FERC upheld an administrative law judge decision that FirstEnergy is responsible for reporting data related to Old Dominion Electric Cooperative load in Virginia (ER12-2399).
The dispute stems from ODEC’s purchase of the distribution facilities and service territory of Potomac Edison, a FirstEnergy subsidiary, in Virginia. FirstEnergy argued that it was no longer responsible for calculating and reporting data for Potomac Edison, such as total hourly energy obligation, peak load contribution and network service peak load, to PJM.
FERC, however, affirmed the judge’s finding that because ODEC did not purchase the transmission facilities of Potomac Edison, FirstEnergy was still responsible for reporting the data in the entire Allegheny Power System zone, which encompasses parts of Pennsylvania, Maryland, West Virginia and Virginia. “As the initial decision found, requiring ODEC to perform the metrics would result in unduly discriminatory treatment of ODEC when compared to other wholesale LSEs in the APS zone,” the commission said.
Massachusetts Attorney General Maura Healey on Wednesday released a study that said additional interstate natural gas pipelines are not needed to guarantee the reliability of New England’s electric grid over the next 15 years.
Instead, reliance on demand response and energy efficiency would protect consumers and also help the region reach its greenhouse gas emissions goals, according to the study.
The Analysis Group study concluded that only the energy efficiency/demand response and EE/firm import option using existing transmission would both reduce ratepayer costs and greenhouse gas emissions relative to the current reliance on dual-fuel capability. Both adding natural gas pipelines and reliance on firm LNG supplies could reduce total costs but not GHG emissions. EE and the firm import of distant low-carbon energy over new transmission lines would cut emissions but increase ratepayer costs, the study said. (Click to zoom.)
“This study demonstrates that we do not need increased gas capacity to meet electric reliability needs, and that electric ratepayers shouldn’t foot the bill for additional pipelines. This study demonstrates that a much more cost-effective solution is to embrace energy efficiency and demand response programs that protect ratepayers and significantly reduce greenhouse gas emissions,” Healey said in a statement.
The study by the Analysis Group runs counter to the view of many regional officials that massive pipeline construction is needed as New England becomes more reliant on natural gas for power generation. In October, the Massachusetts Department of Public Utilities ruled that electric distribution companies can sign contracts for natural gas capacity and pass the costs on to electric ratepayers if the companies can prove that they will save ratepayers money. (See Massachusetts Regulators Endorse Pipeline Contracts.)
The authors said the study used “extremely conservative assumptions,” including applying winter conditions from 2004, one of the coldest years in two decades.
“Under the base case analysis, power system reliability can and will be maintained over time, with or without additional new interstate natural gas pipeline capacity,” the report said.
The study concedes additional natural gas infrastructure would lower electricity prices, but with a steep cost. “Investment in new interstate pipeline capacity generates significant wholesale electricity price benefits but would require up-front and long-term ratepayer commitments,” it said.
Analysts also considered the impact of new transmission needed to import Canadian hydropower, the most expensive option for ratepayers, it indicated.
The study accounted for the recent announcement that the Pilgrim nuclear power plant would close no later than June 2019, resulting in the loss of 680 MW of non-GHG emitting power.
Northern States Power’s Wisconsin ratepayers will be billed for 15% of the nearly $79 million spent on the now-abandoned Prairie Island nuclear project under an agreement approved by FERC last week. The 15% share, totaling $12 million, reflects the most recent coincident peak demand ratios approved for the Wisconsin utility’s interchange agreement with Northern States Power Minnesota, FERC said (ER15-698).
Northern States had planned to expand the capacity of two existing units at the Prairie Island site. Northern States said the shrinking cost of alternative energy and delays in obtaining Nuclear Regulatory Commission approvals “reduced [the project’s expected benefits] to an extent that the project was no longer economical.”
The Minnesota Public Service Commission, which granted a certificate of need for the project in 2009, approved its cancellation in February 2013. In late August, the commission found that Northern States acted in good faith in the development and cancellation of the project.
