Page 1562 – RTO Insider

April 14, 2015June 15, 2023

MISO-PJM Cross-Border Projects Still Languishing, NIPSCO Says

By Chris O’Malley

Northern Indiana Public Service Co., which filed a complaint in 2013 over its frustrations with MISO and PJM’s interregional planning process, says nothing much has changed since then.

“Close to one and one-half years have passed since NIPSCO filed its complaint in this docket, and the same pattern of a great deal of process with no results appears to be holding,” the utility said in a March 31 filing with the Federal Energy Regulatory Commission.

More than a decade after the MISO-PJM seam was formed, no cross-border projects have been approved and built, while hundreds of millions of dollars in market-to-market payments have been made, NIPSCO said, “including approximately $500 million since 2008.”

A MISO member, NIPSCO is located between two PJM transmission zones, Commonwealth Edison to the west and American Electric Power to the east.

NIPSCO’s filing was one of almost a dozen responses FERC received from MISO and PJM stakeholders in response for its request for comments on six rule changes proposed by NIPSCO. (See related story, FERC Floats Possible Orders on PJM-MISO Seam.)

FERC posed the questions as preparation for a yet-to-be-scheduled technical conference on the issues raised in NIPSCO’s complaint (EL13-88).

Three-Step Process

NIPSCO wants FERC to order the MISO-PJM cross-border transmission planning process to run concurrently with, rather than after, the RTOs’ regional transmission planning cycles.

Without such a change, NIPSCO said, it would take more than three years for a beneficial market efficiency project to navigate its way through the three independent processes currently in place.

As an example, NIPSCO pointed to its proposed Reynolds-Wilton Center project, which had been part of the market efficiency study process in MISO’s Transmission Expansion Plan (MTEP13).

Proposed in May 2012, the project was found by MISO to have a strong benefit-to-cost ratio and would have had significant benefits for PJM, NIPSCO contends.

The project was put on hold until it could be studied in the Interregional Planning Stakeholder Advisory Committee process. It didn’t pass; MISO re-evaluated the project a year later, but it didn’t pass MISO market efficiency metrics.

Had it passed IPSAC, however, it would have taken 42 months, NIPSCO estimates.

As it stands, a project would first have to pass through one regional process, with its specific metrics and an independent model built for that study year. Then it would have to pass an interregional process with specific metrics. Lastly, it would have to pass the final regional process again with its specific metrics and model, NIPSCO said.

“Over 10 years of history have verified that no developer has had the necessary foresight or fortitude to successfully run the gauntlet of the MISO-PJM interregional process. NIPSCO, therefore, does not believe that it is possible for a project to navigate all three existing processes.”

NIPSCO is not alone in that view. Southern Indiana Gas & Electric also faulted the three-step process in its response to FERC’s questions.

Other Views

But other stakeholders, including ITC Transmission, said they don’t believe that forcing the cross-border and regional transmission planning processes to run concurrently is the most effective approach. ITC recommends that FERC require MISO and PJM to eliminate the three-step approval process altogether.

Instead, ITC said that projects approved in the coordinated system plan under provisions of the MISO-PJM Joint Operating Agreement should automatically be recommended for approval by both RTOs for cost allocation in their respective regional transmission plans.

“MISO and PJM should also establish a new project category for ‘interregional projects’ in their respective regional planning processes,” ITC said.

Among other stakeholders weighing in is AEP, which maintains that modifying the JOA to conduct concurrent joint and regional studies with identical criteria “is simply untenable.”

AEP said each RTO has planning criteria to address its regional needs, plus has to coordinate with other transmission systems whose regional planning criteria may differ. AEP also said FERC Order 1000 specifically recognizes that regional differences are valid.

As for cross-border market efficiency projects, AEP suggests that each RTO use its regional study process to quantify its regional market efficiency needs and congested flowgates. They also should invite stakeholders to submit both regional and interregional proposals.

