Illinois legislative leaders haven’t decided on their next move following a report that offered options for improving the finances of Exelon’s nuclear power plants.
“The report just came out. We’re still examining it,” Steve Brown, spokesman for House Speaker Michael Madigan, said Friday. Madigan, a Democrat, introduced Resolution 1146, which passed with bipartisan support last spring, asking state agencies to investigate “potential market-based solutions to guard against premature closure of at-risk nuclear plants and associated consequences.”
The resulting 269-page report, released Jan. 8, advised legislators that they could keep the status quo; establish a cap-and-trade program with other states; tax fossil fuel-burning generators; adopt a low-carbon portfolio standard; or embrace a sustainable power planning standard. (See Illinois Considering Carbon Tax, Cap-and-Trade to Save Exelon Nukes.)
All of the options are likely to result in higher power prices for consumers.
Asked whether there would be meetings or public hearings, Brown said, “I don’t know if any of that has been decided yet.”
Brown said the recent turnover in the state’s executive branch will play a part in what happens next. Republican Gov. Bruce Rauner took office last week, replacing Democrat Pat Quinn.
“I’d say later rather than sooner regarding the timetable,” Brown said, adding that it was premature to say which of the five options will gain traction.
“I have not heard any discussion suggesting that there’s a consensus around any of the different ideas,” he said. “It’s an important issue and will take some time to sort out.”
Likewise, the office of House Republican Leader Jim Durkin, who co-sponsored the resolution, offered no timetable for a response to the report.
Exelon has said that its nuclear generating stations in Byron, Clinton and Quad Cities are unprofitable in the current market and that government subsidies and tax credits afforded the wind and renewable energy sectors have created an unfair market advantage for its competitors.
The nuclear power giant argues that its stations should get credit for producing carbon-free electricity.
While Exelon lauded the report as validating its view, others interpreted it differently.
“These reports clearly demonstrate that the economic situation for multiple nuclear facilities is much more manageable than originally thought. The report also finds that the retirements of the Illinois nuclear fleet will not cause reliability problems with the state’s electric supply, except under extreme scenarios never before seen in U.S. energy markets, including PJM,” said David Gaier, spokesman for NRG Energy.
Gaier said the best course of action would be to keep the status quo. “Allowing the market to work, which means no ‘subsidy legislation,’ will save ratepayers more than $120 million per year,” he said.
Much of the Illinois report addresses the potential costs to the state if the plants are retired, which would result in the loss of jobs and tax revenue and the possibility of having to burn more fossil fuels to replace the lost generation.
It was produced by the Illinois Commerce Commission, the Illinois Power Agency, the Illinois Environmental Protection Agency and the Illinois Department of Commerce and Economic Opportunity.
The Federal Energy Regulatory Commission will accept comments until Feb. 19 on price formation in RTO and ISO energy and ancillary services markets.
“With proper price formation, the RTO/ISO would ideally not need to commit any additional resources beyond those resources scheduled economically through the market processes, and load would reduce consumption in response to price signals such that market prices would reflect the value of electricity consumption without the need to curtail load administratively,” the commission said in its notice (AD14-14).
“In reality, RTO/ISO energy and ancillary services market outcomes are impacted by a number of technical and operational considerations. … Notwithstanding the foregoing technical limitations and operational realities, the commission believes there may be opportunities for RTOs/ISOs to improve the energy and ancillary service price formation process.”
The commission held technical workshops on the subject Sept. 8 (uplift workshop); Oct. 28 (shortage pricing/mitigation workshop) and Dec. 9 (operator actions workshop). (See PJM Under Scrutiny at FERC Uplift Hearing.)
The commission’s notice solicits questions in 12 categories:
MISO has asked the Federal Energy Regulatory Commission for a rehearing of the commission’s Dec. 12 order requiring the RTO to modify the way it calculates the “hurdle rate” for determining whether to allow power flows between its north and south regions.
The RTO said FERC’s directive would cause the hurdle rate to soar by 4.5 times the current rate of $9.57/MWh, making transfers between the regions of more than 1,000 MW — the maximum allowed by SPP without paying additional transmission charges — uneconomic (ER14-2445-002, ER14-2445-003).
MISO began limiting flows last spring between its northern and southern regions after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW physical contract path. SPP has billed MISO more than $35 million for flows exceeding 1,000 MW.
While seeking to resolve the dispute with SPP, MISO last July asked FERC for permission to implement the $9.57/MWh hurdle rate — an adder to the LMPs of the importing sub-region — to establish market signals indicating when the savings from avoided redispatch costs exceed SPP’s additional transmission charges.
MISO anticipated the hurdle rate could result in about $34 million in annual production cost savings, benefitting consumers.
‘Irreparable Harm’
But MISO told FERC this month that the new method of calculating the hurdle rate ordered by the commission, and SPP’s Service Agreement charges, mean its ability to use its 1,000 MW of contract path rights “is significantly limited and its market is suffering irreparable harm.”
