CAMBRIDGE, Md. — Retiring PJM board members Jean Kinsey and Richard Lahey marked their final Annual Meeting last week with reminiscences on the industry’s past and some views on its future.
Lahey, former dean of engineering at Rensselaer Polytechnic Institute and an expert on nuclear reactor safety technology, was one of two original PJM board members, having joined with Chairman Howard Schneider 19 years ago.
He was there as PJM grew from its roots as a “tight power pool” to its current 13-state footprint with wholesale energy, capacity and ancillary services markets. It became the nation’s first fully functioning ISO in 1997 and the first RTO in 2001.
“We had some advantages in that it wasn’t unusual for us to operate that kind of grid,” he said, noting PJM was founded in 1927. “The disadvantage was you were sort of entrenched in a certain way of doing it and it didn’t scale up. Fortunately, there were people on the board who had been from large corporations, and they made some very positive suggestions on how to scale it up.”
At the beginning, Lahey recalled, “our independence was challenged by some of the members, and we took a position that we weren’t going to sit at the board unless we were independent. And because we did that we’ve been able to function very well.”
Lahey said a strength of the board has been its diversity. “There’s people from retail, there’s people from Wall Street-type backgrounds. There’s people from universities, from the industry. What it means is when we come to reach a decision, we have very rich discussions. And a lot of times there’s quite a few changes depending on the input.”
Kinsey, who holds a doctorate in agricultural economics and is a former University of Minnesota professor who specialized in food safety, recalled the “steep learning curve” she faced after joining the board 13 years ago.
She said the board’s biggest challenge over her tenure was its efforts to perfect PJM’s market design. “We keep tweaking the market as the environment in which [generators] operate changes,” she said, noting current challenges in incorporating the externalities of carbon emissions.
“Going forward, I think the major challenge is going to be how you operate an efficient grid with a lot of smaller generating units — microgrids, behind-the-meter [generation],” she said. “The grid magnifies the economies of scale. If you have things peeling off that, how can you keep the value of that core operation?”
Retirement Plans
Lahey, who retired from RPI seven years ago, is hoping to reduce his outside consulting work to spend more time boating and on the beach with his family at his home in St. Augustine, Fla. “If you retire, it’s sort of nice to have time to enjoy yourself,” he said.
Kinsey, who retired five and a half years ago from Minnesota, is president of the university’s retiree’s association. She plans to spend her free time learning photography.
“I’ve become quite interested in photography becoming art, where you can take a piece of a picture and create a design out of it,” she said. “The other part of my brain is crying to be recognized.”
CAMBRIDGE, Md. — Keeping the lights on, planning for the future and facilitating efficient electricity trading will continue to be PJM’s core mission, CEO Andy Ott told members in reviewing his first year at the helm of the RTO.
But PJM needs to be positioned for changes, he said, like the ones that necessitated the move toward Capacity Performance — legacy assets were becoming less reliable, and new gas generation didn’t have fuel security.
“We addressed that change abruptly. We need to avoid those kinds of abrupt changes in the future — abrupt change in the markets doesn’t help anybody,” he said. “Our goal … is to stabilize our rules to make sure we see these emerging trends coming.”
The industry is evolving rapidly, Ott noted, “not only the volume of change, but how quickly those changes are occurring.”
He pointed to changing load profiles and fuel mix, the Clean Power Plan, gas-electric coordination, renewable and distributed energy resources (DER) and cybersecurity.
“The key is to make sure that as we look forward, we strategically evaluate how those changes are going to affect our markets,” Ott said. “We can’t get caught by surprise. We need to make our systems more and more resilient.”
He also singled out some areas that he said need to evolve: the Regional Transmission Expansion Plan process; PJM markets, to accommodate gas-electric coordination and DER; and enhancing the value of the RTO’s services.
“I see a tremendous opportunity for us if we can find a way to harness the distributed energy resources that are inevitably coming onto the system,” he said. “It will make the grid more resilient and will result in lower cost and … less operational uncertainty.”
Ott said PJM also will be studying the value of fuel diversity from an operational perspective.
“Should we be looking at fuel diversity as an attribute? And under what circumstances would we do that?” he said.
The topic will be the subject of an upcoming report, he said.
Md. Energy Adviser Delivers Keynote
Mary Beth Tung delivered the keynote address at the final session of the PJM Annual Meeting last week, just two days after being appointed director of the Maryland Energy Administration by Gov. Larry Hogan.
Maryland, with 12,264 MW of capacity, is a net importer of energy, she told the group.