“If the sum of each RTO’s portion meets or exceeds the total cost of the interregional proposal, then the proposed interregional project would be included in the list of finalists from which the most efficient and cost-effective projects would be selected,” AEP said.

Cost apportionment of approved cross-border projects would be in proportion to the market efficiency benefits that each RTO derives, AEP said.

RTOs: Process is Improving

MISO and PJM rejected assertions that their regional transmission planning cycles are impeding cross-border projects.

In joint comments to FERC, the RTOs say they already have a “highly aligned” interregional planning cycle.

In a joint 2014 study, both RTOs evaluated cross-border transmission issues and identified opportunities for more than 80 projects “using a single model with a single set of mutually agreed upon assumptions.”

“Although no project passed the interregional or regional criteria, any interregional projects would have had timely approval in both the regional and interregional processes,” the RTOs said. “Accordingly, the respective planning cycle timing and synchronization was not an issue; rather, the fact that projects did not pass the cost/benefit analysis exclusively relates to the criteria themselves rather than any mismatch in the timing or lack of coordination between the interregional planning analysis and the respective RTEP and MTEP processes.”

‘Quick Hit’ Projects

Since NIPSCO’s complaint, the RTOs noted, they have proposed to build at least 26 “quick hit” transmission projects that could be done quickly and cheaply on lower voltage flowgates to address constraints on both sides of their seam. (See MISO, PJM Ponder List of ‘Quick Hit’ Upgrades).

PJM officials told the Transmission Expansion Advisory Committee last week that the projects could eliminate $280 million of the $400 million in annual congestion at the top 38 historical market-to-market constraints.

PJM’s Chuck Liebold said the quick-hit effort resulted after planners asked themselves, “Are we missing something that would be easy to do?”

“We’re trying to do the right thing,” he said. “We’ve had studies that haven’t produced any projects.”

April 11, 2015June 15, 2023

PJM Responds to FERC Queries on Capacity Performance, Requests Approval

By Suzanne Herel

PJM on Friday filed a 37-page response to questions raised by the Federal Energy Regulatory Commission about its Capacity Performance proposal and requested that the board accept the plan effective April 1 so that it may implement the changes in the Base Residual Auction scheduled for next month.

“Despite [their] success in retaining and attracting sufficient capacity to ensure resource adequacy requirements are met, the capacity markets are failing to incentivize adequate generator performance. Resources in PJM have not performed as expected,” PJM said.

“Simply, [the Reliability Pricing Model’s] current capacity market performance incentives and requirements are weak, and therefore require immediate reform,” PJM said, noting that the auction secures commitments on a three-year, going-forward basis.

“If PJM deferred these changes to the following BRA, held in May 2016 for the delivery year that starts on June 1, 2019, it would mean that the PJM region would let five more winters pass after 2014 without implementing a full remedy to the manifestly deficient performance requirements in the current rules,” it said.

Hoping to Avoid Auction Delay

While the RTO had 30 days to respond to FERC’s March 31 order deeming its Capacity Performance filing deficient, it expedited the reply in hopes it can avoid having to postpone the BRA — something it has never done. However, because of the uncertainty surrounding the new Capacity Performance product — and because the Tariff requires the auction be held in May — the RTO last week requested a waiver to delay the BRA. (See PJM to Respond on Capacity Performance Friday; Seeks Auction Delay.)

PJM said that if FERC does not respond to the waiver request by April 24, the RTO will consider it withdrawn. Meanwhile, it is advising stakeholders to prepare for the auction to be held as scheduled May 11-15.

FERC’s four-page order questioned 10 areas of the proposal, which was conceived to increase reliability expectations of capacity resources with a “no excuses” policy (ER15-623). PJM’s proposal called for larger capacity payments for over-performing participants and higher penalties for non-performers.

FERC asked PJM to explain its derivation of an appropriate competitive clearing price when no new capacity is required in a locational deliverability area (LDA), and to provide more detail on a default offer cap and how it would apply in several situations.

PJM responded in detail, saying “a default Capacity Performance resource offer cap, based on net [cost of new entry] times the balancing ratio, is reasonable and appropriate.”

