Exelon is encouraged by Energy Secretary Rick Perry’s order to study if government regulations and policies are forcing baseload power plants into early retirement and thinks courts will uphold the programs that provide zero-emission credits benefiting its nuclear power plants, executives said during the company’s first-quarter earnings call Wednesday.
The executives also said Exelon’s bids in PJM’s upcoming capacity auctions will reflect the economic needs of its plants, even if that leads to some of its plants not clearing the auction.
Exelon CEO Christopher Crane said Pepco Holdings Inc., which the company acquired a year ago, has only rate cases in D.C. left from its first planned cycle of rate filings under Exelon and has started the second cycle at its Maryland and Atlantic City Electric subsidiaries.
Crane also said Exelon is not concerned that the bankruptcy of Westinghouse, which is one of the suppliers of fuel for its nuclear plants, will impact its ability to get fuel for the plants.
“We continue to competitively bid our reactor fuel suppliers … and we move that around based off of pricing,” Crane said.
Exelon’s first-quarter results exceeded earnings and revenue estimates. Its adjusted operating earnings of 65 cents/share beat the Zacks consensus estimate of 61 cents but were down from 68 cents the year prior. Its net income was $1.07/share, up from 19 cents/share in 2016. The company’s revenue was $8.76 billion, beating the Zacks consensus estimate of $8.48 billion, and up 16.5% from $7.48 billion a year ago.
“We’re off to a great start in 2017,” Crane said.
Crane and Joseph Dominguez, Exelon’s executive vice president of governmental and regulatory affairs and public policy, made positive comments about Perry’s recent memo directing department staff to conduct a 60-day inquiry into “the extent to which continued regulatory burdens, as well as mandates and tax and subsidy policies, are responsible for forcing the premature retirement of baseload power plants.”
The memo has been interpreted by foes of coal-fired and nuclear power plants as an attempt to find reasons for the department to support both.
Exelon has the nation’s largest nuclear generation fleet and its plants have faced pricing pressure from cheap natural gas and the plunging costs of utility-scale solar arrays and wind farms.
“Energy Secretary Perry’s recent directive to look at the importance of preserving baseload generation is early but encouraging,” Crane said. “We appreciate the secretary’s focus to promote needed market reforms to compensate these assets.”
Exelon has argued that its nuclear plants need to be compensated for their ability to provide emissions-free power, and New York and Illinois have established zero-emissions credits to do that. The programs have been challenged by other power providers and some environmental groups, although other environmental groups have backed them.
On March 31, Exelon assumed ownership and management of operations of the James A. FitzPatrick Nuclear Power Plant in Scriba, New York, which is eligible for zero-emission credits. | Entergy
Crane said a New York federal judge heard oral arguments March 29 on Exelon’s motion to dismiss a lawsuit challenging ZECs. “We made strong arguments at this hearing and believe the law is clearly on our side,” Crane said. (See Federal Suit Challenges NY Nuclear Subsidies.)
The judge has not said when he would rule on the motion, Crane said, and that if Exelon prevails, it expects its opponents to appeal the judge’s decision. If it doesn’t prevail, he said, it will proceed with the case.
In Illinois, two groups of plaintiffs have challenged the ZECs in federal court. The cases have been combined before one judge, who has delayed action on a motion for a preliminary injunction against the ZECs while he receives a full briefing on Exelon’s motion to dismiss the cases. (See IPPs File Challenge to Illinois Nuclear Subsidies.)
Crane said the briefing will be completed by May 15 and the judge is scheduled to let the parties know his intention concerning the cases on May 22.
Exelon began recognizing ZEC revenues in New York on April 1, Crane said. In Illinois, he said, it has filed tariffs to begin collecting the ZEC payments on June 1 but doesn’t expect the actual procurement process to conclude until fall.
The earnings call came the day after the conclusion of a two-day technical conference at which independent power producers asked FERC to take action to prevent the ZECs from undermining the NYISO and PJM markets. (See related story, NYISO See Carbon Adder as Way to Link ZECs to Markets.)
Crane said he expects clearing prices in the upcoming PJM capacity auction to “come down to bidding behavior.”
“You have seen us bid our assets in recent auctions to reflect the underlying economic needs of the individual plants, which in turn has led to some of our plants not clear[ing]. You should expect us to bid our assets in the same responsible fashion in this next upcoming auction.”
Exelon expects a ruling on Pepco’s D.C. rate case in July, CFO Jonathan Thayer said. It expects rulings in the Maryland and Atlantic City Electric cases in the fourth quarter of 2017 and the first quarter of 2018, respectively, Thayer said.
WASHINGTON — More than 50 stakeholders from PJM, NYISO and ISO-NE made their cases to FERC last week on how to resolve the increasing conflicts between state energy policies and wholesale markets.
Many of those who testified also had appeared at the commission’s September 2013 technical conference, which was billed by then-Commissioner Tony Clark as a “check-up” on the capacity markets six years after the inception of PJM’s Reliability Pricing Model. Participants at that time differed on the health of the markets and whether major changes were needed. (See Old Issues, New Technologies in Capacity Debate.)
Last week, however, virtually everyone was calling for change — the disagreements being over how much, how fast, what kind and whether it should be directed by FERC or come from stakeholders.
The diagnosis: The patient is running a fever and will only get worse without treatment.
“The challenge before the commission, the states and all other stakeholders is no less than the question of whether the power industry will continue to use competitive markets as the basis for investment decision-making,” Peter Fuller, vice president of market and regulatory affairs for NRG Energy, said in his written testimony.
“Is there a role for the markets? Absolutely,” said Scott Weiner, deputy for markets and innovation at the New York State Department of Public Service. “The energy markets will always be there. The capacity market may not be.”
FERC scheduled the conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).
“There are three ways this could go,” acting FERC Chair Cheryl LaFleur said at the opening of the two-day conference May 1. “A designed market solution, a litigated outcome or a planned change in the regulatory construct of how we handle resource adequacy. The fourth outcome — an unplanned change in the regulatory construct — or unplanned and piecemeal regulation, is one that I think we should avoid because I think it would be a bad outcome for customers and market participants in terms of cost, reliability and regulatory certainty.”
“All options, in my mind, are on the table,” added Commissioner Colette Honorable.
Factions
The witnesses fell into several camps.
Public power representatives said they should be relieved of participation in the capacity markets, which they say are too expensive and inflexible. Unlike in 2013, they had lots of company in calling for change.
Independent power producers called for FERC to act decisively to protect markets from out-of-market contracts and subsidies.
The grid operators differed on their preferred role for FERC, with PJM and NYISO urging the commission to set deadlines and provide direction.
Officials from New England said they will continue to pursue their states’ clean energy mandates with or without cooperation from the wholesale markets.
