MISO’s Board of Directors last week approved a $2.5 billion transmission expansion plan funding 369 projects, including a 500-kV line to carry Canadian hydropower to Minnesota Power customers.
The $676 million Great Northern Transmission Line is the single most expensive project in MISO’s 2014 Transmission Expansion Plan, the product of 18 months of work by MISO stakeholders. The line, which will connect the Manitoba border to the Minnesota Iron Range, is set for completion around 2020.
The plan also includes 50 baseline reliability projects totaling $269.5 million, six generator interconnections totaling $38 million and 312 “other” projects totaling $1.5 billion, including those supporting lower-voltage transmission systems.
The plan will allow for the interconnection of 726 MW of new wind generation and import of 883 MW of hydroelectric power from Manitoba, said Jennifer Curran, MISO’s vice president of system planning and seams coordination, in a memo to the board.
Interconnection requests are shifting from predominately wind to a mix of natural gas and wind, as gas-fired generation steps in to replace coal plants forced to retire or switch fuels because of federal environmental rules, MISO said. Natural gas interconnection requests in MISO soared to 9,424 MW this year, from 1,994 MW in 2011.
There also have been about 810 MW of new solar request interconnections in 2014. “This could be the result of recent federal energy legislation and the economic stimulus package, and the lower price of solar photovoltaic modules,” the MISO plan states.
MTEP 14 was the first planning cycle that included full participation of MISO’s south region in economic and reliability planning.
The south region is targeted to receive about $359 million in transmission investments, including two of the largest projects in MTEP 14: a $60 million, 115-kV line by Entergy in Mississippi, and a $56.3 million, 230-kV line in Louisiana.
Since MTEP ‘03 about $19 billion of transmission project investment has been identified, with roughly 40% of it completed. MTEP 14 covers projects expected to be completed by 2023.
If you want to know why many think that demand response hasn’t fulfilled its potential in MISO, talk to Brian Helms.
Helms, the director of energy services at new MISO member Century Aluminum, said that when he attended a MISO workshop he was unable to get an answer about what form of approval would be needed to register his plant as a Load- Modifying Resource. And when he asked his local utility how to sign up, it told him it wasn’t interested.
“The path to providing those resources is kind of tortuous and murky,” Helms recounted at the MISO Advisory Committee’s “hot topic” discussion on demand response last week.
The committee sought stakeholder input on how to make the most of demand response programs, and whether MISO should take any action while waiting for final word on whether last May’s appellate court ruling voiding the Federal Energy Regulatory Commission’s Order 745 will stand.
Unlike PJM, most of MISO’s demand response assets are administered through state programs. While that means less disruption if the D.C. Circuit Court of Appeals ruling in the Electric Power Supply Association v. FERC case stands, stakeholders told the committee the disparate state rules make it more of a challenge for the RTO to maximize such resources. (The D.C. Circuit yesterday granted the U.S. Solicitor General’s request for more time to seek a Supreme Court rehearing of the case.)
Representing end-use customers, DeWayne Todd, energy services manager at Alcoa in Newburgh, Ind., said that MISO has done a good job of integrating available Load-Modifying Resources through legacy interruptible electric service rates.
Demand Response Resources ‘Untapped’
But Demand Response Resources are largely untapped in the energy and ancillary services markets due to retailers’ restrictions on participation and compensation, the End-Use Sector said. They cited the Independent Market Monitor’s State of the Market report, which shows there are just 75 MW of controllable Demand Response Resources — all attributable to Alcoa, which often interrupts production when electric price signals rise. (See chart.)
“I think there’s a huge opportunity, and not just [in] smelting, but other customers and consumers, as well,” Todd said.
The Environmental Sector agreed, saying MISO’s minimum threshold of 5 MW for participation in energy and ancillary services markets is too high. PJM’s threshold, they noted, is 100 kW.
The Environmental Sector recommended MISO employ demand response as a “transmission-like resource” in its planning, saying DR resources could help maintain reliability at lower cost than System Support Resources while longer-term transmission or generation solutions are implemented. “DR can also reduce or eliminate the need for costly transmission upgrades, or be paired with a transmission upgrade or voltage support to help eliminate potential reliability issues,” it said.
