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.
CAISO is moving forward with an initiative meant to ease the integration of distributed resources into its markets.
The main goal of the program: to make it easier for grid-connected resources such as rooftop solar, energy storage, plug-in electric vehicles and demand response to participate in the ISO’s market operations, creating more system flexibility and reducing carbon dioxide emissions.
“The number and diversity of these resources are growing and represent an increasingly important part of the resource mix,” CAISO said in its revised proposal.
On May 4, CAISO provided an update on phase two of its Energy Storage and DER initiative, which will propose changes that are due to be reviewed by the Energy Imbalance Market (EIM) Governing Body on July 13 and submitted to the ISO’s Board of Governors for approval during its July 26-27 meeting.
The proposals involve improving the accuracy of DR contributions through alternative energy usage baselines, distinguishing between charging energy and station power for storage resources, and developing a net benefits test for DR resources that participate in the EIM.
Expanded Baseline Options
According to CAISO, a majority of market participants support a set of baselines to assess the performance of proxy demand resources — DR aggregations of retail customers — that was developed by a stakeholder working group.
| CAISO
While the current “10-in-10” baseline methodology is considered accurate for many large commercial and industrial customers, stakeholders don’t think it is appropriate for all customer types, prompting the working group to propose additional baselines. Using the 10-in-10 methodology, the ISO calculates a baseline by examining the 45 days prior to a trade date and finding 10 “like” days in which no DR was required. The ISO then uses hourly average meter data to create a baseline representing a typical load profile, and the resource is paid for reducing usage below the baseline.
Under the new proposal, baselines for residential resources would be based on a four-day weather match that estimates what electricity use would have been in absence of DR dispatch under similar weather and on similar days, and using a control group of similar users.
Commercial baselines would be based on the 10-in-10 method with a 20% adjustment cap, an average of the previous five days and a control group. Baselines are adjusted using actual load data in the hours preceding a DR event to better reflect variables that might not be present in the historical data.
“Stakeholders who supported the proposal stated that the use of additional baselines for residential and commercial customers would improve the accuracy and reduce bias when compared to the 10-in-10 baseline,” CAISO said.
Joint Review of Station Power Rules
Another working group is developing new market rules for energy storage resources.
CAISO is working with the California Public Utilities Commission to distinguish between station power and wholesale charging energy with respect to energy storage devices. The regulator is seeking to redefine station power — electricity used by a generator itself — from a retail perspective, and the ISO said it is important that the rules do not conflict with each other.
The ISO is proposing to simplify its definition of station power as energy used to serve a resource’s own load and settled under a retail tariff.
CAISO said it proposed the changes because it is concerned that storage resources will commingle their charging load and station power load and use wholesale, ISO-metered electricity to serve station power load. If this happens, either the local retail electricity provider is not getting paid for serving station power, or the storage resource is getting charged twice at both the wholesale and retail level for the power.
One option would be to require that wholesale load and retail load be metered separately, but the grid operator is examining whether there are other ways to solve the problem.
CAISO has also proposed revisions to the DR net benefits test that establishes the price threshold above which DR bids are measured. ISO staff and the internal Market Monitor agree that there is a gap in the test’s formula.
The proposal would enable the DR benefits calculation to include natural gas price indices beyond California in order to accommodate EIM participants outside of the state, allowing them to participate as DR resources in the CAISO market.
NRG Energy posted sharp losses in the first quarter on lower hedge margins and declining capacity revenues in the eastern U.S., signaling that 2017 is turning out to be a predicted “trough year,” CEO Mauricio Gutierrez said.
NRG Energy CEO Mauricio Gutierrez | NRG
The company lost $203 million ($0.52/share) during the quarter, compared with net income of $47 million ($0.24/share) for the first three months of 2016.
“The roll-off of higher-priced hedges that were executed after the polar vortex of 2014, lower capacity revenues in the East and a few known one-time items accounted for almost 75% of the total decrease,” Gutierrez told analysts during a May 2 earnings call.
NRG management last quarter established a special committee to make recommendations to the company’s board on its stated initiatives, especially regarding refinancing of debt for subsidiary wholesale electricity provider GenOn Energy, which the company last year said might be forced to file for Chapter 11 bankruptcy protection.
ERCOT Most Promising, Needs Better Price Signals
Market fundamentals make ERCOT the most attractive market for NRG, but management said it wants to see improved price signals before making more capital expenditures there. With future reserve margins in the high teens, the company is focusing on how increased loads, fewer new builds and more retirements can quickly tighten the market and create scarcity conditions in Texas.
W.A. Parish Power Plant in Thompsons, Texas
“ERCOT has historically understated the actual number of megawatts leaving the system. … Looking forward, we see the same anemic estimate for retirements in the reports, assuming only 840 MW between 2017 and 2022,” Gutierrez said.
NRG last month announced that it will mothball Greens Bayou 5, taking 371 MW out of the ERCOT system.
“And we believe that there are close to 5 to 6 GW of already identified generation at risk today in the market,” Gutierrez said.
East Challenges Margins
Low natural gas prices and new efficient generation in the East continue to challenge NRG margins, although PJM this month will implement its first 100% Capacity Performance auction, helping the company maintain a positive outlook on capacity markets.
| NRG
The higher reliability requirement under this new construct will be problematic for megawatts that cleared in previous auctions as base capacity, including less reliable generation and demand response.
“These resources will have to make a decision between taking themselves out of the market or pricing in a higher reliability premium,” NRG said.
The company is concerned about recent actions by various states that it thinks could undermine the integrity of competitive markets.
“Out-of-market subsidies and contracts bestowed pricing that was needed to attract new capital investment, but often [by] raising prices for the end users,” Gutierrez said. “We and a number of other parties have filed legal challenges to the nuclear subsidies in both New York and Illinois because we believe they’re not legal and because regulators should focus on crafting competitive solutions for public-policy objectives.”
Other first-quarter highlights included the transfer of 311 MW of utility-scale solar to subsidiary NRG Yield for $130 million. The company also offered NRG Yield its remaining 25% interest in NRG Wind TE Holdco, an 814-MW portfolio of 12 wind facilities.
NRG also started construction on the 600-MW Carlsbad Energy Center in Southern California, which it expects to complete on deadline in the fourth quarter of 2018.
