FERC is considering changes to its Electric Quarterly Report (EQR) rules, including requiring data on ancillary services transactions and changes to how financially settled trades are reported.
In its Sept. 22 notice of the proposed changes, the commission said it will accept comments on the proposals for 60 days following their publication in the Federal Register (RM01-8, RM10-12, RM12-3 and ER02-2001).
Ancillary Services
Transmission providers currently report ancillary services such as reactive supply and regulation in the EQR’s Contract Data section. FERC is proposing that transmission providers also report information about transactions made under their ancillary services agreements in the EQR’s Transaction Data section.
FERC said the information will “help the commission, the public and the industry determine the actual rates being charged for service under these agreements [and] increase price transparency into the wholesale ancillary services markets.”
Booked Out Transactions
The commission also is seeking to clarify the reporting of “booked out” trades — those settled financially without any transmission of power.
FERC said EQR submissions relating to book outs frequently contain inconsistent or inaccurate information, making it difficult to determine how much power is being traded compared to how much is actually being delivered.
“We find that, based on the current EQR database configuration, it is not possible to differentiate book outs of energy or capacity because EQR filers do not have the option to distinguish between the two products,” FERC wrote.
To create a distinction, FERC proposed amending its data dictionary to replace “booked out power” with the product names “booked out energy” and “booked out capacity.”
FERC also seeks to clarify that booked out transactions must be reported in the EQR regardless of the number of parties involved. The notice provides examples of how booked out transactions should be reported when:
two companies sell physical energy to each other for the same delivery period;
one company sells energy to another company and, in real time, the company buying the energy signals the seller to reduce the amount of energy it is providing; and
at least three companies are in a chain of energy sales and one company appears twice in that chain.
Tariffs and Time Zones
FERC also proposed that filers submit into the EQR’s tariff reference fields tariff-related information that they currently submit in the e-Tariff system and that they include time zone information for transmission capacity reassignment transactions.
FERC said last week it remains unconvinced that MISO’s plan to integrate qualifying facilities into Entergy’s footprint would violate Occidental Chemical’s rights under the Public Utility Regulatory Policies Act, denying the company’s request for rehearing of its April order (EL13-41-001).
MISO’s QF plan, implemented when Entergy first joined the RTO, included two options for QF participation, a “hybrid” option and a behind-the-meter option. Occidental claimed the commission failed to address its argument that QFs participating under the behind-the-meter option would have to give up their PURPA rights. Much of FERC’s original order focused on Occidental’s arguments against the hybrid option. (See FERC Denies Occidental’s PURPA Complaints.)
In its original order, “the commission discussed … why requiring a behind-the-meter QF to be reflected in MISO’s commercial model as an Entergy asset for purposes of MISO market participation does not unduly discriminate against QFs,” FERC said. “Occidental has not elaborated why the commission erred in its rejection of Occidental’s arguments that the behind-the-meter option is unduly discriminatory.”
FERC concluded that QFs “could participate in the MISO market while continuing to exercise their rights pursuant to PURPA, and that MISO does not need to modify its Tariff.”
NextEra Energy’s bid to acquire Texas’ largest electric utility, which cleared a U.S. bankruptcy court earlier this week, may have to navigate some choppy waters with state regulators.
At the Public Utility Commission’s open meeting Thursday, Chairman Donna Nelson and Commissioner Ken Anderson both expressed concerns with NextEra’s proposed $18.7 billion purchase of Oncor.
Anderson said his concern is with the $275 million termination fee to be paid to NextEra should the company be out-bid by a last-minute competitor, or if the commission rejects the sale or imposes overly “burdensome” conditions. Nelson said she was concerned about the impact on competition.
Anderson said he has no problem with the termination fee itself, but with how it is structured.
“This merger agreement … appears to be an effort to really tie the commission’s hands in the proceeding,” he said. “If I read the merger agreement and if the commission rejects the transaction in its entirety as not in the public interest, subject to some caveats, there’s no termination fee.
“If, on the other hand, the commission purports to approve it, but with what they call burdensome conditions … that could have a material adverse effect on NextEra or its credit rating … the result is they could walk the deal and get $275 million. Now that’s an extraordinary requirement.”
‘Offended’
“I have frankly been offended by [the merger agreement], but it is what it is,” Anderson added. “I don’t know where the $275 million is coming from, but it can’t be from Oncor’s ratepayers.”
Anderson said he wanted to explain his concern “so the potential applicant, if it wants to, can address them.” The commissioner admitted he has not reviewed the merger agreement in detail, but he promised to file a memo “maybe” next week that fully explains his viewpoint (Docket No. 42750).