Aggregators ‘Frozen Out’
The environmentalists lamented that third-party providers, which play a big role in PJM, are “largely frozen out” of MISO’s markets. Among MISO states, only Illinois permits aggregators of retail customers (ARC) to participate, they said.
The Organization of MISO States said MISO “has done an adequate job of meeting FERC requirements for DR, while balancing stakeholder desires for sometimes conflicting market parameters.”
It urged the RTO to work with market participants to accommodate new demand response technologies and remove barriers to participation. OMS cited methods of directly controlling customer-owned electric water heaters to support grid reliability. Participants “would like to develop programs to offer this DR in MISO’s ancillary services market, however current MISO protocols, relating to metering and zonal boundaries, may be prohibiting participation,” OMS said.
The Transmission-Dependent Utilities Sector said MISO has allowed DR fair access to its markets and said load-serving entities should continue to have the option to operate their DR programs at the retail level, without offering it as a wholesale product.
Reliability Benefits
The Public Consumer Group acknowledged that the state-by-state variation in demand response programs is a challenge for MISO but that the RTO should nonetheless make increasing DR a top priority, saying such resources could aid reliability and reduce rates.
During last winter’s polar vortex, the group said, MISO did not even consider calling on DR resources, unlike PJM. “As a result, capacity margins were unnecessarily tight, and prices, which were ultimately passed on to consumers, were likely higher than necessary,” it said. “In addition to paying higher prices when DR is not called upon in near-emergency circumstances, end-use consumers in MISO are not getting appropriate use of DR resources for which they are paying in their rates. … Because DR is so rarely called upon, customers are not enjoying the full value of these resources.”
IPPs: Demand Response Has No Place on Supply Side
MISO’s independent power producers took a position similar to that of generators in PJM and ISO-NE, citing the EPSA ruling in arguing that demand response has no place in the supply side of wholesale markets. “MISO will need to establish parameters for load-serving entities and state regulators in order to use these assets focusing on their primary function: load modification, also known as load shaving,” they said.
“There’s a lot of uncertainty, but it’s pretty clear if you look at ISO New England and PJM, they’re being very proactive in what they’re doing with DR and moving it back over to where it traditionally was prior to the advent of organized wholesale markets,” Mark Volpe, senior director of regulatory affairs for Dynegy, told the committee.
Advisory Committee Vice Chairman Kevin Murray said that’s problematic.
“You could take an approach as Mark suggested and force all the demand response back on to the load side of things,” he said. “The problem with that, as MISO has observed, [is] it produces a result where it’s not integrated into MISO’s market when it’s dispatched, [and] it has the effect of reducing load, [depressing] prices during a point in time when the system is stressed during an emergency.”
A number of commenters noted that DR programs among the states differ widely, with some going back decades.
Directors Judy Walsh and Michael Curran said MISO might consider offering incentives to replace the many differing utility contracts with a model that would be easier for MISO to manage.
“I wonder if there’s a way to structure a new opportunity for these players where they would opt-in to some other opportunity to participate in the market where in fact [they] get paid for participating,” Walsh said. “Perhaps we could move out of these old contracts.”
The Federal Energy Regulatory Commission will hold four technical conferences next year to discuss the effects of the Environmental Protection Agency’s Clean Power Plan on reliability and wholesale electricity markets.
FERC announced the conferences in response to a request from three Republican lawmakers, including Alaska Sen. Lisa Murkowski, who will likely become the chair of the Energy and Natural Resources Committee when Republicans take control of the Senate in January. The Republicans said in a letter to FERC that the EPA “lacks the mission and the expertise to determine what is necessary to maintain the reliability of the nation’s electric grid.”
The first conference will be held on Feb. 19, with a “National Overview” session led by the commission itself. It will be a part of FERC’s monthly open meeting, which will start an hour earlier to accommodate the conference. Staff will conduct three more regional conferences in D.C., St. Louis and Denver on dates to be announced.
Participants in the first conference will discuss whether state regulators “have the appropriate tools to identify reliability and/or market issues that may arise” as a result of compliance with the plan, as well as how to coordinate with RTOs on how to comply.