No Rehearing in MISO Wind Interconnection Study Matter
FERC denied MISO’s request for rehearing of an order that found that the RTO violated its obligations to an interconnection customer regarding network upgrade studies. The commission said that MISO had not alleged any specific errors in a 2013 order that found the RTO had improperly concluded that the Jeffers South wind generation facility was obligated to fund construction of a $43 million 161-kV line from Dotson to New Ulm, Minn. (EL10-86-004).
Jeffers South said MISO neglected its duty to identify the least expensive network upgrade option. In its rehearing request, MISO argued that the study process was valid because Summit Wind, Jeffers South’s predecessor, had agreed to it.
In last week’s order, FERC told MISO to permit Jeffers South to name a new point of interconnection at Heron Lake. “We expect all of the parties to endeavor to perform their obligations pursuant to the Tariff and in a cooperative manner going forward,” FERC said.
No Time Value Refunds in Michigan Contract Dispute
FERC reversed an administrative law judge ruling requiring the payment of time value refunds in a dispute between the 1,633-MW Midland Cogeneration plant and Consumers Energy (ER10-2156). The dispute concerned the plant’s interconnection agreement with Consumers and a second agreement in which Consumers bought most of the output of the plant. Consumers later sold its transmission to Michigan Electric Transmission. “If Consumers Energy and Michigan Electric were required to refund the time value of payments received, or to be received, from Midland for services performed prior to acceptance of the facilities agreement, they would necessarily have operated at a loss, contrary to long established commission policy,” the commission said.
FERC Rejects Louisiana Rehearing Bids on Entergy Depreciation
FERC rejected two rehearing requests by the Louisiana Public Service Commission in cases involving Entergy’s depreciation rates:
FERC denied the Louisiana PSC’s request to reconsider a previous order that affirmed an administrative law judge’s initial determinations approving depreciation rates for Entergy Arkansas (ER10-2001). The Louisiana regulators had challenged the judge’s decisions regarding the admissibility of witness testimony.
FERC also denied rehearing of the Louisiana PSC’s complaint that the state could not use state-determined depreciation inputs in the bandwidth formula used to equalize production costs among Entergy’s operating companies (EL10-55). The order affirmed FERC’s finding that the PSC had not shown the commission’s use of the depreciation rates was unjust or unreasonable.
Nuclear power plant owners are welcoming reports that Gov. Andrew Cuomo wants state regulators to mandate that half of the state’s energy come from renewable energy sources by 2030 while creating incentives for nuclear to remain viable in the interim.
Governor Andrew Cuomo
Getting 50% of its energy from wind, solar and other renewable resources by 2030 is currently a state goal, but it lacks the force of an order from the New York Public Service Commission. The governor is also seeking a way to keep the R.E. Ginna and James A. Fitzpatrick nuclear plants on Lake Ontario in the state’s fleet to help New York meet the federal Clean Power Plan. The hope for those in the nuclear industry is that these combined efforts will mean their plants will serve as the primary source for low-carbon power in the near term.
The New York Times first reported the proposed mandate on Sunday. A source told RTO Insider the details could be released in the governor’s annual State of the State address in January, with final action by the PSC hoped for about six months later.
“If true, this new policy would be a welcome and constructive step that promotes the transition to clean energy,” said David Tillman, a spokesman for Ginna’s owner, Exelon. “We believe that with the governor’s leadership, a state clean energy standard can be implemented that would recognize the zero-carbon, economic and reliability attributes of nuclear energy while maintaining New York’s focus on renewable energy and efficiency.”
Advocates from different sectors of the power industry were generally pleased by the news.
“The clean energy standard as proposed by the governor is an important and forward-looking approach that will help attract investment in renewables and address market problems that need fixing,” Gavin Donohue, president of the Independent Power Producers of New York said in a statement. “The alternative is the potential loss of nuclear power in New York due to currently low natural gas prices — a scenario that would be catastrophic for both ratepayers and the environment.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, supported the plan but is less sanguine about the nuclear component. “Gov. Cuomo’s reported directive to the Public Service Commission to mandate the 50% renewables by 2030 goal is great, encouraging news for the renewable energy industry,” she said. “Nuclear power, while emitting less carbon than coal or oil, nevertheless does not meet the definition of renewable technologies. Supporting uneconomic and aging power plants should not be the long-term solution, but should be a transition to a renewable energy future.”