Balancing Ratio

PJM introduced the balancing ratio to adjust a resource’s committed unforced capacity (UCAP) to reflect its expected performance during Performance Assessment Hours. The proposed ratio would be calculated by dividing total load and reserves on the system by total generation and storage capacity commitments during the Performance Assessment Hour.

Regarding concern raised by some interveners that the balancing ratio is too difficult to estimate in advance, PJM said that if the commission accepts the offer cap agreed upon by PJM and the Independent Market Monitor, it will use a historical weighted average based on the previous three delivery years. During that period, there were 70 hours — including 42 hours of RTO-wide emergency — that would have been Performance Assessment Hours.

“Capacity Performance provides extremely strong incentives for resource availability and therefore, over time, will eliminate occurrences like those seen in the winter of 2014,” PJM said. “As a result, the expected value of the balancing ratio is anticipated to increase over time to a value that is more indicative of the summer Performance Assessment Hours, which averaged around 93.5%.”

FERC also requested any analyses the RTO had conducted on expected performance charges and bonus payments under the proposal. The commission asked if it made sense to phase in the penalties and for ideas of how to provide incentives for resource performance. In addition, it asked PJM how it plans to evaluate the performance of external resources not pseudo-tied to the RTO.

PJM cited the transitional structure it proposed in the plan that would allow PJM and capacity market sellers to adjust to the new product over the two remaining delivery years before 2018/19.

“As such, PJM therefore believes that it is unnecessary to provide further transition into the Capacity Performance structure from the standpoint of the non-performance charge, because load should be assured that Capacity Performance resources have the full incentive to invest appropriately in their resources from the 2018/2019 delivery year forward,” it said. “Phasing in the non-performance charge rate beyond what PJM has already proposed in its transition mechanism would inappropriately dilute this incentive.”

April 9, 2015June 15, 2023

PJM, Pepco Investigating Cause of DC-Area Outage

By Suzanne Herel

PJM and utility officials said yesterday they are still investigating what caused the failure of a 230-kV transmission line that briefly cut power to the White House and much of the D.C. area Tuesday afternoon.

The incident caused a drop in voltage that led the Calvert Cliffs nuclear units to trip offline and federal agencies and other customers to transfer to their backup systems.

The incident occurred around 12:40 p.m. after a fault on a 230-kV transmission line in southern Maryland, PJM’s Chris Pilong told the Market Implementation Committee on Wednesday. Pilong said the failure was believed the result of “failed insulation.”

The Southern Maryland Electric Cooperative (SMECO) said the incident occurred at the Ryceville substation in Charles County when a PEPCO conductor “broke free from its support structure and fell to the ground.” CNN reported that local firefighters extinguished a small fire at the substation, which is jointly owned by PEPCO and SMECO.

“No other outside influences are expected,” Pilong said. “It was just a fault, a failed insulator.”

Maintenance Outage

Pilong said the incident occurred while several 230-kV lines in the area were out of service for planned maintenance and that the problem was exacerbated by a stuck breaker. Three remaining 230-kV lines and a 500-kV bus were lost, and the fault and voltage drop “rippled” to surrounding substations, he said.

SMECO said the failure cut power to its Ryceville and Hewitt Road stations as well as PEPCO’s supply to the Morgantown and Chalk Point interconnections. “No SMECO equipment was damaged and all protective devices operated correctly to isolate SMECO equipment from the PEPCO fault,” it said.

The grid recovered — returning its area control error to normal bounds — in about seven minutes, Pilong said.

The outage trapped people in elevators, darkened D.C.’s subway stations and caused some institutions — including a Department of Energy building, the main campus of the University of Maryland and some Smithsonian museums — to shut down for hours, The Washington Post reported.

Wholesale Prices Spike

In addition to causing disruptions to consumers and businesses, the incident resulted in a spike in wholesale prices, with real-time LMPs in the BGE zone rising from less than $38 at noon to more than $344 for the 1-2 p.m. hour. The other zones most affected were DOM, PEPCO and APS (see chart).

