Page 1543 – RTO Insider

July 10, 2015

Regulators, Generators, IMM Seek Changes to PJM Capacity Performance Order

By Rich Heidorn Jr.

State regulators, consumer advocates, generators and the Independent Market Monitor have asked the Federal Energy Regulatory Commission to modify its June 9 order largely approving PJM’s Capacity Performance plan.

Most of the rehearing requests were filed Thursday, along with PJM’s submission of a 556-page compliance filing responding to the commission’s request for changes to its plan.

Maryland and D.C. regulators asked the commission to reverse the order, while generators sought relaxation of penalty provisions. Two filings seek expedited review before PJM’s “transition” auctions begin July 27.

Load Forecast

One asked FERC to order PJM to update its peak load forecasts for the upcoming capacity auctions or delay them (EL15-83).

The complainants — the PJM Industrial Customer Coalition, the Sustainable FERC Project and regulators or consumer advocates from Delaware, D.C., New Jersey, Maryland, Pennsylvania and West Virginia — say that PJM’s newly designed load forecast could reduce the amount of capacity procured by approximately 7,000 MW, saving consumers about $625 million.

While PJM told stakeholders at the May Load Analysis Subcommittee meeting that the new model is a “noticeable improvement” over the current forecast, the plaintiffs say, the RTO has said the new forecasts won’t be ready for incorporating in the capacity auctions until November.

The transition auction for delivery year 2016/17 is set for July 27-28 and that for 2017/18 for Aug. 3-4. The Base Residual Auction for 2018/19 is scheduled for Aug. 10-14.

The plaintiffs say FERC should either order use of the new models under the current auction schedule, delay the auctions until November or reinstate the short-term resource procurement target — also known as the “2.5% holdback” — for the BRA. FERC eliminated the holdback in its June 9 ruling. (See FERC OKs PJM Capacity Performance: What You Need to Know.)

They asked FERC to rule by July 17, saying continued use of the current model “will lead to substantial and imprudent over-procurement of capacity, resulting in unjust and unreasonable capacity prices for consumers.”

The plaintiffs said PJM has overestimated the RTO’s reliability requirement by an average of 6.25% in delivery years 2010/11 through 2015/16. The new model attempts to better account for energy efficiency and other factors.

PJM Vice President of Planning Steve Herling told RTO Insider on Thursday that the RTO reworked its load forecasting model with a focus on how it would affect the regional transmission expansion planning process. “We have not even begun to figure what the implication will be for” the capacity market, he said. “It started as an RTEP issue.”

In addition, he said, there is more work to do, including updating zones with new metropolitan area mapping and investigating the current practice of using 40-plus years in weather simulations. And, he added, the model has yet to pass through the stakeholder process. “Any change like that has to go through a vetting process,” he said.

Annual DR

Most of the same complainants — along with the Public Power Association of New Jersey, Duquesne Light Co. and regulators and consumer advocates from Illinois — also are seeking expedited hearing of a complaint seeking to allow annual demand response resources to bid into the transition auctions.

The plaintiffs acknowledged that the commission’s June 9 order “did not discuss specifically” whether annual demand resources could participate in the transition auctions. “This specific issue was not raised for the commission’s consideration because, ostensibly, it was clear from the operative provisions of the as-filed version of Section 5.14D [of PJM’s Tariff] that the transition auctions applied to all Capacity Performance resources, which, by definition, includes annual demand resources and other types of resources.”

The complainants said PJM has told them and other stakeholders that the Tariff does not permit annual DR’s participation.

“PJM’s view is that only generation capacity resources are eligible to participate in transition auctions. PJM has acknowledged, however, that no operational basis exists for excluding annual demand resources from the transition auctions. It appears that PJM’s concern is whether sufficient bases exist under the Tariff language that has been accepted by the commission to allow all types of Capacity Performance resources to participate.”

PJM has not responded to the filing, but in a separate challenge by the Advanced Energy Management Alliance Coalition, the RTO said Thursday it intended to exclude DR and energy efficiency from the transition auctions.

PJM said the transition auctions were designed to “provide a glide path” for generation resources that needed time to make investments to meet Capacity Performance requirements.

“The decision to limit the transition auctions to generation capacity resources was made in light of the fact demand response resources or energy efficiency resources would not need the same glide path, and also taking into account the continued uncertainty associated with the availability DR and EE to serve as Capacity Performance resources” following the D.C. Circuit’s EPSA ruling voiding FERC’s jurisdiction over DR (EL15-80). (See Supreme Court Agrees to Hear Demand Response Appeal.)

Market Monitor: ‘Inconsistent’ Incentives

The Monitor requested FERC revise findings in its June order that it said “create incentives in the energy market that are not consistent” with the Capacity Performance market design.

The Monitor cited FERC’s rejection of PJM’s proposal to allow parameter limits based only on resources’ physical constraints, saying the commission’s action would result in increased uplift payments.