Iberdrola USA, whose Rochester Gas & Electric unit negotiated the RSSA with Exelon, would not comment on the purported extension of Ginna’s operation. “We’re working to complete the Ginna Reliability Transmission Alternative to meet our requirement, anticipating it will be completed in mid-2017 when the plant is supposed to be retired,” spokesman John Carroll said.
GRTA is intended to provide access to other generation sources to supply the Rochester area and render Ginna unnecessary.
In contrast to the lifeline Cuomo is offering to the upstate nuclear units, the governor has repeatedly called for the closure of Entergy’s Indian Point plant, citing concerns over the safety of New York City, 30 miles south.
The PSC was supposed to take action on several clean energy orders at its meeting on Thursday, including one on a retail renewable portfolio standard, but the items were pulled from its agenda at the last minute.
“Because these programs are so important, we wanted to make sure we are examining all the issues. It is absolutely our intent to pursue these programs. Nobody should read anything into this, other than they are complex matters for our state energy policy and it’s important that we get it right,” commission chair Audrey Zibelman said to open the meeting.
FERC last week reaffirmed its rejection of MISO’s proposal to institute a mandatory capacity market, denying rehearing of its 2012 order on the issue.
In June 2012, FERC conditionally approved revisions to improve deliverability of capacity resources in the MISO footprint, but the commission rejected MISO’s request that the Planning Resource Auction become obligatory and subject to a minimum offer price rule. More than 15 entities, including MISO’s Independent Market Monitor, requested a rehearing.
Critics say vertical demand curve like that in MISO results in excessive price volatility. Dynegy included this chart in a presentation to investors last year, saying that when resources fall short of requirements, prices spike to the cost of new entry (CONE).
Capacity suppliers complained that MISO’s capacity construct is discriminatory because it requires sellers, but not buyers, to participate. Others took issue with MISO’s use of a vertical demand curve and two-month forward period before the auction.
In its order last week, FERC again rejected MISO’s proposed mandatory auction for resource deficiencies and upheld the use of a vertical demand curve (ER11-4081-001).
Load-serving entities, “as buyers of resources, must obtain sufficient resources to meet their planning resource margin requirement or pay a significant penalty of 2.748 times [the cost of new entry]. We do not consider this requirement and its associated penalty to be a ‘free pass,’ as characterized by capacity suppliers, or that buyers have no incentive to purchase capacity, as NRG [Energy] claims,” FERC ruled.
It also said MISO had not met its burden of proving its proposal was just and reasonable.
The commission also denied rehearing of the decision to reject MISO’s proposed minimum offer price rule, again concluding that customers “lacked the incentive to suppress auction prices in the MISO capacity market.” On the other hand, FERC reiterated its defense of MISO’s fixed resource adequacy plan, saying LSEs do not “have an incentive to exercise market power in the MISO region” and market manipulation is “unlikely.”
Daily Peak Load
The rehearing request by the Coalition of MISO Transmission Customers, a group of industrial customers, challenged MISO’s use of daily peak load, a method FERC directed the RTO to use three years ago, replacing the grid operator’s proposed daily pro rata method.
“We find that the use of the daily peak load contribution methodology until sufficient data exists to use the peak load contribution methodology does not represent undue discrimination against LSEs in retail choice states. … Requiring MISO to use available historical information, as Coalition of MISO Customers recommend, does nothing to resolve this data gap because MISO cannot force electric distribution companies to provide the necessary data,” FERC decided.
To comply with the commission’s June 2012 ruling, MISO revised its Tariff language. FERC accepted the edits, conditionally approving MISO’s map of zonal boundaries that pinpoint major transmission constraints and local balancing authorities and instructing the RTO to remove a reference to a minimum offer price rule (ER11-4081-002).
