Power prices briefly spiked above $1,000/MWh on Long Island Wednesday due to a combination of cold weather and an unplanned transmission outage.
The price jolt occurred around noon and lasted for only a few minutes when the East Garden City Bank #2 line failed due to equipment issues between 10:45 a.m. and 2 p.m., according to NYISO spokesman David Flanagan.
The Long Island Zone K jumped to about $1,102/MWh. The adjacent Zone J, in New York City, remained at about $33/MWh.
The Zone K day-ahead forecast was for 2,450 MW from 9 a.m. to 2 p.m., but real-time demand was 2,550 MW.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
A. Manual 10: Pre-Scheduling Operations — This update, an annual review, includes a new section highlighting the criticality of reporting outages on facilities providing black start service.
B. Manual 14D: Generator Operational Requirements — Modified to provide consistency with revised North American Electric Reliability Corp. standard VAR-002-3, effective Oct. 1, 2014. Sections 7.1.2 and 7.3.4 contain revisions regarding notifications of status changes on automatic voltage regulators, power system stabilizers and reactive capability.
C. Manual 01: Control Center and Data Exchange Requirements — Addition to Section 3.2.4 regarding user agreements related to purchase of PJMnet connections.
3. Zonal and Residual Metered Load Aggregates (9:30-9:45)
Members will be asked to approve Tariff revisions related to data availability for the bus distribution factors for zonal and residual metered load aggregates utilized by the day-ahead energy market. If there are technical problems that prevent PJM from obtaining the load distribution factors from the snapshot one week prior to the operating day, the load distribution factors from the most recently available day of the week that the operating day falls on will be used.
4. Harmonization of PJM’s Governing Documents (9:45-10:00)
The committee will be asked to approve Tariff and manual revisions related to enhanced inverter capabilities. The new rules will apply to Federal Energy Regulatory Commission jurisdictional inverter-based generators defined as asynchronous generation that have an Interconnection Service Agreement or a Wholesale Market Participation Agreement. The changes will not affect merchant transmission facilities, HVDC inverter-converter facilities or existing generation. (See Enhanced Inverters Clear MRC.)
The New York Public Service Commission on Thursday approved a plan by Consolidated Edison of New York to address overloads in Brooklyn and Queens through a $200 million program that will deploy distributed generation and demand-side management (DSM) in order to defer installation of a $1 billion substation until at least 2026.
The commission said it was the first time New York has chosen to relieve congestion in “non-traditional” methods instead of authorizing construction of utility infrastructure.
Con Ed’s plan is consistent with the state’s “Reforming the Energy Vision” program to restructure the electricity market with greater reliance on technology and distributed resources, the commission said. “The commission is making a significant step forward toward a regulatory paradigm where utilities incorporate alternatives to traditional infrastructure investment when considering how to meet their planning and reliability needs,” the order states.
Commission Chair Audrey Zibelman added that because of the recent D.C. Circuit Court of Appeals decision striking down federal jurisdiction over demand response in wholesale markets, it’s important for state regulators to set market rules for that resource.
Con Ed said the feeders serving the Brownsville No. 1 and 2 substations began to experience overloads in 2013 and would be overloaded by 69 MW for 40 to 48 hours during the summer by 2018. A new substation, transmission subfeeders and a switching station would cost $1 billion, according to the company. The PSC accepted the company’s estimate of the DM Program’s costs and ordered a cap of $200 million.
The program would include 52 MW of non-traditional utility-side and customer-side relief, including about 41 MW of energy efficiency, demand management and distributed generation, and 11 MW of utility-side battery energy storage. This will include incentives to upgrade building “envelopes,” improve air conditioning efficiency of equipment, encourage greater use of energy controls, and establish energy storage, distributed generation or microgrids.
This will be supplemented by approximately 17 MW of traditional utility infrastructure investment, consisting of 6 MW of capacitors and 11 MW of load transfers from the affected area to other networks.