Coal and nuclear power supply more than four-fifths of the state’s generation; among the challenges the state faces is that nearly 66% of its coal-fired power plants are at risk of retirement. To address that loss, the state has a number of new natural gas-fired facilities scheduled to come online in the next few years.
A member of the Regional Greenhouse Gas Initiative, Maryland has a goal of reducing carbon emissions by 40% compared with 2006 levels by 2030, she said.
Maryland faces a unique hurdle in that its geography lends itself to air pollution, Tung said — 70% of pollution wafts in from surrounding states.
Still, she said, the state has been successful in reaching its energy goals.
In 2008, legislation imposed a requirement to reduce per capita electricity consumption by 15% from 2007 levels by 2015. It achieved 99% of that directive and plans to continue toward a 2% reduction in electric sales at a rate of 0.2% annually.
Board Members Elected; Standing Ovation for Lahey, Kinsey
Members unanimously elected Dean Oskvig and Mark Takahashi to the Board of Managers and re-elected Terry Blackwell to a new term. Blackwell was appointed last year to fill the term of William Mayben.
The new members take the place of Jean Kinsey, who served on the board 13 years, and Richard Lahey, who held his seat for 19. They received a standing ovation. (See Committee Recommends 2 Industry Vets for PJM Board.)
Oskvig recently retired as CEO of Black & Veatch. Takahashi is CFO of Ascendant Group.
Stakeholder Survey Indicates Member Satisfaction
A survey of stakeholders last year drew an 87% approval rating, compared with 90% in 2013.
PJM listed the key drivers of satisfaction as markets/reliability management, the stakeholder process, member support and corporate reputation.
Going forward, it plans to establish best practices for employees to assist members via email; increase the use of the Salesforce tool; and promote the knowledge base among members.
PJM also is creating a forum to discuss tool-related changes and information technology efforts that affect members, and offer more tool-specific training.
Members Endorse Revisions
The committee endorsed the following as part of the consent agenda:
Revisions to Manual 34: PJM Stakeholder Process as a result of a periodic review. The changes update language and formatting for clarification and graphics for better readability.
Changing the emergency energy default customer baseline (CBL) from the “hour before” methodology to the current default economic CBL. (See “Members Endorse New Way to Measure Emergency DR,” Market Implementation Committee Briefs.)
Tariff and Operating Agreement updates incorporating business rules for dynamic transfers.
The New Hampshire siting board said Thursday it needs more time to consider the Northern Pass transmission line, pushing back its decision until Sept. 30, 2017.
The state’s Site Evaluation Committee, following guidelines in state law, originally thought it would wrap up its review by the end of the year. (See Committee Rules Northern Pass Application Complete.)
But the Society for the Preservation of New Hampshire Forests, citing the complexity of the case, filed a motion asking for a suspension of the normal schedule. The committee agreed.
Committee Chair Martin Honigberg said it was “unrealistic” to complete the review by the end of the year, according to the New Hampshire Union Leader. He said September 2017 “was probably the right date” and didn’t anticipate any further delay.
The 192-mile, $1.6 billion project would bring 1,090 MW of Canadian hydropower into New England. Project developer Eversource Energy, which had hoped to begin construction next year and have the line in operation in 2019, called the decision “disappointing.”
“It will only delay the realization of the substantial benefits of this project in New Hampshire and throughout New England,” Bill Quinlan, president of Eversource’s New Hampshire operations, said in a statement. “We look forward to the written order outlining the details of this schedule and in the meantime will be evaluating our options for seeking reconsideration.”
Eversource had agreed to bury 60 miles of the line, but preservationists and advocates for the state’s tourist industry had opposed the impact of the line on the natural environment and wanted the entire project underground.
“We applaud the SEC subcommittee’s decision to extend the timeframe to consider the Northern Pass application. It will improve the process. Taking an appropriate amount of time to consider all of the impacts a 192-mile transmission line would have on New Hampshire makes sense,” Jack Savage, spokesman for the forest society, said in a statement.
FERC reassured LS Power last week that the company’s plan to base some of its interstate administrative and operational activities in its Austin, Texas, office won’t trigger commission jurisdiction over ERCOT and its market participants (EL16-46).
Cross Texas Transmission is renting 16,000 square feet at the CityView Center building in Austin. Photo source: Loopnet.com
New York-based LS Power, which maintains infrastructure across the country, is developing the Cross Texas high-voltage line connecting wind farms in the Texas Panhandle to the ERCOT grid.
Cross Texas’ primary and backup control centers are in Austin, and LS Power wants to use those facilities to monitor, operate and control similar transmission infrastructure outside of Texas. But first, the company wanted to confirm the administrative work across state borders wouldn’t require FERC’s involvement.
