for grammar and to clarify roles and responsibilities under North American Electric Reliability Corp. definitions.
Manual M10: Pre-Scheduling Operations. Revised to allow for maintenance outage procedures under Capacity Performance rules. PJM members are now required to specify an “early return time” for planned outages and submit outages with at least three days’ notice. It also grants PJM authority to recall an already underway outage with 72 hours’ notice.
Manual M14D: Generator Operational Requirements. Incorporates minor changes to the cold weather testing program for seldom-used generators. (See “Members Choose Status Quo on Winter Testing” in PJM Operating Committee Briefs.)
Manuals 14B and 14A: Generation and Transmission Interconnection Process. Changes document how PJM will oversee transmission projects that have benefits in at least two categories, including baseline reliability upgrades, market efficiency and public policy. (See PJM Wins OK on Multi-Driver Tx Projects.)

— Suzanne Herel and Amanda Durish Cook

October 6, 2015

Stakeholder Soapbox: Why PJM’s Capacity Performance Isn’t Good for the Markets

By Marji Rosenbluth Philips

It’s no secret that Direct Energy believes that PJM’s Capacity Performance market structure, approved by FERC, is both over-priced and unlikely to achieve its intended results. In this op-ed piece, we explain why.

PJM’s Reliability Pricing Model was not designed to deal with winter peaks and the reliance on Marcellus shale gas. Nor did the RPM specifically target nuclear, coal and inefficient units for extra revenue.

Need for Comprehensive Overhaul

Instead of doing a comprehensive overhaul, and without much of a stakeholder process, PJM tried to Band-Aid the RPM and developed the CP structure in about four months.

This Band-Aid seems targeted less toward fixing an unreliable system and more to increasing revenues for certain generators. Otherwise why would FERC have exempted fixed resource requirement entities from having to make their system as reliable as the rest of PJM?

Direct Energy protested the CP transition auctions for several reasons.

Generators had already taken measures to improve their performance after the polar vortex.

PJM required consumers to fund a new winter testing program that allowed many generators to have “trial” runs so that there were far fewer operational challenges for units that had not been run in a while.

Generators themselves publicly reported making greater investments because the costs of non-performance during the polar vortex were so high.

And the transition money is unlikely to contribute to better performance during their three-year periods: nuclear units will still incur unanticipated forced outages, and gas generators will unlikely be able to firm up their fuel as few units have permits that allow dual fuel and burning of oil, or they lack space to install storage.

Moreover, payments are not high enough to allow generators to purchase firm gas supply. DE also protested the method by which the auctions were being cleared, because there were two ways to do it and PJM chose the more expensive way.

That is now all history. But our concerns continue.

Illusory Insurance?

Consumers are paying for what may very well be an illusory insurance policy. First, there is no guarantee that a polar vortex event will occur again. Consumers would be better off paying higher real-time energy prices when the system is stressed than doling out billions of dollars annually for an event that may not occur.

And even if it does, there is no guarantee that the generation will be there physically. As noted above, many generators cannot invest in dual fuel or storage facilities, and payments are not significant enough to fund new pipelines to procure firm transmission. Even if the payments were sufficient, unless generators enter into the gas markets during timely nomination periods, they cannot procure firm gas.

We believe that prudent generators are not going to invest more money into their facilities but are more likely to seek financial hedges to cover non-performance risk. So at the end of the day, physical performance is no more guaranteed under CP than it was under the RPM.

Moreover, we are now more than ever dependent on fewer generators to achieve reliability. There are numerous resources that could run for short periods of time, or during one season, that are no longer eligible to be providers of capacity.

This simply makes no sense: There is no reason why there cannot be differing payment structures for capacity. PJM says all megawatts are equal; but they already gave up on that concept when they introduced differing payment structures for demand response (which is a very valuable reliability tool in the wholesale markets that we hope the Supreme Court will recognize) and ran the transition auctions using two different products and clearing curves.

Diverse Resources

There is no reason why the RPM could not have been expanded to include more diverse resources and less expensive ones to help achieve system reliability.