The commission said the project is hoped to have a salutary effect on utilities statewide. “Important and critical lessons will be learned as changes to traditional utility operations and ratemaking are explored, which are consistent with the core elements of the REV proceeding,” it said.
PJM stakeholders last week agreed to review modeling practices that the RTO said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market.
Members of the Market Implementation Committee approved a problem statement proposed by Stu Bresler, vice president of market operations.
Bresler said PJM’s capacity modeling considers all external firm point-to-point transmission resources as sinking to the “rest of RTO” region, including historic resources that actually sink in constrained zones. While PJM uses this transfer capability in calculating the Capacity Emergency Transfer Objective/Capacity Emergency Transfer Limit (CETO/CETL), it does not allocate the benefits of the capability to the transmission holder. This can expose the load-serving entities to locational capacity price differences, Bresler said.
Under the problem statement, stakeholders will consider adding a mechanism in the capacity market similar to one used to allocate Auction Revenue Rights to historical transmission paths in the energy market. PJM said the issue affects “a very limited number of entities.”
Market Monitor Joe Bowring, however, warned “it’s a slippery slope.”
“There were a lot of entities who had bilateral agreements when they joined the market. There is no reason to make special allowances for preexisting arrangements or for those who do not like the outcome of market rules,” Bowring explained after the meeting. “Others will seek concessions related to locational capacity price differences that are also not permitted by the market rules.”
Waiver Request
Bresler said the issue caused one PJM member in Commonwealth Edison’s locational deliverability area to seek a waiver of PJM’s Reliability Assurance Agreement before last May’s base residual auction.
It was an apparent reference to the Illinois Municipal Electric Agency, which won a waiver from the Federal Energy Regulatory Commission regarding its means of serving the Naperville, Ill., portion of its load (ER14-1681).
IMEA said it had agreed to pay $468 million for rights to capacity resources for self-supply of its ComEd load through 2035. IMEA said it had acquired firm transmission rights to ensure delivery of external capacity resources in Kentucky and Illinois. Without a waiver, it said, its investment in self-supply would be worthless and it would have had to spend as much as $24 million per year in additional costs to serve its Naperville load.
PJM supported the request, noting that the “ComEd LDA was recently, and for the first time ever, modeled with a separate VRR Curve.”
The commission approved the one-year waiver, concluding that it would “not lead to undesirable consequences,” but it urged IMEA and PJM to discuss a solution for future years.
Commissioner Philip Moeller dissented, saying the waiver “will transfer costs incurred on behalf of IMEA to everybody else in Chicago and its neighboring areas.”
PJM and MISO have reached agreement on a new product for interchange transactions similar to the Coordinated Transaction Scheduling (CTS) product PJM launched Nov. 4 with NYISO.
The product is intended to reduce uneconomic flows between PJM and its western neighbor. PJM says almost half of the transactions from PJM into MISO occur when prices are higher in PJM.
Under CTS, traders would be able to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeded a threshold set by the bidder.
PJM outlined its plan to the Market Implementation Committee Friday.
The new product will be in addition to two existing means of trading between the two RTOs: hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers. PJM and MISO will require CTS transactions to be submitted 75 minutes before the flow begins. Traditional transactions can be submitted only 20 minutes in advance.
“Market participants can still be a price taker if they feel they have a better idea of future prices than PJM,” said PJM’s Rebecca Carroll.
The CTS product is expected to be similar to the PJM-NYISO offering except that both PJM and MISO will evaluate the trades: only those trades that clear both PJM’s and MISO’s thresholds will clear. NYISO alone is responsible for clearing transactions for the original CTS product.
“Neither one of us [PJM and MISO] do an economic clearing today. We both need to make software changes,” Carroll explained.
PJM and MISO hope to obtain members’ approval in time for a filing with the Federal Energy Regulatory Commission in May 2015. Implementation may not occur until the third quarter of 2016 because of software changes required. “So we need a longer runway to get these software changes implemented,” Carroll said.
MISO’s Board of Directors Thursday rejected proposed guidelines on how the board chair makes committee appointments.