Initially, it was thought that up to 500 MW might have been lost, but later it was determined that customers had switched to off-grid power. About 300 MW returned to the grid within 40 minutes, PIlong said. By late afternoon, only the line that was the source of the fault was out of service.

“There was never a loss of permanent supply of electricity to customers,” PEPCO said.

Calvert Cliffs

Exelon, which operates the Calvert Cliffs units, said the plant shut down automatically as designed during significant electrical disturbances. However, Exelon told the Nuclear Regulatory Commission it is investigating why an emergency diesel generator serving Unit 2 did not start.

“Both reactors will remain in ‘hot shut-down,’ which means the reactor remains ready to resume power production, until the offsite grid disturbance can be addressed,” Exelon said.

As of Wednesday evening, the NRC still listed output at Units 1 and 2, which have a combined capacity of 5,474 MW, as zero.

April 8, 2015

PJM to Respond on Capacity Performance Friday; Seeks Auction Delay

By Suzanne Herel

VALLEY FORGE, Pa. — PJM plans to respond by Friday to the Federal Energy Regulatory Commission’s questions about its Capacity Performance proposal, Executive Vice President for Markets Andy Ott told the Market Implementation Committee Wednesday.

On March 31, FERC said PJM’s proposal to increase capacity resources’ compliance penalties and rewards was deficient and gave the RTO 30 days to provide additional information (ER15-623). (See FERC: PJM Capacity Performance Filing ‘Deficient.’)

The RTO is expediting its response in hopes of getting quick clarity into the rules that will govern its upcoming Base Residual Auction so that stakeholders have time to prepare, Ott said.

On Tuesday, PJM asked FERC to delay the May 11-15 BRA (ER15-1470). The RTO requested that the commission act on its request by April 24, with comments due by April 14. PJM’s filing Tuesday asked for permission to delay the BRA until 30 to 75 days after a commission order on the merits of the proposal, but no later than the week of Aug. 10-14.

If FERC does not respond by April 24, PJM will withdraw its waiver request and conduct the auction under current Tariff requirements in May.

“We’re trying to get a signal from FERC as to which approach we should take,” Ott said. “We’re looking for certainty.”

“Delaying the auction is not something we’ve done lightly,” he added.

April 7, 2015

PJM Files to Delay Capacity Auction

Still hoping to win approval for its proposed revamp of capacity market rules, PJM asked the Federal Energy Regulatory Commission Tuesday to delay the May 11-15 Base Residual Auction.

On March 31, FERC said PJM’s Capacity Performance proposal was deficient and gave the RTO 30 days to provide additional information (ER15-623). (See FERC: PJM Capacity Performance Filing ‘Deficient.’)

PJM’s filing Tuesday asked for permission to delay the BRA until 30 to 75 days after a commission order on the merits of the proposal, but no later than the week of Aug. 10-14 (ER15-1470).

The RTO requested that the commission act on its request by April 24, with comments due by April 14.

Andy Ott, executive vice president for markets, will brief the Market Implementation Committee at about 10:30 a.m. Wednesday on the RTO’s plans for responding to the deficiency order.

April 7, 2015

Divided FERC Trims ROE on NY Tx Projects, Orders Hearing

By William Opalka

Five transmission projects intended to serve New York City and respond to a potential nuclear plant closure suffered setbacks last week as a divided Federal Energy Regulatory Commission rejected the developers’ cost allocation proposals and reduced their requested returns on equity (ROE).

The commission granted some of the developers’ requests for ROE incentives but ordered settlement and hearing proceedings on proposed formula rates, protocols and the base ROE (ER15-572).

On Dec. 4, NYISO proposed a cost-of-service formula rate template and formula rate implementation protocols on behalf of New York Transco, comprised of affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric.

The companies submitted five projects in response to competitive solicitations issued by the New York Public Service Commission.