Carbon Adder
Economists have been telling FERC and others for years that the simplest way to reconcile the markets with environmental policies is to incorporate the cost of carbon into LMPs and generation dispatch. While New York and PJM are exploring ways to do so, New England policymakers said differences in state policy goals make it politically unpalatable despite its economic elegance.
IPPS: FERC Should Act Decisively Against Subsidies
Independent power producers NRG, Calpine, Dynegy and Eastern Generation, and their trade group, the Electric Power Supply Association, called for FERC to act quickly and firmly.
“A policy approach that lets any given action prevail at all costs in the name of a ‘state preference’ regardless of the detrimental impact on federally regulated wholesale markets would be the exception that swallows the rule of law in the” Federal Power Act, EPSA CEO John Shelk said. “If the commission wishes to continue delivering the benefits of wholesale markets, it needs to direct steps be taken by the Eastern ISOs/RTOs by specific deadlines to ensure that wholesale markets are protected and not undermined.”
FERC’s “hands-off approach” to date “rightly allowed states to experiment on the edges of the wholesale market with a variety of new programs and to avoid over-burdening these fledgling initiatives with federal intervention,” said Abe Silverman, vice president and deputy general counsel at NRG.
Now, however, the commission must develop “rule-of-reason” tests “to delineate how state programs are harmonized with competitive markets,” he said. “Wherever the line is eventually drawn, there clearly must be a line if the Federal Power Act is to have meaning.”
Calpine CEO Thad Hill also called for swift action.
“The legal process is lengthy, and it will take the courts considerable time to work through these issues. The commission should not wait for the courts to act, but instead the commission should be prepared to act quickly and decisively when viable proposals are brought before it,” he said.
Joining the IPPs in calling for action was Seth Kaplan, EDP Renewables’ senior manager for regional government affairs, who cited the D.C. Circuit Court of Appeals’ April ruling in Emera Maine v. FERC. That ruling upheld FERC’s Order 1000 finding that FERC-regulated transmission planning must accommodate state public-policy requirements. (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)
“The Emera decision reaffirms once again that FERC and the entities it regulates have the ability — and I would argue obligation — to recognize state policies, like renewable portfolio standards and procurements, as cost drivers that must be recognized in the transmission planning and cost-allocation process,” Kaplan said.
Aleksandar Mitreski, senior director of regulatory affairs for Brookfield Renewable, agreed, saying “the time is ripe for public-policy objectives to be incorporated into the wholesale markets.”
Independent consultant Roy Shanker said FERC must take a leadership role because stakeholder negotiations will not prevent litigation. “The fundamental differences among parties … make any cooperative solutions unlikely,” he said. “In the presence of such fundamental differences, any path forward requires the commission to exercise its full authority over wholesale markets in order to find a resolution that does not cannibalize markets.”
New England: Butt Out, FERC
State officials from New England were equally forceful in saying they don’t want FERC interfering with ongoing stakeholder processes.
“Our work with the National Council [on Electricity Policy] supports the idea that states are well suited to collaboratively working out answers to the policy questions addressed by this technical conference,” said Vermont Public Service Board Commissioner Sarah Hofmann, a member of the NCEP’s executive committee.
“The New England states have shown the ability to work collaboratively to address climate change through [the Regional Greenhouse Gas Initiative], which is a program under state control,” New Hampshire Public Utilities Commissioner Robert Scott said. “Addressing carbon emissions through a federally controlled tariff based on state policies raises significant concerns not only about the potential for unreasonable allocation of costs but also states’ rights. If the federal government wishes to regulate carbon emissions in the wholesale electric sector, Congress should pass a law giving the appropriate agency such authority.”
The Beginning of the End of RPM?
Public power representatives reiterated their longstanding complaints about mandatory capacity markets, saying they could provide resource adequacy more cheaply through bilateral contracting and self-supply.
Lisa McAlister, general counsel for regulatory affairs at American Municipal Power, said FERC should eliminate the mandatory participation requirement in PJM’s capacity market. “RPM is a ‘market’ in name only, and, as time has gone on, fewer and fewer PJM market participants use that term to describe it,” she said.
“With respect to meeting adequacy needs, the markets have been a success,” said Cliff Hamal, managing director at Navigant Economics, who has consulted for AMP in PJM’s new capacity initiative. (See PJM Capacity Task Force Debates the Value of Price Transparency.) “With respect to doing so at a reasonable cost to consumers and consistent with meeting other legitimate policy goals, I think we can do better.”
Hamal said the capacity market’s cost of capital is increased by a “volatile, fickle and frail price mechanism that relies more on regulatory nurturing than the fundamentals of supply and demand.”
While RTOs should continue to set capacity obligations for load-serving entities, Hamal said, the LSEs should be allowed to meet their obligations independently.
“I believe the most promising option would be to allow state policies to be implemented through a formal commitment to bilateral markets. States would withdraw from the RTO centralized auctions and meet their capacity objectives bilaterally,” he said. “Energy markets will continue to function and capacity markets will return to providing the ‘missing money’ in the sense of a supplemental payment needed to ensure supply adequacy after consideration of all other revenue streams.”
Deadlines for Stakeholder Processes
Silverman said the commission should “direct each of its ISO/RTO markets to set forth a comprehensive plan to integrate state goals into its wholesale market outcomes in a sustainable manner. Unless the commission mandates such a process — by a date certain — I fear that states will continue to pursue carbon mandates outside of the organized markets, and society will be deprived of the benefits of competitive markets.”
PJM and NYISO officials said they would welcome FERC deadlines to pressure stakeholders to compromise on rules for incorporating state initiatives into the markets.
“We don’t want to run a 50% market. … We want to be the market that all resources depend on … for entry decisions, and we will work with the state to achieve those goals,” said Rana Mukerji, senior vice president of market structure for NYISO. “The stakeholder process … is long and contentious. Having deadlines works miracles.”
“Yes, there are compromises that come out [of the stakeholder process]. Yes, they can lead to maybe suboptimal … approaches,” said PJM Senior Vice President for Operations and Markets Stu Bresler. “But I can say without reservation [that] almost universally what comes out of a detailed stakeholder vetting of an issue is better than what went into it.
He added: “Deadlines and guidance from the commission are always helpful with respect to the efficiency of how that stakeholder process works.”
ISO-NE and the New England Power Pool, however, urged FERC to give them breathing room. Matt White, chief economist for ISO-NE, said the RTO will file a proposal with FERC by late this year or early 2018.
“The house is not burning down so fast that we must make an exigent circumstances filing with you within a week,” he said. “Coming up with something we can do and you will not be tweaking it again and again and again and again is probably worth six to nine months of our time.
“We have a very active stakeholder process that is deeply engaged on these issues,” he continued. “A deadline would not be terribly helpful.”
Not everyone saw the value of stakeholders’ participation, however.
