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.
WASHINGTON — A key House committee last week approved what would be the first comprehensive energy legislation in eight years, but hopes for passage dimmed after Republican amendments eroded bipartisan support.
H.R. 8, the North American Energy Security and Infrastructure Act of 2015, cleared the House Energy and Commerce Committee 32-20 on Wednesday with support from only three Democrats. The bill includes measures to improve energy infrastructure, resilience and reliability while increasing scrutiny of RTOs and FERC.
Pallone (left) and Upton.
A preliminary draft of the bill had passed a subcommittee unanimously. But Wednesday’s markup devolved into partisan sniping after Chairman Fred Upton (R-Mich.) replaced the original bill with a 208-page amendment that stripped gas and electric infrastructure funding sought by Democrats. The amendment also includes provisions that would speed the approval of liquefied natural gas export terminals and repeal current law requiring that federal buildings phase out the use of fossil fuel-generated energy.
The changes left Rep. Frank Pallone (D-N.J.), the ranking Democrat on the committee, fuming. “This bill only aims to help polluters in my opinion,” he said. “It continues to ignore the impact of climate change, which remains the biggest threat to our energy security and way of life.”
Upton said the bill is intended to create jobs, improve infrastructure and ensure affordable energy. “While it has been difficult to find bipartisan consensus on as many fronts as I would have liked, I believe we have written a substantive, thoughtful bill,” he said in opening the committee markup.
Congress has not approved a comprehensive energy bill since the Energy Independence and Security Act of 2007. While the House bill is unlikely to pass as is, many of its provisions could find their way into final legislation if bipartisanship prevails.
The Senate Energy and Natural Resources Committee passed its own legislation, the Energy Policy Modernization Act, on July 30 by a bipartisan 18-4 vote.
The package, crafted by Chairwoman Lisa Murkowski (R-Alaska) and ranking member Maria Cantwell (D-Wash.), also would expedite LNG projects and streamline the federal permitting process. It includes measures to improve energy efficiency and cybersecurity and encourage hydropower and geothermal development.
Below is a summary of the House bill’s major provisions affecting the electric industry:
RELIABILITY
Fuel Security
The bill would require traditional vertically integrated utilities to incorporate “reliable generation” into their integrated resource plans, defining it as generation facilities with firm-fuel contracts, dual-fuel capability or sufficient on-site fuel to operate “for the duration of an emergency or severe weather conditions.” (Section 1107)
The requirements would not apply to companies engaged in competitive, unbundled retail electric sales.
FERC Reliability Review
FERC, in consultation with the North American Electric Reliability Corp., would be required to conduct reliability analyses of any federal rule affecting electric generators that is expected to result in an annual effect on the economy of at least $1 billion. The FERC review would evaluate the impact of the rule on electric reliability; resource adequacy; the nation’s electricity generation portfolio; the operation of wholesale markets; electric transmission lines; and natural gas pipelines. (Section 1108)
RESILIENCE
Hardening
The bill would require all utilities to develop plans for improving the resilience of their systems against physical sabotage, cyberattacks, electromagnetic pulses, geomagnetic disturbances, severe weather and earthquakes. Among the measures that utilities may consider are the hardening of distribution facilities; technologies that can isolate or repair problems remotely, such as advanced metering and monitoring and control systems; cybersecurity measures; distributed generation; microgrids and non-grid-scale energy storage. (Section 1107)
State regulators “shall consider” authorizing spending on such improvements, the bill says.
The legislation also establishes a competitive grant program for states and local governments for spending on resilience and reliability. (Section 1201)
Strategic Transformer Reserve
The bill would authorize the creation of a stockpile of large power transformers and trailer-mounted mobile substations to recover from the threats listed above. (See “Hardening.”)
The issue caught Congress’ attention as a result of the April 2013 rifle attack on Pacific Gas and Electric’s Metcalf substation and a campaign by former FERC Chairman Jon Wellinghoff to raise awareness of the grid’s vulnerabilities. Wellinghoff cited a 2013 FERC analysis that he said concluded that an attack that disabled nine critical substations could cause an extended blackout in the continental U.S. (See Report: Sabotage Threat Uncertainty Could Lead to Wasteful Spending.)