Two AC projects, the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, are intended to alleviate congestion on transmission lines serving the New York metropolitan area. (See Tx Plan to Open NY Choke Points Without New ROWs.)

The other three “Transmission Owner Transmission Solutions (TOTS)” projects were designed to address reliability concerns expected if the Indian Point nuclear plant closes. NYISO and the transmission owners sought an April 3 effective date on their proposed formula rate, protocols, cost allocations and 10.6% base return on equity.

The commission:

Granted requests for construction work in progress, abandonment and pre-commercial cost recovery incentives, and a 50-basis-point ROE adder for membership in an RTO, subject to a cap within the “zone of reasonableness,” to be established through the hearing procedures.
Approved an ROE adder for risks and challenges for the Edic-Pleasant Valley 345-kV line while rejecting it for the Oakdale-Fraser 345-kV line and the TOTS projects.
Ordered the applicants to revise sections 3(e)(ix) and 4(b) of the formula rate protocols, as requested by the New York Association of Public Power, to provide more transparency. The commission said it was concerned with the allocations of shared plant or expense items between members of NY Transco and their parent companies.
Rejected the cost allocation for all five projects.
Denied applicants’ request for an ROE adder for being a transmission company. The commission said NY Transco’s members were not “sufficiently independent” to merit incentives, noting that they serve 84% of the state’s load and own 64% of its high voltage transmission and 4% of its generation capacity.
Ordered hearing and settlement procedures on NY Transco’s proposed formula rates, protocols and base ROE, including components of the formula rate and the allocation of various expenses between the TOs and NY Transco. The commission ordered appointment of a settlement judge within 15 days and a report on the status of negotiations by May 4.

Dissents on Capital Structure

The majority also rejected applicants’ request for a “hypothetical” capital structure incentive of 60% equity and 40% debt for all five projects, instead approving a 50/50 structure.

NY Transco said it would use its actual capital structure in the formula rate after the projects are placed into service but that the hypothetical capital structure would improve its credit rating, reducing financing costs by $168 million compared with a 50/50 structure.

The majority said it agreed with protests by the PSC and others that the 60/40 capital ratio is “excessive for an entity such as NY Transco, whose affiliates … will construct the projects and perform the maintenance and physical operation of the NY Transco assets.”

That sparked a partial dissent by FERC Chairman Cheryl LaFleur and Commissioner Philip Moeller. “Today’s order does not merely apply an overly rigid approach to evaluating these capital structures; the majority has failed to provide any criteria or guidance as to how the commission will evaluate these capital structures going forward,” they wrote. “We believe the applicants demonstrated the required nexus between the need for the requested hypothetical capital structure and the facts of this particular case, and we would have granted the requested transmission incentive.”

LaFleur and Moeller also said the additional proceeding adds “needless uncertainty” to efforts to expeditiously build transmission infrastructure.

Cost Allocation

The commission rejected the cost allocation method for the AC and TOTS projects because it imposed costs on the New York Power Authority and the Long Island Power Authority, both public entities that have not been allowed to join NY Transco.

The PSC said the cost allocation proposal it initially supported included the voluntary participation of LIPA and NYPA, and covered 18 transmission projects throughout the state. NY Transco was originally planned as a six-party Transco, which included NYPA and LIPA, but the New York state legislature refused to allow NYPA permission to participate.

NYPA serves municipal systems throughout the state, but NY Transco’s cost allocation proposal would have assessed its municipals located upstate at the same rate as downstate municipals. “Grossly inequitable situations would arise where a NYPA customer located in the Rochester region would be allocated 16.9% of the costs while another [Rochester Gas & Electric] customer located across the street … would be allocated only 8.9% of the costs,” the commission said.

Because NYPA and LIPA have not accepted the cost allocation method, it cannot be considered a “participant funding method,” the commission said.