MISO claims that the SPP-MISO Service Agreement assesses charges for every hour of the 24-hour day for even a 30-second, unintentional “incursion” over the threshold.
The RTO “continues to see that redispatching generation is more economic than incurring hurdle rate charges at $9.57/MWh,” MISO said. “When the hurdle rate soars to almost $42/MWh as a result of the commission’s order, it is clear that MISO’s market participants will not be able to realize the economic benefits of allowing flows to be dispatched in excess of the 1,000-MW threshold even though there is available uncongested capacity above 1,000 MW.”
FERC said it agreed with Madison Gas & Electric and WPPI Energy that “by dividing the hourly approximation of the SPP Service Agreement charges by all intra-regional flows, MISO’s proposed hurdle rate is too low and would allow flows when the economic benefits of such transfers would be less than the SPP Service Agreement charges.”
The hurdle rate has not been universally accepted within MISO’s footprint. The Mississippi Public Service Commission contends that the hurdle rate could distort energy prices and effectively treat MISO’s north and south regions as separate RTOs.
Other Fallout from Seams Spat
The flow dispute with SPP has had other effects. Last month, FERC approved MISO’s request to suspend action on long-term transmission service requests (TSRs) between its north and south regions through April 1.
The order (ER14-2022) also allows MISO to waive Tariff requirements and North American Energy Standards Board standards involving flows exporting from MISO South to PJM. MISO told the commission that the waiver request would affect 10 pending long-term firm TSRs from a single customer totaling 2,831 MW.
That waiver request provided some insight into MISO’s thinking in integrating Entergy before the dispute with SPP arose.
Originally, MISO said it anticipated that the primary restrictions on flows between its north and south regions would be set under the Operations Reliability Coordination Agreement (ORCA), a seams agreement with SPP.
MISO also said it thought it would have extra time to negotiate seams agreements governing flows between those regions.
The need for a 1,000-MW limit on flows between north and south was a “sudden and unexpected development,” MISO told FERC.
DALLAS — The Markets & Operations Policy Committee approved the following measures at its two-day meeting last week. The issues will next be considered by the Board of Directors.
MARKET WORKING GROUP
Transitional ARR Allocation Process OK’d
The MOPC approved without opposition a rule that will allow transmission owners that are new to the Integrated Marketplace to participate in an auction revenue rights allocation prior to the monthly allocation if they are unable to participate in the annual one (MPRR 221).
Revised LTCR Process Approved
Members approved a response to an Oct. 28 FERC order finding SPP not in compliance with guidelines 3 and 5 of Order 681, which set the rules for long-term firm transmission rights (MPRR 227).
FERC ordered SPP to create a process for offering long-term congestion rights (LTCRs) for transmission upgrades to “any party” and to allow load-serving entities to nominate candidate LTCRs prior to a simultaneous feasibility test to determine the availability of the nominated LTCR.
SPP’s response proposes a transmission planning study process that would grant candidates incremental LTCRs in lieu of Tariff Attachment Z2 credits for sponsored transmission upgrades. It also would allow LTCRs and incremental LTCRs to be nominated prior to the simultaneous feasibility test instead of selecting them after the test.
Bill Dowling of Midwest Energy, a customer-owned utility in western Kansas, was among several members who voted no. He said it is unfair for entities that make relatively inexpensive transmission upgrades, such as replacing a wave trap, to be entitled to LTCRs, “competing with those who have invested hundreds of thousands or millions” on bigger improvements.
“We just flat-out think FERC got it wrong,” he said.
American Electric Power’s Richard Ross said he shared Dowling’s concerns but that the proposal was a “reasonable response” to the FERC order.
“We’re not going to convince FERC they got it wrong,” Ross said. “We have to do something.”
Action on Day-Ahead Must-Offer Rule Deferred
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The committee approved a Market Working Group recommendation that it defer action on changes to the current limited day-ahead must-offer rule.
In November, the working group voted to recommend that no action be taken on the rule until the deadline for reporting to FERC on how it is working. The vote followed a presentation by SPP staff in October on results of a six-month evaluation of the rule’s impact. The analysis found that almost $362,000 in penalties were issued for shortages in 128 hours between March 1 and Sept. 30.
The majority of the working group said having no day-ahead must-offer rule was preferable to the current limited one and that there was no need to address changes to the current rules now.
The report to FERC is due 15 months after the Integrated Marketplace went live last March 1 and will incorporate 12 months of market data.
Resource Hubs Process Revised; New Hub Created
The committee endorsed an initiative to eliminate discrepancies between the market hubs establishment process in the Marketplace Protocols and that in the Tariff, approving without opposition a compliance filing in response to a 2013 FERC order (ER13-1173).
The vote included approvals of six current resource hubs that have not been previously made official — GRDA_HUB; GRDA_HUBSA; UCUHUB; GSPR2014HUB; OMPA_GENHUB; and KCPLHUB — and one new hub, GSPR2015HUB.
