Page 1163 – RTO Insider

May 8, 2018

UPDATED: PJM Capacity Proposals Widely Panned

[Editor’s Note: This story has been updated to include additional filings posted at FERC after RTO Insider went to press Tuesday morning.]

By Rory D. Sweeney and Rich Heidorn Jr.

If it were a Broadway show, PJM’s “jump ball” proposals for protecting the capacity market from subsidized resources would have closed after one night.

Monday was the deadline for the critics to file their comments on PJM’s proposal and the reviews were largely negative. RTO Insider’s initial review of four dozen filings found almost no commenters wholeheartedly endorsing either PJM staff’s capacity repricing proposal or the Independent Market Monitor’s MOPR-Ex plan to extend the minimum offer price rule to existing resources in addition to new entries (ER18-1314). (See PJM Board Punts Capacity Market Proposals to FERC.)

PJM’s plan would allow state-subsidized generators to bid into capacity auctions but ensure they don’t suppress prices by removing those offers in a second “repricing” stage of the auction.

Numerous commenters said PJM had failed to prove the need for the proposed changes, arguing there was little evidence state subsidies, such as nuclear plants receiving zero-emission credits, were suppressing prices. Several commenters said the proposals would increase prices while failing to address the capacity and energy markets’ fundamental flaw: the failure to capture attributes valued by states, such as carbon-free generation. PJM’s state regulators, led by the Organization of PJM States Inc. (OPSI), were unanimously opposed.

Capacity Repricing Proposal Capacity Market PJM — Exelon’s Clinton Power Station is one of the nuclear plants eligible for zero-emission credits in Illinois. New Jersey is considering similar subsidies for its nuclear plants.

Hedging Their Bets

While few commenters enthusiastically endorsed either proposal, many offered qualified support for MOPR-Ex. Others hedged their positions.

Dominion Energy, Public Service Electric and Gas, American Electric Power and the Nuclear Energy Institute said FERC should reject both options but that if forced to choose, they preferred PJM’s proposal. While “imperfect,” repricing “is a far more balanced a solution” that respects state initiatives and avoids the possibility of load paying twice for capacity, NEI said.

Exelon opposed both options but called the Monitor’s proposal “particularly indefensible.”

Old Dominion Electric Cooperative — seeking to protect its self-supply resources procured outside of the capacity market — said both proposals should be rejected but that it would accept MOPR-Ex if it were amended to include the municipal/cooperative entity exemption from the capacity repricing proposal. “ODEC’s primary position remains that the commission should avoid layering yet another significant design change onto the already complex [Reliability Pricing Model] construct,” it said.

Consumer advocates from D.C., Maryland and New Jersey also said they would accept MOPR-Ex over repricing, subject to a settlement proceeding or stakeholder process “to further refine” it. The Ohio Consumers’ Counsel took a similar position, saying MOPR-Ex proposal is “less detrimental to markets and to consumers because it is more likely to encourage uneconomic generating resources to retire.”

IMM Joe Bowring acknowledged his proposal “is not perfect” but “is the only choice consistent with markets in this proceeding.”

The PJM Industrial Customer Coalition gave the proposal lukewarm support, saying its members “do not object” to it as “a reasonable extension of the existing construct” but are in full opposition to the repricing proposal.

Several commenters questioned why PJM was pushing for swift action on the proposals while it is conducting its quadrennial review of the variable resource requirement curve and launching a fuel security initiative. (See PJM Seeks to Have Market Value Fuel Security.)

“In light of other, overlapping initiatives currently underway, it is unwise and unnecessary for PJM to push forward with either of the proposed capacity market modifications — particularly when both modifications failed to obtain stakeholder consensus,” AEP said.

American Municipal Power said FERC should order PJM to reconvene the Capacity Construct/Public Policy Senior Task Force “without arbitrary deadlines to complete the evaluation of whether and what types of changes are needed to accommodate state actions.”

“The commission should reject the proposal and direct PJM to reconvene the stakeholder process in its administrative resource adequacy construct, as well as the current quadrennial review process and the novel fuel security proposal,” AMP said.

“Rather than seeking multiple arbitrary commission deadlines and guided processes for the additional work needed to resolve issues with PJM’s proposal, the commission should direct PJM to address the issues with the two proposals and create a supportable proposal that achieves the first principles identified by the commission in the [ISO-NE Competitive Auctions with Sponsored Policy Resources] proceeding.” (See Split FERC Approves ISO-NE CASPR Plan.)

Blow It Up and Start Over

Several companies suggested FERC use its Section 206 powers to craft a solution, though they disagreed on how urgent the problem is.

NRG Energy asked FERC to create “its own just and reasonable capacity market design.”

“While NRG agrees that the existing PJM rules are being overwhelmed by subsidized generation, neither of the two PJM proposals will result in a long-term sustainable market structure,” NRG said. “Inaction is not a viable option.”

The PJM Power Providers Group agreed “the threat … is real” and backed developing a different MOPR “that removes many of the exemptions contained in the MOPR-Ex proposal.”

The New Jersey Board of Public Utilities asked FERC to reject the filing and order PJM to “ensure that any future capacity market revisions are complementary to” attributes sought by the states.

“PJM’s proposals do not aid the commission in its longstanding efforts to harmonize state policies with capacity market planning,” the BPU said. “Status quo is the appropriate action for now.”

The American Public Power Association said the proposals are “further evidence of the ongoing unsuitability of mandatory capacity markets to ensure resource adequacy.” It said, “bilateral contracting or ownership should be supported instead of merchant development of generation resources.”