The applicants had proposed to allocate the costs of the three TOTS projects using an adjusted load ratio share approach, with 75% of the costs allocated to transmission districts southeast of the UPNY/SENY constraint and 25% allocated to upstate districts, a departure from the default ratio for public policy projects (60% downstate, 40% upstate). The PSC adopted a 90% downstate/10% upstate cost allocation for the AC projects.

The commission said the AC projects could qualify for regional cost allocation if the PSC decides they should be evaluated under NYISO’s Order 1000 public policy transmission planning process and the ISO selects the projects in the regional transmission plan.

Because the TOTS projects were evaluated by the PSC before NYISO’s Order 1000 transmission planning process, the ISO must reevaluate and select them to be eligible for regional cost allocation, the commission said.

Alternatively, the commission said the applicants may submit a revised allocation shared only by entities that agree to pay, “either by renegotiating the cost allocation with LIPA and NYPA or by allocating the costs solely among those transmission developers participating in the NY Transco.”

AC Projects

The commission said the 153-mile, Edic-Pleasant Valley 345-kV line deserved a risk-reducing incentive because it would relieve transmission congestion on existing lines by 41% in 2022.

The project would connect National Grid’s Edic substation in Oneida County to Con Edison’s Pleasant Valley substation in Dutchess County, entirely within existing rights-of-way. The project, including three new substations, would move an additional 1,000 MW from central New York to the southeast region. The line is expected to reduce transmission congestion costs, line losses and installed capacity costs by a net present value of almost $1.3 billion to $4.5 billion over 10 years.

The commission rejected such a bonus for the Oakdale-Fraser 345-kV project, saying it was not convinced it relieved “chronic and severe congestion.” The project would add a second, 57-mile 345-kV line between the Oakdale and Fraser 345-kV substations.

Indian Point Contingency

The three TOTS projects were approved by the PSC as a contingency plan for the loss of Entergy’s Indian Point nuclear plant. Entergy told investors last year it would consider shutting down the plant’s two units if it can reach a “constructive” settlement with state officials.

The transmission projects, which have an in-service deadline of June 1, 2016, are the:

Fraser-Coopers Corner project, estimated at $66 million, which will increase power transfer by reducing series impedance over the existing 345-kV Marcy South transmission lines;
Ramapo-Rock Tavern project ($121 million), which will add a second 345-kV line from Con Edison’s Ramapo 345-kV substation to Central Hudson’s Rock Tavern 345-kV substation; and
Staten Island Unbottling Project ($262 million), which involves transmission upgrades to Con Edison’s interconnecting 345-kV transmission line with Cogeneration Technologies Linden Venture, to allow generating facilities located on Staten Island to export power to the rest of New York.

April 3, 2015June 15, 2023

PJM Asks FERC for Direction on Refunds from Illegal Trades

By Ted Caddell

PJM has asked the Federal Energy Regulatory Commission to untangle the question of how profits from trades that are determined to be illegal get calculated and refunded (IN15-5).

In a filing Wednesday, PJM Associate General Counsel Jacqulynn Hugee referenced a March 6 Order to Show Cause and Notice of Proposed Penalty requiring City Power Marketing and trader K. Stephen Tsingas to explain why they shouldn’t be sanctioned for up-to-congestion (UTC) trades investigators contend violate the Federal Power Act. Hugee filed a similar request in the case of hedge fund twins Rich and Kevin Gates and Houlian “Alan” Chen (IN15-3).

FERC Office of Enforcement staff alleges that the City Power trades resulted in profits of $1,278,358 and recommended that the profits be refunded. The staff also recommended that City Power be fined $14 million and Tsingas $1 million. The refunds and penalties are pending a final ruling by the commission. Tsingas and City Power have until April 6 to answer the charges.

PJM, in anticipation of a determination against Tsingas and City Power, wants to know just who gets the refunds and how they are to be calculated.

Handling the refunds, Hugee noted, could be complicated. She noted that although the March 6 orders don’t say so, usually it is the RTO involved that is tasked with refunding any profits to market participants.

