BALTIMORE, Md. — While panelists discussing baseload price supports at the annual meeting of the National Association of Regulatory Utility Commissioners last week didn’t find much common ground, they did agree that energy markets should put a price on the attributes the grid needs.
The discussion revolved around the U.S. Department of Energy’s Notice of Proposed Rulemaking, which urged FERC to adopt price supports for generators that can maintain a 90-day fuel supply. The proposal has been criticized for ostensibly focusing on coal and nuclear units, but discussion has not focused on what qualities the grid requires to be reliable and resilient.
“The proposal on the table is a solution in search of a problem,” said Marty Durbin, the executive vice president and chief strategy officer for the American Petroleum Institute, which supports oil and natural gas interests. “We’ve earned the market share that we have.
“The polar vortex keeps coming out, and I want to grab my red challenge flag and throw it on the floor,” Durbin said, referring to arguments that gas-fired units don’t have enough fuel security to maintain the reliability of the grid. The severe cold snap in the winter of 2014 created a reliability scare after as much as 22% of PJM’s generators were unable to run when dispatched and gas prices spiked.
The NOPR referenced that situation as an example of why larger units with onsite fuel are necessary, even if they are uneconomic.
“Wyoming’s interest in the NOPR is really about our customers and our coal, not about coal generation,” Wyoming Public Service Commissioner Kara Brighton said.
Define and Value
“We have never viewed the FERC NOPR as a subsidy for coal,” said Paul Bailey, the CEO of the American Coalition for Clean Coal Electricity. “We view this as a way to value a resilience attribute.”
“We need to decide what’s important and put a value on them,” Durbin said. “That’s really all this is about.”
“This has to be solved holistically,” Herling said. “Infrastructure alone isn’t going to solve the problem. Fuel security alone isn’t going to solve the problem. … Resilience is a rest-of-career conversation.”
“Before we conclude that the markets aren’t supporting these resources, we should ask the question: ‘Do we have the right market rules?’” said Kathleen Barrón, senior vice president for competitive market policy at Exelon, the nation’s largest nuclear operator. “What are the risks that we’re facing, both from manmade and natural sources, to those sources of fuel supply? We probably should get some input from [federal departments] that are experts in security … and have those organizations provide input to the RTOs.”
The Public Utility of Commission of Texas on Friday welcomed Arthur C. D’Andrea, who replaced longtime Commissioner Ken Anderson as its third member.
D’Andrea was appointed by Texas Gov. Greg Abbott on Nov. 14 to a term expiring Sept. 1, 2023. He joins Chair DeAnn Walker, who, like D’Andrea, worked in Abbot’s office before joining the commission.
Brandy Marquez, DeAnn Walker (l-r) welcome Arthur D’Andrea to the Texas PUC
“It seems natural for him to be on the same floor now,” Walker said after calling Friday’s meeting to order.
Brandy Marty Marquez, now the PUC’s longest-tenured commissioner with four years of experience, is the only member to have been appointed by former Gov. Rick Perry. She said it felt “weird” as she sat in Anderson’s chair.
“It feels like I’m in a totally different room. Who are all you people?” said Marquez, greeting D’Andrea as the “Brazilian bad boy.”
Anderson, whose latest term expired in August, joined the commission in 2008, making him its longest serving member ever.
Brandy Marquez praises former Commissioner Ken Anderson.
Marquez shared several thoughts on Anderson with the commission and its audience, teasingly saying he is a “very snazzy dresser” and “likes to rock a winter beard.” She also called Anderson “the consummate gentleman, who’s not afraid to kick a little hindquarters now and then,” and the “ultimate protector of our energy-only market.”
Marquez said she had recently read an article that referred to parents as the “original gangsters, because they tell you like it is to your face, and behind your back, they compliment you wildly.”
“That’s pretty gangster,” she said. “Commissioner Anderson never missed an opportunity to compliment his staff, to compliment the staff of the commission, and to compliment the bar that argued before it. He always said that the quality of the folks that came before this commission was his favorite part of the job.”
D’Andrea
D’Andrea wasted little time in making himself at home, spending nearly 30 minutes questioning parties to a Southwestern Electric Power Co. (SWEPCO) rate case (Docket 46449). The PUC decided to take up the case again at its Dec. 14 meeting over requests by intervenors to be granted additional time to conduct discovery after SWEPCO added late expert testimony.