“The commission clearly has a role to play in ensuring that the nation’s energy markets and infrastructure adapt to support compliance with the proposed Clean Power Plan,” FERC Chairman Cheryl LaFleur said. “These technical conferences will be an opportunity for the commission to hear from a wide range of stakeholders across the country on issues related to reliability, market operations and energy infrastructure.”
Murkowski said she appreciated FERC announcing the conferences. The conferences are “no substitute for EPA’s failure to engage FERC and [the Department of Energy] in a formal, documented process to address the impact on electric reliability of EPA’s series of major rulemakings in recent years,” she said.
“I remain hopeful, however, that the conferences will be useful to develop a better public record on these crucial questions, and I will remain as vigilant on this issue as I have been since 2011.”
Republicans have made blunting the EPA’s Clean Power Plan a top priority for when they take full control of Congress, following a wave of Republican victories in Senate elections in November. (See GOP Election Victories Unlikely to Thwart EPA Carbon Plan.) One of the casualties was Sen. Mary Landrieu (D-La.), the current chair of the Energy Committee. (See related story, Honorable Clears Senate Energy Committee.)
PJM on Friday filed its long-awaited Capacity Performance proposal with the Federal Energy Regulatory Commission, a two-docket, 1,275-page capacity market overhaul that it hopes will prevent a repeat of last January’s poor generator performance.
EL15-29, filed under sections 205 and 206 of the Federal Power Act, contains proposed changes to PJM’s Operating Agreement and Tariff “to correct present deficiencies in those agreements on matters of resource performance, and excuses for resource performance, in the wholesale markets administered by PJM.”
ER15-623, filed under section 205, proposes changes to the Reliability Pricing Model rules in the Tariff and Reliability Assurance Agreement.
PJM will ask the Federal Energy Regulation Commission this week to raise the cost-based energy offer cap to $1,800/MWh through March 2015, CEO Terry Boston said in a letter to members Tuesday.
The proposal, authorized by the Board of Managers, would let offers up to $1,800 set clearing prices. Generators could recover “justifiable costs” above $1,800 through make-whole payments, but such offers would not set prices for other market participants.
The Section 206 filing comes after stakeholders failed over eight months to reach consensus on changes to the current $1,000/MWh cap.
The issue resulted from the spike in gas prices last January, which pushed some generators’ costs above $1,000. FERC granted PJM’s request for a waiver from the cap to allow some gas-fired generators to cover their costs.
“We believe this action is prudent preparation for the possibility of high fuel costs that could result in generating sources not recovering their costs despite producing power when most needed to meet high demand,” Boston wrote.
Although PJM is not expecting the same weather extremes this winter, Boston wrote, “seeking approval for a higher cap through this winter [allows PJM] to avoid any possibility of having to scramble to submit waivers that seek FERC decisions in 24 hours.”
Boston noted that the concept of allowing cost-based offers in the energy market to set prices up to $1,800/MWh mirrors the proposal presented at the Nov. 20 Members Committee. Old Dominion Electric Cooperative’s Ed Tatum — who negotiated the proposal with Gabel Associates’ Mike Borgatti — withdrew it after it became clear it had little support from members representing load. (See Last Ditch Effort to Break PJM Offer Cap Deadlock Fails.)
Boston said PJM limited its proposed change to the coming winter “in anticipation of FERC developing a longer-term solution to offer cap issues from a national perspective over the next year.”
PJM is reducing its load forecast for 2018 by 2.6%, due in part to a temporary change in modeling that aims to address over-forecasting in recent years.
Acknowledging criticism that its forecasts have overestimated economic growth and failed to capture energy efficiency and behavioral changes that have dampened demand, PJM officials will use a “binary variable” to reduce next year’s forecast.
“There are things outside our model that our model is not picking up,” PJM’s Andrew Gledhill told the Planning Committee last week in a briefing on its draft load forecast.
Before applying the variable, PJM was projecting a 1.5% reduction in its 2018 summer peak load compared with the projection it made last year.
In addition to reducing the forecast for summer 2018 — the delivery year for next year’s capacity auction — the draft report reduces the summer peak load forecast for 2015 by 4,716 MW (-2.9%).