The Energy Department would be required to develop a plan for the reserve and identify preferred funding options, including fees on owners and operators of bulk-power systems and critical electric infrastructure, federal appropriations, and public-private cost sharing. (Section 1105)
Grid Security Emergencies
If the president declares a grid security emergency, the Secretary of Energy would have authority to order measures to protect or restore the reliability of critical electric infrastructure. (Section 215A)
FERC
Merger Authorization
It would limit FERC review of merger and consolidation acquisitions to those of $10 million or more. (Section 4222)
FERC Enforcement
FERC would be required to create an Office of Compliance Assistance and Public Participation to “promote improved compliance with commission rules and orders.” (Section 4211)
The proposal is an apparent response to complaints by some in the Washington energy bar that FERC’s Office of Enforcement, formerly headed by Chairman Norman Bay, is unfair and heavy handed. (See Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info.)
The office would “promote improved compliance” with commission rules through outreach and publications and, “where appropriate, direct communication with entities regulated by the commission.’’
The provision is intended to provide entities subject to FERC regulation “the opportunity to obtain timely guidance for compliance with commission rules and orders” — an opportunity FERC says it already offers through “no-action” letters.
RTOs/ISOs
GAO Study
The Government Accountability Office would be required to conduct reports on each RTO’s and ISO’s “market rules, practices and structures.” (Section 4221)
The grid operators would be judged on a number of issues, including whether they produce just and reasonable rates; facilitate fuel diversity, reliability and advanced grid technologies; and promote “equitable treatment of business models, including different utility types.”
GAO also would evaluate the transparency of grid operators’ governance structures and stakeholder processes as well as the transparency of dispatch decisions, including the need for out-of-market actions and the accuracy of day-ahead unit commitments.
The report also would review how well grid operators facilitate “the ability of load-serving entities to self-supply their service territory load.”
The American Public Power Association, which opposes mandatory capacity markets, said the bill doesn’t go far enough. The group said the bill doesn’t address problems faced by public power utilities “forced to participate in the FERC-blessed mandatory capacity markets and is silent on the issue of self-supply for such LSEs.”
APPA, which represents more than 2,000 community-owned, not-for-profit utilities, said it wants the legislation changed to allow wholesale markets to “become more affordable and workable for public power utilities that are willing and able to build a variety of power generation facilities if not blocked from doing so by rules skewed toward certain market participants.”
Financial traders could benefit from a requirement that RTOs ensure “the proper alignment of the energy and transmission markets by including both energy and financial transmission rights in the day-ahead markets.”
Industry sources said the provision would encourage more widespread use of products similar to PJM’s up-to-congestion trades and ERCOT’s point-to-point congestion hedges.
Capacity Markets
RTOs and ISOs operating capacity markets would be required to provide to FERC an analysis of how the markets use competitive forces and include “resource-neutral” performance criteria. FERC would be required to report to Congress on whether each market meets the criteria and make recommendations for those that don’t. (Section 215B)
INFRASTRUCTURE
Deadlines
A final decision on a federal authorization for gas pipelines would be due no later than 90 days after FERC issues its final environmental document, unless a schedule is otherwise established by federal law. (Section 1101)
It would require the Energy Department to act on applications for LNG export facilities within 30 days of the conclusion of reviews under the National Environmental Policy Act. (Section 3006)
Frank Macchiarola, executive vice president for government affairs at America’s Natural Gas Alliance, praised the bill, saying that it “recognizes and seeks to maximize the opportunities presented by our nation’s domestic energy abundance.” ANGA represents independent natural gas exploration and production companies in North America.
Carbon Capture
The Energy Department would be required to evaluate all carbon capture and sequestration projects funded by the agency every two years. (Section 1109)
Hydropower
The bill would reauthorize hydroelectric production incentives through fiscal year 2025 and require FERC to minimize infringement on private property rights in issuing hydropower licenses. (Sections 1301-1304)
FERC would be authorized to issue exemptions from licensing requirements for development of new hydropower projects at existing non-powered dams.
It would build on changes in two bills enacted in 2013 that streamline regulations on small hydropower sites. A 2012 Energy Department report said the powering of non-powered dams could unlock 12 GW of generating capacity. (See Tiny Hydro Projects Joining Generation Mix in PJM.)
APPA said it was disappointed that the bill does not include “substantive” licensing reform.
“The current hydropower licensing process must be reformed so that public power and other utilities can increase reliable emissions-free hydropower generation without unnecessarily prolonged resource agency review,” it said.
The bill would provide special relief for one hydro project, however.