D’Andrea was an assistant general counsel in the governor’s office (2015-2017) and an assistant solicitor general for the state’s attorney general (2009-15). He received a bachelor’s degree in chemical engineering in 1998 and a law degree from the University of Texas.
PUC to Ask MISO to Create Texas Local Resource Zone
Picking up on an issue Anderson followed for several years, the PUC has requestedMISO seek FERC approval to create a separate local resource zone (LRZ) that would “better align the costs and benefits” of market efficiency projects (MEPs) for the portions of Texas within the RTO’s footprint.
The commission asked for an effective date no later than Dec. 6, saying it would lead to a “more granular estimation” of transmission projects’ costs and benefits. Staff told the PUC that Texas currently pays 18% of the costs while receiving 70% of the benefits, and that a Texas LRZ would still have the state “bearing less of the costs than the benefits.”
The action came after Walker attended an Entergy Regional State Committee (ERSC) meeting in place of Anderson, who was the PUC’s liaison to MISO.
At their Dec. 7 meeting, MISO’s Board of Directors will consider the $129.7 million, 25.5-mile West of the Atchafalaya Basin 500-kV economic project in southeast Texas, which is being submitted as a market efficiency project. Texas will receive 72.1% of the production cost benefits from the project and be responsible for 17.9% of the costs, while Louisiana will receive 27.7% of the benefits but be responsible for 70% of the costs.
Walker said ERSC members discussed four proposals to address the issue, one of those being a separate LRZ within MISO that would contain only its Texas territory for cost-allocation purposes.
“Commissioner Anderson … spent lot of time on this. This was his preference,” Walker said. “After delving into it, I think it’s the best answer.”
When Entergy joined MISO in 2013, a MISO South sub-region was created that included two LRZs. A third was created in 2015 to incorporate the portions of Mississippi in the MISO footprint.
Rulemaking Would Require Periodic Rate Reviews for IOUs
The PUC adopted a proposed rulemaking requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings, as required by the recent Texas Legislature’s Senate Bill 735 (Project 47545).
The rulemaking would require each electric utility in ERCOT’s footprint to file for a comprehensive rate review within 48 months of its most recent rate order.
The ruling applies to AEP Texas, CenterPoint Energy, Cross Texas Transmission, Electric Transmission Texas, Lone Star Transmission, Oncor, Sharyland Utilities and Sharyland Distribution Services, Texas-New Mexico Power, and Wind Energy Transmission Texas.
In a memo to Marquez and D’Andrea, Walker said she found it “unacceptable” that some non-investor-owned transmission service providers have not had a rate review in more than 20 years. The commissioners agreed with Walker’s proposal that schedules for the non-investor-owned transmission providers be considered in a separate docket (Project 46393).
The commission is accepting comments on its proposed rulemaking. It is facing a June 1 deadline under state law to complete the rulemaking.
Commission to Intervene in EDF FERC Complaint
Following an executive session, the commissioners voted to intervene EDF Renewable Energy’s Section 206 complaint against MISO, PJM and SPP (EL18-26).
In its Oct. 30 complaint, EDF asked FERC to order the grid operators to amend their Tariffs and joint operating agreements to provide more information regarding the treatment of “affected systems” — areas that neighbor RTOs hosting new generation.
The complaint has drawn 10 intervenors from a wide range of the industry.
Order 2003 and the RTOs’ tariffs and JOAs require the host and neighboring RTOs to “coordinate.” But EDF said interconnection customers in MISO, PJM and SPP “have no idea what ‘coordination’ means because of the lack of detail in the Tariffs and JOAs.”
The company said the RTOs should file revisions providing details on the timing of affected systems studies; the base models used in the analyses; cost allocation of generation projects on either side of transmission seams; and whether the studies will use the energy or network resource interconnection service standard.
WASHINGTON — Protesters interrupting FERC’s monthly open meetings over the commission’s approval of natural gas pipelines has become a regular occurrence, but it’s not every day they include an Academy Award-nominated actor.