The bottom line is that we strongly support the principles that generators should receive just and reasonable compensation for their performance, but that compensation should be commensurate with the benefits a unit provides to the system. Consumers have been asked to foot an extraordinarily high insurance bill that the chief regulator, FERC, admits is not based on any kind of consumer analysis or even comparative analysis of what is the most efficient way to achieve stated reliability goals.

This is the saddest part of our regulatory system today.

And we need to find a way to fix it. Somewhere in the calculus of how to run good markets, there needs to be an assessment of whether there is a more efficient way to get the same or similar benefits.

Marji Rosenbluth Philips is director of RTO and federal services for Direct Energy, one of the largest retail providers of electricity and natural gas in North America.

If you’d like to contribute an op-ed article for Stakeholder Soapbox, contact Rich.Heidorn@RTOInsider.com.

October 6, 2015

Generators Seek to Reopen PJM Capacity Performance Rules

By Rich Heidorn Jr.

Generators asked PJM stakeholders last week to consider changes to the RTO’s new Capacity Performance program, saying the rules approved by the Board of Managers without stakeholder consensus are overly punitive.

A group calling itself the “Supplier Coalition” asked the Markets and Reliability Committee to consider two problem statements. One would expand ways for generators to minimize underperformance penalties by netting them against over-performing generators. The second would consider widening the force majeure rules under which generators can escape penalties.

Bob O’Connell, of Main Line Electricity Market Consultants, said the current rules have “ineffective and inefficient options” for generators to manage the risk of underperformance during CP compliance hours. O’Connell said current rules allow companies with multiple generators to offset poor performance with over-performing units under “narrow criteria” but does not allow after-the-fact offsets, such as bilateral trades.

That could force smaller generators to seek mergers, reducing competition, he said. It could also result in “onerous” financing terms for future generators, he said.

pjm — Storms flooded Central Maine Power’s substation in Bath last month. Source: Central Maine Power

Walter Hall of the Maryland Public Service Commission expressed support for O’Connell’s proposal to consider changes, saying it could reduce the risk premiums generators include in their offers. Hall said any changes must be “consistent with the reliability enhancement objectives” of the CP program.

But Market Monitor Joe Bowring said the change could upset the “increased risk, increased reward” bargain at the heart of the CP rules. “It was an explicit part of the design. It was done on purpose,” he said.

Exemption for Transmission Outage

Ken Foladare of Tangibl outlined the second problem statement, which would reconsider PJM’s catastrophic force majeure rules. Foladare said the current rules would penalize generators for nonperformance even if it was impossible to deliver power because of a widespread blackout or a system disturbance.

Foladare’s initiative would consider circumstances for waiving penalties when the nonperformance resulted from a lack of transmission service.

Katie Guerry of EnerNOC said stakeholders should consider any changes to CP rules together in a single committee, such as the former Capacity Senior Task Force.

“We have lots of issues we’d like to see revisited,” agreed Marji Philips of Direct Energy. “The piecemeal approach is not the way to get there.” (See Philips’ op-ed, Why Capacity Performance Isn’t Good for the Markets in the Long Term.)

“Both these [problem statements] suggest that you have created costs for providers … that are not reflected in value,” said Bruce Campbell of EnergyConnect, adding that the proposals were “rammed through the stakeholder process.”

When PJM and stakeholders designed the original capacity market rules, “we spent a lot of time working through the gory details,” Campbell said. “That did not happen in this process.” (See FERC OKs PJM Capacity Performance: What You Need to Know.)

The problem statements will be brought to a vote at the next MRC meeting Oct. 22.

Scenario Analysis

The MRC also was briefed on the scenario analysis PJM is planning to conduct on the recently completed first Base Residual Auction under CP.

The analysis will consider nine scenarios used in each of the last two years and one new one that reruns the results using the variable resource requirement curve shape and gross cost of new entry values used in the 2017/18 BRA. The rules were changed for the 2018/19 BRA following the RTO’s triennial review. (See PJM Board Orders Filing on Capacity Parameter Changes.)

