Chicago-based Exelon would open a headquarters in the district and offer more customer credits under a tentative agreement D.C. Mayor Muriel Bowser’s office has reportedly struck to support the company’s purchase of D.C.-based Pepco Holdings Inc.
Bowser
While neither Bowser’s office nor the companies would confirm the draft settlement, several intervenors in the merger process told Bloomberg and the Washington City Paper that the document was being shared among interested parties on Friday.
The move comes as the D.C. Public Service Commission is scheduled to decide Wednesday whether to grant a joint request by the district’s attorney general and the companies to stay proceedings in the matter until Nov. 4. The request is an attempt to buy time to strike a deal that might be acceptable to the D.C. PSC, which unanimously rejected the acquisition in August. (See DC Halts Exelon’s Acquisition of Pepco Holdings; Pepco Stock Tumbles.)
Wall Street remains skeptical that Exelon will consummate the deal.
Exelon shares closed Monday at $30.30, up 1.6% for the day, while Pepco rose 0.4% to $25.41. But both remain about $2 below their prices on Aug. 24, before the PSC’s rejection.
Exelon Appeal
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. (See Exelon Appeals DC PSC Decision; DC Mayor Confirms Negotiations.)
The filing came at the same time the mayor confirmed her office was discussing a settlement agreement with the companies that would constitute a new filing to the commission. Previously, Bowser’s office had said it agreed with a letter of opposition filed by Attorney General Karl Racine’s office listing 40 conditions that should be met for the deal to be accepted.
Negotiations Continuing
On Monday, Racine spokesman Rob Marus said it was premature to say whether the attorney general would support the outcome of negotiations, which he said were continuing.
“The settlement to be weighed in on is a different settlement,” he said. “The Office of the Attorney General has a role to weigh in early on in the process; now we’re in a different place in the process.”
Marus said Racine, whose former law firm did work for Pepco, had recused himself from the issue.
According to the City Paper, Robert Robinson, president of the Grid 2.0 Working Group, was among the intervenors who viewed the working settlement.
He said the district government won more concessions because of its initial opposition, but the agreement still represents an “about face” that doesn’t address all the issues. “We’re going to get locked into a deal of economic slavery, of continuing to pay higher and higher prices,” he said.
Unique Concessions
D.C. is the last holdout to the $6.8 billion deal, which already has been approved by FERC and regulators in New Jersey, Virginia, Maryland and Delaware. The states negotiated their agreements on a “most favored nation” status, meaning that if any subsequent agreement were more beneficial, it would have to be bestowed in kind on them.
In making its decision, the D.C. PSC said it weighed seven factors of public interest, among them the effects on ratepayers and shareholders, market competition and preservation of natural resources and the environment.
Berliner
Roger Berliner, a regulatory attorney and Montgomery County councilman who led opposition to the merger in Maryland, said he suspects the settlement will be largely unique to D.C. and not invoke changes to the other states’ agreements.
For example, he said, Pepco is headquartered in D.C. If Exelon agrees to open another headquarters, it wouldn’t have to provide the same concession elsewhere.
“It’s hard for me to imagine how they would strike a deal that would trigger the most favored nations clause,” Berliner said.
He also was skeptical about Exelon being able to offer a commitment to renewable energy that would overcome the commissioners’ concerns.
“We had settlement negotiations with [Exelon] and said, ‘If you are prepared to be the best in the country when it comes to renewables, we can have this conversation,’” he said. “Clearly that was something they were not prepared to do.”
That, Berliner said, underscored the concern — also perceived by some in D.C. — that Exelon’s nuclear portfolio presents an insurmountable conflict of interest with a commitment to renewable energy.
Sides Mobilize
In D.C., the most vocal support for the deal has come from the business community and dozens of charitable groups who receive funding from Pepco.
In a media blitz that included churches, minority groups and former D.C. Mayor Anthony Williams, supporters urged reconsideration of the merger, saying it would bring increased grid reliability, jobs and opportunities for minority businesses.
Dinegar in an Exelon video with other D.C. business and civic leaders supporting the merger.