Before SPP created the hubs process in 2012 (Marketplace Protocol Revision Request 90), the Tariff had general “placeholder” language about market hubs, but the Protocols were silent. The MPRR made modifications to the Tariff and added several sections to the Protocols, with market hubs split into two categories — trading hubs and resource hubs — with separate approval processes.
The filed Tariff language referenced the approval process in the Protocols: the SPP Market Monitoring Unit reviews proposed resource hubs for consistency with the market hub criteria while the Markets Working Group and MOPC must approve trading hubs.
The FERC order rejected all changes to the hubs establishment section of the Tariff, leaving in place the original language, which requires all market hubs be recommended by MOPC and approved by the Board of Directors.
But the proposed changes had already been incorporated into the Protocols, and were not removed after the FERC order, resulting in the discrepancies between the Protocols and Tariff.
The filed Tariff language said that approved market hubs won’t take effect until they have been posted for 45 days, while the original Tariff language set a six-month posting requirement. The compliance filing will seek a waiver from the six-month posting requirement for the newly-created hubs.
Kansas City, NW Kansas No Longer Constrained Areas
MOPC approved the Market Monitoring Unit’s recommendation (TRR 149) to eliminate the Kansas City area and the Northwest Kansas area as frequently constrained areas (FCAs).
SPP’s Tariff defines FCAs as areas with one or more binding transmission or reserve zone constraints that are expected to be binding for at least 500 hours annually and within which one or more suppliers are pivotal.
As a result of transmission expansions, the MMU said, the two regions no longer experience high levels of congestion that left them vulnerable to market power by a dominant supplier.
SPP’s third FCA, the Texas Panhandle, is unaffected by the change.
The three FCAs were recommended by Potomac Economics, under contract with the MMU, before the Integrated Marketplace was launched.
REGIONAL TARIFF WORKING GROUP
Regional Cost Allocation Review Remedies Added
Members approved remedies for addressing problems identified in regional cost allocation reviews (TRR 131).
SPP’s Tariff requires the RTO to review the reasonableness of its regional and zonal allocation methodologies at least once every three years.
The revision adds to the Tariff potential remedies for correcting imbalances in cost allocations:
Acceleration of planned upgrades;
Issuance of Notifications to Construct (NTCs) for selected new upgrades;
Apply regional allocation to all, or a portion, of the cost of any project that otherwise would not qualify for regional allocation;
Recommend potential seams transmission projects;
Transfer zonal annual transmission revenue requirements (ATRRs) to the region-wide ATRR;
Exemptions from allocated costs associated with future transmission projects; and
Change cost allocation percentages as defined under Section III of the revision’s Attachment J.
Jeff Knottek, of the City Utilities of Springfield, Mo., said he was supportive of the changes but was concerned they don’t do enough to correct inequities.
Tariff Revised to Eliminate ‘Windfall’ Point-to-Point Revenues
The MOPC approved Tariff revisions to eliminate ambiguity in the application of credits for point-to-point (PTP) revenues (TRR 143). The revisions are intended to make the Tariff consistent with the incorporation of multi-owner zones that have both formula-rate and stated-rate ATRRs.
The changes clarify the transmission owner’s obligation to account for all point-to-point revenues beyond the TO’s allowed ATRR. If the TO’s formula rate template does not account for adjustments to the zonal ATRRs and Schedule 11 ATRRs for PTP revenue, the proposed Tariff revisions will allow SPP to reduce the charges in the settlement process.
“This is making sure there isn’t either a windfall” or a shortfall, said Regional Tariff Working Group Chairman Dennis Reed of Westar Energy. “This ensures that the target that SPP will try and hit [for PTP and other transmission revenue] is correct.”
Rules for Seams Transmission Projects Approved
MOPC approved additional Tariff language governing the rules for seams transmission projects, as outlined by the policy paper released by the Seams Steering Committee in September (TRR 144).
AEP’s Ross expressed misgivings about the changes, saying the Regional State Committee should know that “they may not be getting all they expected.”
OTHER MATTERS
Staff to Update Wind Integration Study
SPP operations staff will update a 2010 study to evaluate the impact of increasing wind generation on the SPP system.
The original Wind Integration Task Force study, which was completed in January 2010, focused on balancing, forecast needs, tool development and transmission adequacy. Results were incorporated into the design of the Integrated Marketplace.
In the five years since, installed wind capacity in the RTO is approaching or has passed the levels forecast in the study.
“There’s a lot higher penetration of wind. There are more operational concerns and issues that we have to be aware of,” said Operating Reliability Working Group Chairman Jim Useldinger of Kansas City Power and Light.
“Just this week we went from 7,000 MW to 700 MW [of wind generation] in a short period of time,” one SPP staffer said.
A year ago, the working group presented a proposal to update the study to reevaluate transmission adequacy based on new wind capacity forecasts.