ERCOT doesn’t fall under FERC supervision through the Federal Power Act, and it has been very careful to maintain that autonomy.
LS Power argued that the activities of its Austin-based employees “will not result in any change to the power flows into or out of ERCOT or mean that electric energy is being sold or transmitted in interstate commerce.” Therefore, the terms of ERCOT’s autonomy should remain intact, they argued.
FERC agreed.
“ERCOT utilities are not generally subject to commission jurisdiction under the FPA because their facilities are neither used for transmission nor for sales of electric energy in interstate commerce (except as a result of interconnection and wheeling service provided pursuant to orders under Sections 210 and 211 of the FPA),” the commission said.
“Petitioners’ employees providing control center services does not change that fact; their actions will not involve the flow of electric energy, or the commingling of electric energy, between ERCOT and the rest of the continental United States, nor will they involve sales of electric energy at wholesale between ERCOT and the rest of the continental United States.”
The state is already meeting the carbon dioxide emissions target under the final year of EPA’s Clean Power Plan, thanks to reduced use of coal-fired power generation because of the low price of competing natural gas.
The state’s carbon emissions were 30.1 million tons in 2015, down from 39.7 million tons in 2014, according to an analysis by the Department of Environmental Quality. The state’s target for 2030 is 30.6 million tons.
Southwestern Electric Power Co. said that SPP did not dispatch its Arkansas coal plants as much in 2015 as the previous year. The company said lower natural gas prices and mild weather were the primary factors.
Regulators Reopen San Onofre Rate Deal, Moody’s Frowns
Moody’s Investors Service took a dim view of a Public Utilities Commission decision to reopen a 2014 agreement that shouldered ratepayers with most of the multibillion-dollar shutdown costs of the San Onofre nuclear plant.
The commission earlier this month decided to reopen the $4.7 billion settlement amid disclosures that secret meetings were held before the deal was approved 18 months ago and complaints from stakeholders. The plant was closed prematurely in 2013 after a radiation leak was discovered during the replacement of a steam generator.
Delmarva Power Proposes To Raise Rates Post-Merger
Stockbridge
Delmarva Power, one of the Pepco utilities recently acquired by Exelon, is asking the Public Service Commission for a $62.8 million electric rate hike and an increase of $21.5 million for its gas services.
President Gary Stockbridge said the money is needed to cover $120 million in upgrades to the gas system and $222 million in improvements to its electricity infrastructure.
For a typical residential customer, the increases would translate to $10.23/month for electricity and $13.55 for gas.
Future Shaky for Bill to Save Quad Cities, Clinton Stations
The chair of the Senate Energy and Public Utilities Committee said Thursday that it’s unlikely Exelon’s “Next Generation Power Plan,” which would extend state clean power subsidies to nuclear plants, will come to the floor before the legislative session ends May 31.
Exelon has said it will shutter its struggling Quad Cities and Clinton nuclear power plants if the General Assembly doesn’t act, and if Quad Cities doesn’t clear the PJM Base Residual Auction. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
Among other provisions, SB1585 would extend state subsidies for clean power to nuclear plants. It also would allow Commonwealth Edison to shift its billing model from one based on monthly kilowatt-hour consumption to a demand charge assessed on a customer’s peak monthly usage.
The amount of employed coal miners in the state has hit a nearly 120-year low, according to a report released this month from the Energy and Environment Cabinet. About 6,900 coal miners are working in the state, the lowest number recorded since 1898.
The cabinet also reported that coal production fell 13% in the first quarter of 2016 to 11 million tons, the lowest level since 1939.
Cabinet Assistant Director Aron Patrick said he anticipates that coal’s decline will bottom out by 2018. “Currently we are supplying coal to power plants that are scheduled to close before 2018,” Patrick said. “So in the near term, i.e., 2016 through 2017, there likely will be continued declines. But 2018 and beyond, there probably will be some sort of stabilization.”
The proposed 26-turbine Somerset Wind project in the Misery Ridge area won’t be affected by a change in zoning regulations that allow communities to opt out of a fast-track wind development zone, according to the project’s developer.
More than 20 communities have petitioned the state for exemptions from a law providing for an expedited permitting area, which allows for the fast-track development of commercial wind farms in parts of the state’s unorganized and rural areas.
Last week, landowner Weyerhaeuser withdrew its opposition to several townships opting out of the expedited permitting area. SunEdison said that those townships were not part of its plans for the project.