“We know that reliability will be enhanced,” James Dinegar, president of the Greater Washington Board of Trade, said in a video posted on the merger partners’ website. “It’s the right move for strengthening this region and then positioning us as we continue to grow to be the strongest region in the country.”
Pepco Chairman Joseph M. Rigby is a former chairman of the Board of Trade and currently serves on its senior council.
Opposition to Stay
Opposing the acquisition are more than half of the district’s Advisory Neighborhood Commissions and nearly half of the 12-member City Council. The Office of People’s Counsel, which also has advised against approval without significant concessions, could not be reached for comment on Monday.
Meanwhile, the Grid 2.0 Working Group and D.C. Public Power filed their opposition to the request for a stay.
If the settlement constitutes a new filing, Grid 2.0 argued, it and Exelon’s request for a reconsideration should be considered independently on parallel tracks.
In its filing, D.C. Public Power also offered an alternate solution: “There are, in fact, merger arrangements that can be practically implemented that fully satisfy public interest concerns [such as] DCPP’s proposal to buy Pepco’s D.C. assets in a divestiture from Exelon/PHI. The result would be an independent, D.C.-based not-for-profit electric power utility serving the interests of the citizens of the District of Columbia.”
Massachusetts Gov. Charlie Baker said last week that long-term contracts for hydropower are the quickest and most cost-effective way for the state to reduce rising energy costs and reach greenhouse gas reduction goals.
The first-term Republican testified before the legislature’s Joint Committee on Telecommunications, Utilities and Energy in support of his bill to mandate the state’s utilities seek long-term contracts to procure hydropower.
Massachusetts Gov. Charlie Baker testifying before the legislature in support of his bill to mandate that the state’s utilities seek long-term contracts to procure hydropower.
New England power generators have complained that elected officials’ urge to “do something” about rising power costs in the region risks market development just as power plant owners are willing to invest there. (See New England Generators: State Interventions Risk Market Development.)
Baker confronted that argument in his remarks that described how ISO-NE’s main concern is reliability and plant owners need to provide returns to their investors.
“When acting in line with their obligations, none of these players are primarily concerned with costs to the consumer or environmental considerations. That is the status quo,” he said. “We are left with the critical question of who addresses energy costs and environmental concerns. The answer to that question is us.”
The 2008 Global Warming Solutions Act mandates a reduction in greenhouse gas emissions of 25% from 1990 levels by 2020. A 2010 state energy plan said Massachusetts would need at least 1,200 MW of hydropower to reach the target.
“We are in danger of being out of compliance with our own law,” Baker said.
Hydropower on that scale would likely come from Canada, but nothing precludes hydro resources in the U.S. from bidding into any solicitations from the utilities, he said. Baker said hydro can be obtained under current law, but that is unlikely in the absence of long-term contracts.
The contracts would only be pursued if state regulators determined they were cost-effective, the governor said.
Baker also said he would consider testing the market for the viability of offshore wind projects and suggested the legislature could amend his bill to include that resource. The Cape Wind project in Nantucket Sound, under development for more than a decade, was halted after it failed to complete financing after a protracted legal battle.
The governor also repeated his call for action to reduce electricity costs, which are among the highest in the nation, through regional efforts. (See Baker: New England Must Sacrifice to Lower Costs.)
FERC has begun a non-public investigation over allegations of improprieties in MISO’s April capacity auction and will hold a technical conference on the matter Oct. 20.
The commission’s actions, disclosed last week, are in response to complaints filed by Illinois Attorney General Lisa Madigan, Southwestern Electric Cooperative, Illinois industrial energy consumers and the public interest group Public Citizen over MISO’s Planning Resource Auction, which resulted in a nine-fold price increase in Zone 4, which comprises much of Illinois.
Public Citizen called for an investigation in May into whether Dynegy improperly withheld capacity in Zone 4, an allegation the company has denied. Public Citizen also alleged that MISO brushed aside recommendations by its staff that Zones 4 and 5 be merged due to their concerns about Dynegy’s growing share of capacity in Zone 4 after the company acquired four generators there from Ameren.