“By permitting generation owners to establish unit parameters based on non-physical limits, the … order has weakened the incentives for units to be flexible and has weakened the assignment of performance risk to generation owners,” the Monitor said. “Contractual limits, unlike generating unit operational limits, are a function of the interests and incentives of the parties to the contracts. If a generation owner expects to be compensated through uplift payments for running for 24 hours regardless of whether the energy is economic or needed, that generation owner has no incentive to pay more to purchase the flexible gas service that would permit the unit to be flexible in response to dispatch.”

In contrast, NRG Energy and Dynegy asked FERC to clarify that capacity resources will not be penalized if PJM does not schedule them or reduces their output as the result of parameter limitations approved by the RTO.

The Monitor also called for changes regarding eligibility and documentation of risk premiums, the sub-zonal dispatch of DR and the calculation of “performance hours” and peak load obligations.

State Regulators Fear Higher Prices

The Illinois Commerce Commission said the commission’s order will create unnecessary barriers to market entry and undermine market power mitigation, resulting in higher costs for consumers.

The ICC said FERC erred in eliminating unit-specific cost reviews and the 2.5% holdback. It also faulted FERC for limiting the types of resources permitted to aggregate for the purpose of performance measurements, and in prohibiting external resources lacking pseudo ties from offering as Capacity Performance.

The Pennsylvania Public Utility Commission and the Delaware Public Service Commission joined the ICC in challenging the commission’s changes to PJM’s market mitigation rules and the elimination of the 2.5% holdback. They also questioned how penalties will be calculated; changes to credit requirements; the transition mechanism; and the elimination of extended summer DR and limited DR.

The Delaware commission also filed a separate rehearing request asking FERC to “identify the components of the balance upon which it relied for the determination that the market rule changes were just and reasonable” and asking that PJM be required to make informational filings regarding the costs and benefits of the new rules.

“Without such a requirement from this commission, any information and/or data would only be available on an ad hoc basis, which would not provide an appropriate foundation for the commission to make any assessment as to the ultimate cost effectiveness to customers of [Capacity Performance] and, perhaps more importantly, whether the costs for the implementation of [Capacity Performance] are appropriate and necessary,” Delaware said.

Generators: Penalties Excessive

The PJM Power Providers (P3) Group supported the commission’s ruling but asked FERC to clarify that generators operating within their approved parameters would not be subject to non-performance penalties. It also asked for clarification on what “performance quantifiable risks” can be included in avoidable cost risk calculations for units seeking to submit offers above the market seller offer cap. Exelon also requested rehearing on the issue.

“While both PJM and the commission expressly supported Tariff provisions that allow risks of fulfilling the obligation to offer capacity to be reflected in capacity offer cap calculations, the commission should go one step further and direct PJM to specifically enumerate known risks in addition to permitting the reflection of all reasonable risks undertaken to support a capacity offer,” P3 said.

Essential Power, Competitive Power Ventures, NextEra Energy and Invenergy Thermal Development contested FERC’s decision to eliminate monthly stop-loss limitations from PJM’s proposal, saying it failed to justify its decision through “reasoned decision-making.”

The coalition also said the commission erred in deciding that generator non-performance should not be excused even in circumstances beyond the control of generators, such as catastrophic weather events, compliance with state-approved tariffs or PJM-approved transmission outages.

GE Energy Financial Services, the operator of the 1884-MW Homer City coal-fired generating plant in Indiana, Pa., challenged FERC’s decision to make generators liable for a failure to deliver due to problems with transmission lines and switchyard equipment outside plant boundaries.

It said FERC was wrong in agreeing with PJM that generators were the market participants best able to bear the risk of transmission outages. “The best-placed party to bear this risk is the relevant transmission owner (and through it, load), which already collects payments to maintain these facilities,” it said.

“Unlike the ‘strict liability’ standard for generation delivery included in the CP revisions, transmission owners have limited their liability based on the customary ‘prudent industry practice’ standard. Thus, a supplier may have no recourse at law against its transmission ‘vendor’ — a sole source provider — even though the transmission owner has been paid to provide the service that it failed to deliver.”

The generator acknowledged that PJM may designate a transmission outage as a “catastrophic force majeure” that excuses generators for non-performance. But it noted “those events are intended to be region-wide in nature, even though Homer City will be equally unable to deliver its power upon the failure of its local transmission lines.”

“The penalties assessed against Homer City in that event would be funneled to other, luckier resources, which were fortuitously not in the wrong place at the wrong time.”

Public Service Enterprise Group also asked the commission to reinstate the existing force majeure provisions.

Calls for Reversal

While most of the filings sought to tweak the new rules, regulators from Maryland and D.C. argued that FERC should reverse its approval of PJM’s overhaul of the capacity market, saying it is “unnecessary for reliable service operations” and will increase end user costs in PJM by as much as $6 billion.