Senate Proposes Legislation To Regulate Retail Choice Cap
The Senate is considering legislation that would impose a new electric generation service charge on retail customers entering the deregulated market, which advocates of competition say would hinder retail electric choice.
The proposal, which is supported by utilities, would retain a 10% cap on the amount of power the state can receive from alternative generators and out-of-state suppliers. But, along with the additional charge, it would require alternative suppliers to prove future resource adequacy.
“Adding a punitive new capacity charge will all but thwart electric choice,” said Laura Chappelle of the Energy Michigan trade association. Sen. Mike Nofs, the bill’s sponsor, said the new law is necessary to ensure reliability.
State Becoming a Hotbed for Solar Energy Development
Interest in developing solar power is soaring in the state, with out-of-state developers working to lease land to develop solar farms.
“There’s a lot of prospecting in our area for sure,” said Susan Conell, Cascade County planning director. She said at least six different companies from North Carolina, South Carolina, California and Virginia have called the county inquiring about the county’s solar regulations.
NorthWestern Energy, the largest public utility in the state, has signed five 25-year power purchase agreements with California-based Cypress Creek Renewables for 14 MW of solar power from in-state farms. Statewide, two out-of-state developers alone are proposing 43 solar projects, each 3 MW, NorthWestern said.
JCP&L Revives Controversial Transmission Line Project
Jersey Central Power & Light is reviving plans to build a 10-mile 230-kV transmission line in Monmouth County, a project that was canceled 25 years ago after local protests.
The so-called Monmouth County Reliability Project is virtually identical to the old line, but it will cost a lot more: $75 million, compared to $14.5 million in 1991. The company says the demand for power has caught up to what had been forecast for the area back when the line was first proposed.
PJM has called the project necessary for regional grid stability. It would run along an existing railroad right of way.
A race for a seat on the Public Regulation Commission has become hotly contested, as challenger Cynthia Hall has portrayed incumbent Karen Montoya as being deferential to the state’s largest utility company, Public Service Company of New Mexico.
Hall, a lawyer who finished second to Montoya in a three-way race in 2012, says the incumbent has been “far too close” to PNM. She cites the commission’s approval last year of the utility’s plan to close two coal-fired units at the San Juan Generating Station.
Montoya’s website touts her record as commissioner. She said in the last four years, the commission has approved the largest solar array in the state and lowered the universal service fee on residents’ phone bills.
Albuquerque Delays Decision To Increase Renewable Energy
The Albuquerque City Council has delayed voting on a resolution that calls for the city government to obtain at least 25% of its electricity from solar by 2025.
The two council members who introduced the resolution acknowledged they have no idea how much the effort will cost. The resolution calls on the city’s energy council to weigh various options, from retrofitting existing city buildings with solar arrays to constructing a new solar farm. An implementation plan would be due by 2017 and the City Council could decide what path to pursue.
NYISO said a total of 41,874 MW of supply is available to meet summer power demand in the state, well above its forecasted peak demand of 33,360 MW.
The total capacity includes 38,534 MW of generating capacity from power plants, 1,248 MW in demand response resources and 2,092 MW from out-of-state resources.
Last summer’s peak demand of 31,138 MW, recorded on July 29, 2015, was below the 15-year average of 31,540 MW.
The Public Service Commission created the state’s first-ever Energy Affordability Policy to provide $248 million in direct relief to low-income residents.
The new policy will limit energy costs to no more than 6% of household income.
The order will immediately increase the number of low-income utility customers receiving monthly discounts by 50%, from 1.1 million customers to 1.65 million. The order also creates a multiagency low-income energy task force to develop new strategies aimed at all of the state’s 2.3 million households at or below 200% of the federal poverty level.
Duke Ordered to Excavate Coal Ash, but May Get Reprieve
State environmental authorities ruled that Duke Energy must excavate all of its coal ash dumps and ponds, which the utility says would “significantly increase” its estimated $4 billion in coal ash remediation costs. But the regulators said they may later change the ruling to allow the company to make improvements to the storage areas instead.
In response, Duke said it would seek regulatory approval to pass on to ratepayers any additional costs it incurred if it is required to remove all the ash.
Environmentalists said the ruling doesn’t go far enough to protect drinking water of those living near the sites. Gov. Pat McCrory’s administration “is making a mockery of the law and continuing to cower away from taking one iota of meaningful action to clean up leaking coal ash dumps,” said Pete Harrison of the Waterkeeper Alliance.
Bill Would Impose Financial, Safety Regulations on Solar, Wind
Cook
A bill introduced by two Republican state senators would impose safety requirements on wind and solar farms that critics say could be stricter than those on coal-burning and nuclear plants.