“FERC should immediately begin a formal inquiry to rationalize the capacity and energy market constructs with the long-term financial needs of different operational categories of electric generation,” said John P. Hughes, CEO of the Electricity Consumers Resource Council, which represents large U.S. manufacturers. “We strongly oppose any attempt to solve this problem via negotiated settlements in ISO or RTO stakeholder processes.”
Now What?
The “crossroads” for the markets, as multiple speakers called it, comes at a time when FERC has never been less prepared to act. With three empty seats, it has been without a quorum since February; Honorable announced last month that she won’t seek a new term when hers expires in June.
So, as the participants wheeled their suitcases to cabs outside FERC headquarters at the end of the two-day hearing, the commission’s policy direction could hardly be more uncertain.
With President Trump — who has moved to dismantle his predecessor’s climate change policies — in a position to fill four of the five seats, at least some of the new members could be hostile to Northeast states’ climate policies. At press time, there were numerous reports that Trump will nominate Pennsylvania regulator Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) to fill two Republican vacancies on FERC. Chatterjee was described in a Bloomberg profile as “the McConnell adviser determined to stop the Clean Power Plan.” (See related story, Trump Nominates Republicans Powelson, Chatterjee to FERC.)
Even if the commission did support an RTO-administered carbon adder, would it have the authority to do so?
Certainly someone will ask the courts that question.
VALLEY FORGE, Pa. — PJM’s proposed problem statement and issue charge on whether states can control energy-efficiency participation in the capacity market drew heated debate on two issues — one expected and the other not — at last week’s Market Implementation Committee meeting.
Because of the ongoing debate, a vote on endorsing the proposal was delayed until next month with one objection and one abstention.
The proposal was developed in response to a current proceeding before the Kentucky Public Service Commission on energy-efficiency requirements, said Denise Foster, PJM’s vice president of state and member services. PJM’s rules on load-modifying resources offering into the market, such as demand response, don’t address whether energy efficiency should be treated the same as DR, so the RTO is considering how and whether to add it.
However, PJM is specifically limiting the scope to avoid discussing whether state jurisdiction factors into the discussion, despite stakeholder suggestions to include it. The issue charge would establish requirements for energy efficiency entering the market, rules around those requirements and how to handle energy-efficiency resources that have already cleared past capacity auctions.
Tom Rutigliano, representing Electric Market Connection, expressed concern that the proposal would ostensibly grant state regulators new power to restrict energy efficiency participation in wholesale markets. He pointed to the Supreme Court case EPSA v. FERC as confirming that FERC has jurisdiction over retail customer participation in the wholesale markets.
“We appreciate that Kentucky may have claims, but we feel at this point, it’s not really appropriate to put PJM and its stakeholders in the position of deciding if those jurisdictional claims are correct or not,” he said. “This is really not at this point a stakeholder issue.”
His concerns were echoed by Rick Drom, an attorney with Eckert Seamans Cherin & Mellott, who offered a presentation titled “A Flawed Solution Seeking a Problem.” He said any discussion on PJM deferring to state regulatory authorities is premature and that the proposal risks balkanization of the energy market.
Drom’s arguments, however, were overshadowed by his unwillingness to name whom he represented at the meeting. He said his client, whom he said is one of the largest energy efficiency providers in the PJM footprint and operates in Kentucky, fears reprisal from opponents. Drom said he met with senior PJM staff to explain the situation, and they agreed to let him speak without naming his client.
Bruce Campbell of CPower noted that Eastern Kentucky Power Cooperative is seeking a declaration from the Kentucky PSC that the utility has the authority to “terminate electric service to any energy-efficient resource provider who violates Kentucky law, a commission order, rule or regulation or commission-approved tariff.” Drom acknowledged that was part of his client’s desire to keep its name hidden.
When Drom refused to identify whom he represented, Calpine’s David “Scarp” Scarpignato requested a point of order, citing Manual 34 rules that require speakers to identify whom they represent. Other stakeholders supported the request, noting that it would create a bad precedent.
Chantal Hendrzak, the chair of the MIC, called a short recess for Drom to explain the situation to Scarp. Scarp maintained his request, which led Hendrzak to acknowledge that PJM would take greater care considering similar requests in the future.
DR Open Registration Under Consideration
PJM is considering changes to when DR can be registered. Currently, all registration must be completed prior to the beginning of the delivery year, so new customers who wish to enter after June 1 are barred from participating and those who leave can’t find new customers to take over their responsibility.
The RTO is offering three options. The first would move the deadline to Dec. 1. The second would have no registration deadline. The third would also have no deadline but would require registered DR to test prior to the delivery year and new registrations to test on the first active day. All three would allow for the daily deficiency penalty to change daily, and the test commitment would change from the daily average during summer period to daily average for delivery year. The third solution, proposed by the Independent Market Monitor, would instead use the peak commitment day for the delivery year.
Stakeholders who don’t handle DR asked if there was a strong preference among stakeholders who do regarding which option they supported. Bruce Campbell of CPower said he generally supported the second option. A stakeholder poll produced identical support of 51% for the first and second options and minimal support for the third one. However, there was greater support (69%) for the status quo.
WASHINGTON — If the economists who testified at FERC’s technical conference last week agreed on nothing else, it is that a carbon adder is the simplest way for the power markets to value emission-free generation.
New York is going to try and translate the theory into practice as a way of addressing the impact of the state’s zero-emission credits (ZECs) for its upstate nuclear plants, officials told FERC.
On the first day of the two-day conference (AD17-11), state and NYISO officials asked FERC for time to develop their plan even as merchant generators called for immediate action to block the subsidies or respond to their effects on the wholesale markets.
The ZECs are part of New York’s Clean Energy Standard, which mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. The CES also calls for renewables to meet 50% of the state’s energy needs by 2030.
The subsidies will support Exelon’s two-unit Nine Mile Point, and the single-unit R.E. Ginna and James A. FitzPatrick plants for more than 12 years at a cost estimated as high as $7.6 billion. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.) At a legislative hearing into the ZEC program in Albany on May 1, however, New York Public Service Commission interim Chair Gregg Sayre said he expects the actual cost may be much less, perhaps as low as $2.86 billion.
NYISO CEO Brad Jones told FERC that while the ISO supports the ZEC program, it wants to find a way to incorporate the payments into the wholesale market.
The ISO has hired the Brattle Group to develop a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. Generating units that emit carbon would incur a penalty based on their level of carbon emissions; the penalties collected by the ISO would be “returned to customers in some equitable manner.”
Jones said the project was in its “initial stages” and that implementation could take three years.
That is too long for other stakeholders.
“I was shocked to hear [Jones] say yesterday that he doesn’t think the rates are just and reasonable but we have three years to work out a solution,” said Abe Silverman, vice president and deputy general counsel for NRG Energy. “No, this is something that needs to happen almost immediately.”
John Reese, senior vice president of Eastern Generation, said the issue is particularly acute in New York, which has a one-year forward capacity auction, unlike the three-year auctions in PJM and ISO-NE. Eastern Generation operates almost 5,000 MW of generation in NYISO and PJM, including 18% of New York City’s capacity.