The commissions said the penalty provisions are not consistent with the higher revenues expected under the changes and said it should have held evidentiary hearings over the cost effectiveness of the changes. They also contend that the transition auctions are unnecessary.

Public Citizen also asked the commission to reverse its approval, citing the dissent by Chairman Norman Bay, who contended PJM’s overhaul of the capacity market was unwarranted. (See Norman Bay’s Dissent: ‘Two Carrots and a Partial Stick’.)

The group also asked that the commission review rates resulting from future capacity auctions under its “just and reasonable” standard.

“Public Citizen does not believe that the findings in this case are supported by ‘substantial evidence,’ but rather by the commission’s desire to further its market-based experiments in promoting and enabling ISOs and RTOs. Public Citizen fears that in doing so, however admirable its original intentions may have been, the commission may have lost sight of the primary goal of the [Federal Power Act], the protection of ratepayers from excessive rates and charges, and in fact may be slowly conceding its ability to protect ratepayers at all.”

— Suzanne Herel contributed to this article.

July 7, 2015

Iberdrola Withdraws UIL Acquisition; Plans to Refile

By William Opalka

Spanish energy giant Iberdrola SA on Tuesday dropped its bid to acquire UIL Holdings but promised to file a new application by the end of the month that would address objections raised by Connecticut regulators.

The Connecticut Public Utilities Regulatory Authority issued a draft decision June 30 that lambasted the companies’ application, recommending a final rejection, while giving them a week to respond. PURA said the acquisition was not in the public interest and offered no benefit to consumers. (See Connecticut Regulators Threaten to Reject Iberdrola-UIL Merger.)

The companies last week asked for a 60-day extension to address the decision, which outlined conditions including “ring fencing” of the local utilities, a three-year rate freeze and a commitment to keep their headquarters in the state for seven years. PURA immediately rejected that request as not affording enough time for adequate review and said the companies should file a new application that resets the clock at 120 days.

“The applicants hereby withdraw the pending application, in order to have the docket terminated as of this date and the remaining procedural schedule cancelled, which would, in turn, facilitate the applicants’ filing of a new application,” Iberdrola wrote.

Iberdrola has offered $3 billion for Connecticut-based UIL, including its United Illuminating electric distribution utility and three gas distribution companies in Connecticut and Massachusetts.

In a separate filing made hours before the companies dropped their bid, the Connecticut Industrial Energy Consumers praised the PURA draft decision. “CIEC commends the authority for reaching conclusions regarding the public interest of the proposed transaction commensurate with the record evidence,” the group wrote.

In mid-day trading, UIL stock shot up $1.46 after the announcement to $47.19.

PURA said June 30 it would not approve the deal without “ring fencing” provisions to protect UIL’s Connecticut electric and gas distribution companies from bankruptcies by Iberdrola’s other operations.

Regulators also said they “cannot conclude that the applicants will continue to possess the ability to provide safe, adequate and reliable service to the public.” It said Iberdrola’s financial strength and managerial expertise were adequate, but the company did “not possess the requisite suitability and responsibility to acquire UIL Holdings.”

July 3, 2015

REV Straw Proposal Delayed Another Month

A crowded docket has delayed several key pieces of New York’s Reforming the Energy Vision, including the Department of Public Service staff’s Track 2 straw proposal on ratemaking and rate design.

That document — originally expected in January and then delayed twice to June 1 and July 1 — is now due on July 28, along with staff-proposed rules governing commission oversight of distributed energy resource suppliers.

The New York Public Service Commission secretary on Tuesday granted extensions to commission staff and a working group that faced July 1 deadlines. “These extension requests are generally premised on the need to address concerns expressed by parties and members of the public for relief from the potential burdens imposed by the simultaneous issuance of four products in this proceeding,” the secretary wrote.

In requesting the delay, commission staff noted the overlap among the proposals, its own workload and the public comment periods for each.

The Market Design and Platform Technology Working Group report is now expected on July 13.

A staff benefit cost analysis was filed July 1.

The August 2014 Track 1 straw proposal preceded the first REV order, which created the framework for development of clean and distributed energy resources. That led to the February PSC order that also set the schedule for these four docket items. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)

“Track 2 will propose specific regulatory reforms to the utility business model, rate-making approaches and rate design to achieve REV policy goals,” according to the Rocky Mountain Institute, an advisor to the PSC.

— William Opalka

July 3, 2015

FERC Accepts NYISO Voltage Support Rate

The Federal Energy Regulatory Commission on Tuesday accepted NYISO’s new method for calculating payments for voltage support services (VSS), which will keep the overall expenditure constant in the near term (ER15-1042).

FERC said in April that the ISO needed to more fully explain its proposed methodology. The existing rate was set in 2002. (See FERC Requests More Info on NYISO Voltage Compensation Change.)