Sen. Bill Cook, co-sponsor of SB843, said the increase in renewable projects is prompting complaints about safety, appearance and negative effects on property values. Cook represents the area where a Spanish developer is building the Amazon Wind Farm.
Among the provisions, the bill would require that a wind farm could not generate more than 35 decibels of sound, the volume of human whispering, as measured from a neighboring property.
A House committee last week defeated a bill that would have begun phasing out the state’s zero-emissions tax credit for the wind industry at the end of 2017 rather than 2020.
Members of the state House Joint Committee on Appropriations and Budget questioned whether it would be fair for lawmakers to renege on a deal made just last year that included a five-year property tax exemption for the wind industry to expire at the end of this year. The bill was defeated by a 13-15 vote.
The state currently is scheduled to end the 10-year tax credit for new wind farms placed in service after Dec. 31, 2020. By moving the deadline up to 2017, the state would have saved $306 million.
The Independent Regulatory Review Commission last week rejected a proposal from the Public Utility Commission that would have curtailed net metering at 200% of a customer’s annual consumption.
The PUC has 40 days to amend, withdraw or present to lawmakers its rule.
“I don’t believe the authority exists to create such a cap,” IRRC member W. Russell Faber said in explaining the board’s disapproval. The PUC said it worried that homeowners trying to make money from selling back alternative electricity would drive up the cost of power and prevent utilities from being able to collect enough money to maintain the grid.
Power Company of Wyoming said it is reconsidering plans to break ground on the $5 billion Chokecherry Sierra Madre wind farm after two bills moved forward in the State Legislature that would raise taxes on wind energy.
The Revenue Committee advanced a bill to raise the production tax on wind beyond the current $1/MWh and a second bill that would obligate wind companies to hand over to the state some portion of the federal wind energy production tax credits they currently receive.
The bill “has created significant uncertainty and added a huge new risk regarding our plans to construct and operate two new renewable energy businesses in Wyoming,” said Kara Choquette, a PCW spokeswoman. The company has worked for more than a decade to obtain the regulatory clearance for the 1,000-turbine, 3-GW installation.
FERC last week dismissed a complaint by Southern Maryland Electric Cooperative alleging that it has the right to a Capacity Performance credit from J.P. Morgan Ventures Energy Corp., saying the contractual dispute would be better resolved by a court (EL16-35).
In 2011, the parties executed a capacity purchase and day-ahead heat rate call option on physical electricity for the Brandywine Generation Facility from Jan. 1, 2014, through Dec. 31, 2021. The power purchase agreement provides SMECO a 225-MW Reliability Pricing Model capacity credit in exchange for a monthly payment to JPMVEC.
SMECO said that it did not believe JPMVEC intended to transfer the credit under PJM’s new Capacity Performance model and instead treat the product as base capacity.
“Determination of the dispute between SMECO and JPMVEC depends upon whether the parties contracted to sell and purchase capacity specifically from the Brandywine facility with the intent to allow SMECO to meet its RPM obligation, as SMECO claims, or whether the parties contracted for the transfer of any type of capacity from any source without regard to SMECO’s RPM obligation, as JPMVEC argues,” the commission ruled in declining to exercise primary jurisdiction in the case. “The outcome of this matter appears to turn on interpretation of the parties’ intentions and construction of the relevant clauses in the Brandywine PPA rather than any determination requiring our special expertise.”
Commissioner Cheryl LaFleur dissented from the opinion, saying the decision “effectively consigns SMECO to a potentially lengthy and costly court proceeding to resolve what is, in my view, a clear and easily resolved contractual interpretation that is squarely within the commission’s jurisdiction and expertise.”
Not only would she have supported exercising primary jurisdiction in the matter, she said, she would “find that the parties’ contract requires JPMVEC to provide SMECO with capacity credits to meet SMECO’s obligations under the RPM.”
In addition, LaFleur said, FERC erred by “failing to frame the dispute between these two parties in the proper context of the broader transition underway in the PJM capacity market.”
She urged the commission to exercise primary jurisdiction over future Capacity Performance issues to ensure consistent interpretation of common contractual language and avoid the unintended undermining of Capacity Performance reforms.
ISO-NE will issue more than $20 million in refunds to capacity resources that were prevented from reducing their offers in Connecticut for reliability reasons in the 2008 Forward Capacity Auction under an order issued by FERC last week (ER08-633).
Load-serving entities that will have to make additional capacity payments under ISO-NE’s resettlement plan.