In the same order, FERC responded to Illinois Commerce Commission’s concern that the Tariff could hinder state commissions’ responsibility for enforcing resource adequacy, saying it was beyond the scope of the compliance proceeding.
LaFleur: Room for Improvement
At FERC’s open meeting Thursday, Commissioner Cheryl LaFleur said she supported the order “because I believe, based on this record and in the context of the primarily vertically integrated MISO region, the resource adequacy construct that we have approved is just and reasonable.”
“I’ve often noted that we need to take account of legitimate regional differences and I think we’ve tried to do so in this order. But I do want to comment to say that a determination that a market construct is just and reasonable does not mean that it cannot be improved. I want to recognize that there are a lot of efforts underway in the MISO region to consider reforms to the adequacy construct and I very much encourage parties to stay engaged in those processes, and I’ll be continuing to follow them closely.”
Amid increasing concern over threats to the nation’s power grid, the North American Electric Reliability Corp. last week ran a rigorous, two-day drill that simulated terrorist attacks.
“There were cyberattacks on corporate computers, infiltration of transmission systems and substations, explosives and shootings,” NERC CEO Gerry Cauley said in a press briefing Thursday, the final day of GridEx III. The exact scenarios were kept secret.
Cauley said that about 10,000 people at 315 organizations — electric generators, transmission companies, law enforcement, and local, state and federal government agencies — participated in or monitored the drill.
GridEx II, in 2013, drew 234 organizations and an estimated 3,000 participants. The first sector-wide grid security exercise was held in November 2011.
While details on the drills are kept close to the vest by NERC and the participants, a public report, expected out in January, will detail what the grid operators faced and how they fared.
The GridEx II report noted that the drill included simultaneous physical and cyberattacks. It laid out the “lessons learned” and recommendations, including efforts to enhance information sharing.
It also recommended expanding the capabilities and role of the industry group that coordinates with federal agencies on grid threats, the Electricity Sub-sector Coordinating Council.
Southern Co. CEO Tom Fanning, the head of ES-CC, said planning for the exercise began more than a year and a half ago and was essentially complete before the terrorist attacks in Paris on Nov. 13. So, although Fanning and his colleagues were in constant contact with federal counterparts after the attacks, they did not have an effect on this year’s drill.
That, he said, is an example of how grid operators must use current events to keep up with evolving threats. “The threat is ever changing,” Fanning said. “We know we have to continually anticipate the threat and adapt our own strategy. Being perfect here is an aspiration. We know we are always going to have to get better.”
“We are acutely aware of the recent events [in Paris] and the heightened urgency,” Cauley said. However, he said, “we have intentionally not built that into the exercises.”
This year’s drill was intentionally challenging, if not overwhelming, Cauley said. “It is a national exercise, and includes Canada and observers from Mexico,” he said. “The cyber vectors that we used started early [Wednesday] with attacks on public Internet and customer sites. We want to make sure this is not day-to-day stuff; it is rare,” he said. “We wanted to test the system.”
“There are cyberattacks in coordination with physical attacks, combined with trucks, and shootings to create some kind of enduring damage,” Cauley said. “This is not to be a simple, easy, one-day or two-day recovery.”
Cauley said cyberattacks have a bigger role in GridEx III than they did in previous exercises. Recently, there have been several public conversations about grid’s vulnerability to such attacks. Broadcaster Ted Koppel has been on a tour promoting his controversial book, “Lights Out,” about the grid’s vulnerability. Earlier this fall, a British think tank released a report asserting that U.S. nuclear power plants are at risk from cyberattacks. London-based Chatham House said the “risk of serious cyberattack on civil nuclear infrastructure is growing” because of its reliance on commercial “off-the-shelf” software.
“There are methods and tactics that exist to cause control systems to cause damage to equipment,” Cauley acknowledged. “But as a practical matter, it is very, very difficult to carry out” a successful cyberattack on security-hardened grid facilities.