Peak load for 2020, the next Regional Transmission Expansion Plan (RTEP) study year, was cut by 4,152 MW (-2.5%) versus last year’s projection.
Economist James Wilson, a consultant to consumer advocates, questioned the use of the binary variable, saying it overcorrects in the short term and results in too high a rate of growth in later years. “It’s not a very good approach,” he said.
PJM Vice President of Planning Steve Herling said the debate would soon be moot. “I’m less concerned about the long-term implications of [this year’s fix] because we’re not going to be doing it next year,” he said.
Wilson also questioned why forecasters continue to add years to their historical period instead of dropping some of the earlier years.
Wilson said the first four years of PJM’s 1998-2014 historical base was a period when peak demand was growing in about a 1-to-1 relationship with growth in PJM’s economic variable, an elasticity that hasn’t been seen since and which may not return because of increased energy efficiency and demand response.
“A better way to move the forecast in the right direction would be to drop some of those now-anomalous early years from the forecast period,” he said.
Gledhill said the data from those previous years remains valid. “When you start shortening the estimation period, you’re shortening the period where you can measure how load reacts to economics,” he said.
Direct Energy’s David “Scarp” Scarpignato backed Wilson’s argument. “Something’s changed that’s making that data way-back-when less useful in the forecast,” he said. “Do you really want more data points if some of the data points are garbage?”
Herling said a final forecast report will be presented by the end of this month.
The electric and natural gas industries remain divided over the start of the gas day, nine months after federal regulators proposed changing the start time from 9 a.m. CT to 4 a.m. CT.
On March 20, the Federal Energy Regulatory Commission issued a Notice of Proposed Rulemaking proposing the change to better align it with electric operations (RM14-2). The commission gave the North American Energy Standards Board six months to reach consensus among its gas and electric industry stakeholders. (See FERC: Six Months to Move Gas, Electric Schedules.)
But NAESB reported in September that the two sectors remained split, with the gas industry resisting any change in the start time. When the comment period on the NOPR closed at the end of November, there was no evidence of any change in the stalemate.
Thus it will be up to FERC to decide whether to change the start time over the gas industry’s objections.
Whether Chairman Cheryl LaFleur has the votes to force a change is unclear. The commission approved the NOPR on a 3-1 vote with LaFleur, Commissioner Philip Moeller and former Commissioner John Norris in support. Commissioner Tony Clark dissented, saying he wanted to give the industries more time to reach consensus before FERC “put its thumb on the scale” in favor of a change.
In their comments, stakeholders from both industries were largely supportive of other modifications proposed by NAESB.
Besides changing the start of the gas day, FERC proposed moving the deadline to schedule gas for the Timely Nomination Cycle from 11:30 a.m. CT to 1 p.m. CT and increasing the number of intraday cycles from two to four. NAESB’s proposals were similar: it proposed the same start time for the Timely Nomination Cycle, but it suggested moving the end time from 4:30 p.m. CT to 5 p.m. CT. NAESB also added one extra intraday cycle to the proposal, instead of FERC’s two.
But the standards board was unable to bring the two industries to an agreement regarding the gas day, with electric favoring the earlier gas-day start time so it more closely aligns with the electric day, and gas saying the time change is unneeded and may be disruptive to gas markets.
Battle Lines Remain in Place
In its late September filing detailing its modifications, NAESB said that stakeholders on the Gas Electric Harmonization Committee had narrowed 13 proposals to four, each containing identical cycle schedules but different gas-day start times.
“Despite forum participants casting over 13,000 votes on 56 different motions, no single proposal gained the supermajority support required of both [electric and gas] quadrants to reach consensus on a single proposal,” NAESB said.
The board instead left the start time question up to FERC, submitting a proposal with the provisions that had common agreement while replacing all references to the start time in the standards with a question mark.
While some stakeholders suggested minor alterations to NAESB’s proposed cycle schedules, they each fell into one of two camps when it came to the gas day start time.