If PJM is ordered to do so, Hugee wrote, the calculations necessary to complete the refunds through the usual month-end billing adjustments “can be very time consuming, taking weeks or months to complete.” She asked that the commission order the refunds be made based on Tsingas’ and City Power’s activity “on an hourly basis, per operating day,” rather than a lump sum that would have to be split up on a pro-rata basis. She asked FERC to do those calculations.

Hugee also sought direction on how refunds should be made to parties who are no longer PJM members and asked that if any former members are due refunds but still owe money to PJM, the refunds be used to clear that debt first.

She noted that there were six entities also alleged to have engaged in sham trades, who would also be considered victims of the City Power/Tsingas trades. “PJM asks that the commission indicate in its order whether these six entities are entitled to receive the portion of the disgorged funds that are due to be refunded to them or whether they should be excluded from any such refunds,” she wrote.

April 3, 2015June 15, 2023

CEO Crane: Exelon Studying Distributed Generation, is Looking to Adapt

By Suzanne Herel

CEO Christopher Crane outlined Exelon’s position on distributed generation, shared his vision for the distribution company of the future and provided insight into the financial struggles faced by the firm’s nuclear power plants during two days of testimony before the D.C. Public Service Commission this week on the proposed $6.8 billion acquisition of Pepco Holdings Inc.

“There has to be an equity conversation not only about the microgrid, but the cost of the infrastructure,” Crane said. “We support distributed generation. But the other side of getting in on all this new, neat technology is that we keep people whole. We need to be mindful of the load profile that the generation is going to serve. You can get to a position where you’ve overbuilt and inequities come out of that.

“Who’s going to bear the expense? Is the solar power provider going to contribute to that, or is it going to be on the back of other customers?”

Asked by Commissioner Joanne Doddy Fort to describe the role of the distribution company going forward, Crane — who earlier said the industry’s technology has advanced more in the past few years than in his entire career — replied that it was about adapting.

“We’re trying to define the approach that we’re taking with the utilities,” he said. “To deny it and stay in the old utility ways reduces the relevance that the company can have.”

To that end, Exelon has directed research teams to work with such groups as the Edison Electric Institute and the U.S. Energy Department’s National Labs to identify emerging technologies.

“I do believe in 10% penetration in distributed generation,” he said. “That could be a great opportunity to redesign the operating model to support those microgrids going on.”

In addition, he said, Exelon is investing in storage companies.

Before facing questions from the three commissioners, Crane was grilled by two staunch critics of the planned acquisition: the D.C. Office of People’s Counsel and the D.C. government, both of whom delivered stinging opening statements. (See CEO Crane to DC PSC: Committed to Jobs, Ratepayers.)

Both cautioned the commissioners that the sale of Pepco would have far-reaching consequences.

“While this is not a ‘rate case,’ any decision emanating from this case will largely predetermine the parameters of the next filed rate case,” OPC said. “Second, public participation and concern over the proposed acquisition has been unprecedented.”

An approval, OPC said, “will not only impact every proceeding involving Pepco, it will potentially impact the legislative initiatives that currently exist concerning renewables and distributed generation. The order approving this merger will not be static document. It will serve as a guidebook that will be referred to for decades to come.”

Perhaps the most important question, it said, “is this: If the takeover is approved and it becomes apparent thereafter that Exelon’s priorities are not aligned with the city’s priorities, what ability will this commission have to address the conflict?”

Attorney John Coyle, representing the city government, said “If you approve this proposed merger, it is likely to be the last, as approval would place the retail supply of electricity between the Schuylkill and the Potomac under a single company — albeit one run from Chicago and having merchant generating interests that span the country.

“Sixteen years after this commission approved Pepco’s divestiture of its generation, which divestiture contributed to the development of a reasonably robust market for wholesale electric power, you now find yourselves asked to approve a reconsolidation that brings generation back to the same corporate ‘family’ that runs the District’s transmission and distribution infrastructure.”