“APPA agrees that such state policy goals should be accommodated, but raising capacity prices for customers without any assured benefit is not the way to do it,” the association said.

Full Rejection

Consumer advocates from Illinois, Delaware, West Virginia, Kentucky and Indiana said FERC doesn’t have the authority to choose one of the two proposals. “Effectively, PJM is asking the commission to conditionally approve a proposal and then oversee a rewrite of that proposal,” they said.

The Illinois Commerce Commission also questioned FERC’s authority to act on either proposal, adding that, despite “PJM’s lip service to states’ rights … PJM reserves to itself the discretion to cherry-pick which resources are worthy of state policy revenue.”

“State laws that do not seek to impermissibly intrude upon the wholesale electricity market or abrogate a commission mandated rate, properly fall within the jurisdiction reserved to the states and do not violate the [Constitution’s] Supremacy Clause,” the ICC wrote.

Rare Endorsements

One full-throated endorsement came from comments filed jointly by Starwood Energy Group and Direct Energy, who argued MOPR-Ex “is narrowly tailored to mitigate artificial price suppression in PJM’s capacity market while retaining core market fundamentals” and “preserves the ability of both customers and investors to bring new capacity resources, and offer existing economic capacity, into the market on a competitive basis.”

The companies opposed PJM’s repricing proposal and repeatedly juxtaposed the two to argue for MOPR-Ex, which it said “does not thrust the capacity repricing costs onto the market generally.”

The American Petroleum Institute also expressed support, arguing that repricing “effectively provid[es] preferential treatment to high-cost, subsidized resources for capacity commitments that continue to inefficiently displace lower-cost resources.”

“Contrasted with capacity repricing, implementation of MOPR-Ex is straightforward and narrow with all subsidized resources subject to mitigation without exception, and nonsubsidized resources would not be subject to mitigation,” API said in a joint filing with private equity Panda Power Funds and J-POWER USA Development, an independent power producer and developer with 2,700 MW of generation operational or under development in PJM.

LS Power Associates also backed MOPR-Ex saying it is “based on the well-established minimum offer price rule that has long been part of PJM’s capacity market,” while the repricing proposal is “fundamentally unfair” and “irredeemably flawed.”

Rockland Capital argued for the MOPR-Ex with settlement discussions to “ensure that the exceptions from mitigation are tailored to preserve wholesale market prices first and accommodate state interests second.”

The Natural Gas Supply Association was less outspoken in its support but nonetheless urged approving and suspending implementation of MOPR-Ex, then directing those involved to engage in settlement discussions to consider “how exemptions are provided and the appropriateness of unit-specific exemptions, including exemptions provided for units subject to a renewable portfolio standard.”

The group pointed to the nuclear subsidies recently passed in New Jersey as evidence “that the time is now to address state subsidies given that the number of subsidies in the market continue to grow.” (See Exelon to Push for Laws, Rules to Boost Profitability.)

Vistra Energy and its Dynegy Marketing and Trade subsidiary took a similar position, saying “an appropriately designed” MOPR is the best way to support competition.

The Electric Power Supply Association said it opposed capacity repricing but agreed “100%” with PJM that changes are needed.

“The commission should summarily reject the ‘capacity repricing’ proposal … which would enable and encourage state interference with the commission-jurisdictional RPM market, and should instead focus on a MOPR approach, consistent with its recent commitment to ‘use the MOPR as [its] standard solution’ where state policies threaten the organized capacity markets.”

EPSA noted that the Monitor’s MOPR-Ex plan received more support among stakeholders than PJM’s alternative. If the commission does not find MOPR-Ex just and reasonable, EPSA said, it should find PJM’s current MOPR rules are not just and reasonable because they don’t cover existing resources.

Exelon, however, said MOPR-Ex “would prevent state-supported clean generators from clearing at all, replacing them with polluting units. Perversely, that will not just force customers to pay higher electricity prices but also will inflict on customers the additional costs of grappling with the pollution [MOPR-Ex] has created.”

‘Externalities’

Exelon said PJM’s premise — that states making payments to recognize the environmental benefits of renewable and nuclear generators states are “distorting” price signals — is incorrect.

“Sound economics understands that when states tax polluting generators, or pay clean generators for their environmental value, they do not ‘distort’ price signals. They reduce distortions and account for true economic costs and benefits. The only distortion comes from treating clean and polluting generators as the same when they are not.”

The Institute for Policy Integrity at New York University School of Law, a nonpartisan think tank that says it is dedicated to improving the quality of government decision-making, also cited the markets’ failure to value environmental externalities.

FirstEnergy, in a joint filing with East Kentucky Power Cooperative, also agreed that the capacity market is failing to account for externalities — but defined those uncompensated attributes as “resilience, fuel diversity and fuel security.”

“The simple facts are, notwithstanding numerous amendments and market design enhancements through the years, PJM’s wholesale capacity market has never worked as intended. States are compelled to address the needs of their constituents. It therefore should be no surprise that states within the PJM footprint are responding to this long-term market failure by implementing policies that are designed to preserve important generation units and their associated attributes, including generation and zero-emissions attributes.”

They said FERC should reject PJM’s proposals and require the RTO to “develop a holistic solution to the fundamental issues facing its markets.”

Resume Negotiations

Several commenters called on PJM to return to stakeholder negotiations.

Dominion said it opposes both proposals because they extend mitigation to existing capacity resources. “Dominion Energy does not agree that existing capacity resources have the same pricing effects as new capacity resources and warrant identical treatment,” it said. FERC should insist the RTO resume stakeholder discussions to develop rule changes “that focus on actual distortive pricing effects stemming from state public policies,” Dominion said.