“Changing the start of the gas day is unnecessary to achieve the commission’s objectives in this proceeding and could create unintended adverse consequences to the natural gas industry,” said the Natural Gas Council, which represents companies in all segments of the gas supply chain. In comments filed late last month, the council urged FERC to adopt NAESB’s proposed cycle schedules, which it said would address generators’ concerns over running out of gas toward the end of the gas day, as demand for electricity ramps up during the morning.
The council also noted the regional disparity between generators who wanted an earlier start time, with those on the West Coast siding with the gas industry in maintaining the status quo. The proposed change would mean a 2 a.m. PT start time.
“Disrupting the entire natural gas market by moving the start of the gas day would be an overwhelming undertaking,” the council said. “The commission should not require a change to the national gas day to address a problem that is more limited and regional in nature.”
RTOs, meanwhile, support the earlier start time.
“The current start of the gas operating day … requires electric generators to nominate gas over two electric days. Gas scheduled during the day-ahead Timely Nomination Cycle covers the evening peak of one electric day, and the morning electric ramp of the following electric day,” the ISO/RTO Council said in its comments. “Schedules for the second electric day, which correspond to the morning electric ramp, are not yet known when generators nominate gas. Moving the gas operating day to an earlier time would allow generators to nominate gas in the day-ahead Timely Nomination Cycle, i.e., the most liquid cycle, to cover the morning electric ramp and the evening peak of a single electric day.”
The IRC represents all nine RTOs in North America, including CAISO, which the council said also supported an earlier start time. A number of RTOs filed their own comments as supplements to the IRC’s.
“Moving the gas day to 4 a.m. CT or earlier, coupled with changing the Timely Nomination Cycle to 1 p.m. CT, will enable owners of gas-fired generators needed for the peak morning period to timely nominate and schedule gas supply to support their ability to generate electricity at the start of the morning peak,” said ISO-NE, which noted New England’s heavy reliance on natural gas and its past difficulties procuring it.
MISO and SPP also voiced their support for the earlier start time, with SPP also proposing an even later start to the Timely Nomination Cycle.
Representing Diverse Views
Some stakeholders stayed neutral in the start-time discussion, as their membership was too diverse and divided to take a position on either side of the issue.
In its comments, the Electric Power Supply Association, which represents players in both the gas and electric industries, said it supported NAESB’s modifications and that it could not support either start time because its members were divided. But it also noted that there was a broad consensus on one aspect of the start time.
“While there are EPSA members on each side of this issue in terms of the 4 a.m./9 a.m. debate, there is clear consensus that some other time between 4 a.m. and 9 a.m., or different times set for different regions of the country, is not acceptable or workable,” EPSA said.
The Edison Electric Institute, which represents U.S. investor-owned utilities, also refrained from taking a position on the gas-day, but did offer support for NAESB’s modifications. It also urged FERC, regardless of what it decides, to “provide the necessary lead time to ensure that the changes are made in a coordinated manner that maintains the reliability of both the electric and the natural gas systems.”
EEI recommended that FERC implement the changes during a “shoulder month,” preferably in the spring, when demand isn’t as high.
PJM’s new graduated queue-entry cost structure has not persuaded interconnection customers to file their requests earlier, PJM officials told members last week.
About 54% of the project applications in the queue that closed Oct. 31 (AA1) came in the final month, and 43% of those came in the final week — 26% on the final day — said David Egan, manager of interconnection projects. In the previous queue, before the fee structure was changed, 47% of applications came in the final month.
“This is not workable,” said Steve Herling, vice president of planning. “It hasn’t really improved with the changes we’ve made.”
Under the new structure, the deposit for applications filed in the first four months was set at $10,000; for the fifth month, $20,000; and for the last month, $30,000.
“I’m noodling on a method to fix this. That is going to be a proposal that we bring to better allow my group to handle it,” Egan said, inviting suggestions to incent early participation. “This is creating big chunks of work, and invariably things get dropped or missed.”
Projects totaling about 30,000 MW are currently under study, with another 19,000 MW under construction. Natural gas accounts for 80% of the total. PJM received 2,376 project applications in the queue. Of that, 23% are in-service and 172 agreements were terminated.