The MOPC asked the task force to revise the study scope based on what the RTO’s staff can provide without employing external analysts.
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The task force’s revised proposal recommends staff use current and forecast wind installations to review the transmission adequacy assumptions from the 2010 study.
It also will look at operating characteristics and impacts including frequency response (Consolidated Balancing Authority needs vs. wind capability), reactive capabilities under low-wind and high-wind-low-load scenarios and the likelihood of wind events becoming contingency events.
The goal will be to determine the need for any new operational requirements on wind farms and provide inputs into transmission planning studies.
The study, which is expected to take about one year, will be split to provide initial results regarding operational concerns sooner because the transmission review could take longer.
Meanwhile, the Generation Working Group released its biannual report, which recommended no changes to SPP’s methodology for establishing net capability for wind and solar facilities.
Effort to Streamline Aggregate Study Procedures Wins OK
Members approved a measure to revise the Aggregate Study process in an effort to make it more efficient (TRR146). The revisions also consolidate the process into Attachment Z1. Members also approved BPR051, which documents the procedures for the new process.
Order 1000 Task Force Gets New Boss, More Members
The Competitive Transmission Process Task Force will expand its membership and report to the MOPC under a charter change outlined to the committee.
The task force will have at least at least six and as many as 15 members with experience and knowledge in electric transmission engineering design, project management and construction, operations and maintenance, rate design and analysis, and finance.
Larry Holloway of the Kansas Power Pool expressed concern that the charter didn’t list policy experience among the requirements for task force members. Holloway also said it needed diversity with viewpoints of those other than incumbent transmission owners.
Terri Gallup of AEP responded that “a lot of [current task force members] have policy titles within our companies” in addition to experience in the fields listed in the charter.
MOPC Chairman Noman Williams, of South Central MCN, said no committee vote was required on the charter change.
Minimum Design Standards for Competitive Upgrades Approved
Members approved without opposition minimum design standards for competitive transmission upgrades (MDS) with a correction noting that 230-kV circuits should have ratings of at least 1,200 amps, not 2,000 as shown in the MDS.
SPP Announces ‘One-Stop Shop’ for Tracking Document Changes
SPP is creating a Web page as a “one-stop shop” for finding the latest version of the Tariff, Marketplace Protocols, business practices and other documents subject to the RTO’s revision request process.
“You won’t have to go to four different Web pages to find them,” explained Debbie James, manager of market design.
The primary working groups will review all changes to the revision request process prior to MOPC approval of the changes.
SPP, MISO Agree on Revised Flowgate Process
SPP and MISO have agreed on a new process for coordinating tie-line flowgates. The two RTOs have agreed to begin using the new process even before filing it with FERC early this year as an addition to their Joint Operating Agreement.
The party with functional control over the most limiting equipment for the flowgate will be the managing entity and is responsible for available flowgate capability (AFC) calculations. New tie-line flowgates will initially be created as temporary and will not become permanent for 60 days after notification is posted.
The initiative began when SPP staff was assigned to research whether MISO had followed procedures in creating a new flowgate on a line between it and the Empire District Electric. [MISO FG #6257: Ozark 161 kV (EDE) to Omaha 161 kV (EES) for the loss of Osage 161 kV (EES) to Eureka 161 kV (CSWS)].
Empire officials were “surprised” by the flowgate, said David Kelley, SPP’s director of interregional relations.
“I think we’ve identified maybe a gap in our process,” Empire District’s Bary Warren said. There should be explicit criteria for establishing permanent flowgates, including a dispute resolution process, he said.
SPP staff will propose the new coordination process to Associated Electric Cooperative, Kelley said.
Project Pinnacle ‘Close to the Finish Line’
Barbara Sugg, vice president of information technology, told members SPP is “very, very close to the finish line” for Project Pinnacle, implementing Phase 2 of the Integrated Marketplace, including market-to-market rules, long-term congestion rights and regulation compensation.
CONSENT AGENDA
MOPC also approved the following items on the consent agenda with no discussion:
BPWG-BPR 065 BP 7250 Modification: Generator Interconnection Service
MWG-MPRR 209 Change Start-Up Offer from Daily to Hourly
Massachusetts needs additional natural gas pipeline capacity to avoid severe energy shortages in the next few decades, a study commissioned by the state concluded. Even if the capacity is built, winter price spikes caused by severe cold and competition for gas as a heating fuel will remain through 2019, according to the “Massachusetts Low Gas Demand Analysis” study by Synapse Energy Economics.
Measures like demand response, the ISO-NE Winter Reliability program and fuel switching to oil-fired generation will meet electricity demand, but price shocks will occur, Synapse said.
The study, ordered by former Gov. Deval Patrick, repeats many of the same claims from previous analyses by New England states and the regional power grid operator. Environmental advocates from The Acadia Center said the study was too limited in its scope and unnecessarily justifies construction of a controversial gas pipeline that would serve the entire New England region.