Talen Energy Marketing and its fleet of generation subsidiaries argued both proposals are “inadequate” and asked FERC to “direct PJM to engage with its stakeholders in a broader price reform effort, including necessary revisions to the energy market, that would seek to appropriately compensate generators for other, non-price attributes that provide measurable value to the grid.”

States Unanimous

In a rare unanimous vote, OPSI urged FERC to reject both proposals and argued that PJM should “respect the resource choices of state policymakers unless there is a legal determination that a state policy impermissibly intrudes” on federal jurisdiction. State subsidies aren’t impacting the market’s ability to attract resources and provide adequate returns, and PJM’s evidence to the contrary is purely “speculative” and anecdotal, OPSI said.

“Data shows that adequate numbers of generation resources are consistently able to recover their costs, while receiving rational price signals, from PJM markets,” OPSI said. “PJM abandons the cost-minimizing principle and instead proposes an exceedingly complex design change that will place more weight on administratively determined artificially inflated prices rather than actual market participant offers.”

It noted that the Monitor’s State of the Market report found the average age of at-risk units is 42 years while a Department of Energy-funded report found that the average lifespan for coal units in the Eastern Interconnection is 40 years.

“Such findings seem less indicative of market failure, than of rational market signals of entry and exit. … Rather than rising, there is significant data that shows capacity prices should be falling,” OPSI said, noting the results of PJM’s recent quadrennial analysis of its demand curve and recommendations to reduce the expected cost for a new unit to enter the market.

OPSI said the CCPPSTF was flawed because its charter limited it to only consider the capacity market.

The Maryland Public Service Commission said PJM’s proposed changes would “obscure resource clearing, increase uncertainty and raise customer prices.”

The Pennsylvania Public Utility Commission noted that neither proposal received a two-thirds majority at the Markets and Reliability Committee and that both “could result in subsidized resources in one state, significantly increasing market prices in another state.” (See “No Consensus on Capacity Revisions,” PJM MRC/MC Briefs: Jan. 25, 2018.)

It said capacity repricing would incent market sellers to underbid in the first stage of the auction “causing further price volatility” while MOPR-Ex could cause states to pay twice for capacity even as it suppresses energy prices.

The Public Utilities Commission of Ohio said FERC should preserve the current rules “until a direct path to addressing state subsidies, if at all, can be determined.”

“The commission, state commissions and other parties have taken significant steps to resolve perceived capacity market design deficiencies that have not been fully implemented. Yet, in less than three years, PJM is again before the commission proposing another significant overhaul of the capacity market under far less certain circumstances,” PUCO said. “While PJM has provided information on the price suppression effect of subsidies, it has not similarly substantiated the level of penetration of state-subsidized resources that would trigger the need to depart from the status quo with another major overhaul of RPM. Furthermore, the PUCO notes that there is no analysis as to the cost impacts of either proposed option on load.”

The New York Public Service Commission, which is working with the NYISO to incorporate a carbon adder into its wholesale market to accommodate state-subsidized nuclear plants, sought assurances that the commission’s ruling on the PJM proposal “will not serve as binding precedent for other control areas.”

“This is critical for other control areas to have the autonomy needed to develop market mechanisms that address their regions’ unique circumstances,” the PSC said in a joint filing with the New York State Energy Research and Development Authority.

Environmental Groups Oppose

A joint filing from the Sustainable FERC Project, Sierra Club, Natural Resources Defense Council and Environmental Defense Fund asserted that “PJM wrongly puts the commission in the position of policing the efficiency of state policies.” The proposals put “wholesale market rules on a collision course with states’ core duty to protect the public.”

The filing included a report from “subsidy expert” Doug Koplow that argued energy subsidies “have long been pervasive at both the federal and state level without attendant impacts on PJM’s wholesale markets that have prevented that market from attracting record levels of investment.”

“Even if one state’s policies were to somehow to harm customers in other states, that would not justify commission intervention to countermand those laws where they are lawfully within the state’s authority,” the filing argued.

The Solar RTO Coalition, a newly formed group of solar developers and capital providers, said it is “challenging” to address supply-side subsidies.

“The sheer scope of some of the issues that are associated with how to best incentivize the ‘proper’ development of generation resources … are part of the reason why PJM’s stakeholders were unable to come to a consensus.”

Both OPSI and the Solar Coalition sought to distinguish PJM’s filing from ISO-NE’s CASPR proposal, which the coalition said “was much narrower in scope.”

Ari Peskoe, of the Harvard Electricity Law Initiative, said, “PJM fails to explain why it equates state support for legacy assets with competitive state programs for environmental attributes, even though it concedes that the latter affect wholesale rates ‘to a lesser degree.’”

“Commission approval would substantially expand RTO authority in a field of shared authority. … States did not sign up to have a regional system operator pick and choose among their generation procurement programs, and any assertion to the contrary is unsupportable,” he said. “If the commission approves one of PJM’s proposals, it should expect a steady stream of [Federal Power Act Section] 206 complaints about laws and regulations ensnared or uncaptured by PJM’s arbitrary rules.”

Self-supply Concerns

Dayton Power and Light said either of the two proposals are improvements over the status quo but that FERC should correct “deficiencies” in the proposals by adopting changes to the fixed resource requirement (FRR) option that allows state regulators and regulated utilities to supply their own load with their own capacity resources outside the RPM.