NYISO derived the $2,592/MVAR compensation rate by dividing the total VSS compensation paid to qualified VSS suppliers in 2012 by the total lagging and leading reactive power capability of all qualified VSS suppliers in 2012.

“This explanation demonstrates that the proposed amendments maintain the approximate total dollar value of the current VSS program in the near term,” FERC wrote.

NYISO used 2012 as the base year for its calculations when it began developing the proposal. From 2014 onward, the payments will be tied to the consumer price index.

“We find that by applying a VSS compensation rate to both leading and lagging reactive power capability, NYISO’s proposal reasonably addresses the failure of the existing rate to address a significant shift in reliability needs, from primarily lagging reactive power support to primarily leading power support,” FERC also wrote.

The revisions are effective Jan. 1.

— William Opalka

July 3, 2015June 15, 2023

Dynegy: No Evidence of Misconduct in Auction

By Chris O’Malley

MISO and its Market Monitor have joined Dynegy in denying allegations of improper conduct in the RTO’s Planning Resource Auction last April, which resulted in a nine-fold price increase in Zone 4.

The filings with the Federal Energy Regulatory Commission were in response to complaints in May by a consumer group and the Illinois Attorney General that Dynegy may have illegally manipulated the auction (EL15-70).

MISO’s 186-page response insists that it followed commission-accepted rules (EL15-70). It also stated that its Independent Market Monitor confirmed that the auction was in compliance “and produced the results it should have produced” despite prices in Zone 4 clearing at $150/MW-day compared with just $16.76 a year earlier.

“Those higher prices are the source of complainants’ discontent. However, MISO conducted the auction exactly as required under its Tariff, and none of the complainants provides any evidence to the contrary. Accordingly, these complaints should be dismissed with prejudice,” MISO told FERC.

MISO’s filing came a day after public service commissions, consumer watchdogs and attorneys general in Illinois, Indiana, Iowa, Michigan, Minnesota and Wisconsin asked FERC to investigate the auction, saying they share concerns that Dynegy “was able to exercise market power” in Zone 4.

“Due to Dynegy’s control of such a significant portion of the capacity available in Zone 4, the capacity market [in the zone] may no longer produce competitive market-based prices for capacity,” the group wrote.

Public Citizen and Illinois Attorney General Lisa Madigan asked FERC on May 28 to investigate whether Dynegy illegally manipulated MISO’s auction through its bidding strategy. Public Citizen also alleged MISO brushed aside recommendations by its staff that Zones 4 and 5 be merged due to their concerns about Dynegy’s growing share of capacity in Zone 4 after the company acquired four generators from Ameren in recent years. (See Public Citizen: Investigate Dynegy Role in MISO Auction.)

Dynegy: We Didn’t Withhold

In a 304-page filing with FERC last week, Dynegy said merging zones wouldn’t have met the requirements of the MISO Tariff. The company said it made no secret of its opposition to merging, meeting at one point with FERC staff to discuss its position.

But Dynegy spent most of its filing denying the more serious allegations of physical or economic withholding. It said all 6,419 MW of its Zone 4 capacity was “either sold bilaterally or at wholesale, exported or offered into the auction.”

The company also rejected claims of economic withholding, including an affidavit from consultant FTI Consulting Managing Director Susan Pope.

“Because of uncertainty about the quantity of offers into the 2015/16 PRA auction from non-Dynegy parties, at the time it formed its offers for this auction Dynegy would not have known with certainty whether and to what extent its non-zero priced offers would be needed to meet the Zone 4 local clearing requirement,” Pope wrote. “This is because under the MISO PRA market rules, there is substantial uncertainty concerning the quantity of supply offers that will be made into the auction.”

The company also rejected the Illinois attorney general’s claim that Market Monitor David Patton improperly calculated its opportunity costs, saying his $155/MW-day estimate reflected its ability to sell capacity into PJM.

The company said the complainants ignored that PJM’s most recent Incremental Auction cleared at $163/MW-day less than a month before MISO’s auction last April.

Market Monitor’s Response

Patton fired back at the complainants’ premise that Dynegy had an unusually strong market presence in Zone 4 and free rein to commit economic withholding.

Zones with “pivotal” suppliers such as Dynegy “are extremely common,” and that’s one reason that RTOs have market power mitigation measures in place, he said, adding that MISO properly applies such measures in its Tariff.

“Our [monitoring] found no evidence of physical withholding,” Patton said.

Patton also said that despite substantially lower auction prices in Zone 4 in previous years, “the simple fact the price of Zone 4 is higher in this planning year than in previous planning years provides no meaningful evidence in support of the complaint.”

In fact, Patton contends prices in other MISO zones “are unreasonably low.”