NERC, grid operators and all other sectors of the industry continue to assess threats and react to them, Fanning said. “I think we are the only industry with mandatory critical infrastructure protection” against cyberattacks, he said. “What we are trying to do here is go beyond the requirement.”
FERC last week released its annual Enforcement Report, noting that it had opened 19 new investigations and closed 22 others with settlements or no action in fiscal year 2015. Settlements resulted in more than $26 million in civil penalties and disgorgement of $1 million in unjust profits. The biggest settlements were over the 2011 Southwest power outage that left more than 5 million people without power for up to 12 hours.
Enforcement staff is currently seeking recovery of more than a $500 million in civil penalties and disgorgement through federal court and administrative litigation.
The commission spent about $316 million during the fiscal year, an increase of almost $9 million over FY 2014. Three-quarters of spending was on salaries and benefits for 1,456 full-time equivalents, according to its annual financial report to Congress, which also was issued last week.
FERC approved two reliability rules proposed by the North American Electric Reliability Corp.:
One order approves reliability standards EOP-011-1 (Emergency Operations) and PRC-010-1 (Undervoltage Load Shedding) (RM15-7, RM15-12, RM15-13). It also includes a revised definition of the term “remedial action scheme” and eliminates use of the term special protection system. NERC said the two had previously been used interchangeably, resulting in ambiguity.
The second approves Transmission Operations (TOP) and Interconnection Reliability Operations and Coordination (IRO) reliability standards (RM15-16). The commission said the revised standards are more precise and clarify the delineation of responsibilities between applicable entities while eliminating gaps and ambiguities. Eight current TOP standards were compressed into three. FERC ordered NERC to revise the standards within 18 months to include transmission operator monitoring of non-Bulk Electric System facilities; specify that data exchange capabilities include redundancy and diverse routing; and require testing of alternate or less frequently used data exchange capabilities.
Rehearing Denied on e-Tag Access
FERC denied rehearing in its 2012 order (Order 771) granting the commission, RTOs, ISOs and their market monitoring units’ access to electronic tags (e-Tags) used to schedule transmission (RM11-12-001). The National Rural Electric Cooperative Association, the Edison Electric Institute and Southern Co. filed rehearing requests, while Open Access Technology International filed a request for clarification. Before the 2012 order, RTOs could only access e-Tags for interchange transactions that flowed into, out of or across their footprints.
WILMINGTON, Del. — A Tariff change endorsed by stakeholders last week will allow PJM to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auction for the 2016/17 delivery year.
PJM procured more than 4,200 MW of new capacity in that auction in August.
The resources would be sold in the third incremental auction for the delivery year, which is set for February. (See “Tariff Change Would Allow PJM to Sell Excess Capacity for 2016/17” in PJM Markets and Reliability & Members Committee Briefs.)
PJM Assistant General Counsel Jen Tribulski said PJM would seek a waiver from releasing capacity if FERC ordered the removal of demand response from the capacity market before the third incremental auction as a result of a Supreme Court ruling upholding the Electric Power Supply Association’s challenge to FERC’s jurisdiction over DR.
Although the lower court ruling specifically addressed DR in the energy market, some legal experts believe a ruling against FERC would also apply to capacity.
If it ruled in such a manner after the auction but before the start of the 2016/17 delivery year in June, or after the delivery year started but with a retroactive clause, PJM would need to repurchase at least 4,000 MW. This could result in a net cost increase.
If FERC removed DR from the capacity market after the delivery year and did not make the order retroactive, no further action would be necessary. The same holds true if FERC removed DR only from the energy market.
Market Monitor Joe Bowring questioned why PJM would release the capacity at all, given the contingencies and the potential of incurring additional cost.
“It’s not prudent to hold on to those megawatts when we can give value back to the load with megawatts we don’t need,” Tribulski said.
Higher IRM for Next Three Delivery Years Endorsed
With one “no” vote and 27 abstentions, the Members Committee approved an increase in PJM’s Installed Reserve Margin.