“With the minor tweak to the FRR rules, Dayton believes that market price outcomes will be preserved and states wishing to subsidize varying attributes of generation can be accommodated,” it said. “The only changes needed is to allow for a partial or overlay FRR within a state as opposed to a full zone as the rule exists today. If a state subsidizes 1000 MW of generation for any reason it deems appropriate, it would remove a corresponding amount of load including reserve requirements from the PJM RPM auction.”

In its own filing, EKPC asked FERC to force PJM to change MOPR-Ex’s “public entity” exemption to recognize that the co-op is the only winter-peaking load-serving entity within PJM’s footprint. The proposal uses LSE’s zonal summer-peak demand forecasts to calculate the LSE’s eligibility for the exemption. The LSE cannot own more than 600 MW of generation above the peak summer load it serves. However, EKPC procures generation to cover its higher winter peak, which would put it beyond the 600-MW cap.

The Illinois Municipal Electric Agency avoided comment on MOPR-Ex and focused on criticizing the repricing proposal, which it said would hurt load in the ComEd zone by reducing capacity transfer rights allocated to load “due to the predictable decreased clearing of lower-priced imported generation under stage one.”

The National Rural Electric Cooperative Association reiterated its opposition to PJM’s mandatory capacity market. “However, recognizing that the commission may not at this time unravel PJM’s mandatory capacity construct, NRECA urges that the commission … mandate that any outcome of this proceeding must contain specific exemptions for self-supply by cooperative utilities and other load-serving entities.”

May 6, 2018

CenterPoint Touts Vectren Deal in Earnings Call

CenterPoint Energy executives said Friday they were “excited” about the company’s proposed acquisition of Indiana utility Vectren, saying it presents them with future growth opportunities.

“This transaction will continue to advance us towards our vision of being the nation’s leader in delivering energy, service and value,” CenterPoint CEO Scott Prochazka said during the company’s first-quarter earnings call with analysts and investors. “We’re excited about CenterPoint’s post-merger future.”

CenterPoint announced the $6 billion deal last month. The combined company would serve more than 7 million customers, operate electric and natural gas delivery systems in eight states and hold about $29 billion in assets. (See CenterPoint Energy to Acquire Vectren in $6B Deal.)

The Houston-based company hopes to close the acquisition in the first quarter of 2019. The deal still requires approvals from Vectren shareholders, FERC, the Federal Communications Commission, and regulators in Indiana and Ohio.

“We are combining two companies with strong capital investment opportunities and rate base growth,” said CFO Bill Rogers. “We believe we also have the right mix of unregulated products and services to meet the customer needs of today and tomorrow. This merger provides us the opportunity to deliver even stronger earnings results than we would as separate entities.”

CenterPoint reported first-quarter earnings of $241 million ($0.55/share), compared with $160 million ($0.37/share) for the same period in 2017, beating the Zacks Consensus Estimate of 44 cents.

Investors reacted to the news by driving CenterPoint’s share price up 6.1% to $26.88 at the market’s open. The stock closed at $26.41.

Vectren CenterPoint OGE earnings Q1 2018 — The combined CenterPoint-Vectren service area | *CenterPoint Energy*

Prochazka said the Vectren acquisition will lessen the company’s exposure to the midstream space through Enable Midstream Partners, a gas-gathering and processing joint venture with Oklahoma’s OGE Energy. CenterPoint owns a 54.1% share of Enable, while OGE holds a 25.7% limited-partnership interest and a 50% management interest.

“We continue to believe Enable is well-positioned for success,” Prochazka said, pointing to Enable’s earnings announcement earlier in the week in which it reported all-time highs for quarterly natural gas gathered volumes and processed volumes.

That’s not to say CenterPoint isn’t continuing to look for opportunities to reduce its ownership in Enable.

“We need to be very thoughtful and do so in a coordinated fashion with Enable, so we don’t have a negative impact on Enable,” Prochaska said.

Rogers made it clear that CenterPoint will not sell off portions of Enable to fund the Vectren acquisition, saying three times, “We do not intend to sell Enable common units to finance the acquisition of Vectren shares.”

OGE Gets Huge Boost from Favorable Weather

OGE on Thursday credited favorable weather for first-quarter earnings that almost doubled analysts’ projections.

The Oklahoma City-based company reported earnings of $55 million ($0.27/share), compared with 2017’s first-quarter profits of $36 million ($0.18/share). A Thomson Reuters survey of analysts had expected earnings of 15 cents/share.

CEO Sean Trauschke told analysts and investors during a conference call that it was the first time in five years OGE has begun a calendar year with weather that has driven up electricity sales.

“It feels good to have the first quarter behind us with positive weather,” Trauschke said. “Weather changes. It’s not something you can control. What does not change is our execution and focus on getting better.”

Ironically, Trauschke’s comments came in the aftermath of severe weather that hit OGE utility Oklahoma Gas & Electric’s service territory on May 2.

“Tornadoes, high winds, rain, hail, the full complement,” Trauschke said, promising that service would be restored by noon May 3.

OG&E contributed earnings of 16 cents/share, double its performance in 2017’s first quarter. Trauschke said its Mustang Energy Center’s seven new units have already seen “close to 500 starts” and produced more power this year than its legacy units did all last year.

OGE’s revenue for the quarter was $492.7 million, up 8% from last year. Noting the company realizes most of its earnings in the second and third quarters, Trauschke reaffirmed year-end earnings guidance of $1.90 to 2.05/share.

The company’s stock price gained $1.41/share with Thursday’s earnings release, finishing the day up 4.3% at $34.23/share.