Prices in Zone 4 cleared at $150/MW-day, compared with just $16.75 a year earlier.
FERC said it is holding the all-day conference to obtain additional information and “determine what further action, if any, may be appropriate” to address the complaints (EL15-70, et al). The conference, which will be webcast, will include discussions of current market power mitigation rules, the calculations of auction parameters and zonal boundaries.
The conference will be run by staff from the offices of General Counsel, Energy Market Regulation, and Energy Policy and Innovation. Stakeholders will have until Nov. 4 to submit post-technical conference comments.
FERC said the conference will not address the non-public investigation being conducted by the Office of Enforcement into “whether market manipulation or other potential violations of commission orders, rules and regulations occurred before or during the auction” (IN15-10). FERC said the investigation began “shortly after” the auction concluded April 14.
In its complaint in May, Public Citizen suggested that Dynegy could have inflated prices by either not offering some capacity or by offering some of it at such a high price that it would not clear.
Madigan filed a complaint saying that Dynegy’s increased generation portfolio in Zone 4 made it a “pivotal supplier” in the zone. Madigan also complained that in approving the Dynegy acquisition, FERC declined to look at its effect on competition and prices in Zone 4 and instead only considered a competitive analysis of MISO as a whole.
Former Idaho Gov. Cecil Andrus is suing the Department of Energy to get information behind a proposal to ship nuclear waste to a nuclear research facility on the Snake River. Andrus suspects the federal government intends to turn the facility into a permanent storage site for spent fuel from commercial reactors.
The former four-term governor sued after receiving mostly redacted documents under a Freedom of Information Act request. He says a 1995 legal agreement between Idaho and the department prohibits such shipments and called for the removal of nuclear waste already stored there.
“I suspect they know what they are planning will be very controversial and, for that reason, want to keep it secret,” he said in a statement.
EPA Finalizes Coal Plant Toxic Metal Effluent Rules
The Environmental Protection Agency released its final version of rules governing the release of toxic metals in the wastewater from steam electric power plants. The rules set limits on the amount of arsenic, mercury, selenium and nitrogen in the wastewater streams from de-sulfuring flue gases, and they set a zero limit on discharges from coal ash transportation.
The rules also encompass wastewater discharges from mercury control systems and coal-gasification wastewater.
The agency said that only 134 of the nation’s 1,080 coal-fired plants will need to make pollution-control investments and put the annual cost of compliance at about $480 million. The rules were last updated in 1982.
Pilgrim Station, already under increased scrutiny from the Nuclear Regulatory Commission, has received failure notifications for four new negative findings from an August inspection.
The most recent inspection included a finding that Pilgrim’s primary weather tower was inoperable on eight occasions between 2012 and 2015 and without backup. If a radiological release occurred during those times, the plant would have had to rely on the National Weather Service for data, NRC said. It said the failings raised doubts that owner-operator Entergy could “protect the health and safety of the public in the event of a radiological emergency.”
Pilgrim was already noted as being among the nation’s three worst-performing nuclear generating stations. Entergy has said it may be too costly to correct all the deficiencies and is investigating the possibility of closing it.
Pushed by technological and market advances, and an impending deadline for a key federal incentive, solar pricing is becoming more competitive, according to a report from the Lawrence Berkeley National Laboratory.
The lab said that utility-scale solar projects have been receiving about 5 cents/kWh in power sales agreements. Wholesale electricity prices in the U.S. ranged from 2 to 6 cents/kWh.
The prices reflect the 30% federal investment tax credit. That credit is scheduled to fall to 10% after 2016. The report — “Utility Scale Solar” — shows that installed project costs have dropped by more than 50% since 2009, and projects are performing at an average capacity factor of 29.4%, up from 26.3% in 2011.
US Falling Behind in Offshore Wind Power, Professors Say
Firestone
The U.S. has fallen behind in the development of offshore wind power, even as land-based wind and solar have taken off, according to an academic study.