The IRM is used in the Reliability Pricing Model capacity auctions. The Reserve Requirement Study increased the IRM for the 2016/17 delivery year to 16.4% from 15.5%. IRMs also rose for the following two delivery years.
In previous discussions at lower committees, stakeholders had expressed confusion over why the IRM was increasing at the same time the Capacity Performance model is being implemented. (See “IRM, FPR Rising; PJM Methodology Challenged” in PJM Planning Committee Briefs.)
On Thursday, PJM’s Tom Falin said that Capacity Performance on its own does not result in a lower IRM because the Reserve Requirement Study always has been conducted under the assumption that generators will perform at the CP level.
“CP is changing the market rules to match the assumption we’ve always made in the study,” he said.
Finance Committee, Sector Whips, Members Committee Vice Chair Elected
Members elected the following:
Finance Committee (three-year terms)
End Use Customers: David Evrard, Pennsylvania Office of the Consumer Advocate
Generation Owners: Michelle Greening, Talen Energy
Other Suppliers: Marguerite Miller, Credit Suisse
Transmission Owners: Jim Benchek, FirstEnergy
Sector Whips (one-year term)
Electric Distributors: Steve Lieberman, Old Dominion Electric Cooperative
End Use Customers: Susan Bruce, PJM Industrial Customer Coalition
Generation Owners: Joe Kerecman, Calpine
Other Suppliers: Katie Guerry, EnerNOC
Transmission Owners: Jodi Moskowitz, Public Service Enterprise Group
FERC last week rejected a request by consumer advocates that it force PJM to update its 2015 peak load forecast using recent modeling enhancements to prevent over-procurement of resources in this year’s capacity auctions.
“While there will inevitably be some difference between PJM’s load forecast and the amount of capacity that PJM ultimately needs in a given delivery year, the record indicates that PJM has taken steps to ensure the reasonableness of the 2015 load forecast, including making a statistical adjustment based on a percentage of error it had seen in the load forecast over recent years, to account for the effects of energy efficiency programs,” the commission said (EL15-83). “The mere fact that PJM is working on a revised forecast methodology does not render the prior one unjust and unreasonable.”
(Click to zoom.)
The complaint was filed in June by a group that included industrial customers, environmental organizations, state regulators and consumer advocates. It said that using updated methodology released by PJM in December would reduce the peak load forecast for 2016/17, 2017/18 and 2018/19 by at least 7,000 MW, potentially saving consumers more than $600 million. (See Model Change Results in Lower Load Forecast for PJM.)
PJM responded that the revised forecasting model would not be complete and ready for use until November, after the Base Residual Auction and transition auctions had been held. It was approved by PJM’s Markets and Reliability Committee last week. (See related story, MRC Briefs.)
Last week’s order denied the consumers’ request that the auctions be delayed — a moot point since they have already occurred.
The commission also rejected the complainants’ request that PJM be compelled to reinstate a 2.5% “holdback” that was eliminated in FERC’s approval of the new Capacity Performance product.
“The commission specifically found in the Capacity Performance order that the holdback was not necessary to address load forecast errors,” FERC said. “The issue of whether it is appropriate to remove the 2.5% holdback is currently pending on rehearing of the Capacity Performance order and will be addressed in that proceeding.”
The commission required RTOs to revise their day-ahead market schedules in coordination with the new pipeline schedules or show why changes were unnecessary.
The commission approved PJM’s schedule change effective March 31 (ER15-2260 and EL14-24).
FERC also accepted compliance filings by NYISO (EL14-26) and ISO-NE (EL14-23), saying they had justified retaining their existing schedules, with day-ahead deadlines of 5 a.m. and 10 a.m., respectively.
The dispute stems from ODEC’s purchase of the distribution facilities and service territory of Potomac Edison, a FirstEnergy subsidiary, in Virginia. FirstEnergy argued that it was no longer responsible for calculating and reporting data for Potomac Edison, such as total hourly energy obligation, peak load contribution and network service peak load, to PJM.