Actor James Cromwell protesting at FERC | ProtectOrangeCounty.net
James Cromwell — known for his roles in films such as “Babe,” “Star Trek: First Contact” and “L.A. Confidential,” among many others — was one of three protesters who interrupted the commission’s open meeting Thursday. The 77-year-old actor stood after two other protesters had interrupted FERC Chairman Neil Chatterjee as he began to give his closing remarks. He lambasted the commissioners for destroying the environment as he was led out of the meeting room, and could be heard chanting “FERC doesn’t work” as he was led out of the building.
Cromwell, of Warwick, N.Y., later told reporters he had traveled to D.C. with fellow Orange County resident Pramilla Malick to protest the commission’s approval of the Valley Lateral Project, a 7.8-mile extension of the Millennium Pipeline through the county. The lateral would serve the 680-MW Valley Energy Center being built in Wawayanda by Competitive Power Ventures.
FERC’s approval was especially controversial because it ruled that the New York Department of Environmental Conservation had waived its authority to issue or deny a water quality certification by failing to act under the one-year time frame required by the Clean Water Act. (See Environmentalists Denounce Millennium Pipeline Ruling.) Construction of the lateral project has been stayed by the 2nd U.S. Circuit Court of Appeals pending a Dec. 5 hearing by a three-judge panel to review New York Attorney General Eric Schneiderman’s petition to overturn FERC’s decision.
Malick, who was also removed from the meeting for interrupting, was among the petitioners whose request for rehearing of the decision was denied by FERC on Thursday (CP16-17).
She was joined by several other Orange County landowners who argued that the extension is unneeded, in part because the power plant is unlikely to be finished. Malick cited the federal corruption and bribery accusations against a CPV executive and state officials in connection with the state’s approval of the plant. (See CPV Lobbyist, Former Cuomo Aides Named in Bribery Indictment.)
FERC, however, was unpersuaded. “None of the materials relating to the investigation submitted by Ms. Malick indicate that state approval of the Valley Energy Center is subject to the outcome of any investigation,” the commission said. It noted that the facility was 85% complete and on schedule to begin operations by February 2018.
| Millenium Pipeline
“The whole process has been corrupted,” Cromwell told reporters outside FERC headquarters after the meeting. “It should be grounds for stopping the project and having an investigation into how” it was approved.
Malick had argued that FERC violated the National Environmental Policy Act in its environmental assessment by improperly segmenting the pipeline project from Millennium Pipeline Co.’s compressor station in Minisink.
In its Thursday decision, FERC said, “There is no evidence that the Minisink Compressor Station included any facilities to accommodate the future Valley Lateral Project.” It pointed out that the station went into service in June 2013, and Millennium first applied for the lateral in November 2015, demonstrating that they weren’t connected actions under NEPA.
Cromwell’s ejection from FERC is only the latest in a long list of acts of civil disobedience. He madeheadlines this summer for serving prison time after he refused to pay a fine for a 2015 sit-in at the CPV plant construction site. Days after he got out, he was arrested at SeaWorld San Diego for interrupting a show.
“I’ve been thrown out of a number of meetings,” Cromwell said. “It doesn’t matter where it is; it’s the same process. They don’t listen.”
A MISO Board of Directors committee has advanced a $2.7 billion transmission development package that includes 353 new projects — including one divisive line proposed for Texas.
The System Planning Committee of the Board of Directors last week allowed MISO to move ahead in recommending its 2017 Transmission Expansion Plan for full board approval in early December, with RTO staff acknowledging that the plan’s only market efficiency project and competitive bidding candidate has drawn stakeholder ire.
MISO Vice President of System Planning Jennifer Curran said the $129.7 million, 500-kV line and substation in southeastern Texas underwent additional vetting to address concerns about the project’s costs. The RTO hired an additional consultant who verified its estimate, she said.
“As a result, we’re comfortable with the cost estimate for the competitive transmission process,” Curran told the committee during a Nov. 16 conference call.
| MISO
MISO’s Transmission Owners sector last month submitted an unsuccessful motion asking for a six-month delay of the project — one of the priciest in MTEP 17 — until the RTO addresses late modeling changes and a shifting cost estimate on the project. (See MISO Sectors Mull Texas Project Delay for MTEP 17.)
Xcel Energy had questioned the process behind the cost estimate, while Entergy submitted comments expressing concern about MISO overstating the benefits of the project and questioning modeling assumptions used to determine generator commitments in future system planning models.