“I can’t wait for seven years or eight years for this to work out,” he said. “Regardless of which model we end up with, we need to be sending investment signals now!”
The Independent Power Producers of New York argued that the state’s goals and its energy markets have reached a crossroads, saying that out-of-market solutions threaten the ability of the wholesale market to meet system needs at the least cost.
“Retail electricity customers are required to pay for renewable energy credits to support new large-scale renewable resources, as well as zero-emissions credits to support nuclear facilities which might otherwise retire from the market — both of which are out-of-market valuations for environmental attributes,” IPPNY CEO Gavin J. Donohue said. “The implementation strategies used to meet those [CES] goals conflict with the competitive market principles that have produced unparalleled reliability and record-low electricity prices.”
The NYISO discussion focused on several questions, some of which will also be central to challenges to the ZECs in court and before FERC: state vs. federal jurisdiction; the price suppressive impact of ZECs; and the efficacy of saving at-risk nuclear plants versus replacing them with renewables.
Dynegy, Eastern Generation, NRG and the Electric Power Supply Association filed a federal court suit in October claiming the ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The suit asks the court to find the ZECs invalid and order them withdrawn from the CES. (See Federal Suit Challenges NY Nuclear Subsidies.)
The same companies filed suit in February challenging Illinois’ ZECs for Exelon’s Quad Cities and Clinton nuclear plants and have also asked FERC to reject the subsidies (EL16-49). (See IPPs File Challenge to Illinois Nuclear Subsidies.)
Do ZECs Interfere with the Wholesale Markets?
The Supreme Court has attempted to draw the lines between state and federal jurisdiction over the power industry in a series of rulings, most recently the January 2016 ruling in EPSA v. FERC, in which the court upheld FERC’s jurisdiction over demand response, and the April 2016 order in Hughes v. Talen, which rejected Maryland’s subsidy of a generator that could have undermined PJM’s capacity auction.
New York regulators took pains to ensure the ZEC program complied with the court’s advice in the latter case. “Nothing in this opinion should be read to foreclose Maryland and other states from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation,’” the court said.
Scott A. Weiner, deputy for markets and innovation at the New York State Department of Public Service, made an impassioned defense of the ZEC program, saying it was permitted by states’ “settled jurisdiction over environmental policy, resource adequacy, fuel diversity and reliability.”
“Rather than opening this discussion with the question of how state policies can be implemented through federally regulated wholesale markets, we should ask, ‘should they?’ An attempt to select resources through the federally regulated wholesale markets to achieve individual state policies may undermine, even if unintentionally, those very state programs,” he said. “By incorporating state policy into the wholesale markets, the state would have to seek a tariff change to reform its own policy.
“This changing role of the state’s utilities must be harmonized by federal and state regulators acting in respectful collaboration without one seeking to subsume the other.”
Rather than attempting to “absorb” state policies into the federal wholesale markets, Weiner said, FERC should consider removing barriers to new entry by state-supported resources by eliminating buyer-side mitigation.
“It is essential to recognize that policies addressing legitimate state interests may have incidental impacts on wholesale market prices without raising the specter of price suppression or undermining markets.”
NY, Exelon: ZECs not Intended to Suppress Prices
“New York, like other states, does not seek to suppress wholesale market prices. Ending application of this false assumption eliminates the need for market rules based on that presumption,” Weiner said.
Exelon also insisted that ZECs are not vehicles for price suppression, comparing them to the renewable energy credits (RECs) issued in support of state renewable portfolio standards.
“Buyer-side mitigation rules are aimed at large buyers seeking to suppress market prices by introducing new, uneconomic supply. But environmental programs like ZEC programs do not fit that description,” Exelon said. “First, in ZEC and REC programs, the state is purchasing a separate environmental attribute, so ZECs and RECs are not tied to energy or capacity sales.”
Impact, not Intent, is What Matters
Others counter, however, that it is the impact of state policies on prices — not policymakers’ intent — that is at issue.
David Patton, president of Potomac Economics, which provides market monitoring in NYISO and ISO-NE, said nuclear subsidies can be much more damaging to wholesale price formation than renewable subsidies because solar and land-based wind have low capacity values.
Former FERC Commissioner Tony Clark, now a senior adviser at Wilkinson Barker Knauer, said at a conference in March that while FERC hasn’t seen harm to the markets from state REC programs, the scale of the nuclear generation covered by subsidies — 20% or more of the market in some regions — may make them more vulnerable. (See Ott Seeks ‘Resilience’; Clark Handicaps ZECs.)
And even renewables are having a significant impact on prices, Lawrence Makovich, chief power strategist for IHS Markit, told FERC.
He presented analysis that he said demonstrated that wind output suppressed PJM prices by about 24% during the top net load hours in 2015, when peaking units were setting the price. Wind suppressed prices by 4% when net loads were average and by about 9% during minimum load, he said.
“On the cost side, compensating for the impact of wind … [caused] load-following generators to increase output ramping and starts and stops, causing less production efficiency and higher [operating and maintenance] costs,” he said.
Is Preserving Nukes the Best Policy Choice?
Exelon says ZECs are justified because it would take too long and be too costly to replace the zero-emission capacity of at-risk nuclear plants versus renewables. “When a nuclear facility retires, it cannot feasibly be replaced by renewable generation in the time necessary to avoid a spike in emissions. Instead, it will be replaced predominantly by fossil fuel-fired plants emitting significant carbon and other air pollution,” Exelon said.
The company cited Germany’s retirement of its nuclear fleet following the 2011 Fukushima nuclear accident, which resulted in “a massive increase in emissions despite investing in new renewable generation to such a degree that its electricity rates are now among the world’s highest.”
Similarly, the closure of the San Onofre nuclear plant in early 2012 “resulted in an increase in emissions that more than offset all of California’s investment to date in wind, solar and biomass generation,” Exelon said.
New York concluded replacing its nuclear fleet would require that it triple its energy-efficiency targets or construct 9,000 MW of onshore wind or 22,000 MW of solar.
NRG’s Silverman, however, said New York chose an expensive path.
“For $3.5 billion — or approximately half the price of the bailout in New York — the state could have purchased enough renewables to replace the output of all of its at-risk nuclear fleet with 100% new renewable power. Additionally, New York’s Independent Market Monitor found that a new combined cycle on Long Island is a far cheaper means of reducing carbon in New York than the nuclear bailout.”
The impact of state mandates on load-serving entities was the key concern of James Holodak Jr., vice president of regulatory strategy and integrated analytics for National Grid, which owns LSEs in New York and New England.
Holodak said National Grid’s Niagara Mohawk Power subsidiary was forced to absorb $2 billion in stranded costs as a result of New York legislation that required utilities to buy electricity from independent power producers for at least 6 cents/kWh, a price higher than utilities’ production cost.