TO/TOP Matrix
Members approved Version 8 of the TO/TOP (Transmission Owner/Transmission Operator) Matrix, the result of an annual review. The document serves as an index between PJM manuals and North American Electric Reliability Corp. standards and creates no new obligations for PJM or its members.
U.S. Solicitor General Donald Verrilli will ask the Supreme Court to review an appellate court ruling voiding the Federal Energy Regulatory Commission’s authority over demand response in wholesale energy markets.
Verrilli said in a filing yesterday that Chief Justice John Roberts had granted his request to extend a Dec. 16 deadline for filing a petition for a writ of certiorari by one month. “The FERC orders that the court of appeals set aside in this case address an integral feature of the nation’s wholesale electric-power markets under FERC’s jurisdiction — the rules for participation by demand-response resources — that is of substantial importance to the proper functioning of those markets and to assuring just and reasonable rates for wholesale power,” Verrilli said in a Dec. 5 filing requesting the extension.
FERC Chairman Cheryl LaFleur welcomed Verrilli’s action. “I believe the commission’s ability to regulate demand response in wholesale electric markets is of vital importance,” she said in a statement. “Demand response contributes to reliability, sustainability and affordability of electric service.”
NEPGA Request
Verrilli’s action came last week as ISO-NE and others took sides in response to a request by generators that DR be eliminated from New England’s forward capacity market.
The generators said the request was warranted by the D.C. Circuit Court of Appeals ruling that vacated FERC Order 745, which set pricing rules for DR in wholesale energy markets. The ruling, which resulted from a challenge by the Electric Power Supply Association, was also cited in a similar challenge by FirstEnergy in PJM’s capacity market.
As of Friday, nearly 40 entities had sought to intervene in the New England docket, including power generators, demand response providers, consumer and environmental advocates, utilities, state regulators and commercial customers.
ISO-NE said the generators’ request is premature. “NEPGA’s suggestion that demand response simply be removed from the capacity market fails entirely to account for the continued benefits of demand response that currently participates in the wholesale market on the supply side, and the potential for structural and tariff adjustments to reflect these continued benefits.”
The New England Power Pool Participants’ Committee said ISO-NE must follow its filed rate and that NEPGA has not sought to utilize the stakeholder process to change it.
Demand response provider CPower said NEPGA’s complaint should be denied because it will make the capacity market less competitive, resulting in higher prices.
Public Service Enterprise Group was among those filing in support of the generators, saying the commission should prevent the ninth Forward Capacity Auction clearing prices from being distorted by resources that cannot lawfully participate in the auction. Commission action would avoid having to unwind the results of FCA 9 after the auction has run, PSEG said.
NEPGA asked FERC to issue an order by Jan. 15, two weeks before ISO-NE is set to begin its next FCA on Feb. 2.
The U.S. Department of Justice is investigating the interconnection process in PJM’s MAAC sub-region as part of its anti-trust review of Exelon’s $6.8 billion takeover of Pepco Holdings Inc.
PJM officials said last week they had received a request for documents regarding “each proposed generating facility or planned upgrade to an existing facility (300 MW and above) that filed a request with PJM to interconnect in the MAAC sub-region of PJM in the last 10 years.”
The request came just five days after the Federal Energy Regulatory Commission approved the acquisition, without discussion or conditions, at its Nov. 20 meeting (EC14-96).
The Justice Department appears to be investigating concerns previously raised by PJM’s Market Monitor, which said transmission owners may have a conflict of interest in conducting interconnection studies on competitors’ generation.
The request covers PJM and all members involved in the interconnection process. “If you are a transmission owner or generator owner in the MACC sub-region involved in generator interconnection queue requests 300 MW and above in the last 10 years, then you are an affected member,” Dave Anders, PJM director of stakeholder affairs, wrote in an email to members.
Of the more than 1,100 projects submitted in the last 10 years, about 245 of them are 300 MW or above and about 118 are in MAAC. The department wants those documents from all parties by Dec. 16.
“We’re just sending them all of our file cabinets,” joked Steve Herling, PJM vice president for planning, when asked about the request during the Planning Committee meeting last week.