Under the RTO’s “proration” rule at the time, the total payment to all listed capacity resources had to equal the clearing price multiplied by the installed capacity requirement. To achieve this, resources could either receive capacity payments lower than the clearing price (price proration) or reduce their capacity supply (quantity proration). All proration, however, was subject to a reliability review.
Public Service Enterprise Group complained that ISO-NE barred it from prorating its capacity supply in Connecticut, forcing the company to offer at a lower price, which the company said cost it $2.8 million. When its protest and rehearing request were denied by FERC, the company sued in federal court. The D.C. Circuit Court of Appeals ruled in favor of PSEG and remanded the case back to the commission.
Last year, FERC reversed its decision, saying, “We now find that where resources needed for reliability were prohibited from prorating quantity under the proration rule, they should have received the full market clearing price for each megawatt offered.” It ordered ISO-NE to provide a plan for resettlement.
The RTO reported that 5,870 MW would have been prorated had plants been allowed to. The clearing price for FCA 1, conducted in February 2008, was $4.50/kW-month. To determine how much each plant would be owed, ISO-NE took the difference between the clearing price and the prorated price, $4.254/kW-month, converted it to megawatt-years and multiplied it by 5,870. The result was about $17.3 million in refunds, plus about $3.1 million in interest. The RTO said it would recalculate the interest owed upon FERC’s order, so the final amount refunded to companies will be higher.
“We find the resettlements … appropriate to ensure that PSEG and other Connecticut resources that were not able to prorate quantity be paid the full capacity clearing price for each of the megawatts that cleared FCA 1,” the commission said.
Eversource Energy, which was Northeast Utilities at the time of the auction, will pay the bulk of the refunds, at almost $15.6 million. UIL Holdings, now part of Avangrid, will pay about $3.8 million.
A coalition of generators led by American Electric Power and FirstEnergy last week responded to PJM’s analysis of resource investment in competitive markets, saying it presents a skewed view of the risks and benefits of such constructs compared with the traditional regulated model.
Kyger Creek Power Plant
Joining AEP and FirstEnergy in a May 19 letter to the Board of Managers were Dayton Power and Light, Duke Energy Ohio and Kentucky, Buckeye Power and East Kentucky Power Cooperative.
The study was commissioned by the board after AEP and FirstEnergy asked Ohio regulators, and Exelon asked Illinois legislators, for financial aid to support money-losing generators.
The generators said PJM’s paper fails to point out that competitive markets have achieved their benefits because of legacy generation and transmission assets that were built under the regulated utility model, noting that PJM had a reserve margin of more than 20% when it began the capacity market in 2007.
“The paper presents a case in which nuclear and coal baseload resources that do not clear the capacity market for a given delivery year should not have been built. It is naive to think that a future driven by marginal resources through short-term capacity markets can adequately serve customers,” the letter said.
“The [Reliability Pricing Model] construct has never provided long-term price support for investments in long-life assets,” it said. “As a result, a significant amount of generation [in western PJM] has, or is seeking, some type of retail rate support.” (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
The signatories represent 44,000 MW of capacity in the RTO and serve more than 11 million consumers with about 69,000 MW of load. They note that 30% of the capacity in PJM comes from suppliers who operate under a traditional regulatory model.
“We strongly urge the PJM board to recognize that there is a place within PJM for generation supported by the market and by traditional cost-of-service regulation,” the letter said.
The companies said there were several major weaknesses in the PJM report:
Risks to the consumer. PJM’s contention that customers face less risk in a deregulated model is “a short-term view,” the letter said, and is greatly influenced by recent decreases in the price of gas. “In contrast, the regulated paradigm inherently takes a long-term view of investments necessary to maintain proper fuel diversity, plant type diversity, transmission needs and reliability, which results in reduced market volatility and consumer benefits.”
Value proposition of an integrated utility model. Regulated utilities have a legal long-term commitment to serve customers, the letter said, whereas merchant generation can close up shop if they don’t receive the desired return. “PJM does not account for any necessary transmission investment associated with premature retirement of baseload generation,” it said. “Integrated resource plans holistically consider these costs as well as societal and policy objectives. … Customers pay for the cost of new transmission, which often can exceed the costs of keeping a unit online.”
Innovation. “PJM’s market rules and its stakeholder process result in a sluggish response to change,” the letter said, citing what it called “the inability of the markets to accommodate variables such as changing fuel mixes and resource adequacy as a result of environmental policies.”
New investment. The writers contend that market signals have not attracted new technology, and that renewable generation largely relies on bilateral arrangements or government subsidies. They say the capacity market’s one-year clearing price, three years in advance, results in increased price volatility and higher consumer costs.