Holodak said the law forced Niagara Mohawk to sign contracts for output in excess of its actual demand and helped increase the utility’s rates by 25% between 1990 and 1995, causing many industrial and commercial customers to seek alternative suppliers or lower-cost locations.
Holodak said New England states with mandates should adopt a structure similar to that in New York in which each LSE is required to purchase the ZECs from the New York State Energy Research and Development Authority while recovering the costs from its customers. “In this instance, NYSERDA acts as the middleman, which advances the state’s policy goals and presents less risk for utilities than under a mandatory contracting model between the generator and the utility,” Holodak said.
He also made a case for allowing utilities to own renewables rather than being required to purchase them.
“Long-term bilateral [power purchase agreements] with developers equate to ‘virtual ownership’ with utilities and their customers absorbing project risks without the benefits of ownership,” he said, acknowledging that support for utility ownership will depend on utilities’ ability to “produce demonstrable customer savings.”
“We further recognize that this position may seem inconsistent with our broader support for market-based solutions where circumstances permit. However, today’s RTO/ISO markets do not adequately incentivize new entry from zero-emitting resources and it is not clear how or when they will evolve to do so.”
FERC’s agenda said the technical conference “may address matters at issue” in the following pending dockets:
ER16-1404 Power Producers of N.Y. v. NYISO re. buyer-side capacity market power mitigation
WASHINGTON — The minimum offer price rule came up frequently at last week’s FERC technical conference exploring tensions between state clean energy policies and RTO/ISO markets in the East, with some witnesses calling for its expansion and others seeking its relaxation or abolition.
Robert Erwin, general counsel of the Maryland Public Service Commission, called on FERC to help states achieve their energy policy goals by simplifying the “unduly complex” capacity market rules and reducing “the chilling effects” of the MOPR on state innovation.
He was one of several MOPR critics who invoked the words of former FERC Chairman Norman Bay to buttress their case. (See Bay Blasts MOPR on Way Out the Door.)
MOPR ‘Cudgel’
“State policy decisions over new generation — previously exempted under the [PJM Reliability Pricing Model] settlement — have become subject to the cudgel of the minimum offer price rule,” Erwin complained. “We believe that the putative threat of state initiatives that the MOPR was devised to counter is overblown. Accordingly, the Maryland commission agrees with former Chairman Bay that the MOPR, as currently utilized, ‘places [FERC] in constant tension with the states’ and inhibits valuable state policies.”
The Sierra Club also quoted Bay’s comments in calling for “curtail[ing]” the use of the MOPR, citing his criticism that “‘MOPR not only frustrates state policy initiatives, but also likely requires load to pay twice — once through the cost of enacting the state policy itself and then through the capacity market.’”
“We agree that it is essential to mitigate actual buyer-side market power, but encourage the commission to undertake a more careful examination of the evidence as to whether buyer-side market power is exercised in capacity or energy markets and develop appropriate screens to be applied whenever a mitigation mechanism is premised upon the existence of such power,” said Mark Kresowik, deputy director of the eastern region of the Sierra Club’s Beyond Coal Campaign. “As former Chairman Bay observed, ‘the commission simply assumes [buyer-side market power] exists. The commission has not explored or tested these assumptions in its orders, and it does not know whether they are true.’”
Angela M. O’Connor, chairman of the Massachusetts Department of Public Utilities, said that in addition to the short- and long-term policies being discussed by stakeholders in the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, “we hope to explore other potential solutions, including a further examination of the minimum offer price rule, which presents a significant challenge to the participation of state-supported resources in the Forward Capacity Market.”
O’Connor (left) and Scott | RTO Insider
“Any IMAPP proposal that substantially increases the amount of clean energy resources entering the FCM will likely involve either the elimination of or modification of the minimum offer price rule,” said New Hampshire Public Utilities Commissioner Robert Scott, who added that his state has not taken a position on any potential changes to the rule. “Such a change in market design should be accomplished in a thoughtful manner and certainly not without a full understanding of the likely long-term implications for electric rates.”
Harvard University’s William Hogan also quoted Bay in urging FERC to minimize the role of the capacity markets.
“In his last comments about the minimum offer price rule, Commissioner Bay summarized: ‘The premise of the MOPR appears to be based on an idealized vision of markets free from the influence of public policies. But such a world does not exist, and it is impossible to mitigate our way to its creation. The fact of the matter is that all energy resources receive federal subsidies, and some resources have received subsidies for decades.’
“The factual premise is well founded. They are myriad subsidies, many beyond the commission’s jurisdiction,” Hogan continued. “It is also true that the commission cannot, by itself, unwind all these subsidies to create the idealized vision of pure markets.”
While the capacity markets exist, however, Hogan said FERC should “strengthen anti-manipulation efforts such as the MOPR.”
“The avowed purpose of capacity markets is to correct for defects in energy pricing. If this is the case, the commission should have no obligation to accommodate subsidized resources that, in effect, make the problem worse. The commission can and should limit access and discriminate against those subsidized resources that are adding to the problem of inadequate pricing in energy markets.”
PJM Independent Market Monitor Joe Bowring and Dynegy CEO Robert Flexon both told FERC it should expand the rule to include existing generation as well as new resources. PJM officials also have called for such an expansion. (See PJM: MOPR Could be Improved, but not by BRA.)
Flexon said FERC should require “adequate minimum bids for all existing and new resources that receive revenue or revenue certainty (e.g. long-term multiyear contracts, ZEC payments) from sources other than the competitive marketplace. All resources, new and existing, should be required to bid at least the level they would have bid if they were being supported solely by the competitive market.”
“The MOPR should be expanded to address subsidies for all existing and proposed units, and this should be done expeditiously,” Bowring said. “An inclusive MOPR is the best means to defend the PJM markets from the threat posed by subsidies intended to forestall retirement of financially distressed assets. The role of subsidies to renewables should also be clearly defined and incorporated in this rule.”
VALLEY FORGE, Pa. — Even as PJM moves into a heavy outage season, its balancing authority area control error limit (BAAL) remains lower than usual, PJM’s Ken Seiler said at last week’s Operating Committee meeting.
PJM’s excursion minutes dropped to 177 in April, from 257 in March and 224 in April 2016. PJM posted a 99.6% BAAL score for April, improving 0.1 percentage point from a year ago and 0.2 percentage points from March. (See “Inconsistent Weather Contributes to Operational Inaccuracies,” PJM Operating Committee Briefs.)
Seiler said generators beyond PJM’s control but that tied into the RTO’s grid are still overgenerating, which is unbalancing the system. The excursions are mostly happening in “the valley period” between 1 and 3:30 a.m., he said, during light-load conditions when generation is mostly baseload units and wind turbines. He said PJM is working with neighboring grid operators to identify the causes of the issues, beyond large temperature swings.