Section 7 Inquiry
The Justice Department’s notice doesn’t detail why it is seeking the documents. The demand letter notes that it is seeking the documents “in the course of an antitrust investigation to determine whether there is, has been or may be a violation of Section 7 of the Clayton Act … by conduct, activities or proposed action” of the acquisition of Pepco by Exelon.
Section 7 prohibits a merger if “the effect of such acquisition may be substantially to lessen competition or to tend to create a monopoly.”
Exelon spokeswoman Judy Rader said the company has already provided the department with documents in connection with what she called “the DOJ’s review of our proposed merger, not a separate antitrust investigation.”
Interconnection Process
As in non-RTO regions, PJM’s transmission owners conduct the studies that determine what developers will need to spend to connect their generators to the grid without causing overloads or other reliability problems. PJM manages the queue process.
“The process is complex and time-consuming as a result of the nature of the required analyses. The cost, time and uncertainty associated with interconnecting to the grid may create barriers to entry for potential entrants,” the Independent Market Monitor noted in the State of the Market report for the third quarter of 2014. “The queue contains a substantial number of projects that are not likely to be built. These projects may create barriers to entry for projects that would otherwise be completed by taking up queue positions, increasing interconnection costs and creating uncertainty.”
PJM Assistant General Counsel Steve Pincus said PJM received a data request for Exelon’s acquisition of Constellation Energy. That deal closed in 2012.
This is the first time Pincus said he was aware of the department taking interest in the interconnection process.
FERC enforcement staff has investigated interconnection processes in other regions, such as the Southeast. There, independent generators complained that vertically integrated utilities outside of RTOs were using the process to thwart competition by delaying studies and requiring excessive spending on transmission upgrades.
“We think that our process, with the RTO’s independence, addresses those issues that existed in the past,” Pincus said.
IMM Still Has Concerns
Market Monitor Joe Bowring declined to comment yesterday on the department’s inquiry. But the Monitor has been recommending since 2013 that PJM outsource interconnection studies to an independent party to avoid potential conflicts of interest.
“Currently, these studies are performed by incumbent transmission owners under PJM’s direction. This creates potential conflicts of interest, particularly when transmission owners are vertically integrated and the owner of transmission also owns generation,” the Monitor said in the third-quarter report.
“There is also a potential conflict of interest when the transmission owner evaluates the interconnection requirements of new generation which is part of the same company,” the report added.
The Monitor also recommended last year that PJM establish a review process to ensure that projects are removed from the queue if they are not viable, and that commercially viable projects advance in the queue ahead of projects that have failed to make progress.
“DOJ issues these kinds of requests from time to time in large merger cases to gather more information to complete its investigation,” Rader said. “Exelon and PHI have already provided the DOJ with our documents related to this request, and now the DOJ is asking for similar information from other parties. Exelon and PHI will continue to work cooperatively with the DOJ as it conducts its review of our proposed merger.”
Not Routine
But D.C. energy attorney Carolyn Elefant, who has 25 years of experience in federal regulatory matters, sees it as anything but routine.
“It is very unusual,” Elefant said yesterday. “It does seem unusual for the Department of Justice to go right to the transmission organization, and also I am not quite sure why the Department of Justice didn’t raise these issues” with FERC, she said.
Elefant represents the Mid Atlantic Renewable Energy Coalition, one of the interveners in the Exelon-Pepco acquisition docket, but doesn’t represent any of the parties covered by the Justice Department document demand.
“I think it is fair to say that the Department of Justice either has concerns about the acquisition or concerns about FERC’s resolution,” she said.
FERC Approval
In September, FERC issued a notice that it had given permission for staff to communicate with the department.
In its Nov. 20 order, FERC indicated it did not have any anticompetitive concerns with the Pepco acquisition. (See FERC Approves Exelon-Pepco Merger.)
Dismissing concerns of market power, possible rate climbs and suppressed competition, the commission approved the pending acquisition without discussion. Its written decision made clear it didn’t see any market issues with the acquisition, in part because Pepco holds only a negligible amount of generation. “While the commission is aware that Exelon will be a member with more assets after the merger, there is nothing in the record of this proceeding to indicate Exelon will have excessive influence over the stakeholder process or the independence of PJM.”
FERC did not immediately respond to a request for comment yesterday.