Fuel diversity. “PJM’s position that legislators and policymakers should solve the issue of diversity contradicts PJM’s overall premise that any market outcome is superior to regulation,” the letter said.
In closing, the writers note that PJM said its paper was “intended as the beginning of a dialogue on resource investment.”
“We are ready to engage in a fact-based discussion of the risks and benefits associated with different market and regulatory paradigms,” they said, urging PJM to “focus on a market design that accounts for transmission costs, ensures both robust competition and adequate compensation for diverse capacity resources and respects the roles and responsibilities of the states in providing a comprehensive approach to least-cost reliability for consumers.”
Former Public Utilities Commission of Ohio Chairman Andre Porter is crossing state lines to become MISO’s general counsel.
Porter
He will replace Stephen Kozey, who will continue in his other roles overseeing compliance services and serving as secretary to the board. Kozey, the RTO’s first general counsel, will be able to devote more time to remaining responsibilities and advise Porter as he takes on the role, according to MISO.
Porter will begin work at MISO’s Carmel, Ind., headquarters on June 27.
Porter said he did not seek nor consider positions with other RTOs. “MISO is the only place for me. It’s the opportunity of a lifetime … and an exciting one.”
MISO spokesperson Andy Schonert said bringing Porter into MISO involved an “ongoing conversation” between Porter and the RTO, while Porter said he was able to develop a longstanding relationship with MISO from his work in PJM. “I’ve always followed MISO and admired MISO’s transparency. I’m hopeful that I can add to what is already a spectacular team,” he said.
MISO CEO John Bear said Porter’s expertise is “a great match” for the RTO.
“Andre’s background spans a broad spectrum of the energy industry, and he has extensive experience working with commissions and FERC,” Bear said.
Porter holds a bachelor’s degree in political science from Capital University and a law degree from The Ohio State University Moritz College of Law.
Porter worked as an energy, public utilities and real estate taxation attorney before serving as a PUCO commissioner from 2011–2013.
Before returning to PUCO as chairman, Porter led the Ohio Department of Commerce.
Porter resigned from PUCO late last month, just over a year after taking the position and less than a month after PUCO unanimously approved controversial, eight-year power purchase agreements for FirstEnergy and American Electric Power. Porter’s term wasn’t slated to expire until April 2020. (See PUCO’s Porter Submits Resignation.)
The PPAs guarantee the utilities’ merchant generators receive revenue streams above current market prices to shield them from cheaper natural gas generation. The companies asked PUCO to cancel the agreements after FERC ruled that they would need to be reviewed under the commission’s affiliate abuse test. (See PUCO Grants FirstEnergy Rehearing on PPA; Opponents File Protests.) FERC said last month that in spite of Ohio’s retail choice law, the companies’ ratepayers were effectively “captive” customers because the PPAs impose non-bypassable distribution charges.
Critics contend the PPAs, which weren’t subject to competition, could impose billions in extra costs on consumers and equate to coal bailouts. FirstEnergy and AEP maintain the PPAs are essential in keeping their struggling Ohio coal plants operational, and AEP CEO Nick Akins said the company intends to lobby Ohio legislators to reregulate the deregulated Ohio power market or sell all its generation in the state before it consents to submitting its PPA for FERC review.
Porter declined to say whether he was brought back to PUCO to complete the AEP/FirstEnergy agreements.
“I came back to the commission because there were challenges, and I’m the kind of guy that seeks out challenges. It was just really about coming back to a place where I could help. I certainly appreciated my time working with the utilities of Ohio.”
Porter also declined to answer questions on what he thought of the status of the deals now and if AEP could run a successful bid for reregulation in Ohio, citing FERC’s ongoing review and his new commitment to MISO.
“Right now I’m squarely focused on MISO,” Porter said.
Gov. John Kasich named PUCO Vice Chair Asim Haque to replace Porter, making Haque the fourth PUCO chairman in four years.
“I enjoyed my time at PUCO, and I’m forever grateful to Gov. Kasich for the opportunity. I think my successor, Mr. Haque, is more than capable; he’s going to lead with clarity, and the state of Ohio will be well served,” Porter said.
The Public Utility Commission of Texas on Thursday rejected all motions for rehearing in Hunt Consolidated’s proposed acquisition of Oncor, effectively closing the books on a deal thought to be key to Energy Future Holdings’ emergence from bankruptcy (Docket No. 45188).