Patton has often argued that MISO’s capacity market is flawed because it uses a vertical demand curve, which can result in unstable capacity prices. With a vertical demand curve, the last megawatt of capacity needed to satisfy the minimum requirement has a value equal to the deficiency price, while the first megawatt of surplus has no value.

“This means that as the surplus declines to zero, the market will suddenly start to clear at much higher prices,” Patton said.

He also previously said the need for reform “may become particularly acute” as planning reserve margins decline toward the minimum requirement level with the anticipated retirement of significant amounts of coal-fired capacity as early as the 2015/16 planning years.

The $150/MW-day in Zone 4 “is still relatively low when comparing the cost of building a new unit at $247/MW-day,” Patton added.

He said the Zone 4 clearing price also reflects the convergence between MISO and PJM markets, with more than 1,000 MW of capacity in the zone committed to PJM.

Reasons for Price Jump

In its filing, MISO said the fact that the auction prices vary sharply from one year to the next does not establish that prices are unjust or that they are “the product of any lack of oversight or administration on MISO’s part; or that the price was the product of market manipulation.”

Results can vary by location and by year due to commercial decisions of market participants or the supply of capacity offered into the auction, MISO said. In the most recent auction, higher-priced local resources were needed to meet the local reliability requirement in Zone 4, MISO said, because fewer resources were offered in at zero.

Compared to the prior auction, more price-sensitive offers were submitted and more capacity was procured through the auction than through bilateral contracts, MISO said.

Zones may be affected by differing state procurement rules applied to load-serving utilities.

“Each of these factors resulted in higher prices than in the 2014-2015 PRA and are examples of factors that can raise rates wholly independently of any seller misconduct.”

The complainants failed to provide facts to back their claims and their arguments are speculative, collateral attacks, the RTO said.

“For example, Public Citizen speculates that the rate for Zone 4 ‘may be the result of illegal manipulation and gaming of the auction bidding process’ and that ‘Dynegy may have engaged in intentional capacity withholding.’”

Market Concentration

In their complaints, Public Citizen and Madigan raised concerns about FERC’s approval of Dynegy’s acquisition of generating units from Ameren — questioning the commission’s market power analysis at the time.

In its response, MISO said the two complainants did not intervene in the commission proceeding involving Ameren’s application to sell generating units to Dynegy.

MISO said FERC rejected a protest that asserted Dynegy’s proposed acquisition of the Ameren units should be analyzed in a submarket, “finding that the MISO balancing authority area properly defined the geographic market for the purposes of analyzing horizontal market power issues.”

Moreover, MISO said it determined previously that 85% of the capacity for Zone 4 had to be located within the zone. That local clearing requirement was set as a function of local reliability needs, the capacity in the zone and its import capability.

Public Citizen alleged that failing to adjust the local clearing requirement following Dynegy’s acquisition of new generation in the zone may have helped it execute a capacity withholding scheme.

MISO countered that Public Citizen failed to explain how the RTO could set aside the mathematical calculation that its Tariff requires “or how local reliability needs would have been satisfied under its approach given the amount of capacity in Zone 4 and capacity import limits.”

Not ‘Bullied’

One of the more incendiary allegations in the Public Citizen complaint is that MISO rejected recommendations by staff members to merge Zone 4 and Zone 5, given Dynegy’s growing dominance in Zone 4. The alleged motivation: fear that Dynegy would leave MISO for PJM.

Public Citizen cited minutes from a 2014 MISO Loss of Load Expectations Working Group in which a manager of economic studies purportedly stated that staff “are concerned with Dynegy’s offer strategy in the next Planning Resource Auction as they [Dynegy] are now the dominant provider of capacity in the zone.”

Public Citizen alleged the zone merger proposal was swatted down due to “stiff resistance” from Dynegy. The group specifically pointed to Dynegy executive Mark Volpe, who served as vice chair of MISO’s Supply Adequacy Working Group, claiming his role and that of others in the auction design and coordination “do not lend credibility to the auction process and cry out for FERC review of the auction results under Section 206 at least.”

In its response, MISO said there is no basis in fact that Dynegy “bullied it” or threatened to defect to PJM.

MISO said it did study and engage stakeholders in talks about combining Zones 4 and 5 but did not make the change “because additional consideration was warranted based on extensive stakeholder feedback.”

That decision “was made based upon the requirements of the Tariff, overall stakeholder input and MISO’s independent analysis — not based on threats or pressure from Dynegy.”

Discussions about combining zones and other aspects of resource adequacy requirements should continue to be conducted through the stakeholder process, MISO insists, “which will more inclusively engender broad stakeholder and state regulator involvement as compared to settlement judge procedures.”

July 1, 2015

Connecticut Regulators Threaten to Reject Iberdrola-UIL Merger

By William Opalka

Connecticut regulators said Tuesday they will reject Iberdrola SA’s acquisition of UIL Holdings without much stronger ratepayer protections, issuing a draft decision in which they blasted the Spanish conglomerate’s management and said they would not approve the deal based on a “leap of faith.”