“Our actual numbers are very good, actually,” Seiler said. “But when we look outside, we’re starting to see some excursions outside that are starting to have more of an impact on us.”
With new transient-shortage pricing set to go into effect on May 11, PJM’s Chris Pilong said system operators are being trained in how to best maintain lowest-cost generation, but that operations will largely remain the same.
“It’s an awareness issue,” Pilong said. “We need operators to understand these changes, which they do. They’re prepared for them.”
Calpine’s David “Scarp” Scarpignato, who raised the issue, said he agrees with the way PJM is handling the transition.
PJM Considering Compensation in Frequency Response Study
Stakeholders endorsed by acclamation PJM’s plan to address FERC’s recent Notice of Proposed Rulemaking on frequency response. PJM’s problem statement and issue charge suggest that the RTO might consider compensating units for maintaining primary frequency response, even though the NOPR is silent on the topic. (See “Stakeholders Push Back on Paying for Frequency Response,” PJM Markets and Reliability and Members Committees Briefs.)
John Farber of the Delaware Public Service Commission acknowledged it might be “reaching for belt and suspenders,” but he requested that the compensation issue be separated into another phase of the study from the main discussion.
This was received coolly by both stakeholders and PJM staff. “I think separating it too much may complicate the solution space that we come up with,” PJM Vice President of Operations Mike Bryson said. “I think separating it too much may predetermine the solution probably more than we’re willing to.”
VALLEY FORGE, Pa. — PJM will discuss its updated capacity emergency transfer limits at next month’s meetings of the Market Implementation and Planning committees, staff said at last week’s PC meeting. The announcement came just days after Jorge Cardenas, vice president of asset management and centralized services for Public Service Electric and Gas, sent a letter to PJM’s Board of Managers voicing concern about the CETL values calculated for PJM’s eastern region.
Cardenas said the values were overstated, exposing PSE&G customers “to the risk of failing to meet the applicable generation adequacy standard under which PJM plans its system.” CETL values represent the amount of power that can be reliably imported to a locational deliverability area to meet its loss-of-load-expectation threshold. They also impact the Base Residual Auction, which begins tomorrow, so the RTO published the updated values on April 13.
PJM’s Mark Sims said the RTO has received substantial feedback on the CETL calculation methodology since the original numbers were posted in February, so the discussions will explain the RTO’s assumptions and how to “memorialize” them for future use.
Steve Herling, PJM vice president of planning, noted that some stakeholders have suggested using “slightly different” CETL values in the BRA versus the Regional Transmission Expansion Plan, which is why the RTO plans to discuss it at both the MIC and PC next month. He said he “expects” PSE&G’s concerns will be covered during the discussion.
John Farber of the Delaware Public Service Commission noted that PSE&G’s letter is substantially redacted and hard to understand.
“I think the philosophical elements need to be discussed regardless,” Herling said. “Some of the details that were redacted I don’t know will be necessary to everyone’s understanding of the issues.”
PSE&G’s letter suggests that PJM made “invalid assumptions regarding the operation of the controllable lines between PJM and NYISO,” specifically the phase angle regulators on the J/K lines at the Waldwick substation and the 5018 line at Ramapo. PSE&G said PJM’s assumption is “unreasonable” because it would prevent fulfillment of the RTO’s supply obligation to Rockland Electric on the 5018 line, which is part of PJM’s joint operating agreement with NYISO, and because the PARs must be changed individually. Since it would require adjusting PARs on the Waldwick, Ramapo, Goethals and Farragut lines, it couldn’t happen fast enough to address emergency situations, PSE&G said.
The letter also points out that the values assume NYISO will be able to produce certain results on its system, but that assumption might be unwarranted because the ISO will likely also be experiencing any weather-related emergencies that cause PJM to implement emergency actions.
Competitive Planning Process Manual Won’t Address Cost Containment
For PJM to codify its competitive planning processes in time for an upcoming RTEP window, as it hopes to accomplish with its proposed Manual 14F, the RTO won’t have time to address cost-containment provisions that stakeholders have repeatedly brought up. (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)
Herling PJM
“The discussion of cost capping is not going to be completed before we are asking for this endorsement of the manual,” Herling said. “Obviously, this is going to take a little bit longer. We have engaged two different consultants to help us, and we expect that there will be a lot of input from stakeholders, so for now, the coverage of the cost containment in the manual is going to be somewhat high-level. … We’ll amend the manuals as necessary, but we think it’s important to have the rest of the structure of the manuals and the process documented.”
Herling said PJM is “hoping” to have a two-month RTEP window running in the June-July timeframe.
PJM is holding an initial special session of the PC on cost capping and containment on May 24. It’s likely to cover education on types of cost containment that have been used in the industry, along with some financial analysis on how they could potentially be compared, PJM’s Sue Glatz said. Further meetings will be scheduled after that, she said.
The results of those discussions will have to be added into the manual later as amendments. PJM’s Mike Herman brought the manual for a first read last week and will be seeking endorsements at the PC and the Markets and Reliability Committee next month.
DEDS Task Force Ends at PC
Along with Manual 14F, PJM also hopes to secure approval for three designated entity design standard (DEDS) documents in time for the RTEP window. That process will likely be easier because, as Herman explained, the standards only require PC endorsement to become effective.
That unusual situation created concern for American Municipal Power representatives, who have previously questioned why PJM won’t require endorsement at the MRC.
Farber expressed concern about a designated entity agreement he had found filed at FERC that included a 3% rate escalation, which he felt went beyond the standards the Designated Entity Design Standards Task Force was developed to create.
“The designated entity agreement contains all terms and conditions, the requirements and obligations of a party who has been designed to construct a project, not just design standards,” Herling explained. “It’s far more reaching than that.”
The escalation was not pro forma and was unique to that specific project, PJM staff confirmed. The financial agreements were included, Herling said, as protection of the agreement.
“Our feeling was that those terms needed to be memorialized somewhere so that they would be to some degree at least enforceable,” he said. “People are bidding on a project with some form of cost containment. Obviously, we hope that they will then stand by that and we figured by putting it in an agreement that gets filed at FERC that there would be some teeth in it.”
Related to that topic are updates to Manual 14C that PJM is also presenting for endorsement, which focus coordination among entities constructing interconnection facilities. The negotiations could be long and laborious, but it could always be worse: AMP’s Ed Tatum asked what happens when the stakeholders can’t agree.
“We beat them with a stick,” Herling responded.
“But after that, Steve?” Tatum continued.
“We keep beating them with a stick.”
“What are the next steps?”
“It’s a bigger stick,” Herling said. “We’re confident of our ability to find a solution.”
Glatz reassured stakeholders that such measures are a last resort. “We have a long track record of coordinating with entities on both the transmission and on the generation interconnection side, and to my knowledge, we haven’t actually had to beat anybody with a stick yet.”
Tatum thanked them for the explanation and told Glatz he would relay a story about stick beating to her at another time.