The repeated scenarios include an unconstrained simulation in which locational deliverability area limits are removed and CP supply is both added and removed from the bottom of the supply curve in and outside of MAAC.

October 6, 2015

Consumer Advocates’ Funding Request Sparks Sharp Words

By Suzanne Herel

VALLEY FORGE, Pa. — Nearly everyone who spoke at last week’s PJM Members Committee meeting agreed that stakeholder discussions are enhanced by the participation of the Consumer Advocates of the PJM States. But not everyone wants to pay to have them in the room.

A proposal by CAPS Executive Director Dan Griffiths that the RTO fund the group’s $450,000 budget through an assessment on electric customers won support from state regulators and other load interests but drew sharp opposition from suppliers.

Griffiths and West Virginia Consumer Advocate Jacqueline Roberts proposed that CAPS’ budget be funded in part through an assessment on electric sales similar to the funding Organization of PJM States (OPSI). They said it would amount to eight-tenths of a cent for a residential customer using 12,000 KWh annually.

Opposed in Principle

But while the charge would be miniscule, some market participants said they opposed it in principle.

“Our company is a great believer in markets and competitive markets, and we have trouble funding an organization that is comprised of entities that have challenged competition at the state level and at PJM,” said Marji Philips of Direct Energy. “Frankly that was why our company decided we could not get behind this proposal.

“Some [advocates] have been vehemently anti-competition at the retail level,” she added.

“Silencing views that don’t agree with you doesn’t give you a better stakeholder process. It might give you a quieter stakeholder process,” Roberts responded.

“There’s nothing to keep you from dialing in” to the meetings, Philips countered.

She added later that while Direct Energy supports the advocates’ participation at PJM meetings, it believes their funding should come from their states.

CAPS is a nonprofit group made up of consumer advocates from the PJM states and D.C. It was formed in 2012 with start-up funding from a FERC enforcement settlement with Constellation Energy (IN12-7-00), allowing advocates to travel to PJM meetings in Valley Forge, Pa., and Wilmington, Del.

CAPS’ assessment on electricity consumers would be supplemented by remaining Constellation funds along with contributions Exelon has offered to win its acquisition of Pepco Holdings Inc. Exelon’s Jason Barker said that as part of its effort to win approval of the merger, “Exelon has agreed to support reasonable proposals to have PJM members fund CAPS.” (See related story, Reports: Exelon Considering D.C. HQ to Win Pepco Deal.)

The rationale for the assessment, said Griffiths, is that consumers deserve a voice at PJM because the majority of charges they see on their electricity bill are the result of actions taken at the RTO and FERC. “We think that being here is a benefit to everybody,” he said.

Chris Norton, director of market regulatory affairs for American Municipal Power, said the assessment would be unfair to his public power members who are not represented by CAPS. PJM CFO Suzanne Daugherty said there was no way to excuse AMP members from the assessment because many public power customers are supplied through “commingled” customer accounts.

PJM: Up to Members to Decide

PJM Market Monitor Joe Bowring and CEO-elect Andy Ott agreed that CAPS’ involvement has been beneficial.

“If you look at the past 18 months, when the CAPS organization has stood up and been engaged in the stakeholder process, I think it’s been enriching,” Ott said. “The positive nature of having consumer advocates be engaged is obvious. It seems to me that all of us have seen that happen.”

But, he said, “When you get to the question of … should the funding be through the PJM Tariff — there, I think it’s beyond what PJM should be opining on. That’s a members’ decision.”

Dynegy’s Jason Cox and Jesse Dillon, assistant general counsel for Talen Energy, also opposed the proposal.

“If [the amount is] so de minimis, it seems like the states could fund it themselves,” Cox said.

“We don’t think PJM members should be forced to fund private speech and expression with which we may disagree,” said Dillon. To say retail customers would bear the charge is a “sophistry,” he added.

“They’re charging load-serving entities,” he said. “We are an LSE, and we do not have the ability to pass costs on to customers like others might.”

ODEC Position ‘Evolved’

Ed Tatum said the thinking of Old Dominion Electric Cooperative used to be in line with Talen’s.