The Public Utilities Regulatory Authority said Iberdrola failed to reassure it that UIL’s Connecticut ratepayers would be adequately protected from any financial stresses the company may experience from its international operations or other units in the U.S. (15-03-45).

“The authority … questions why the applicants would file a change of control application and not be prepared to provide any evidence that would demonstrate that the transaction is in the public interest,” PURA said. “To not research or provide evidence as to how the transaction would benefit (or harm) ratepayers demonstrates a lack of concern or interest by the applicants in this important area.”

In March, Iberdrola announced it planned to acquire UIL, which has electric and gas distribution companies in Connecticut and Massachusetts, in a cash and stock deal valued at $3 billion. It said it would incorporate UIL’s operations into its U.S. subsidiary, Iberdrola USA. (See Iberdrola Broadens Northeast Footprint in $3B UIL Deal.)

PURA said it would not approve the deal without “ring fencing” provisions to protect UIL’s Connecticut electric and gas distribution companies from bankruptcies by Iberdrola’s other operations.

Final Decision July 17

The companies have until July 7 to provide replies to the 43-page draft. PURA said a final vote on the proposed merger is scheduled for July 17. For the merger to proceed, PURA is also demanding a three-year distribution rate freeze and a seven-year commitment for the headquarters to stay in the state, among other items.

Reaction on Wall Street was swift. UIL stock was trading at about $47.60 throughout the day but immediately dropped to about $45.50 when the draft was released at 3 p.m. It recovered slightly to close Tuesday at $45.82, off $1.71.

UIL CEO James P. Torgerson issued a statement Wednesday saying the company was disappointed in the draft decision but noted that it “provides an opportunity to UIL and Iberdrola to address” regulators’ concerns.

“We look forward to providing clarification and additional information to PURA quickly,” Torgerson said. “We truly believe the proposed transaction can bring significant value to our customers.”

Iberdrola did not respond to requests for comment.

Ring Fencing

In hearings, the state Office of Consumer Counsel said regulators should insist on the type of ring fencing provisions that Exelon has agreed to in its proposed acquisition of Pepco Holdings Inc.

Iberdrola objected, saying the ring fencing conditions were “unprecedented, unnecessary and not within the authority’s jurisdiction.” It agreed to 39 of the 97 conditions proposed by the OCC.

PURA said those conditions were insufficient. “The authority concludes that ring fencing is a necessary condition for this change of control to protect ratepayer interests.”

Iberdrola had separately offered a $400,000 renewable energy integration study, various scholarships worth more than $300,000, charitable giving of at least $2.5 million over four years, a rate credit of $5 million, a $2 million economic development grant and a one-year freeze on electric distribution rates. PURA dismissed the offers — made more than halfway through its 120-day review — as “too little and too late.”

Local Control

Regulators also questioned Iberdrola’s promises that UIL would remain under local control, with the Connecticut management in place, noting the company’s recent history of buying and selling local distribution gas companies.

Iberdrola acquired Connecticut Natural Gas, Southern Connecticut Gas and Berkshire Gas, in Massachusetts, through its 2008 purchase of Energy East Corp., which it rebranded as Iberdrola USA. The company then sold the gas utilities to UIL in 2010. They would be reacquired in the proposed merger.

When Iberdrola first owned CNG and SCG, PURA said, it responded to regulators’ ruling in a 2009 rate case by ordering the gas companies to develop plans that included “austerity measures and work force reductions.”

“The authority is concerned with the applicants’ commitment to local management and whether its management and management practices are suitable for UIL,” PURA wrote.

One issue not raised in the decision is the fate of the defunct English Station generating plant, which sits on a contaminated site in New Haven. Some state officials believe the merger is an opportunity to finally clean up the site, but PURA has already determined it is outside the scope of the merger proceeding. (See Connecticut Officials at Odds over Plant Clean-up, Merger.)

June 30, 2015June 15, 2023

NEPGA: Order Sloped Demand Curve in FCA 10

By William Opalka

The New England Power Generators Association says ISO-NE should adhere to a planned change to a sloped demand curve in the next Forward Capacity Auction (ER14-1639).

NEPGA has asked the Federal Energy Regulatory Commission to clarify a previous order that directed the RTO to continue the effort to eliminate the need for administrative pricing in zones that are short of generation resources or suffer from transmission constraints.

ISO-NE informed FERC in May that the complexities involved in switching to the sloped demand curve could not be resolved in time to “result in just and reasonable outcomes” in FCA 10, which is scheduled for Feb. 8, 2016. ISO-NE also cited the need to reconfigure the zones within the RTO to resolve transmission constraints identified since the last auction as an impediment to a timely resolution. (See ISO-NE Proposes New Capacity Zones for FCA 10.)