— Tom Kleckner

May 6, 2018December 12, 2023

FERC Approves Dissolution of SPP RE

By Tom Kleckner

FERC on Friday approved the dissolution of the SPP Regional Entity (RE) and the transfer of its members to the Midwest Reliability Organization and SERC Reliability Corp., ending a reliability oversight role that had been a source of concern at the commission and NERC (RR18-3).

The commission found that a proposal submitted by NERC, MRO and SERC in March “reflects the transfers of registered entities will ‘promote effective and administration of bulk power system reliability’” in accordance with the Federal Power Act.

The order terminates the amended and revised delegation agreement between NERC and SPP, effective Aug. 31, and revises the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints. The transfer is effective July 1.

FERC said it was “satisfied” that the petitioners and SPP “have considered and established mechanisms to mitigate against the risk of material gaps in oversight of compliance and enforcement activities due to the transfer of registered entities.”

Most of the RE’s 122 registered entities have been reassigned to the MRO, with the remainder joining SERC. NERC will assume the compliance monitoring and enforcement of the SPP RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.

SPP was appointed by NERC as an RE in 2007. The RTO said last July it had reached an agreement to dissolve the RE, citing a mismatch between the RE’s footprint and SPP’s. FERC and NERC had both expressed concerns that SPP failed to ensure the RE’s independence from the RTO.

NERC approved the dissolution in February. (See NERC Board Approves Dissolving SPP Regional Entity.)

NERC, MRO and SERC filed the joint petition with FERC in March.

The RE said it will address transitional and wind-down costs using its approved 2018 statutory assessment funding. Any funds left over will be transferred to MRO and SERC, allocated according to the transferred load-serving entities’ relative net energy for load.

May 6, 2018

FERC, NERC Recommend Expanded Black Start Testing

By Rich Heidorn Jr.

Coal plant retirements have not caused a shortage of black start resources, but grid operators should consider expanded testing, FERC and NERC said last week.

NERC, its eight Regional Entities and the commission released a study May 2 based on information from a representative sample of nine volunteer registered entities, a follow-up to a 2016 joint report. (See Utilities’ Restoration Plans Pass FERC, NERC Review.)

black start resources NERC coal plant retirements — New York skyline when half the city was in blackout due to a power failure during Hurricane Sandy in 2012. Midtown, with the Empire State Building, is in the background with the darkened East Village and other parts of downtown in the foreground.

“Although some participants have experienced a decrease in the availability of black start resources due to retirement of black start-capable units over the past decade, the joint study team found that the participants have verified they currently have sufficient black start resources in their system restoration plans, as well as comprehensive strategies for mitigating against loss of any additional black start resources going forward,” the new report says. “The joint study team also found that participants that have performed expanded testing of black start capability, including testing energization of the next-start generating unit, gained valuable knowledge that was used to modify, update and improve their system restoration plans.”

A next-start unit is the first generator in the cranking path to be energized using power from the black start generator.

The report recommends that:

Black start generators dependent on a single fuel develop alternative fuel capability or take other steps such as signing firm pipeline contracts. “Furthermore, the joint study team recommends that these black start resource owners work with their regulators as necessary, to develop alternative solutions to address potential fuel constraints.”
RTOs and ISOs consider further study of the adequacy of compensation for black start and other resources supporting system restoration, “including any potential threat or impact on black start resource procurement and retention under current compensation mechanisms.”
Grid operators coordinate transmission and generation registered entities to verify model data and ensure the accuracy of black start simulations. “The joint study team recommends that registered entities performing simulations of their system restoration plans, especially those with cranking path auxiliary loads at a next-start generating unit that are large relative to the black start unit, closely coordinate with generator owner(s) to ensure that the associated modeling data used to perform restoration plan simulations [are] accurate. For instance, the dynamic simulations should include energizing the cranking path and next-start generating unit start-up, using generator and load models that have been verified against electrical data captured during various normal system operations or disturbances.”
Transmission operators perform expanded testing of black start cranking paths, including testing during planned maintenance outages.

The report emphasized that its recommendations — while “appropriate for all registered entities responsible for system restoration” — are voluntary and “not subject to mandatory compliance with the recommendations, separate and apart from any obligations of mandatory reliability standards.”

The report also noted “beneficial practices” used by some that may not be universally appropriate. “The joint study team recommends that registered entities consider incorporating these practices, or variations thereof, as appropriate,” it said.

These practices included:

Coordinating the use of black start facilities across multiple transmission service footprints, allowing a black start unit to aid an adjacent area’s critical load.
Providing additional personnel to staff substations and perform safety watches on transmission lines during expanded testing. “At control centers, additional operators would manage and coordinate expanded testing so that system operators can focus on essential system operations with minimal distractions.”
Having black start generators sign agreements with next-start units to facilitate expanded testing.

May 6, 2018

Peak Details Vision for ‘Transitional’ RC

By Jason Fordney

Peak Reliability last week outlined a vision for reworking its current structure and reducing costs as it tries to prevent a mass exodus of customers to CAISO.

The reliability coordinator (RC) said the cost reduction will require reducing the size of its board of directors to three members from six, cutting executive jobs, and eliminating some manual and administrative processes. Its current membership and board would need to approve the changes. Peak has been an RC since 2009 and had a $45 million budget for 2018.

After Peak announced last year it would attempt to establish a West-wide energy market in a partnership with PJM, CAISO said it would depart the organization to become its own RC and offer the services to other utilities in the West. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)

CAISO peak reliability — Peak’s vision and timeline for Transitional RC | *Peak Reliability*

An RC provides member utilities services that help them meet NERC standards and requirements, and is entirely different from a market operator. Choosing Peak as an RC would not prevent an entity from joining CAISO’s market, and vice versa.