But, he said, “Old Dominion’s thinking on this has evolved. We have experienced the stakeholder process without strong [consumer] representation. Through CAPS, now we have an engaged, knowledgeable group of folks [who seek to achieve consensus]. … We would support CAPS.”

Susan Bruce, representing the PJM Industrial Customer Coalition, said her group realizes “the importance of this forum on ratemaking at the state level: Two-thirds or three-quarters of customers’ bills are a result of actions here or at FERC.”

“We think the stakeholder process is more vibrant with them and helps us avoid surprises at the FERC level,” she continued. “My clients, they’re willing to pay that cost.”

The debate echoed that in MISO in April, when the RTO declined a request by consumer advocates for $200,000 to help cover its legal costs in a fight over MISO transmission owners’ return on equity. (See MISO to Consumer Sector: No Money for You.)

Roberts noted, however, that MISO’s advocates receive funding through the tariff for the Organization of MISO States. Griffiths pointed out that CAPS has pledged not to use its funding to litigate at FERC.

Roberts indicated confidence that the funding request will be approved, insisting those who spoke in opposition did not represent a wide group of stakeholders. “We have strong support and support in every sector,” she said.

October 6, 2015

State Briefs

Variable Rate Ban in Effect

Regulators reaffirmed the state’s first-in-the-nation ban on variable rate electric contracts, which was approved earlier this year by the General Assembly and became law Thursday.

The Public Utilities Regulatory Authority ruling said the act’s language “is clear and unambiguous about variable pricing in residential contracts starting on and after Oct. 1, 2015.” Third-party electricity providers who offer the variable rate plans had claimed the language was unclear.

Consumer Counsel Elin Swanson Katz hailed the ruling as “a victory for consumers.” Katz was active in efforts to get the variable rate ban passed.

More: New Haven Register

DELAWARE

Calpine’s Garrison Energy Center Dedicated

Calpine’s Garrison Energy Center in Dover, a 309-MW combined-cycle power plant, was officially dedicated Thursday, though it has been up and running since June.

State officials hope the efficient power plant will help them achieve emission reduction targets set forth by the Environmental Protection Agency’s Clean Power Plan.

Calpine bought the rights to the gas-fired generating facility at the Garrison Oak Technology Park several years ago. The Dover City Council approved a $6 million bond issue for infrastructure improvements, and the state gave Calpine a $2.5 million grant to build a natural gas pipeline.

More: Delaware State News

ILLINOIS

ICC Greenlights Ameren Transmission Line

Construction on a 46-mile transmission line linking Peoria to Galesburg is slated to begin next year after Ameren Transmission won approval from the Commerce Commission.

Ameren’s transmission subsidiary plans to have the $150 million high-voltage line completed by 2018. MISO has also approved the line.

Ameren Transmission chairman and president Maureen Borkowski said the project will boost the state’s economy and create jobs. The project is one of three large new transmission lines being developed by Ameren Transmission as it expands infrastructure in the region.

More: St. Louis Post-Dispatch

INDIANA

IURC Hears IPL’s Rate Hike Request

Indianapolis Power & Light is asking the Utility Regulatory Commission for a $67.7 million rate increase, more than 10 times what the state’s consumer advocate says the utility needs.

IPL first made the request last December, but it was put on hold until Sept. 21 after the Office of Utility Consumer Counselor protested. The consumer advocate contends that the utility needs just $5.9 million to cover increasing maintenance costs and capital expenses to address the utility’s underground transmission faults that have been blamed for causing several dramatic fires and explosions.

The rate case is expected to drag on until next year.

More: Energy Manager Today

KENTUCKY

Paducah Eyes Selling Capacity into PJM

The Paducah Power System is exploring whether to sell surplus power into PJM.

The municipal power system’s board approved a $50,000 deposit for a study to be conducted by PJM. Board chairman Hardy Roberts says he hopes the power system will be able to sell excess capacity to markets in the RTO.

The capacity would come from its gas-fired peaking plant.