The Synapse analysis considered eight scenarios, including low and high natural gas prices, and whether up to 2,400 MW of Canadian hydropower would be available. The scenarios were evaluated from an economic and reliability perspective and assessed for compliance with state Global Warming Solutions Act (GWSA) targets.
Necessary pipeline additions by 2020 range from 25 billion Btu per peak hour for scenarios that assumed low gas demand and a combination of high natural gas prices and no incremental Canadian hydropower, to 33 billion Btu per peak hour for analyses that considered various combinations of gas price assumptions and whether Canadian hydropower was added. By 2030, the additions range from 25 billion Btu per peak hour to 38 billion Btu per peak hour.
The Acadia Center (formerly Environment Northeast), while supportive of the effort to explore alternatives, believes the study is incomplete. The group said it could be misinterpreted as support for a new subsidy that would shift multi-billion dollar risks from private corporations to the public.
A proposal by the six New England governors for a $3 billion taxpayer-supported pipeline transporting shale gas from Pennsylvania stalled in August due to cost concerns in Massachusetts. Patrick temporarily suspended the state’s support of the pipeline after the state legislature failed to act on additional transmission lines to import Canadian hydropower.
The transmission expansion and natural gas pipelines are seen by New England governors as integral parts of an overall regional energy strategy.
The study is limited to Massachusetts, which uses less than half of the energy required in New England and does not have nearly as much renewable energy potential as neighboring states, the center says. It also uses outdated prices for oil and liquefied natural gas, the group said.
“Massachusetts has taken an important but preliminary step toward thorough analysis of viable supply- and demand-side solutions to meet our energy needs,” Acadia Center President Dan Sosland said. “Because electric ratepayers across New England are being asked to subsidize the construction of a pipeline that could take decades to pay off, alternatives need to be examined in all New England states to ensure that we have an accurate, up-to-date picture of how to power the region while reducing risks to consumers and bringing down greenhouse gas emissions.”
NYISO is reorganizing its leadership team in preparation for CEO Stephen Whitley’s plan to retire next year.
NYISO executives Richard Dewey, center, and Thomas Rumsey, right, won promotions as the RTO’s board prepares to replace CEO Stephen Whitley, left, who will retire next year.
The ISO’s Board of Directors announced last week that it had extended Whitley’s contract to mid-2016, when he will cap an eight-year tenure as CEO.
The board also announced a reorganization of NYISO’s leadership team and the promotion of two executives.
Richard Dewey was promoted from senior vice president and chief information officer to executive vice president, responsible for operations, information technology and market structures. Thomas Rumsey, formerly vice president of external affairs, was named senior vice president of external affairs with responsibility for media relations, corporate communications, government and regulatory affairs, stakeholder services and strategic planning.
Senior Vice President and Chief Operating Officer Rick Gonzales has added responsibilities for preparing the ISO for its growing dependence on natural gas as well as the increasing penetration of renewable and distributed energy resources. Senior Vice President of Market Structures Rana Mukerji will be responsible for market design, demand response and system planning.
NYISO said the restructuring will “drive internal efficiencies, expand the scope of its key leaders and best position the company to meet the emerging challenges in the industry.” It cited growing dependence on natural gas, the increased penetration of renewable and distributed energy resources and new environmental regulations as key issues facing the reorganized team.
The NYISO board said it will conduct a nationwide search for Whitley’s successor and consider both internal and external candidates.
Before joining NYISO in July 2008, Whitley was SVP and COO at ISO-NE for seven years. Prior to that, he was ISO-NE vice president of system operations from 2000 to 2001.
He also spent 30 years at the Tennessee Valley Authority, last serving as electric system operations general manager of the transmission power supply group.
The Federal Energy Regulatory Commission on Friday granted PJM’s request to increase the cost-based energy offer cap to $1,800/MWh through March.
“We find that PJM has demonstrated that the current offer cap of $1,000/MWh in PJM is unjust and unreasonable for the winter months,” FERC said in its order, which became effective immediately (EL15-31). PJM had requested the Tariff revision go into effect Jan. 9.
Any cost-based offer, regardless of fuel type, will be eligible to set the LMP, the ruling said, rejecting a request by the Independent Market Monitor that it be restricted to natural gas.
“We find that restricting the proposal to natural gas costs alone would be unduly preferential to those sellers whose electricity is from natural gas-fired generation,” the order said.
Meanwhile, the commission said, it is “exploring potential improvements to market design and operational practices in order to ensure appropriate price formation in energy and ancillary service markets operated by ISOs/RTOs, which involved four staff papers and a series of workshops.”
The order included a request for comments as FERC seeks information on possible alternative offer caps and how it can mitigate seams issues among neighboring RTOs. (See PJM Seeking RTO Consensus on Offer Cap Increase.)