Peak said its funding amount will fall to $28.7 million if CAISO leaves and all other funders stay; it would be $31.2 million if CAISO remains with Peak under the transitional structure. If CAISO departs, remaining members would see a 10% cost reduction under the transitional RC, but if the ISO remains, all members would see a 30% cost reduction.

Peak spokeswoman Rachel Sherrard told RTO Insider that “the [transitional RC] is not a separate organization. It is how Peak would be structured and funded post 2019. It is not a dramatic change in terms of the tools and services that we as the RC currently provide.”

When asked last week about the likelihood of CAISO remaining with Peak, ISO spokesman Steven Greenlee said, “We are moving ahead with our plans to become a RC and offer those services to other entities in the West.”

Peak would operate under the transitional RC structure in 2020/21 and have a $23.5 million operating budget for 2020. It would offer core RC services that ensure reliability and meeting NERC standards, as well as optional services such as Hosted Advanced Applications and the WECC Interchange Tool, which validates E-Tags and confirms power transactions throughout the region. It would also offer interconnection-shared services that support reliability in the West, such as the Reliability Messaging Tool and Enhanced Curtailment Calculator.

After 2021, Peak and PJM would offer bundled market and RC functions, as well as RC-only services at a reduced price.

Peak CEO Marie Jordan last week provided stakeholders a presentation explaining the transitional structure. She also sent an April 27 letter to the organization’s funding parties, member advisory committee and reliability member representatives, touting its experience maintaining reliability of the entire Western Interconnection.

“Over the past decade, in collaboration with its stakeholders, Peak Reliability has built and operated that RC,” Jordan said in the letter. “CAISO has not. SPP has not.”

Peak said it will issue a straw proposal on May 21 that will describe how the transitional structure could be implemented.

CAISO said it expects to begin shadow operations with Peak in May 2019 and become the RC of record for its balancing authority by the end of June 2019.

May 6, 2018

MISO Reliability Group Examines Order 841 Impacts

CARMEL, Ind. — FERC’s extensive energy storage order has handed MISO’s Reliability Subcommittee a new set of to-dos, including devising a storage capacity accreditation process and deciding whether storage will be subject to a must-offer requirement.

MISO Reliability Subcommittee FERC energy storage FERC Order 841 — Harding Street Energy Storage interior | *AES*

The subcommittee will also vet a proposal that will determine whether energy storage owners or MISO will manage the state of charge for resources. The group will additionally consider broader issues around storage, including:

What information MISO needs about batteries to manage real-time operations;
The risks of allowing market participation of energy storage at times when it’s not dispatched; and
Whether MISO should employ reliability improvements to mitigate risks of storage use.

Finally, the group could lay out rules to clarify that energy used for charging is not considered “station power,” which MISO defines as the power a generating facility uses for operating electrical equipment. MISO’s current definition of station power does not include energy used for pumping at a pumped storage facility.

The items were handed down from MISO’s Steering Committee based on recommendations made from the Energy Storage Task Force after discussions on Order 841 and storage’s potential in the RTO.

MISO Reliability Subcommittee energy storage FERC Order 841 — Harding Street Energy Storage exterior | *DOE*

At a May 3 RSC meeting, MISO Market Design Manager Kevin Vannoy said the RTO will bring storage participation straw proposals to a June 6 joint meeting of the RSC, Resource Adequacy Subcommittee and Market Subcommittee. He said MISO will vet storage proposals throughout summer to prepare for a December compliance filing.

Vannoy said MISO still hopes FERC will allow it to set a limit on the number of storage resources that can participate in its markets. FERC’s order set a 100-kW minimum size requirement for participation, causing RTO staff to worry that small resources will flood markets with finite capabilities.

— Amanda Durish Cook

May 6, 2018

Maine Lawmakers Signal Opposition to NECEC

By Michael Kuser

The leaders of two key Maine legislative committees told Massachusetts regulators Friday that they oppose a proposed transmission project that would cross Maine to deliver a large amount of Canadian hydropower to Massachusetts.

In a letter to the Massachusetts Department of Public Utilities, the chairmen of Maine’s joint Environment and Natural Resources Committee and Energy, Utilities and Technology Committee objected to Central Maine Power’s (CMP) New England Clean Energy Connect (NECEC) project on economic and environmental grounds.

The Avangrid subsidiary is set to sign a contract this month with Massachusetts for the state’s 9.45-TWh clean energy solicitation, which was awarded to NECEC — a partnership between CMP and Hydro-Quebec — after the original winner, Eversource Energy’s Northern Pass project, was rejected by siting officials in New Hampshire. (See Mass. P i cks Avangrid Project as Northern Pass Backup.)

The Maine lawmakers wrote that recent expert testimony to their state’s Public Utilities Commission “indicates that Hydro-Quebec will not produce any additional hydroelectricity for NECEC and will instead divert power it now sells to other markets, such as Ontario and New York, to Massachusetts. In fact, NECEC may result in increased greenhouse gas emissions if markets like Ontario or New York have to use dirty fuel mixes to replace the lost electricity from Hydro-Quebec.”

The lawmakers also faulted NECEC for planning to build its line across the Kennebec Gorge, a “world renowned” whitewater rafting and fishing area.

clean energy solicitation NECEC ISO-NE — New England Clean Energy Connect (NECEC) shown in orange | *Central Maine Power*

“It has not proposed burying any portion of the 53 miles of new transmission line, even at this iconic spot that is critical for Maine’s tourism economy,” said Republican Sens. Tom Saviello and David Woodsome, and Democratic Reps. Ralph Tucker and Seth Berry.