The developers of the proposed hydro project on the U.S. Army Corps of Engineers’ W. Kerr Scott Dam on the Yadkin River in North Carolina would have an additional six years to start construction under the bill. Wilkesboro Hydropower has proposed adding a turbine that would generate 2 MW at the unpowered dam.
FERC granted the developers a license in July 2012 giving them two years to begin construction and five years to complete it. In May 2014, FERC granted Wilkesboro Hydropower a two-year extension (P-12642-007).
Under the Federal Power Act, FERC told the developers, the deadline for starting construction may only be extended once.
VALLEY FORGE, Pa. — The Markets and Reliability Committee voted overwhelmingly Thursday to raise the energy market offer cap to $2,000/MWh in a move that outgoing CEO Terry Boston called “the stakeholder process at its best.”
The MRC approved the new cap by an unweighted 84-17 margin, after which the Members Committee gave final approval by voice vote.
Boston said the Board of Managers would approve the new framework and PJM would be filing a Tariff change with FERC within a couple of weeks.
He apologized for not having the Tariff language ready before the vote, saying, “We were not as optimistic as we should have been about this getting approved this morning and afternoon.” He said the language would be made available to members a few days before the FERC filing.
Boston appeared touched by the vote, which comes as his seven-year tenure nears its end. “In the first meeting of the year, after this was voted down last year, I begged for consensus,” he recalled.
There was a smattering of applause when the vote was revealed at the MRC, and many who had sparred this year over the issue offered praise to PJM staff, each other and the four entities who agreed to withdraw their own proposals in favor of the simplified plan: Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3) and the Independent Market Monitor.
“It’s really cool that we were able to pull this off given the short time frame,” said Marji Phillips of Direct Energy, which had initiated the first of the four proposals. “I want to compliment everyone who supported this — especially when I was yelling at you at the last meeting.”
Pepco Holdings Inc.’s Gloria Godson called the vote “a beautiful thing to behold.”
The Details
The proposal caps cost-based offers at $2,000/MWh and allows them to set LMPs, with market-based offers allowed to equal cost-based ones. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through after-the-fact review and subsequent make-whole payments.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.
Jeff Whitehead of Direct Energy, whose proposal would have raised the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers, said the company was willing to back the compromise because it ensures “that as much generator compensation cost is recovered as possible in energy prices, which are hedgeable, and something load servers can compete on.”
“Uplift is not [hedgeable] and is a cost that gets rolled into risk adders that get passed on to consumers,” he added.
Likewise, David “Scarp” Scarpignato of Calpine said P3 didn’t believe the consensus proposal offered the “proper price formation,” but the group was willing to support it because it does allow generators to recover costs and raises the level that can set LMPs.
Temporary Change; FERC Action Expected
Some of those who opposed raising the cap previously — or thought the compromise was insufficient — were willing to support what is now assumed to be a temporary solution. FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
Exelon’s Jason Barker, who at the last meeting on the issue had criticized the framework, supported it Thursday as “an improvement over the status quo” and said he hoped FERC would improve on the filing. “We will look forward to FERC … recognizing flaws inherent in this proposal,” he said. (See Consensus Near on PJM Energy Market Offer Cap?)
Similarly, Dynegy’s Jason Cox said, “Dynegy reluctantly supports this compromise as a way to ensure that our costs are covered until FERC acts. We believe that we should not allow market distortions and continue to support potential massive uplift during critical periods.”
Susan Bruce of the PJM Industrial Customer Coalition said her group continued to have concerns over the proposal but offered support in return for a promise from the Market Monitor and PJM that there would be “robust reporting” on offers between $1,000, the current cap, and $2,000.
Delaware, Maryland Unconvinced
Representatives of state commissions generally opposed the proposal.
John Farber, public utility analyst for the Delaware Public Service Commission, asked that PJM consider releasing information about the heat rates of the generators setting the clearing price.
Walter Hall of the Maryland Public Service Commission said his agency remained unconvinced of a need to raise the cost cap.
Jim Jablonski of the Public Power Association of New Jersey pointed out that PJM fared better this past winter, which saw colder temperatures, than it had during the previous season’s polar vortex.
And, he said, “Capacity Performance is designed to provide a financial incentive to perform whenever needed and designed to eliminate future emergencies. Reliability, therefore, in our view is protected. We do not think a change is warranted. Two thousand dollars is not supportable except as a compromise, has no factual basis and definitely is going to be open to challenge.”