Responding to critics’ concerns, the commission said, “While PJM’s proposal may exacerbate seams issues by creating an incentive for external resources to attempt to sell into PJM when energy prices exceed $1,000/MWh, PJM is proposing only a short-term, temporary change applicable over the next few months.”
FERC also dismissed protesters’ assertions that the waiver would invite unsupported market-based offers above the $1,000/MWh cap.
“PJM’s proposal also provides additional protection to customers by requiring that market sellers provide cost justification for all bids above $1,000/MWh according to PJM’s cost development guidelines, in order to set the LMP,” it said.
Furthermore, it noted, “As we found in the February 2014 Waiver Order, allowing these offers to set LMP promotes efficient resource selection and sends clear market signals so that resource costs are reflected in transparent market prices.”
PJM’s proposal will allow generators to recover “justifiable costs” more than $1,800 through make-whole payments, but such offers would not set prices for other market participants.
The issue arose after a spike in gas prices last January pushed some generators’ costs to more than $1,000. At the time, FERC granted PJM’s request for a waiver from the cap to allow some gas-fired generators to cover their costs.
Because the proposal’s wording did not put a time limit on the price cap hike, FERC is requiring PJM to submit a filing by Feb. 27 to remove the waiver effective April 1. Because that change is ministerial, FERC said it will not entertain protests.
FERC also declined to establish hearing procedures, as some had requested. It also denied PJM Load Group’s motion for extension, saying that “the current situation requires immediate relief.” (See PJM Offer Cap Proposal Sparks Opposition.)
In addition, it disagreed with the Load Group that the proposal would result in retroactive ratemaking.
“The Tariff provisions revise offers solely in the energy market and are prospective, as of the date of this order. They, therefore, have no retroactive effect on past offers or energy prices,” the order said.
PJM’s Section 206 filing seeking the higher cap came after stakeholders failed over eight months to reach consensus on changes to the current $1,000/MWh cap. (See Last-Ditch Effort to Break PJM Offer Cap Deadlock Fails.)
The Federal Energy Regulatory Commission yesterday asked the Supreme Court to overturn an appellate court ruling voiding its authority to regulate the rules used by RTOs to pay for demand response, a day after PJM filed a contingency plan for including DR in its upcoming capacity auction.
The 59-page petition for a writ of certiorari, filed by attorneys for FERC and the U.S. Department of Justice, said the D.C. Circuit Court of Appeals erred in its May 23 ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) that FERC lacked authority under the Federal Power Act to issue Order 745. The order requires RTOs to pay DR providers the same way they pay generators in energy markets — through LMPs.
“FERC’s conclusion that it has the authority [and the responsibility] to regulate the compensation paid by wholesale-market operators for demand-response commitments — and recouped in the wholesale rate set in the auction markets run by those operators — is the best and indeed only sensible reading of the statutory text,” FERC said.
The petition said the Supreme Court should take the case because of the growing importance of demand response.
“Even read most narrowly — as invalidating only FERC’s authority to regulate the level of compensation paid by wholesale-market operators to demand-response providers in energy markets — the decision … threatens significant damage to the nation’s wholesale-electricity markets,” FERC said.
FERC said its regulation of DR participation in wholesale markets “is essential to the commission fulfilling its statutory responsibility to ensure that [wholesale] rates are just and reasonable” and that the EPSA ruling also threatens the participation of DR in wholesale capacity markets.
“Because the court concluded categorically that ‘[d]emand response is part of the retail market,’ and determined that the FPA ‘unambiguously restricts FERC from regulating the retail market,’ its holding throws into serious question whether FERC may review any of the rules established by wholesale-market operators to govern demand-response participation — or perhaps even whether it has authority to permit the participation of demand-response providers in wholesale-electricity markets at all,” FERC said.
PJM Filing
On Wednesday, PJM submitted to FERC its contingency plan to incorporate DR in May’s Base Residual Auction if the Supreme Court rejects the petition and allows the ruling to stand (ER15-852).
General Counsel Vince Duane outlined the plan Dec. 18 to the Markets and Reliability Committee. (See PJM to File Post-EPSA Demand Response Contingency Plan with FERC.) It would allow a load-serving entity “or other wholesale entity” to submit demand-side bids — “wholesale load reductions” — causing PJM to procure less capacity in the BRA.
PJM requested a response from FERC by April 1. If the court agrees to hear the case, PJM would withdraw the filing.
Duane said last month that PJM can expect a decision on whether the court will take the case in March or April.
The New Jersey Board of Public Utilities staff has recommended approval of Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. in a settlement that would give Atlantic City Electric customers $62 million in rate credits.
The settlement, announced yesterday, came as the board was holding public hearings on the merger. If approved by the BPU, Exelon would need only approval from regulators in Delaware, Maryland and D.C. for a deal that would result in a company with more than 8 million customers from Illinois to the Atlantic.