More: WLKY

MISSOURI

Utilities Urge AG to Take on Clean Power Plan

Electric utilities are pressuring state Attorney General Chris Koster to join a legal challenge to the Obama administration’s carbon emission regulations.

Representatives from Ameren Missouri, Kansas City Power and Light, Empire District Electric and groups representing the state’s municipal utilities and electric cooperatives sent Koster a letter Sept. 28 asking him to join other states that have mounted legal challenges to the regulations.

Koster is a Democrat running for governor next year. Many Democrats support the rules, which are opposed by the coal industry and utilities, both politically powerful constituencies in the state. EPA wants the state, which burns coal for 80% of its electricity, to reduce carbon emissions by 37% from 2012 levels.

More: St. Louis Post-Dispatch

NEW HAMPSHIRE

Eversource Fined $250K for Worker’s Death

The Public Utilities Commission has fined Eversource NH $250,000 for failing to repair a broken cross arm on a utility pole in Keene, where an employee of Keene State College was electrocuted while investigating a report of a low-hanging wire.

The PUC’s Safety Division found that the utility’s inspectors discovered the broken cross arm in January 2014, but it went unrepaired for three months before the death of Nathan L. DeMond, whose body was discovered in contact with the wire where it passed closest to the ground. The report said the company “failed to act in accordance with good utility practice” by not repairing the broken equipment promptly.

An Eversource spokesperson said the company has not yet decided if it will appeal the ruling.

More: New Hampshire Union Leader

Lower Eversource Rate Forecast for Winter

Eversource Energy is predicting a winter energy service charge of 10.39 cents/kWh, slightly lower than last year’s winter rate of 10.56 cents. The utility is not formally requesting a rate change at this time but is giving the Public Utility Commission a prediction of what it is likely to ask for in its formal filing in December. The new charge will be in effect from Jan. 1 to June 30.

“Constraints on natural gas supply into New England often drive up the cost of energy during winter months, and the region continues to experience higher energy prices compared to other areas of the country,” said Penni Conner, senior vice president and chief customer officer at Eversource.

More: New Hampshire Union Leader

Report: Room for Improvement in Storm Restoration Efforts

After six major storms in eight years, utilities have gotten better at restoring power, but there’s still room for improvement, according to a 100-page report by state regulators.

According to Public Utility Commission staff, Eversource, which has 70% of the state’s customers, was slow to deploy out-of-state restoration crews during a Thanksgiving storm in 2014, was hampered by weak weather forecasts and did not communicate effectively with its customers about likely restoration times.

Response to the Thanksgiving storm was complicated by holiday staffing issues, but the utilities had plenty of time to prepare, according to the PUC. The commission also expressed concern about inconsistencies in the weather forecasts among utilities.

More: New Hampshire Union Leader

NEW JERSEY

Opponents Decry Proposed PennEast Pipeline

Protesters opposing the PennEast natural gas pipeline took aim at the state’s biggest electric utility, Public Service Electric and Gas.

About three dozen protesters walked from the statehouse to PSE&G, a partner in the PennEast pipeline, demanding the project be killed. Among them was Democratic Assemblywoman Elizabeth Muoio.

PennEast said in a statement that construction of the 36-inch pipeline would have an estimated $1.6 billion positive economic impact and support about 12,000 jobs. The 118-mile pipeline would stretch from in Luzerne County, Pa., to near Mercer County. Affiliates of five gas distribution companies, mostly in the state, are the major customers.

More: The Associated Press

State Has Potential to Recover 4M Tons of Biomass

A Rutgers University study on bioenergy potential shows that the state produces 7 million dry tons of biomass annually, more than 4 million of which could be recovered and used to generate power, heat or vehicle fuel.

The report aimed to update 2007 feedstock and technology assessments and considered statewide waste and biomass resource by location, greenhouse gas reduction potential and policy recommendations.

According to the assessment, the recoverable biomass could generate up to 654 MW of power — 6.4% of the state’s electricity consumption. It also represents the equivalent of 230 million gallons of gasoline, or 4.3% of transportation fuel consumed in the state.