“We disagree with the comments and continue to recommend that the project go forward,” Curran said. She added that the RTO would have risked reliability issues if it granted a delay of the project. The project is meant to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area straddling Texas and Louisiana.
Director Todd Raba asked what recourse Xcel and Entergy have available after MISO rebuffed their concerns. Curran said the companies could approach the board with their concerns and can pursue the RTO’s dispute resolution process.
MISO South Getting More Attention
Curran said more than half the projects in MTEP 17 are baseline reliability projects, most of which are concentrated in MISO South.
“Some of it is just the general lumpiness of upgrades … based on when projects need to be undertaken. Some of it is the continued load growth in the South that is not happening in other parts of our footprint,” Curran said.
BALTIMORE — More than 1,300 regulators and other stakeholders attended the National Association of Regulatory Utility Commissioners’ 129th Annual Meeting and Education Conference at the Hilton Baltimore Inner Harbor, where the theme was “Infrastructure, Innovation and Investment.” The National Association of State Utility Consumer Advocates (NASUCA) attracted more than 200 to its annual meeting at the same hotel.
FERC Commissioner Robert Powelson said it will take a while for the commission to move forward on rulemakings that languished during its six months without a quorum.
Powelson and Neil Chatterjee joined Cheryl LaFleur on the commission in August, restoring a quorum. Two other commissioners, Kevin McIntyre and Richard Glick, are waiting to be sworn in after being confirmed by the Senate on Nov. 2.
“It’s kind of hard to calibrate around some of these high-level decisions that need to be made. It’s critical that people have a little bit of patience as we get back up and running,” he told NASUCA.
Powelson said he expects FERC to act on its November 2016 Notice of Proposed Rulemaking on electric storage within the next three months. (See FERC Rule Would Boost Energy Storage, DER.)
Powelson said he is using the Department of Energy’s NOPR for coal and nuclear plants as an “inflection point to see what’s working and what’s not working in the organized markets. What I know is working hyper-efficiently is wholesale power prices have dropped and that’s a darn good thing. … Let’s not screw that up.”
The commissioner said he also wants to explore “friction” between RTOs and their market monitors, an issue he said was raised by Virginia State Corporation Chairman Mark Christie at a recent conference.
Christie said in an interview later that he was raising a “structural issue that applies across all RTOs.” (See Order 719: FERC Balanced MMU Independence Against RTO Autonomy.) “What constitutes truly independent market monitoring?” Christie asked. “As the regulator of RTOs, FERC is the appropriate forum to tee up the issue and air it out.”
“I don’t want to go back to the old days,” Powelson said. “I really believe in the independence, and protecting the sanctity of that compact for these independent market monitors. I think they should have the ability to file [with FERC]. And I get a sense that Big Brother RTO wants to say, ‘Yeah, you can be seen and heard when it’s appropriate.’ That’s not a good thing in this world of transparency that we live.”
Powelson expressed skepticism that Order 1000 has resulted in competitive transmission development, saying it is another subject worthy of a “conversation” to determine “what’s working and not working” under the order. “I’m not saying we’re going to amend FERC Order 1000, but I think we owe it to ourselves to have that conversation,” he said.
Stefanie Brand, director of New Jersey’s Rate Counsel, asked Powelson if he was aware of concerns by industrial customers and others about the rising cost of supplemental transmission projects, which are not required by FERC or NERC reliability rules. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“Yes, it is something we’re looking at,” Powelson confirmed without elaboration.
Resolutions on Solar Tariffs, Tax Policy OK’d
NARUC’s Committee on Electricity approved a resolution urging the U.S. Trade Representative “to carefully weigh the harm that could result to energy customers from increasing the costs of solar inputs across the country, and the potential challenges to achieving state renewable energy and greenhouse gas goals that may result from higher solar energy prices.” (See Federal Trade Panel Recommends Solar PV Quotas.)
It also approved a measure asking Congress not to restrict state regulators’ ability to determine how any reduction in corporate income tax rates are addressed in utility rates. The resolution said any reductions in taxes on state-regulated investor-owned utilities “should result in a direct benefit to customers, so long as it is captured in the state ratemaking process.”
NARUC members formally elected Connecticut Public Utilities Regulatory Authority Vice Chair John W. “Jack” Betkoski III as its new president for a one-year term. Betkoski has been serving as president since August, when Powelson, a former Pennsylvania regulator, vacated the post to join FERC.