NEPGA suggests that FERC did not explicitly order a sloped zonal demand curve “only because it relied on ISO-NE’s commitment to file sloped zonal demand curves for commission review in advance of FCA 10.”

NEPGA is asking the commission to initiate a Section 206 proceeding and order ISO-NE to file the sloped zonal demand curves developed by the RTO and New England Power Pool stakeholders.

“Market participants have expected for over a year that their participation in FCA 10 would be based on both system-wide and zonal sloped demand curves. Clearing capacity resources on a curve better reflects the incremental value of capacity and leads to a more efficient market outcome,” NEPGA wrote.

June 30, 2015

Plains Eastern Tx Line Foes Cry Foul over DOE Review

By Tom Kleckner

Opponents of Clean Line Energy’s proposed Plains & Eastern transmission line are asking for public hearings and a way to intervene on the project, which would span 720 miles from Oklahoma to Tennessee.

A group called BLOCK Plains & Eastern Clean Line: Arkansas and Oklahoma filed petitions with the Federal Energy Regulatory Commission and the Energy Department’s Office of Electricity Delivery and Energy Reliability on June 16, asking them to conduct a rulemaking for implementing Section 1222 of the Energy Policy Act of 2005.

The Plains & Eastern is the first transmission project being developed with the department under Section 1222, which authorizes the Southwestern and Western Area Power Administrations to participate in transmission projects with third parties in states where they operate if the department determines that they are necessary to reduce congestion or meet demand.

Section 1222 does not allow financial participation by those agencies, but it does authorize the Energy Department to facilitate private sector participation in transmission development by accepting and using third-party funds.

“There is no ‘normal process’ [for Section 1222],” Carol Overland, attorney for BLOCK Plains, said in an interview. “It’s not something ever used before and DOE has not established rules for Section 1222, so we have asked for a rulemaking.”

FERC rejected BLOCK Plains’ petition last week, saying Section 1222 “does not give the commission rulemaking or other authority regarding these matters and is therefore outside of the commission’s jurisdiction” (RM15-22).

Overland said BLOCK Plains has yet to hear from the Energy Department. However, the department has extended the public comment period to July 13, saying it is “accepting comments on whether the proposed project meets the statutory criteria listed in Section 1222 … as well as all factors included in DOE’s 2010 request for proposals.”

The department selected the Plains & Eastern project in 2012 under the RFP. Clean Line hopes to partner with the Southwestern Power Administration, which owns transmission lines and facilities in Texas, Oklahoma, Missouri, Louisiana and Arkansas. (See Clean Line Starts Online Petition for DOE Tx Approval.)

BLOCK Plains, which says its represents Arkansas and Oklahoma landowners, contends the department has improperly conducted reviews on the environmental impact of the project, its need and routing options without first creating a rulemaking process for Section 1222.

Due Process

“The process chosen by the department raises due process issues because there are no established rules, the department’s process severely limits public participation and transparency [and] restricts access to information, and thus far the department offers no opportunity for public hearings or intervention in a contested case,” the group said in its petitions. “The process chosen by the department also severely limits building a record that would support any decision by the department. There is no justification for operating without rules.”

The Plains & Eastern project would deliver more than 3,500 MW of energy from wind farms in the Oklahoma Panhandle to the southeastern U.S. The DC line would connect with the Tennessee Valley Authority.

The department has closed comments on a draft environmental impact statement for the project and is now preparing a final EIS. Clean Line hopes to begin construction on the Plains & Eastern project in 2016, with commercial operation as early as 2018.

June 30, 2015

Project Interest Overwhelms New York’s Green Bank

By William Opalka

New York’s Green Bank has generated so much interest from clean energy and energy efficiency developers that it is asking to borrow from the private markets as well as revise allocations from its state sponsor.

In a report filed with the New York Public Service Commission on Thursday, the bank’s sponsor, the New York State Energy Research and Development Authority (NYSERDA), said its schedule to capitalize the bank with $1 billion over five years is inadequate for its potential project portfolio.

It is asking the PSC for permission “to obtain an external borrowing facility to provide the necessary liquidity and the certainty of sufficient available capital that is critical for private sector engagement” (14-M-0094). The bank was initially funded with $200 million last year and has received requests for $734 million through mid-June.

In its annual business plan filed on June 19, the bank said it has received funding applications that could be leveraged into more than $3 billion worth of clean energy projects statewide.

‘Pillar’ of REV

The bank is one of four initiatives of New York’s Clean Energy Fund, which NYSERDA calls a “key pillar” of the state’s Reforming the Energy Vision program. The fund also includes the $1 billion NY-Sun initiative to build solar projects throughout New York. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)

The bank’s business model is predicated on projects receiving $3 from the financial markets for every $1 in publicly backed funds.