Pepco Holdings, headquartered in D.C., includes Atlantic City Electric, the Pepco utility serving the District, and Delmarva Power & Light, with customers in Delaware and Maryland.
The $62 million in rate credits amounts to $114 for each of Atlantic City Electric’s 544,000 customers. The settlement also includes:
An energy-efficiency program that would provide $15 million in energy savings over five years;
Promises to hire 60 union employees, protect wages and benefits and keep a headquarters at Mays Landing, N.J.; and
Charitable contributions equal to Atlantic City Electric’s $709,000 annual giving for 10 years.
Rate Counsel Rejects Settlement
While the settlement with the BPU staff is a major step toward final approval in New Jersey, it was not signed by New Jersey’s consumer advocate, the Division of Rate Counsel.
Rate Counsel Stefanie Brand told a BPU evidentiary hearing yesterday that she did not sign the settlement because it includes no limit on the post-merger transition costs Atlantic City Electric can seek or any “stay out” — a period of time when the company is prevented from seeking a rate increase.
“Without express limitation on the level of post-merger transition costs recoverable by Atlantic in a future proceeding, costs associated with the merger — such as installing new computer systems or severance payments that would not have been incurred by Atlantic but for the merger — may be sought by the company in Atlantic’s next base rate case without limitation,” Brand said. “In other words, the $62 million of benefits to Atlantic’s customers may be offset or totally wiped out.”
Brand also criticized the settlement’s claims that it would require Exelon to improve Atlantic City Electric’s reliability performance.
The settlement says the company would forfeit 50 basis points in the next electric distribution base rate case filed after January 2021 if it fails to meet a System Average Interruption Frequency Index (SAIFI) of 1.05 interruptions per customer per year or a Customer Average Interruption Duration Index (CAIDI) not to exceed 100 minutes.
Brand said the thresholds represent no improvement over the commitments the company made in the Reliability Investment Program as part of its 2009 base rate case. Brand said the company already has met the 100-minute target and would likely meet the SAIFI goal before the program’s expiration in 2016.
Brand also said the “most favored nation” clause in the settlement — an assurance that New Jersey will benefit from any additional concessions achieved by states yet to approve the merger — was too narrow.
“The decision to approve the merger in New Jersey is not a slam dunk,” Bruce Burcat, executive director of the Mid Atlantic Renewable Energy Coalition (MAREC), said in an interview. “The board will now have to consider the concerns of the non-signing parties and decide whether to approve the joint stipulation.”
Burcat’s group didn’t oppose the settlement. In return, Burcat said, Exelon has agreed not to oppose MAREC’s request that the BPU open a docket to order Atlantic City Electric to use a competitive process for the procurement of a portion of its obligations under New Jersey’s Renewable Portfolio Standards.
Public Hearings Begin in Maryland
The announcement of the New Jersey settlement came the day after a public hearing on the merger in Maryland.
About 100 people attended a Public Service Commission hearing on the merger in Rockville Tuesday night, the first in a series of public-comment hearings before evidentiary hearings begin in late January.
The majority of the crowd either belonged to or were supportive of environmental groups Chesapeake Climate Action Network (CCAN) and 350 Montgomery County, and they cautioned the commission on Exelon’s record on renewable energy.
Many of the speakers said Exelon’s goal was to use Pepco’s ratepayers to subsidize its nuclear fleet, which has become unprofitable.
About 100 attended a Maryland Public Service Commission hearing on the Exelon-Pepco merger in Rockville Jan. 13.
Others, including County Councilmember Roger Berliner, did not take a position on the merger at the hearing. Instead they urged the commission to make Pepco open up its transmission line right-of-ways for recreational use, if it approved the deal. Some speakers were hiking and mountain biking enthusiasts who enjoyed open right-of-ways in the territory of Exelon subsidiary Baltimore Gas and Electric but lamented that their trails were interrupted in Pepco’s territory.
Those who spoke in support of the merger included the Montgomery County Chamber of Commerce, the Maryland Chamber of Commerce, the Hispanic Chamber of Commerce and the Salvation Army.
Exelon has offered $100 million in credits for customers in Maryland and other states, but the PSC’s staff has said it thinks $167 million would be a more appropriate offer. (See Exelon-Pepco Merger Faces Headwinds in Maryland.)
The state Office of People’s Counsel has already urged rejection of the deal, calling Exelon’s “purported benefits … either non-existent or woefully deficient.”
PJM’s Independent Market Monitor Joe Bowring told the PSC in a letter that the merger “raises potential vertical and horizontal market power issues,” repeating concerns he expressed to the Federal Energy Regulatory Commission.
Bowring recommended that FERC require the companies agree to remain in PJM and permit independent third-party interconnection studies. He said Exelon should agree to a review of ratings of all elements of the combined transmission systems and a regular process for reviewing and updating transmission limits. Despite Bowring’s comments, FERC approved the merger without conditions in November.
Hard Sell in D.C.
In D.C., where some public hearings have already been held, Exelon faces a hard sell.