The guidelines, part of proposed changes to the Principles of Corporate Governance, were withdrawn after criticism from board members that they were “too prescriptive” and limited flexibility. The Corporate Governance & Strategic Planning Committee had earlier approved the changes by a 2-1 vote.
Some of the proposed changes spelled out the increase in the board’s membership to nine members from seven (in addition to the CEO), a change approved by the Federal Energy Regulatory Commission in June.
It was the guidelines proposed under the “Selection of Committee Members” that annoyed some directors. The guidelines spelled out the experience that should be required for membership on each of the board’s seven committees. One provision stated that membership on the nominating committee may be rotated annually.
“This is getting pretty prescriptive,” Director J. Michael Evans said. “I don’t think it’s ready for us to take up.”
The board referred the proposals back to the committee.
New Additions to MISO Board
Earlier in the day, MISO members elected two new directors: Thomas Rainwater, CEO of Rainwater Capital Management, and Paul Bonavia, executive chairman of UNS Energy, parent company of Tucson Electric Power and UniSource Energy Services.
One director is the first of two additions to the board between now and 2016 as it expands to nine members. The other takes the place of Shelley Longmuir, an attorney who had been on the board since 2006 but chose not to seek another term.
Baljit Dail, who has served on the board since 2009, was re-elected. All three will serve three-year terms.
The board is expanding from seven to eight directors effective January 1, 2015 and will add its ninth member in 2016.
Members also approved an increases in board members’ compensation. Annual retainers were increased by $10,000 to $70,000. The retainer for commission chairs was boosted by $2,500 to $7,500. The board chair also received a $2,500 increase to $15,000.
A day earlier, MISO’s Advisory Committee cast votes for new leadership. Vice Chairman Kevin Murray, executive director of the Industrial Energy Users-Ohio, was elected chairman for 2015. Tia Elliott, director of regulatory affairs for independent power producer NRG Energy, was elected vice chairman.
PJM’s Market Implementation Committee will begin work in January on an initiative to consider whether the RTO should be required to provide more notice to the market before introducing “closed loop” interfaces to capture operator actions in pricing.
The MIC last week approved an issue charge by DC Energy’s Bruce Bleiweis to consider if such pricing interfaces should be barred from taking effect until they are announced before the monthly Financial Transmission Rights or Balance of Planning Period FTR auction.
In the last year, PJM has created closed-loop interfaces in at least four locations so that operator actions — such as sub-zonal dispatch of demand response — are captured in LMPs rather than uplift. PJM said it must use the interfaces to set prices because its modeling software can only set prices for thermal constraints, not voltage problems.
Connecticut policymakers say inadequate natural gas infrastructure will lead to sharply higher electricity prices despite energy-efficiency measures that will nearly eliminate demand growth over the next decade.
The state’s 2014 Integrated Resource Plan, released last week by the Department of Energy and Environmental Protection, sees the state mirroring regional trends: an increased reliance on natural gas generation hampered by a constrained pipeline system, and shortfalls of capacity and renewable energy sources.
Increased prices for natural gas, capacity and renewable resources are likely to increase the generation rates for retail customers by 63%, from approximately 9.8 cents/kWh in 2014 to 16.0 cents/kWh in 2024.
“Connecticut ratepayers are being affected by critical developments in New England’s wholesale electricity markets that are challenging the affordability and reliability of the region’s electric system,” the plan says.
Demand growth is expected to be flat over the next decade due to the increased use of energy efficiency. Electricity consumption is only expected to grow by 0.05% annually, with peak demand growth at 0.5% annually. The state’s last IRP, in 2012, had projected an increase in consumption of approximately 1% per year.
Those efficiency gains will be offset, however, by several other factors, DEEP says:
New England’s capacity surplus will disappear by 2017, when a shortage of 143 MW is projected, primarily due to the announced retirement of 4,100 MW of non-gas generation. Capacity costs are likely to increase to about 4.9 cents/kWh by 2024, when the region will need an additional 1,700 MW in resources.