More: Biomass Magazine

NEW YORK

PSEG Allowed to Make Partial Tax Payment

The Nassau County Legislature unanimously approved a measure allowing PSEG Long Island to pay nearly $1.4 million less in property taxes than it was initially billed.

The legislature voted to allow the county treasurer to accept a one-time reduced tax payment from PSEG of $28.6 million instead of the $30 million it had been billed. The county is exploring options to collect the remaining amount, including litigation, officials said.

The Long Island Power Authority, which still owns power facilities operated by PSEG, had directed the utility to limit tax-bill increases to 2% because its lawyers said the state-approved LIPA Reform Act of 2013 caps tax hikes to 2% a year on company properties.

More: Newsday

NORTH CAROLINA

Duke Settles Coal Ash, Wastewater Issues with $7M Payment

Duke Energy agreed to a $7 million settlement with the state Department of Environmental Quality, concluding its troubles with state regulators over coal ash and groundwater violations.

The agreement, announced last week, represents a substantial reduction from the initial fine of $25.1 million. The company argued that the state failed to follow its own regulations when it imposed the fine without giving Duke a chance to respond.

The settlement calls for Duke to quicken the pace of cleanup at four of its 14 coal plants and ash-containment impoundments. The state estimates it will cost between $10 million and $15 million for those cleanup projects. Duke in February settled federal charges relating to coal ash with a $101.2 million payment.

More: The Charlotte Observer

State First in Southeast to Break 1-GW Solar Mark

The state became the first in the Southeast, and the fourth in the U.S. overall, to surpass 1 GW of solar capacity, according to a report from the NC Sustainable Energy Association. According to the report, the state follows California, Arizona and New Jersey to reach the 1-GW mark.

While the pace of solar installations has been high in the state, it will probably slow down. The General Assembly in September voted to end the state’s Renewable Energy Investment Tax Credit. The report said that the tax credit helped fund about $182.6 million in solar projects between 2007 and 2014.

The report also said that the clean energy industry in the state now counts about 1,200 companies employing 23,000 people and generates about $4.8 billion in annual gross revenues.

More: SmartGrid News

OHIO

Supreme Court Sets Hearing in Delayed Wind Farm Project

A dispute over the stalled Buckeye Wind Power Project in Champaign County will move forward after the state Supreme Court set Dec. 16 for oral arguments in the case.

The Power Siting Board approved the second phase of the project in May 2013, but nearby property owners and several local government entities appealed.

The project is split into two phases, the first of which was approved in 2010 but is still unbuilt. Combined, the two phases call for construction of about 100 turbines in several townships across rural Champaign County, generating 200 MW.

More: Dayton Daily News

Panel: State Should Halt March Toward Green Goals

Gov. John Kasich’s office said last week a recommendation from a state panel that it indefinitely continue its freeze on renewable and energy efficiency mandates is “unacceptable.”

The Republican-controlled Energy Mandates Study Committee released its report recommending that the state not resume its march any time soon toward achieving at least a quarter of its power from renewable and advanced technology sources.

Green energy advocates say the committee was stacked against renewable energy. Utilities like FirstEnergy, the Akron-based parent of Toledo Edison, have opposed the standards.

More: The Blade

PENNSYLVANIA

Andrew Place Takes Place on PUC

Andrew Place, former corporate director for energy and environmental policy at natural gas producer EQT Corp., was welcomed to his seat on the Public Utility Commission following his unanimous confirmation by the state Senate.

Place helped establish the Center for Sustainable Shale Development and worked at the state’s Department of Environmental Protection. He pledged to be “an unassailably independent voice” on the commission.

“Andrew’s unique background — blending work in academia, business and state government — will serve the commission well as we strive to ensure a continued balance between consumer and utilities,” PUC Chairman Gladys M. Brown said.

More: Public Utility Commission

VIRGINIA

Dominion’s $47 Million Solar Farm Gets State OK

A State Corporation Commission hearing examiner recommended that Dominion Virginia Power’s plan to build a solar farm near Remington is in the public interest and should receive a certificate of public convenience and necessity. The three-member commission must still approve it.