MISO staff said Friday they will recommend three economic projects be included in the 2015 MISO Transmission Expansion Plan. The projects in Southern Indiana, East Texas and Central Arkansas have a projected cost of $281 million, including $85 million that PJM will pay for its share of the Indiana project.
Digaunto Chatterjee, MISO’s director of economic studies, told a special meeting of the Planning Advisory Committee that staff selected the Duff-Rockport-Coleman 345-kV project from among three under consideration near the RTO’s eastern seam with PJM in Southern Indiana.
MISO will pay $67.2 million for the Duff and Coleman substations and a 28.5-mile single circuit between them. PJM will cover the cost of the $38.7 million double circuit line plus $46.5 million in upgrades at the Rockport substation.
Chatterjee said the MISO portion of the project — the Duff and Coleman substations and a 28.5-mile single circuit between them — has a benefit-cost ratio of 16.1 based on MISO’s estimated cost of $67.2 million.
The project, expected in service in 2021, should eliminate congestion around Newtonville and Coleman and provide slightly higher economic benefits than the Duff-Coleman alternative. MISO’s cost will be the same as the $67.2 million Duff-Coleman because PJM will pay $85.3 million for improvements that will allow it to eliminate the special protection scheme at its Rockport substation.
“It’s no difference to us whether it’s one project or two projects connecting with each other,” Chatterjee said.
The PJM portion of the project includes two 765/345-kV transformers in Rockport and a 14-mile double circuit between the substation and Duff-Coleman.
Reacting to concern that the PJM portion of the project could result in unexpected costs, Chatterjee said staff “will make it clear to the board MISO stakeholders don’t want any issues from the PJM side to keep us from going ahead with the project.”
“We fully expect Duff to Coleman will be connected to Rockport,” he told the PAC, “but we won’t let PJM’s processes interfere with our portion of the project.”
Chatterjee said he had received a commitment from PJM saying that will approve the project and pay the incremental costs. (See “AEP Agrees to Pay Share of Market Efficiency Project” in MISO Planning Advisory Committee Briefs.)
East Texas Project
MISO is also recommending two economic projects in its South region, including a two-part construction/rebuild that would ease congestion around an East Texas load pocket.
MISO recommends constructing a new 230-kV transmission line between the existing Lewis Creek substation and a new 345/230-kV substation that will cut into the Grimes-Crocket 345-kV line. In addition, it will rebuild the Newton Bulk-Leach 138-kV line.
MISO South will get projects in East Texas (L) and Central Arkansas (R).
Chatterjee said the project cleared the benefit-cost ratio under two different future generation scenarios, with a B/C of 1.5 assuming future generation inside the load pocket and a 2.88 B/C with generation added outside the pocket.
The project has an estimated cost of $122.5 million and a projected in-service date of 2021. It would ease congestion on three 138-kV lines.
Arkansas Project
The third project, rebuilding the Mabelvale-Bryant South 115-kV line, would reduce congestion in the southwest Little Rock area. It has a projected cost of $6.1 million and a weighted B/C ratio of 5.88, with an estimated 2020 in-service date.
Staff will accept stakeholder input on the three projects through Oct. 2. Previous feedback and MISO’s responses to the South projects have been posted in the Oct. 2 Market Congestion Planning Study meeting materials.
The PAC will consider MTEP 15 during its Oct. 14 meeting, before the plan goes on to the System Planning Committee in October and Board of Directors in December.
A FERC administrative law judge will attempt to settle TransSource’s complaint against PJM concerning the costs of three network upgrades that the company says are being inflated by transmission owners (EL15-79).
TransSource alleges that PJM has refused to provide the company with files relevant to the system impact studies showing the underlying costs of the upgrades, which the company says is in violation of the RTO’s Tariff. PJM maintains that it provided TransSource with all the necessary data and that it is under no obligation to provide the specific files the company is requesting.
The Independent Market Monitor last month requested that FERC settle the dispute. (See PJM Monitor Asks FERC to Resolve TransSource Dispute.) PJM responded by saying it was willing to informally meet with the Monitor, TransSource and the relevant transmission owners to discuss the studies. TransSource rejected this, supporting the Monitor and insisting on a formal process.
The commission said Thursday that it could not rule based on the record before it and set the case for hearing and settlement procedures.