Ellen Nowak, chair of the Wisconsin Public Service Commission, was elected first vice president, and Edward S. Finley Jr., chair of the North Carolina Utilities Commission, as second vice president.
NARUC also named Andreas D. Thanos, of the Massachusetts Department of Public Utilities, the winner of the 2017 Terry Barnich Award. The award, which recognizes commissioners and staff who promote international cooperation among utility regulators, is named for the former chairman of the Illinois Commerce Commission, who was killed in 2009 while working for the U.S. State Department in Iraq. Thanos was named in recognition of his work in Europe, Latin America and elsewhere.
HOUSTON — It’s a sign of the Mexican electricity market’s growing strength that at least some industry experts expect little change after the country’s presidential elections next year.
The country’s constitution limits presidents to single six-year terms. That means every six years, a new president and administration — usually from the Institutional Revolutionary Party (PRI) — is guaranteed to take power, leading to months of transitory uncertainty for the energy sector.
Derek Woodhouse, a partner with Woodhouse Lorente Ludlow, has been advising Mexico’s Energy Ministry (SENER) on implementing the wholesale market and drafting the geothermal energy law and regulations. He expects 2018 to be different.
“Regardless of who wins the election … they’re not going to be able to dramatically change what’s being done,” Woodhouse said during a Gulf Coast Power Association luncheon last week.
For one, Woodhouse said, market reform was written into Mexico’s constitution three years ago. “Second, because the market rules have been put in place, and can only be changed now by the market itself. It will be hard for them to mess up things,” he said.
“I think in many ways, that’s why it was assigned this way, so it can support political changes, and political changes will not affect dramatically what is going on.”
Continuity or Inertia?
Woodhouse would know. In the late 1990s, he was part of a team drafting the country’s initial market reform proposal. When Vicente Fox ended 71 years of PRI rule with his surprise victory in the 2000 election, it put a halt to the market reforms.
“When Fox won the election, nothing happened — not for 12 months,” Woodhouse said. “That’s a political risk of having a new party [in control], because then you cannot have the same teams running the show.”
Woodhouse said the difference now is the nearly three dozen market rules that have been — or soon will be — put in place since new industry laws and regulations were passed in 2014. They govern everything from financial transmission rights auctions to market registration and outage scheduling. A code of conduct and operating guidelines and procedures are among those rules yet to be developed.
Still, further changes will only be expedited if the PRI manages to replace incumbent President Enrique Pena Nieto with another one of its own, Woodhouse said.
“Then you have continuation. At the end of the administration, people … probably know they’re not going to be here, so why take any risk? Why start something you’re not going to end? That triggers a year of nobody doing anything,” Woodhouse said.
Continuity does reign within the Energy Regulatory Commission (CRE), an independent body from the state-owned Comision Federal de Electricidad (CFE) that has long controlled Mexico’s electricity business. CFE is currently being restructured into separate generation, transmission and distribution businesses.
Woodhouse said inertia during the transition between administrations can still be a problem, however.
“You need to wait for the new panel to take over those positions, to learn what to do, and start doing it,” he said. “You have 12 to 18 months that nothing happens. It’s sad because it shouldn’t be like that. They have the tools to make changes, and they’re simply not using them.”
Growing Private Sector Role
SENER is implementing the wholesale market in phases through 2018. It consists of short-term markets (day-ahead, hour-ahead, real-time and ancillary services), medium-term auctions (three-year energy and capacity contracts), long-term auctions, FTR auctions, a capacity balancing market and the 20-year clean energy certificates market for instruments equivalent to 1 MWh of energy from clean sources.
The market’s third long-term auction last week set a new low for average prices at $20.57/MWh, bettering the $33.47/MWh average set in September 2016, according to preliminary results. Mexico will add 2.56 GW of capacity from 16 new projects, with a total investment of $2.36 billion by international players from Canada, China, France, Italy, Japan and Spain.
“We’re devising something that will allow them to look good politically but still incentivizes the private sector to negotiate contracts,” said Woodhouse, who has focused his career on private-sector participation in infrastructure projects traditionally reserved for the public sector.