Dominion has said the solar facility, which will be the largest in the state, could be in operation by late 2016. The 20-MW facility in Fauquier County would tie into existing transmission lines.

More: Fauquier Now

October 6, 2015

Blackstone Seeks Two Coal-fired Plants in New York

By William Opalka

A power plant owner affiliated with The Blackstone Group is asking state and federal regulators for expedited approval to buy two coal-fired power plants in western New York (15-E-0580).

Riesling Power is seeking to buy the 668-MW Somerset facility in Niagara County and the 312-MW Cayuga facility, which is operating under a controversial reliability support services agreement.

Both plants are owned by Upstate New York Power Producers, formed by a group of bondholders that purchased the plants from the bankrupt AES Energy East for $240 million in 2012. The filing asks for approval by the New York Public Service Commission’s Dec. 17 meeting. The buyer said all personnel would remain in place and the plants would continue operating. The purchase price was not disclosed.

“Expedited approval is appropriate here because the proposed transfer does not raise any issues regarding retail energy sales to captive ratepayers or market power concerns in the competitive wholesale markets in New York and is consistent with commission precedent,” the state filing states.

Upstate New York Power, whose largest stockholders are the California Public Employees’ Retirement System (CalPERS), Carlyle Strategic Partners, J.P. Morgan Investment Management and Marathon Asset Management, asked for FERC approval of the deal by Nov. 24 (EC15-214).

Riesling is a wholly owned subsidiary of Bicent Power, which in turn is 95.6%-owned by GSO Capital Partners. GSO represents the credit-oriented business of The Blackstone Group, one of the largest players in the leveraged buyout business. Upstate New York Power had hired Blackstone in 2014 to sell the plants, according to Power Finance and Risk.

Neither Riesling nor Bicent own generation in New York, the filing states.

The Plants

Cayuga, a 60-year-old pulverized coal-fired power plant on the eastern shore of Cayuga Lake in Lansing, N.Y., is operating under a RSSA with New York State Electric and Gas (NYSEG). The plant is also the subject of a PSC proceeding considering whether to repower it from coal to natural gas.

Plant owners had proposed to mothball the facility in early 2013, but NYISO and NYSEG determined the plant was needed for system reliability. A one-year RSSA was ordered by the PSC. With no suitable alternatives identified, the commission approved a second RSSA that expires June 30, 2017.

Upstate New York Power recently filed a revised proposal to convert the plant to natural gas. (See Cayuga Power Plant Repowering Opposed.)

NYSEG, Niagara Mohawk and several stakeholders are promoting the proposed Auburn Transmission Project Phase 2 as an alternative to the Cayuga repowering (13-T-0235). The project has been endorsed by PSC staff.

Somerset, a pulverized coal-fired power plant in Barker, N.Y., on the southern shore of Lake Ontario that began commercial operations in 1984, has been described as too distant from existing natural gas pipelines for a conversion.

The largest taxpayer in its home county, Somerset is a merchant plant selling its output into NYISO.

Energy Highway

When New York Gov. Andrew Cuomo proposed the Energy Highway in 2012 to bring power from generation plants upstate to load centers in and around New York City, Upstate New York Power responded that the plants could play an “important role” for the proposal.

“New York’s energy needs require a diverse blend of fuel-type resources to provide the state’s residents and businesses with a dependable and affordable energy pool,” the company said. “Upstate New York Power Producers looks forward to being a part of the solution.”

It said the two plants are in compliance with the current environmental regulations and “well positioned” to meet future regulations, having invested in technologies including flue gas desulfurization and selective catalytic reduction to reduce sulfur dioxide (SO₂) and nitrogen oxides (NO_x) emissions.

Last month, the PSC staff took a step toward making the highway a reality, recommending transmission routes that would help move 1,000 MW of upstate generation. (See NYPSC Staff Recommends $1.2B in Transmission Projects.)

Somerset, located in Zone A, is connected to the main 345-kV east/west transmission corridor with NYSEG at the Kintigh Switchyard. Cayuga, in Zone C, connects with NYSEG at the Milliken Switchyard at 115 kV.