Coyle questioned the timing of the deal, which comes as Exelon is struggling to maintain three money-losing nuclear reactors in its home state of Illinois, where it is pushing legislation that would impose a surcharge on electricity customers. [Editor’s Note: An earlier version of this article mistakenly put the number of money-losing reactors at six.]

“No business pays a $1.6 billion premium over market price (in a $6.8 billion stock purchase transaction) for the privilege of generating 2.1% of the $1.6 billion in savings over 10 years, and then giving the claimed savings away.

“Any analyst who has looked at this transaction has expressed the understanding that its point is to acquire a great deal of reliable, regulated cash flow to ease the costs of Exelon’s generating fleet — and particularly its nuclear assets — over the shoal of wholesale power market prices depressed for the time being by the availability of shale gas and oil in unprecedented quantities and at unusually low prices.”

Under questioning, Crane said that Exelon last year lost $100 million alone on its Clinton reactor.

Under the current market design, Crane said, revenue is not sufficient to maintain its six underperforming nuclear plants.

“The quick business decision would be to shut the units down,” he said.

“But, we have the responsibility also of what that would mean to the community,” he said, noting that the Clinton generator significantly supports the tax base of DeWitt County. “We have a commitment not to act too quickly but to work with stakeholders to come up with a market-based fix.”

Regardless, he said, Exelon’s motive in acquiring Pepco is not to shore up its nuclear fleet.

“The generation company overall is profitable,” he said. “It maintains a strong balance sheet. We’re not limping along on the generation company — we have assets that are under-earning or losing money.

“Just so we have the characterization right, this is not a broken car. This is an entity with assets that are losing money, and you find out how to fix it or shut them down. We do not need the regulated revenue to fund or make up for any of that challenge.”

D.C. and Maryland are the last holdouts to the transaction. The acquisition has been approved by the New Jersey Board of Public Utilities, the Federal Energy Regulatory Commission, the Virginia State Corporation Commission and the staff of the Delaware Public Service Commission.

The evidentiary hearings, which are being webcast, continue through April 8 in D.C. and are scheduled for April 15-17 in Maryland.

April 3, 2015

Niagara Mohawk ROE Settlement Certified

A Federal Energy Regulatory Commission settlement judge on March 27 certified an uncontested proceeding to reduce transmission owner Niagara Mohawk Power’s return on equity to 10.03% from the current 11.5% (EL12-101, EL13-16, EL14-29).

Niagara Mohawk, a unit of National Grid, reached the agreement with the Municipal Electric Utilities Association of New York, the New York Association of Public Power and the Allegheny Electric Coop. (See FERC Staff Endorses Niagara Mohawk ROE Settlement.) As a result of the settlement, the hearing ordered by the commission last year will not be necessary.

April 3, 2015

New England Generators Challenge Sloped Demand Curve

By William Opalka

New England power generators asked a federal appeals court to overturn Federal Energy Regulatory Commission orders that accepted ISO-NE’s change to a sloped demand curve in advance of this year’s Forward Capacity Auction.

NextEra Energy Resources, NRG Energy and Public Service Enterprise Group filed a petition for review Monday in the D.C. Circuit Court of Appeals.

A year ago, ISO-NE and the New England Power Pool Participants Committee jointly filed revisions to the RTO’s Tariff to establish a system-wide sloped demand curve for the Forward Capacity Market, which were accepted by FERC (ER14-1369). A rehearing request of what became known as the Demand Curve Order was denied by FERC on Jan. 30.

ISO-NE formerly used a vertical demand curve, which produces a single clearing price for all cleared resources at the point where the demand and supply curves intersect. Before the eighth Forward Capacity Auction in February 2014, ISO-NE determined a potential for a capacity shortage, which would invoke administrative pricing provisions in the Tariff. Capacity prices in FCA 8 tripled to about $3 billion.

In response to a FERC order just prior to FCA 8, ISO-NE posited that a sloped demand curve would be a long-term solution, eliminating the need for administrative pricing rules.

In filings last year, PSEG asserted that the sloped curve failed to meet the one-day-in-10-years loss-of-load expectation.