A group of professors from the University of Delaware, writing in Proceedings of the National Academy of Sciences (subscription required), noted that offshore wind turbines were installed back in 1991 in Europe, but no such facilities dot the U.S. coasts.
“As we celebrate the 10-year anniversary of the U.S. Energy Policy Act of 2005, it is disheartening to see that while land-based wind and solar have reached new heights, U.S. offshore wind has remained a missed opportunity,” says the paper’s lead author, Jeremy Firestone.
Federal Judge in Wyoming Blocks New Fracking Rules
Skavdahl
A federal judge has blocked the Bureau of Land Management from implementing new rules concerning fracking on federal land. U.S. District Court Judge Scott Skavdahl said the agency lacks the authority to institute the new regulations.
The states of Wyoming, North Dakota, Colorado and Utah, as well as the Independent Petroleum Association of America and the Western Alliance, had sued to block the new federal rules, which they argued duplicated state rules, making it more expensive to drill for natural gas and oil in shale regions.
“Congress has not authorized or delegated to the BLM authority to regulate hydraulic fracturing and, under our constitutional structure, it is only through congressional action that the BLM can acquire this authority,” Skavdahl wrote in a 54-page decision.
EPA Gives North Dakota Coal Plants Extra Time on Clean Power Plan
Glatt
The Environmental Protection Agency has pushed the deadline for North Dakota to come up with a plan to meet its Clean Power Plan goals from fall 2016 to fall 2018. Under the new plan, the state is required to reduce carbon emissions 45% by 2030.
State environmental chief Dave Glatt said the 2016 deadline would have been nearly impossible to meet. “We spent 10 years developing a regional haze (pollution reduction) plan, and this is a lot more complicated,” he said.
EPA, in response to prodding from U.S. Sen. Heidi Heitkamp (D-N.D.), has promised to help determine the best ways to bring clean coal technology and renewables into the generation mix as part of the effort to meet the mandate.
TVA’s Sequoyah Reactors Get NRC License Extensions
The Nuclear Regulatory Commission last week granted 20-year license extensions to the Tennessee Valley Authority’s two Sequoyah reactors in Soddy-Daisy, Tenn.
“Extending Sequoyah operations will play an integral role in reducing our carbon emissions while reliably supplying electricity at the lowest possible cost,” said Joe Grimes, TVA’s chief nuclear officer.
NRC has granted license extensions to 78 U.S. nuclear reactors so far, each for 20 years. Applications for another 16 renewals are pending.
The Nuclear Regulatory Commission announced several senior personnel changes as part of its plan to streamline operations.
Mike Weber, the current deputy executive director for Material, Waste, Research, State, Tribal and Compliance Programs, was named director of the Office of Nuclear Regulatory Research. Jennifer Uhle is moving from her position as deputy director for engineering in the Office of Nuclear Reactor Regulation to become director of the Office of New Reactors. Catherine Haney, director of Nuclear Materials Safety and Safeguards, will become Region II regional administrator in January.
The changes, said NRC Chairman Stephen Burns, “will put in place a management structure well suited to ensuring we accomplish our mission of protecting people and the environment even as we reduce our size and budget.”
U.S. Rep. Ed Whitfield (R-Ky.), chairman of the House Subcommittee on Energy and Power, announced last week he will not seek re-election to a 12th term in 2016.
Whitfield, 72, a leader of the Republican opposition to the Environmental Protection Agency’s carbon emission rules, will stay through the end of his term in December 2016. Whitfield’s long-time aide, Michael Pape, and state Agriculture Commissioner James Comer, who finished second in the Republican primary for governor in May, have announced they will seek the seat.
Rep. Pete Olson (R-Texas), the subcommittee’s vice chairman, is the leading candidate to replace Whitfield as chairman of the panel. Whitfield’s departure also increases the odds that Rep. John Shimkus (R-Ill.) will succeed Rep. Fred Upton (R-Mich.) as chairman of the Energy and Commerce Committee. Upton must relinquish the chairmanship at the end of this term due to GOP term limits.
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.
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.
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.
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.
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.
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
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.”
Cox and ODEC’s Ed Tatum
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 (NOx) 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.