“Hiring consultants would lengthen the process by 12 months, so we came with the idea of allowing them, from the top, to sit down and negotiate,” he said. “They’re not used to doing that. That was perceived as something corrupt. We are giving them that option because now, legally, they can do it. But they’re still very nervous. ‘Yeah, but how is it going to look if I sit down and discuss a contract with someone?’”
Woodhouse said the market is just awakening, with many players “just learning how to play the game.” Only five companies are listed as qualified suppliers, and a number of their contracts are in the 1- to 3-MW range.
“They’re testing the waters to see how their software runs,” Woodhouse explained.
FERC last week rejected NERC’s request to eliminate public posting of self-reported compliance exceptions and to expand compliance exceptions to include some moderate-risk violations.
“In most situations, information on NERC’s resolution of compliance and enforcement matters should be transparent and publicly available,” the commission said. The rejections came in an order in which the commission accepted NERC’s annual report on its Compliance Monitoring and Enforcement Program (CMEP) (RR15-2-005).
In February 2015, the commission allowed NERC to move to a risk-based approach to compliance monitoring and enforcement, which allowed low-risk violations of reliability rules to be recorded and mitigated without formal enforcement actions. It also allowed registered entities that passed a NERC review of their internal controls to self-log and mitigate minimal-risk violations, subject to periodic, rather than individual, reviews by the Regional Entity. (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.)
Incentive Lacking?
NERC said the commission “unintentionally removed an incentive for registered entities to participate in the program” when it required public logging, contending that it had reduced interest in the program.
| NERC
The Edison Electric Institute, the ISO/RTO Council (IRC) and MISO transmission owners were among those supporting NERC’s proposal to eliminate public posting. The IRC noted that only 59 of more than 1,200 registered entities participate in self-logging, saying that the incentives to participate were inadequate.
The American Public Power Association, Electricity Consumers Resource Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group opposed the elimination of public posting in a joint filing, saying the transparency was needed to educate the industry and preserve the credibility of NERC’s enforcement program. They said that because compliance exceptions are a significant percentage of noncompliance, the public disclosures allow registered entities to understand compliance requirements. They also said the public posting could help identify unnecessary or redundant reliability requirements.
The commission said it agreed with the commenters who supported continued public disclosure. “The value of maintaining the transparency of self-logged noncompliance continues to outweigh the asserted benefit that might accrue from increasing the incentive to participate in the program,” FERC said, citing the “minimal” burden of public posting and the benefits it provides in “educating industry and ensuring consistency across NERC’s and the Regional Entities’ compliance and enforcement programs.”
Find, Fix and Track Program
FERC also rejected NERC’s proposal to expand the compliance exceptions program to include moderate-risk noncompliance, although all commenters supported NERC’s request.
Moderate-risk violations that have been corrected are currently subject to the Find, Fix and Track (FFT) program, which allows NERC to process them through informational filings instead of the formal Notice of Penalty procedure.
“We are not persuaded that the claimed efficiency gains in processing certain moderate-risk violations as compliance exceptions, rather than as FFTs, are sufficient to outweigh our concerns with treating many moderate-risk noncompliances through a nonenforcement track,” FERC said. “While this approach may be appropriate for minimal risk violations, NERC has not adequately justified this limited approach for moderate-risk violations.”
The commission also raised questions about the FFT program, saying its staff had identified a compliance exception involving falsification of battery testing records by a registered entity’s employee that was disposed of via the FFT process. “The commission does not consider it appropriate to process instances of noncompliance involving falsification of records as compliance exceptions or FFTs,” it said. “Rather, such circumstances warrant a full Notice of Penalty.”
NOPR on Training, Coordination of Protection Systems
In a separate Notice of Proposed Rulemaking, the commission proposed reliability standards PRC-027-1 (Coordination of Protection Systems for Performance During Faults) to ensure protection systems used to detect and isolate faults operate in the intended sequence.
The NOPR also proposed the approval of reliability standard PER-006-1 (Specific Training for Personnel) to ensure that personnel involved in real-time operations are adequately trained (RM16-22).
FERC set a refund effective date of Sept. 30, 2016, the date NEPGA filed its complaint.
NEPGA filed a rehearing request asking the commission to apply the revised PER — and any resulting refunds to capacity suppliers — to an Aug. 11, 2016, scarcity event.