The state expressed skepticism about ISO-NE’s ability to fill the shortfall. “There has not been a shortage of capacity before to test the auction’s ability to attract new investment. ISO-NE has recently instituted major changes in the capacity market rules, which add to the department’s concern that the upcoming February 2015 auction may not attract the new capacity that is needed, driving up capacity prices and threatening system reliability. If the market fails, DEEP may pursue options within state authority to procure capacity resources, if needed.”
The region now depends on natural gas for more than half of its power generation, a situation that will be exacerbated by planned coal plant retirements and a shortage of pipeline capacity to deliver gas to both power plants and winter heating. “This problem is too big for any one state to solve alone, and all New England states should contribute to a solution,” the IRP says. Regional pipelines are seen as a potential solution, but local opposition that was especially loud in Massachusetts has put some initiatives on hold.
The wholesale spot market price of natural gas delivered to New England has spiked from about $1-3/MMBtu before 2012-13 to $8/MMBtu in 2012-13 and almost $14/MMBtu in 2013/14, adding $3 billion to wholesale electricity prices.
Gas pipeline capacity expansions expected to enter service in November 2016 as part of Connecticut’s Natural Gas Expansion Plan may provide only temporary relief, the plan says.
Competition between Connecticut and other states for a limited supply of new renewable resources will likely add 0.3 cents/kWh to retail rates by 2024. The impact would be larger but for long-term contracts signed with large wind, solar and biomass facilities, which will save ratepayers more than $235 million over the next two decades. These programs, including a solar incentive program and utility-owned renewables, will only provide about 2,400 GWh of renewable energy by 2020, or about 40% of Connecticut’s renewable portfolio standards goal of 20% by 2020. The plan calls for increased support for distributed generation to address the renewable shortfall.
The plan proposes using existing state authority to solicit large-scale hydropower to offset some natural gas generation, or seeking new authority from the legislature to run a competitive procurement process for liquefied natural gas (LNG) and gas pipeline capacity.
“Neither ISO-NE, the Federal Energy Regulatory Commission, nor key market actors such as electric generators or gas pipeline developers have proposed any meaningful market reforms that will cause electric market participants to invest in urgently needed, cost-effective gas pipeline infrastructure.”
The IRP notes a marked decrease in emissions since 2007, with NOx, SO2 and CO2 down 71%, 95% and 28%, respectively. But it said emissions will increase slightly as gas infrastructure constraints cause an increase in generation from the state’s remaining coal-fired capacity.
The plan also proposes “reviving and improving” state demand response programs if the D.C. Circuit Court of Appeals decision voiding federal jurisdiction over DR is not overturned by the Supreme Court.
The Federal Energy Regulatory Commission last week approved Duke Energy Progress’ $1.2 billion purchase of 700 MW of generation from the North Carolina Eastern Municipal Power Agency.
The deal will give Duke NCEMPA’s share of the Brunswick and Shearon Harris nuclear plants and the Mayo and Roxboro coal plants, generators that Duke jointly owned with NCEMPA.
Duke and NCEMPA agreed to the sale in late July and submitted it for FERC approval on Oct. 10. (See NCEMPA to Sell 700 MW of Generation to Duke.) There were no protests opposing the deal or comments asking for any conditions. In its order, the commission said it had no concerns about adverse effects on horizontal or vertical competition resulting from the deal.
The deal must still be approved by the Nuclear Regulatory Commission and regulators in North and South Carolina. Company officials are targeting to close in the third quarter of 2015.
According to Duke, NCEMPA members have accrued more than $2 billion in debt and its customers’ rates have increased since the 1980s. While FERC did not say whether it expected rates to go down, it found that rates would not be adversely affected by the deal. Duke will collect $343 million through rates, FERC said, but the company included a five-year hold-harmless commitment that it would not increase rates as part of the deal. NCEMPA members, and their customers, would still be on the hook for paying off the remaining debt, but the sale will significantly lessen it.
After breezing through regulatory approvals by Virginia and the Federal Energy Regulatory Commission, Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. (PHI) is starting to run into some headwinds.