AC Better than DC

Among those testifying to the Maine PUC on April 30 was Stephen Whitley, former NYISO CEO and ISO-NE COO, who appeared on behalf of NextEra Energy Resources.

Whitley said that, unlike other proposed HVDC transmission lines in the region, CMP’s project is completely overhead, and that it would be much more useful to build an AC line “that can be looped, serve load and interconnect other renewable generators.” A DC line would not support interconnecting multiple generators located at different points of interconnection along its route, he said.

In addition, Whitley said, NECEC is not traditional utility transmission, but a merchant project dependent on the market. If contracted by Massachusetts, it will execute only a 15- to 20-year power purchase agreement with the electric distribution companies for a DC transmission line that has at least a 40-year life.

“Thus, even if one accepts the purported needs and benefits CMP attributes to the transmission line for Maine and Massachusetts, there is a cliff on those needs and benefits once the PPA expires,” Whitley said.

Fair and Equal

The Maine lawmakers also faulted CMP for offering “far less to Maine than Eversource offered New Hampshire during the Northern Pass process.”

New Hampshire would have received more than $210 million in benefits from Northern Pass, they said, while the TDI New England Clean Power “project would have resulted in direct payments of $372 million to Vermont for clean water, habitat conservation and clean energy development. CMP has not offered comparable mitigation for Maine.”

They cited other testimony before the PUC that the NECEC project “will suppress existing and future renewable energy generation in Maine due in part to increased congestion on the transmission system.”

The lawmakers concluded: “We are unwilling to sacrifice future development of Maine’s solar and offshore wind industries, which would provide real greenhouse gas benefits and more jobs for Maine citizens, just to provide Hydro-Quebec the ability to market its electricity in Massachusetts.”

Hydro-Quebec partnered separately with Eversource, Avangrid and TDI-NE on three different transmission projects for the MA 83D clean energy solicitation last summer.

May 6, 2018

CPUC Cautions of Return to Bad Old Days

By Jason Fordney

California could return to the conditions preceding the energy crisis of the early 2000s if the transition to fragmented decision-making and electricity procurement is not managed correctly, the Public Utilities Commission said in a report issued last week.

The report on California retail electricity choice, entitled “An Evaluation of Regulatory Framework Options for an Evolving Electricity Market,” is meant to guide the discussion as the CPUC, state lawmakers and other entities work to manage the disaggregation of energy procurement from traditional utilities to an environment with much more residential rooftop solar, community choice aggregators (CCAs) and private electricity sellers through the state’s Direct Access program, which allows nonresidential customers to purchase directly from a competitive supplier.

According to the paper, decision-making around reliability, affordability and safety is splintering from central authorities such as the CPUC to multiple entities.

“In the last deregulation, we had a plan, however flawed,” the report says. “Now, we are deregulating electric markets through dozens of different decisions and legislative actions, but we do not have a plan. If we are not careful, we can drift into another crisis.”

The paper examines how electric delivery can remain reliable as the market fragments, particularly from the growth of CCAs. It expresses concerns about reliability, affordability and ability to decarbonize the electric system if the transition is not managed effectively.

CPUC energy crisis direct access program — | *California PUC*

During the energy crisis, market design flaws, insufficient monitoring and “gaming” by market participants caused price spikes, collapse of competitive suppliers and rolling outages. The state became the model for how not to manage electricity restructuring and received much attention, particularly regarding the artificial shortages created by the Enron energy trading firm.

Splintering Model

The current model was developed after the crisis, with load-serving entities required to demonstrate each year that they have contracted for adequate energy supply. The paper poses the question of whether there needs to be a single entity responsible for policymaking, implementation and enforcement.

It also explores how new technologies could be financed, how to reduce the use of fossil fuels such as natural gas and how to properly compensate utilities. It also asks whether there should be a state entity to manage “behind-the-meter” generation and other entities that are not under the jurisdiction of the CPUC, as well as evaluating other regulatory models that evolved in New York, Illinois, Texas and Great Britain.

“I think there are solutions to a lot of the potential problems, although there is not a single or a dominant design to target them,” CPUC President Michael Picker told RTO Insider last week. He added that some customer choice models are built around a particular technology such as rooftop solar, battery storage, demand response or natural gas fuel cells that can be obtained through small generator incentive programs.

“We have to do something to address the disaggregation of supply and the splintering of decision-making,” Picker said. About 13% of load across the state is provided through the Direct Access program to commercial and industrial customers.

It’s not the CPUC’s job to get in the way of CCA growth, Picker said, but “we do have to do something to respond to the growing disaggregation.”

CCAs Respond

The CPUC got pushback from CCAs in February when it approved an order implementing a registration process for them along with other changes to the regulatory structure. (See CCAs Oppose CPUC Decision, Process.)

In a statement Thursday, the California Community Choice Association said the CPUC report “wrongly asserts today’s energy system lacks regulation and adequate planning.”

“Highly regulated locally controlled CCAs were designed to help correct the problems from the energy crisis, and they are performing as intended — delivering reliable, affordable and clean energy to local customers, while exceeding the state’s [greenhouse gas] goals,” Executive Director Beth Vaughan said. “It is important to recognize in this report that other states use energy-choice program models that differ widely from those used by CCAs in California.” She said CCAs are committed to “reliability, affordability, decarbonization and social equity.”