People’s Counsel Sandra Mattavous-Frye urged the D.C. Public Service Commission to reject the merger. “The office’s painstaking, comprehensive review and analysis details how the Pepco/Exelon application fails to meet each of the commission’s seven public interest factors,” she said in a statement last month. “Overall, there are far too many risks for consumers and nothing but benefits for Pepco and Exelon.”
A coalition calling itself Power D.C. is also opposing the merger. Although Exelon has promised $14 million in incentives for the District, the coalition, which includes the Sierra Club, CCAN, D.C. Working Families and the D.C. Environmental Network, said the merger wouldn’t benefit ratepayers or businesses.
Delaware PSC Wants $63M
Exelon has offered $17 million in customer credits in Delaware, but a Delaware Public Service Commission consultant has said $62.9 million, or $100 per customer, would be a proper offer. Public hearings are scheduled for February there.
Delaware Public Advocate David L. Bonar said he didn’t expect a settlement in New Jersey so soon.
“I was somewhat surprised the BPU signed off on the agreement as quickly as they did, but not surprised that the New Jersey Rate Counsel declined,” he said.
Bonar said all parties are continuing to work toward a settlement in Delaware, but added, “We are not quite there yet. A merger worth billions of dollars can’t be taken lightly.”
He said his office is “not ready, at this time, to say it’s in the best interest of Delaware as presently constructed.”
Burcat said he didn’t think what happened in New Jersey, where ACE serves a minority of the state, will have an impact on the question in Delaware, Maryland or D.C.
“In the other jurisdictions, Exelon will end up controlling the vast majority of the service territories and will also end up serving most of the electricity load,” Burcat said. “Consequently, the ramifications of the merger in these jurisdictions are substantially higher.”
Exelon has repeatedly said the merger would be a good thing for all concerned. “We believe that the facts — which are available in the testimony we’ve filed with the commission and other information we have provided to the parties through the regulatory process — will show that this merger is in the public interest and will benefit customers and the community,” spokesman Paul Adams said last month.
Justice Department Review
RTO Insider reported last month that 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 the merger. (See DOJ Probing Interconnection Process in Exelon-Pepco Merger.)
Exelon said yesterday that the Justice Department’s review period expired Dec. 22, meaning the Hart-Scott-Rodino Antitrust Improvements Act no longer precludes completion of the merger.
“Exelon and PHI will continue to work cooperatively with the DOJ until it advises them that it has concluded its evaluation of the merger,” Exelon said.
Michael Brooks contributed to this article.
[Editor’s Note: An earlier version of this article incorrectly said the Maryland Public Service Commission had sought $167 million in concessions from Exelon. That recommendation was by the PSC’s staff.]
American Electric Power has hired investment bank Goldman Sachs to investigate the sale of its merchant generation fleet in Ohio and Indiana, both coal- and natural gas-fired.
TheStreet, which first reported the news, said the plants — with a combined capacity of about 8,000 MW — could fetch $2.8 billion to $3.6 billion, based on a price of $350 to $450 per kilowatt. AEP officials confirmed hiring Goldman Sachs but said no decisions have been made.
Melissa McHenry, an AEP spokeswoman, identified the nine plants as:
Gavin – 2,665 MW
Cardinal Unit 1 – 595 MW
Conesville Units 5 & 6 – 810 MW
Waterford – 840 MW
Darby – 507 MW
Conesville Unit 4 – 339 MW
Zimmer – 330 MW
Stuart – 603 MW
Lawrenceburg – 1,186 MW
All of the plants are in Ohio except for Lawrenceburg, which is in Indiana. They represent a total of 7,875 MW.
The news isn’t exactly unexpected. AEP officials have been saying for the past several months that such a deal could be in the company’s future.
AEP Ohio President Pablo Vegas told Columbus Business First in an interview late last year that the plants in question are struggling to remain profitable.
“Those power plants that are on the economic bubble today are essentially coal plants and nuclear plants,” Vegas said. “They’re struggling in the PJM market to cover their fixed costs.”
AEP has gone before the Public Utilities Commission of Ohio seeking long-term guaranteed rates for some of its largest plants in an effort to remain competitive. (See AEP Seeks State Backing for Aging Ohio Coal Plant.)
If PUCO doesn’t rule in AEP’s favor, this could be the backup plan.
Other companies have taken steps to reduce their exposure to the volatility in merchant generation.
Duke Energy exited the field, selling its interest in 11 plants in Ohio, Pennsylvania and Illinois and its retail energy business for $2.8 billion to Dynegy. PPL is in the process of spinning off its generation in a joint venture with Riverstone Holdings.
Illinois legislative leaders haven’t decided on their next move following a report that offered options for improving the finances of Exelon’s nuclear power plants.
vestment bank Goldman Sachs to investigate the sale of its merchant generation fleet in Ohio and Indiana, both coal- and natural gas-fired.