Citing doubts about Exelon’s claimed economic benefits, the staff of the Maryland Public Service Commission said the company should provide $167 million in credits to customers, an increase of two-thirds over the $100 million the company offered.
And last week, the Maryland Office of People’s Counsel urged the commission to reject the deal.
“There is no doubt that this acquisition is a boon to PHI shareholders, but it offers nothing to Maryland’s utility customers,” People’s Counsel Paula M. Carmody said. “While Exelon has provided a ‘checklist’ of purported benefits, including better reliability, to customers and the state, OPC has determined that they are either non-existent or woefully deficient.”
The Chicago-based energy giant still needs approval from Maryland, D.C., Delaware and New Jersey, in addition to the U.S. Department of Justice.
Like several groups that have filed comments with the PSC opposing the acquisition, Carmody is concerned about the size of the company that would result.
“Exelon already owns [Baltimore Gas and Electric], but this acquisition would allow Exelon … to control electric utilities serving 80% of Maryland’s electric customers,” she wrote. “Such an acquisition would allow Exelon to exercise undue influence and control over regulated electric service and retail electric company policies in most of the state of Maryland and much of the footprint in the PJM wholesale market area.”
Market power issues are at the forefront of other interveners’ concerns, including PJM’s Independent Market Monitor, Joe Bowring. Repeating concerns he expressed during the FERC approval process, Bowring said mitigation measures should be taken to keep the combined companies from exerting undue influence.
“The proposed merger raises potential vertical and horizontal market power issues,” Bowring wrote in a letter to the PSC last week.
Bowring recommended requiring the companies to agree to remain in PJM and to permit independent third-party interconnection studies. RTO Insider reported last week that the Department of Justice is investigating the interconnection process in PJM’s MAAC sub-region as part of its review of the merger. (See DOJ Probing Interconnection Process in Exelon-Pepco Merger.)
The Monitor also 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.
FERC approved the acquisition without requiring any of Bowring’s proposed mitigation measures. (See FERC Approves Exelon-Pepco Merger.)
Bruce Burcat, executive director of the Mid Atlantic Renewable Energy Coalition (MAREC), said that even mitigation measures wouldn’t keep Exelon from growing too powerful for the market.
“The size and scope of this merger in and of itself raises a lot of angst for MAREC as we are very troubled by the ability of this huge utility to dominate markets,” Burcat wrote the Maryland commission last week. “I am not sure that there is a sure way to completely mitigate or even anticipate the impacts … that the combination of these companies will present to regulators, competitors and most importantly ratepayers.”
Like many other groups, MAREC has also filed opposition briefs with regulatory agencies in D.C., Delaware and New Jersey.
While the Maryland PSC staff report didn’t urge rejection of the merger, it said that Exelon’s claims of economic benefits to the state was “deeply flawed” and said that the deal could result in job-loss impacts totaling up to $309 million.
In addition to the $100 million in customer credits, Exelon has promised to continue the charitable giving that Pepco did, to the tune of $50 million over the next 10 years.
Exelon spokesman Paul Adams acknowledged that not all parties are satisfied with what the company is offering but said the acquisition is a good deal for the entire territory.
“As part of this [PSC review] process, we are open to feedback and discussions with all stakeholders,” he said in a prepared statement. “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.”
Exelon has gathered some allies in Maryland. In October, the president of the Montgomery County Council, Craig L. Rice, wrote the PSC to say he believes that “the combination of these two companies is clearly in the public interest and will benefit Pepco customers, Montgomery County and the State of Maryland.”
Brien Poffenberger, CEO of the Maryland Chamber of Commerce, expressed his support in a letter published last week by The Baltimore Sun. “With so much at stake, it’s right that the Maryland Public Service Commission and other stakeholders take a hard look at what this merger will mean for consumers. But it’s also clear that Exelon has been a reliable partner, and it has the track record to prove it,” he wrote.
Hearings before the PSC are scheduled to begin Jan. 26. Hearings in New Jersey are set for Jan. 12. Both D.C. and Delaware have scheduled hearings for February.