The CPUC said the report is not meant to advocate specific policy actions but seeks instead to “jumpstart a conversation.” Comments on the report are due on June 4, which can be filed at customerchoice@cpuc.ca.gov, and the commission has also set up a webpage for the initiative.

May 6, 2018

NRG Posts Q1 Profit on Asset Sales, Cost Savings

By Michael Kuser

NRG Energy is transforming itself by “right-sizing” its generation fleet, reducing costs and expanding its retail business, the company’s chief executive said during an earnings call Thursday.

NRG earned $233 million in the first quarter, compared with a loss of $169 million in the same period last year.

CEO Mauricio Gutierrez said the improved results were driven by $80 million in cost savings and higher energy prices caused by cold weather in Texas and the Northeast.

NRG continued to reduce its generation fleet last quarter, closing on the $42 million sale of its 154-MW Buckthorn Solar project to NRG Yield. The company also announced the sale of its Canal 3 peaking plant in Sandwich, Mass., for approximately $130 million, with the deal expected to close in the third quarter. It expects to close $3 billion in asset sales this year.

NRG last quarter also spent $210 million acquiring supplier XOOM Energy, expanding the company’s retail sales capabilities and presence in the East.

Texas Shines

While the company has in recent years highlighted the significant risk of retirements and the slowdown in new builds in ERCOT given persistently low power prices, Gutierrez pointed out the situation is showing signs of reversal.

“Last year, we finally saw the retirement of about 4,200 MW of uneconomic coal generation, which tightened reserve margins,” Gutierrez said. “As a result, we are entering this summer with the lowest reserve margin on record at around 10%. Prices have responded accordingly with summer on-peak prices currently trading at about $150/MWh.”

NRG Energy Inc. capacity auction earnings q1 2018 — NRG Headquarters in Princeton, NJ. | *NRG*

Asked whether he expects Texas to see an increase in either new gas-fired generation or more utility-scale solar coming online in response to the high peak prices, Gutierrez said one season does not mean much when deciding on a 25-year investment.

“So far, what we have seen is only the expectation on one summer of high prices,” Gutierrez said, adding that in an energy-only market such as ERCOT, “price is everything,” providing the “right signal and incentive” for developers to invest capital in the market. “So, you need to see two things: You need to see them high enough and you need to see them long enough to attract this capital investment.”

PJM Capacity Auction

Gutierrez also highlighted the PJM capacity auction for planning year 2021/22 being held this month, with results scheduled to be posted May 23.

“Last auction saw a slowdown in new builds and over 7 GW of announced retirements added to the PJM deactivation list this year,” he said. “But there is still uncertainty on how these will play out in terms of market tightening. As you are aware, some generators are seeking compensation for plants that are not needed for reliability and not economically viable.

“While some entities are grasping a bailout in the short run, we see capacity rationalization as a necessary first step towards a healthy market,” Gutierrez said. “And we are confident that there will be continued support for the competitive market value proposition. Beyond PJM, our risk portfolio is well-positioned given our fuel diversity and location near load pockets.”

Gutierrez referred to the “uncertain” effect of “all these out-of-market conversations that are happening today.”

But, he said, “I am encouraged by seeing FERC and the different ISOs take a very specific stance in terms of the protection of competitive markets and making sure that they don’t negatively impact those markets.”

Quotes courtesy of Seeking Alpha.

May 6, 2018

Con Ed Braces for Possible Regulatory Storms

By Michael Kuser

Consolidated Edison’s first-quarter earnings jumped more than 10% on an increased rate base and a weather-related boost in steam revenues, but the company noted Thursday that it faces regulatory scrutiny for its role in subway power outages, its tax accounting and its storm response preparedness.

The company earned $428 million in the first quarter, compared with $388 million in the same period a year ago.

“While we continue to face challenging weather events, we remain focused on our long-term strategy of providing customers with the technology and options they need to live and work today,” CEO John McAvoy said in a statement accompanying Con Ed’s May 3 earnings release.

Regulatory Update

A company presentation pointed out that, in a proceeding investigating a New York City subway power outage last April, the New York Public Service Commission last year issued orders requiring Consolidated Edison Company of New York (CECONY) to upgrade the electrical equipment that serves the subway system. The utility plans to complete the required actions this year.

The PSC in January also initiated an audit of the income tax accounting of certain state utilities, including CECONY and sister utility Orange and Rockland Utilities (O&R), which serves customers in southeastern New York and northern New Jersey (18-M-0013).

Con Ed earnings Q1 2018 NYPSC — ConEd plant on the East River at 15th Street in New York City

Con Ed noted that two storms in March damaged its utilities’ electric distribution systems, interrupting service to approximately 209,000 CECONY customers, 93,000 O&R customers and 44,000 Rockland Electric customers. Con Ed said the recovery of $106 million in storm-related costs is subject to review by the PSC and the New Jersey Board of Public Utilities, both of which are investigating utilities preparation and response to the storms, and may penalize them.

O&R last month updated its January rate filing with New York PSC, asking to increase its electric rates from $20.3 million to $22.5 million.

Tax Cuts and Rates

Con Ed expects the federal Tax Cuts and Jobs Act of 2017 to result in customer rates likely being reduced to reflect the reduction in the corporate tax rate from 35% to 21%, elimination of bonus depreciation and the amortization of excess deferred federal income taxes the utilities collected from their customers that will not need to be paid.

The PSC opened a proceeding on the new law (17-M-0815), and commission staff on March 29 recommended that most utilities be required to begin to credit their customers’ bills with the net benefits of the tax cuts on Oct. 1.

The company expects a commission decision after the 90-day comment period expires in late June.