More than half of the current funding requests — in both the number of projects and their financing needs — has come from energy efficiency programs. The rest is divided among wind, solar, bioenergy and other projects.

The $734 million in funding requests are in various stages of the bank’s pipeline. As of June 12, the Green Bank had $338 million of projects in its “active portfolio,” meaning they had passed advanced stages of review by its scoring committee. About $500,000 in transactions have closed.

The bank started in 2014 with plans to be capitalized with $1 billion in public funding over five years. Last year it received $165 million in ratepayer funds through the system benefits charge (SBC) and another $45 million from New York’s share of money from the cap-and-trade program of the Regional Greenhouse Gas Initiative.

Seeking Advance

NYSERDA says it appears the bank’s current funding levels will be unable to keep up with the amount of projects seeking aid.

The bank is seeking an advance of $150 million now to keep momentum going in the project pipeline. It would then draw funds from NYSERDA over a total of 10 years instead of five, with lower annual allocations over the extended time frame. It said the private credit facility it is seeking “would be put in place at the point it is needed, sized to ensure that the available amount would not itself become the constraint on [the bank’s] ability to run and grow its business.”

Without the $150 million, NYSERDA said, the bank will lose $1.5 billion in private investment over the next decade.

The bank’s aim is to become self-sustaining within a few years as loans are repaid and that money is recycled to fund future projects. The bank anticipates it will reach a “steady state” of annual commitments of about $200 million.

The bank was formed to leverage investment in clean energy technologies and energy efficiency programs that may not attract private capital on their own.

But the bank’s report says its expertise was also crucial in assisting two upstate clean energy projects that ultimately were financed through private sources. It cited a 60-MW biomass energy project at the U.S. Army’s Fort Drum, for which the bank was originally committed to purchase $10 million of its debt.

It also said its consultations with private banks helped familiarize them with an ongoing project to install solar arrays at several Finger Lakes region vineyards.

June 30, 2015

Transmission Developer: PJM TOs Inflating Upgrade Costs for ARRs

By Michael Brooks

A merchant transmission developer last week accused several PJM transmission owners of inflating the costs of upgrades necessary to approve three auction revenue rights requests.

TransSource LLC asked the Federal Energy Regulatory Commission to order PJM to provide it with data showing how the RTO calculated the almost $1.7 billion in upgrade costs in its system impact studies (SIS) for the requests. TransSource said the RTO has repeatedly refused to release the data, in violation of its Tariff (EL15-79).

The company also requested fast-track processing of its complaint and asked that FERC suspend a July 12 deadline to execute facilities study agreements in order for the requests to retain their positions in the ARR queue.

TransSource — not to be confused with Transource Energy, a joint venture of American Electric Power and Great Plains Energy — said that if it misses the deadline and forfeits its queue positions, it could lose $6 million per month in incremental ARR revenues.

PJM estimated the requests, identified by their queue position numbers Z2-053, Z2-069 and Z2-072, to be worth, respectively, 156.1 MW, 105 MW and 204.6 MW in incremental ARRs. It estimated $376.5 million, $783.8 million and $586.8 million in upgrade costs.

TransSource alleges that the transmission owners whose lines would require upgrades necessary to award the ARRs “intentionally assigned to those queue positions a scope of mitigation that is materially too broad in an effort to defeat TransSource’s network upgrade request.”

Z2-053 and Z2-069 are both sourced in Bridgewater, N.J., and sink in Hoboken and South River, respectively. Z2-072’s source is the Indian River power plant in Delaware, and its sink is New Church, Va., on the Delmarva Peninsula. The ARRs require upgrades on lines owned by Public Service Electric and Gas, PPL, Jersey Central Power & Light and Delmarva Power & Light.

“On 12 occasions TransSource has asked PJM to explain how it determined the scope of mitigation used in its SIS and has requested access to the underlying data inputs, assumptions that the PJM TOs submitted to PJM and that PJM used to determine the SIS scope of mitigation and costs. Each time, PJM has refused,” TransSource said. PJM told TransSource that it had no right the data, according to the company.

TransSource pointed to the section in the PJM Tariff that requires the RTO to “provide a copy of the system impact study and, to the extent consistent with the Office of the Interconnection’s confidentiality obligations in … the Operating Agreement, related work papers to all new service customers that had new service requests evaluated in the study and to the affected transmission owner(s).”

The company said the scope of work outlined in the studies is “badly inflated and intended to defeat the TransSource network upgrades … making it difficult, if not impossible, for TransSource to secure the financing required for its network upgrades.”

TransSource added that its queue positions “directly affect numerous PJM Order 1000 Regional Transmission Expansion Projects, several of which stand to be rendered unnecessary if TransSource’s projects are completed and become operational.”

The complaint was filed by TransSource Manager Adam Rousselle, who did not return a request for comment.