The commission’s unanimous vote allowed its March 24 order conditionally approving the acquisition to stand. Because the Hunt group has said it couldn’t complete the deal as approved, that means the order will “evaporate,” as Commissioner Ken Anderson put it.
The Hunt group and other EFH creditors had filed a request May 18 asking the commission to vacate the order and dismiss the proceeding, which would have left open the possibility of a new application.
Commission Chair Donna Nelson said she was joining her two fellow commissioners in denying the motions “solely in the interest of allowing us to be done with this today.”
“Time is of the essence in this case,” she said, “which is funny because of how it’s dragged along.”
The Hunt group asked the commission in September for approval to acquire Oncor, the largest transmission company in Texas, for almost $20 billion. In March, the commission approved Hunt’s proposal to split Oncor into two companies, one of which would operate as a real estate investment trust (REIT). (See Texas Commission Approves Oncor REIT Structure.)
However, the PUC attached conditions to the approval that included sharing the REIT’s tax savings with Oncor customers, which EFH creditors found unacceptable. EFH filed a new Chapter 11 reorganization plan May 1, saying it would be unable to complete the Oncor acquisition as it tries to eliminate $42 billion in debt. (See EFH Files New Chapter 11 Plan; Oncor-Hunt Deal in Doubt.)
Richard Nolan, an attorney for the Hunt group, said his parties had concluded May 17 that if they were to pursue a new transaction, “it will require a new application.”
“From our perspective … it would be more helpful to clear the decks and make a fresh start,” Nolan said. He said the original proceeding became moot when the acquisition was terminated.
He received no argument from intervenors and PUC staff, who all agreed with denying the rehearing request.
“I don’t want to go through another proceeding where we end up with major stumbling blocks,” Anderson said. “ERCOT, and the Texas power market, will benefit from getting this matter resolved.”
The Hunt group said it will continue to work with stakeholders on a plan that meets its goal of keeping Oncor under management control by Texans. “The commission’s actions today now allow all parties to engage in conversations about next steps,” Hunt spokesperson Jeanne Phillips said in a statement.
While Phillips, Anderson and others have expressed a strong desire that Oncor remain under in-state control, Florida-based NextEra Energy reportedly remains a suitor. The company made its own bid for Oncor last year, only to be outflanked by the Hunt group.
Anderson said that with the proceeding behind the commission, it can now take a more assertive role in EFH’s bankruptcy case in Delaware.
“We’ve generally been pretty passive up until now,” he said.
Under EFH’s new bankruptcy exit plan, it would again be broken up into two parts (Oncor and the competitive Luminant and TXU Energy businesses), with noteholders potentially being able to grab Oncor. EFH has asked the bankruptcy court to hold a hearing on the plan Aug. 1.
The state’s Site Evaluation Committee, following guidelines in state law, originally thought it would wrap up its review by the end of the year. (See 
Moody’s Investors Service took a dim view of a Public Utilities Commission decision to reopen a 2014 agreement that shouldered ratepayers with most of the multibillion-dollar shutdown costs of the San Onofre nuclear plant.
The chair of the Senate Energy and Public Utilities Committee said Thursday that it’s unlikely Exelon’s “Next Generation Power Plan,” which would extend state clean power subsidies to nuclear plants, will come to the floor before the legislative session ends May 31.
The amount of employed coal miners in the state has hit a nearly 120-year low, according to a report released this month from the Energy and Environment Cabinet. About 6,900 coal miners are working in the state, the lowest number recorded since 1898.
The proposed 26-turbine Somerset Wind project in the Misery Ridge area won’t be affected by a change in zoning regulations that allow communities to opt out of a fast-track wind development zone, according to the project’s developer.
Jersey Central Power & Light is reviving plans to build a 10-mile 230-kV transmission line in Monmouth County, a project that was canceled 25 years ago after local protests.
NYISO said a total of 41,874 MW of supply is available to meet summer power demand in the state, well above its forecasted peak demand of 33,360 MW.
The Public Service Commission created the state’s first-ever Energy Affordability Policy to provide $248 million in direct relief to low-income residents.
State environmental authorities ruled that Duke Energy must excavate all of its coal ash dumps and ponds, which the utility says would “significantly increase” its estimated $4 billion in coal ash remediation costs. But the regulators said they may later change the ruling to allow the company to make improvements to the storage areas instead.
A House committee last week defeated a bill that would have begun phasing out the state’s zero-emissions tax credit for the wind industry at the end of 2017 rather than 2020.
The Independent Regulatory Review Commission last week rejected a proposal from the Public Utility Commission that would have curtailed net metering at 200% of a customer’s annual consumption.