FERC on Thursday rejected the request, saying it would impose “an unforeseen and significant increase in costs” to load.
“Such application is inconsistent with the commission’s notice requirements under the [Federal Power Act],” FERC said. “We recognize that there is a lag between when the event occurs and when the billing to reflect the PER adjustment takes place; that lag in billing, however, does not satisfy the notice requirements under the FPA.”
The January order said the amount of the PER increase would be determined in an evidentiary proceeding if stakeholders were unable to reach a settlement.
On Aug. 31, Settlement Judge H. Peter Young certified an uncontested settlement requiring ISO-NE to increase the daily PER strike price for each hour “by the amounts that actual five-minute reserve shadow prices exceed the pre-December 2014 reserve constraint penalty factors (RCPF) values for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively).”
The revised strike price will replace the strike price value in hourly PER calculations for Sept. 30, 2016, through May 31, 2018. The settlement has not been approved by the commission.
NEPGA President Dan Dolan and ISO-NE officials could not be reached for comment.
FERC last week accepted network transmission service agreements between SPP and Kansas Municipal Energy Agency (KMEA) and Sunflower Electric Power, pending modifications to address the inconsistent treatment of a generation resource (ER17-889).
KMEA’s Jameson Energy Center | KMEA
The commission directed SPP to make a compliance filing within 30 days to resolve a modeling discrepancy in the power-flow analysis, which failed to account for a 9-MW gas turbine (Garden City 2) at KMEA’s Jameson Energy Center in Garden City, Kan.
SPP agreed to file revisions to KMEA’s service agreement to reflect the additional network resource, with an effective date of March 1, 2017, and to remove a reference to the unit that imposes revenue crediting requirements.
The RTO filed with FERC in January service agreements between it and KMEA as a network customer, and between it and KMEA and Sunflower as a network customer and host transmission owner, respectively. Commission staff tentatively accepted the agreements in March while FERC lacked a quorum.
Sunflower and its Mid-Kansas Electric owner, which also includes five co-ops and a not-for-profit electric company, intervened to point out the initial service agreement with KMEA excluded Garden City 2 but required the unit to pay revenue credits as a network resource. They requested FERC require SPP to remove the unit from the revenue credit payment or add Garden City 2 as a network resource.
SPP acknowledged its mistake and said it performed an additional analysis using updated model information, reposting the results in an aggregate transmission service study in February. It confirmed network service for KMEA used Garden City 2 as a designated network resource, effective March 1.
FERC last week approved cost responsibility assignments for 39 baseline upgrades recently added to PJM’s Regional Transmission Expansion Plan (ER17-2362).
The allocations were filed on Aug. 25. Thirty-five projects will be allocated to the transmission zone in which they are located, including five projects of less than $5 million each. Two projects will address Form 715 local planning criteria, and 28 involve circuit breakers and associated equipment. The remaining four projects are “lower voltage facilities” that are allocated based on the solution-based distribution factor (DFAX) method.
PJM’s control room | PJM
Old Dominion Electric Cooperative challenged two of the DFAX allocations, saying it was unable to replicate PJM’s analysis. It asked the commission to direct PJM to provide the detailed information “for the sake of transparency” and to determine whether the upgrades are appropriately allocated entirely to the American Electric Power zone. ODEC questioned PJM’s 100% allocation of another project to the American Transmission Systems Inc. zone, arguing that the results of the DFAX analysis produce a 1.32% allocation to ATSI.
FERC accepted PJM’s defense of its allocations. The RTO said because only ATSI had a DFAX percentage greater than 1% for project b2898 — reconductoring the Beaver-Black River 138-kV line — that zone was assigned the entire cost of the $20 million project.
PJM said it used “an appropriate substitute proxy” for the baseline projects, reactive power upgrades that can’t be addressed by DFAX analysis, which measures over transmission lines or transformers. PJM developed an “interface comprised of the lines and transformers that surround the entire AEP system,” a localization method PJM often uses “because the majority of reactive power upgrades are intended to provide local voltage support.”
ODEC has also asked the D.C. Circuit Court of Appeals to overturn FERC’s policy of allocating all costs from Form 715 projects to the zone of the transmission owner whose criteria triggered the upgrades. ODEC said the cost allocation for the two Form 715 projects should be subject to the outcome of its challenge.