“We appreciate you holding that one for later,” Herling said.
ISO-NE out of this ‘World,’ According to PJM Reserve Requirement Study
PJM has released for approval its assumptions for its 2017 reserve requirement study, and one thing PJM staff wanted to make clear is that ISO-NE has been completely removed from its calculations of the “World,” which consists of the four external systems with direct ties to PJM: NYISO, MISO, Tennessee Valley Authority and SERC Reliability’s VACAR region in Virginia and the Carolinas.
“Last year … we had New England inside of the World,” PJM’s Patricio Rocha-Garrido said. “Later on, when we ran load model selection analysis, we realized that if we keep New England in the World, then PJM and the World would be peaking on the same week, which was not consistent with what we were seeing from the historical perspective. Based on this, we introduced a change to the World load model, which switched the peaking week of the World load model.”
“I hope RTO Insider reports that PJM kicked ISO New England out of the World,” said Carl Johnson, who represents the PJM Industrial Customer Coalition.
Johnson then asked for PJM to perform a sensitivity study on what the results would be if it continued to use the commercial probability in its study. PJM doesn’t plan to adjust the megawatt rating of future generation by the commercial probability, as it has done in the past.
The assumptions will also correct what PJM sees as incorrect accounting in the past of behind-the-meter generation. No longer can BTM owners choose to be capacity resources. PJM’s Tom Falin said BTM will be reflected based on how it has impacted the metered load history over the past eight or nine years. That will be specified later this summer when the PC is asked to endorse a historical time period, he said.
“This language is just catching up to our current practice,” Falin said. “I would say the original language was wrong.”
Ramapo PAR Cost Allocation Forging New Territory
PJM’s current cost allocation construct is not applicable to the replacement of the Ramapo PARs because PJM’s JOA with NYISO points to the Northeast Protocol for most planning issues, and the protocol is an agreement that includes ISO-NE, PJM’s Chuck Liebold told the Transmission Expansion Advisory Committee last week. (See NYISO, PJM Discuss PARs’ Benefits, Cost Allocation.)
PJM is considering broadening the planning included in the JOA to include transmission facilities eligible for interregional and regional cost allocation. The current process uses an avoided-cost method, but PJM could use a solution-based distribution factor. Several other options are under consideration as well.
President Trump reportedly has nominated Pennsylvania regulator Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), to fill two Republican vacancies on FERC.
Powelson and Chatterjee, who will seek terms expiring in 2020 and 2021, respectively, would restore the commission’s quorum, which was lost in February with the resignation of former Chairman Norman Bay.
Powelson, a member of the Pennsylvania Public Utility Commission, is the current president of the National Association of Regulatory Utility Commissioners — a familiar stepping stone for FERC commissioners. Both Commissioner Colette Honorable and former Commissioner Tony Clark served one-year terms as NARUC presidents before their appointments.
Honorable announced last month that she will not seek a new term when hers expires in June, meaning Trump will be able to nominate two additional commissioners to join acting Chair Cheryl LaFleur.
McIntyre | Jones Day
Multiple outlets reported the nominations late Monday night. The White House has not officially announced the nominations as of press time. Numerous reports have also identified Kevin McIntyre, co-head of the energy practice at law firm Jones Day, as the third nominee and likely chairman.
Powelson
A fixture at NARUC meetings, Powelson is a big, back-slapping man known for his sense of humor. An avid Philadelphia sports fan, he is certain to engage in good-natured trash-talking with LaFleur, who occasionally wears Boston team jerseys to commission meetings.
He was nominated to the Pennsylvania PUC in 2008 and served as chairman between 2011 and 2015. His current term expires in 2019.
Powelson was elected NARUC president last November after serving as president of the Mid-Atlantic Conference of Regulatory Utilities Commissioners in 2014-15. (See “Powelson Replaces Kavulla as President,” Overheard at NARUC Annual Meeting 2016.)
He is on the Board of Trustees of Drexel University and previously served as the president of the Chester County Chamber of Business & Industry, in suburban Philadelphia. He joined the Chester County chamber after serving as director of government relations for the neighboring Delaware County Chamber of Commerce and a stint as staff assistant to former Rep. Curt Weldon (R-Pa.).
He became the subject of some controversy in March when he told an industry conference that opponents of pipeline projects are engaged in a “jihad.”
He later apologized. “I used the word ‘jihad’ while characterizing the actions of individuals who have engaged in threatening or disruptive behavior: interrupting public meetings, preventing officials from speaking, harassing federal and state regulators along with their families, and otherwise attempting to halt the public discussion about important infrastructure projects,” Powelson wrote in a statement, as reported by State Impact. “In retrospect, that was an inappropriate choice of words.”
In 2014, Powelson resigned from the Greater Philadelphia Energy Action Team — a group dedicated to expanding the energy industry in southeastern Pennsylvania — after critics said it put him in a conflict of interest.
He has a bachelor’s in political science and government from St. Joseph’s University and a Master of Governmental Administration in public finance from the University of Pennsylvania.
Chatterjee
Chatterjee, a former lobbyist for the National Rural Electric Cooperative Association, became McConnell’s energy adviser in 2011 after working for two years as a staff aide for the coal state senator.
Chatterjee University of Cincinnati
A November 2015 interview with Bloomberg Government identified Chatterjee as “the McConnell adviser determined to stop the Clean Power Plan.”
“Leader McConnell promised to do everything he could to fight for the people of Kentucky, who were concerned about the impact the Clean Power Plan would have on their jobs, bills and way of life,” Chatterjee, who said he drives a hybrid car, told Bloomberg. “He is going to continue that fight. It is an honor and a privilege for me to staff him.”
Chatterjee told Bloomberg his mentors include C. Boyden Gray, who as counsel to President George H. W. Bush was involved in drafting the 1990 Clean Air Act amendments, the Energy Policy Act of 1992 and a cap-and-trade system for acid rain emissions.
Chatterjee graduated from St. Lawrence University and received a law degree from the University of Cincinnati College of Law. Before joining McConnell’s office, he worked for the House Republican Policy Conference, former Rep. Deborah Pryce (R-Ohio) and the House Ways and Means Committee.
Eversource Energy on Wednesday reported first-quarter earnings of $259.5 million ($0.82/share), up 6.3% from $244.2 million ($0.77/share) in the same period a year ago off increased investment in transmission.
CFO Phil Lembo said in a conference call with analysts Thursday that through March, Eversource has invested more than $146 million in 28 transmission projects comprising the Greater Boston and New Hampshire Solution, with work expected to be completed in 2019. The company also has invested more than $141 million in 27 small projects in Greater Hartford, all of which should be completed by next year.
Transmission earnings were up 11% from a year ago to $94.2 million, the company said. Electric distribution and generation earnings improved 5.26% year-on-year to $114.1 million, reflecting higher distribution revenues and lower property tax expense, which were partially offset by higher storm restoration costs and higher depreciation expense. Natural gas distribution contributed 19.6% of earnings with $50.8 million in the first quarter, a negligible decrease from last year.
The company reaffirmed its 2017 earnings-per-share guidance of $3.05 to $3.20 and its projected 5 to 7% long-term EPS growth rate.
Northern Pass Moving Toward 2018 Construction
Together with partner Hydro-Québec, Eversource will bid the Northern Pass transmission project into the request for clean energy proposals in Massachusetts to bring Canadian hydropower into New England. The RFP is for up to 9.45 TWh annually for up to 20 years; bids are due on July 27; and projects will be selected for negotiations by Jan. 25, 2018. Bay State Wind, a 50/50 partnership between Eversource and DONG Energy, also will bid into a separate RFP exclusively for wind projects south of Martha’s Vineyard.
Hydro-Québec Substation at Ayer, Mass.
The New Hampshire Site Evaluation Committee began hearings on Northern Pass in April. The company expects those to conclude, and the U.S. Department of Energy to have issued a final environmental impact statement, by Sept. 30. The Eversource timeline foresees a presidential permit in the fourth quarter and construction beginning in January 2018.
| Eversource
Regulatory Activity
The Massachusetts Department of Public Utilities in June will begin hearings on the electric rate reviews Eversource filed in January for NSTAR Electric and Western Massachusetts Electric — which include a proposal to combine the two utilities.
“FERC approved that combination earlier this year,” Lembo said. “We expect to get a decision on the case around the end of November with new rates effective in January of 2018.”
In Connecticut, Eversource joined the Office of Consumer Counsel and the attorney general on April 18 in filing a motion to modify the merger agreement with Connecticut Light and Power that was approved by the Public Utilities Regulatory Authority in 2012. The motion jointly requested that PURA extend the deadline for implementing new rates to July 1, 2018, and it was approved on April 20.
The day of the conference call, PURA approved revised rates for residential and business customers of CL&P and Avangrid’s United Illuminating. According to PURA’s statement, effective July 1, 2017, Eversource’s residential generation rate will increase slightly from 7.87 cents/kWh to 8.01 cents/kWh. UI’s residential generation rate will decrease from 9.26 cents/kWh to 7.6 cents/kWh. The new rates will be in effect through the end of 2017.
Return on Equity
Lembo also commented on the D.C. Circuit Court of Appeals’ April 18 ruling overturning FERC’s 2014 order setting the base return on equity for Central Maine Power and other New England transmission owners at 10.57%. The court said the commission failed to meet its burden of proof in declaring the previous 11.14% rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
“The court decision is still recent, and really, the New England transmission owners as a group need to decide what the next steps will be,” said Lembo, adding that the TOs in June need to file a proposed regional network service rate.
“One could say that the last approved ROE by FERC is the 11.14% … so in the [rate] request, we’re looking for a 10.5% ROE in the case, and the total rate increase is about $60 million at NSTAR Electric and about $36 million at Western Mass Electric,” he said. Lembo later in the call said that NSTAR at the end of 2016 “was probably a little shy of that number of 10.5% when you do all the calculations for Massachusetts, and Western Mass was closer to 9%, so not at the levels that we were looking for in this case.”
Eversource concluded its presentation to analysts by showing how natural gas pipeline projects lack funding or are delayed, trapping gas just west of New England. Pipeline capacity from the west (New York, Pennsylvania and Ontario) is 3 Bcfd, mostly contracted to local distribution companies, while New England LDC load on a cold winter day totals more than 4 Bcfd. Generators must rely on secondary capacity or imported LNG and Canadian offshore supplies to serve their needs, creating price/reliability issues. Meanwhile, offshore natural gas production in Eastern Canada is down more than 50% from its peak and continuing to decline.
Quotes based on the transcript provided by Seeking Alpha.
WEC Energy Group turned a larger profit in the first quarter despite warm weather and slumping electricity demand in the company’s Midwest markets — coupled with an ongoing rate freeze.
The company reported $356.6 million ($1.12/share) in net income for the first three months of this year, up from $346.2 million ($1.09/share) during the same period in 2016. Revenue increased 5% to $2.3 billion.
However, retail deliveries of electricity for WEC’s Wisconsin and Michigan utilities were down 1.1% year-over-year, excluding consumption at iron ore mines in Michigan’s Upper Peninsula. Residential use was down 2.1%.
CEO Allen Leverett attributed the extra income to more effective cost controls, better-than-forecasted electric fuel recoveries and the decoupling mechanisms at WEC’s Illinois and Minnesota gas utilities — all of which helped to offset the effects of warm weather. Decoupling separates a utility’s profits from energy commodity sales, with rates of return adjusted to meet revenue targets.
Leverett said WEC will have to continue to operate tightly over the next two years after its We Energies subsidiary last month filed a settlement with Wisconsin regulators agreeing to freeze all business and residential base rates. Twenty-four of the utility’s largest business customers have so far signed on to the agreement, which will hold base rates steady through 2019.
“This will make for a total of four years that base rates will be flat,” Leverett said during a May 2 earnings call. “This would essentially give our customers price certainty through 2019 and require us to continue to manage our costs aggressively.”
The proposed agreement would extend current earnings-sharing mechanisms in which return on equity is shared equally between customers and shareholders, while earnings above a 10.5% return are given back to customers. That arrangement would be extended through 2019 at Wisconsin Electric and Wisconsin Gas, with a similar two-year mechanism put in place next year at Wisconsin Public Service.
“Settlements are uncommon in Wisconsin, but at this point, I expect the process to move expeditiously,” Leverett said, adding that the deal will allow customers with expiring pricing options to avoid a price increase.
UMERC Project Map | WEC Energy
WEC’s bid for regulatory approval for the construction of two new gas-fired plants in Michigan’s Upper Peninsula is also moving as expected, Leverett said. The two plants will serve the newly formed Upper Michigan Energy Resources Corp., a partnership of WEC subsidiaries Wisconsin Electric Power Co. and Wisconsin Public Service. (See Michigan Upper Peninsula Getting its Own Utility.)
The company has obtained all local approvals for the plants and is just awaiting a go-ahead from the Michigan Public Service Commission, which Leverett anticipates will happen.
“As you may recall, our last several major proceedings in Michigan have resulted in settlements which the commission approved. We would welcome a similar outcome in this case,” he said.
WEC will also invest about $300 million to modernize the Peoples Gas distribution system in the Chicago area. Leverett said that program is continuing as planned, even while the company awaits a review decision from the Illinois Commerce Commission that should come later this year.
Exelon is encouraged by Energy Secretary Rick Perry’s order to study if government regulations and policies are forcing baseload power plants into early retirement and thinks courts will uphold the programs that provide zero-emission credits benefiting its nuclear power plants, executives said during the company’s first-quarter earnings call Wednesday.