“Burdensome” conditions sank a previous bid to buy Oncor from its bankrupt parent, Energy Future Holdings, when creditors objected to the PUC’s conditional approval in March of Hunt Consolidated’s offer. One of the commission’s requirements was that the Hunt group share potential tax savings with the utility’s ratepayers. (See Hunt Reopens Oncor Bid in Lawsuit Against PUCT.)
For her part, Nelson said she is concerned with the deal’s tax implications and its effect on ERCOT’s competitive market. The Internal Revenue Service earlier this summer issued a ruling that eliminates a potential $4 billion tax liability for its remaining assets, power generator Luminant and electricity retailer TXU Energy.
Anderson noted that NextEra has “substantial competitive assets” in ERCOT that could give the company an unfair advantage, a position Nelson agreed with. Brandy Marty Marquez, the PUC’s third member, was silent during the discussion.
“As this transaction has progressed, it does feel in many ways like a step backwards … with respect to [Oncor’s] ownership,” Nelson said. “The reason the [ERCOT] market is restructured the way it was with separate and regulated [transmission and distribution providers] was to grant generators and retailers access to customers and a way of serving those customers.”
Oncor is not a separate, unbundled company like most in the ERCOT market. As part of EFH’s leveraged buyout of TXU Corp. in 2007, the commission required Oncor to be ring-fenced from its sister companies with a separate, independent board of directors.
“The utility press says part of the reason NextEra buys Oncor is they continue to invest in generation and take advantage of the production tax credits,” Nelson continued. “I do want to look at those, as well.”
An Oncor spokesman declined to comment on the commissioners’ statements.
OK from Bankruptcy Court
On Sept. 19, NextEra won approval from the U.S. Bankruptcy Court in Delaware of its bid for Oncor after increasing its offer by $300 million in cash. The company said it would also make other changes to satisfy EFH creditors (Docket No. 14-10979).
EFH’s legal counsel told U.S. Bankruptcy Judge Christopher Sontchi during a hearing that unsecured creditors will now receive an additional $450 million. NextEra will pay $4.4 billion in cash for Oncor and assume its debt and other liabilities, including funding $9.5 billion for the repayment of EFH debt. Oncor was valued at $18.4 billion before NextEra added its sweetener.
After the collapse of the Hunt group’s bid, NextEra announced in July it had reached an agreement with EFH to purchase its 80.25% stake in Oncor. The other 19.75% is owned by an investor group led by Borealis Infrastructure Management and Singapore’s GIC Special Investments. (See NextEra Reaches Deal for Oncor.)
NextEra says it expects to file a joint application with the PUC “soon,” and that it expects the transaction to close in the first quarter of next year.
“Our proposed transaction provides Oncor with a financially strong, utility-focused owner that shares Oncor’s commitment to providing customers with affordable, reliable electric delivery service and significant value and certainty for the EFH bankruptcy estate,” NextEra CEO Jim Robo said in a statement.
NextEra said the deal is subject to bankruptcy court confirmation of EFH’s Chapter 11 reorganization and approval by FERC and the Texas commission, as well as “other customary conditions and approvals.”
NextEra shares have gained $4.72 since Monday, closing at $128.03/share Thursday.
The Hunt group remains unfazed by NextEra’s progress, with spokesperson Jeanne Phillips saying Hunt “will continue to work with all stakeholders to develop a Texas-based solution for the purchase of Oncor.”
EFH has been struggling to emerge from bankruptcy for more than two years now. It has proposed to sell Luminant and TXU to senior creditors owed $24.4 billion. Another hearing is scheduled in bankruptcy court next Monday.
WASHINGTON — FERC on Thursday approved a NERC reliability standard requiring grid operators to assess and protect against the threat of geomagnetic disturbances (RM15-11).
The final rule (Order 830), effective 60 days after its publication in the Federal Register, is nearly identical to the commission’s proposed rulemaking issued in May last year. Under the rule, certain transmission owners and planners will be required to assess the vulnerability of their systems to a “benchmark” GMD event, defined as a one-in-100-year occurrence. They would then need to submit plans to mitigate the identified vulnerabilities. (See FERC Takes Next Step on GMD Standard and Questions and Answers on NERC’s Proposed GMD Rules.)
NERC will also need to submit a work plan within six months of the rule’s effective date detailing how it will study GMD events in general, “given the limited historical geomagnetic data and because scientific understanding of such disturbances is still evolving,” FERC said.
“While we recognize that scientific and operational research regarding GMD is ongoing, we believe that the potential threat to the Bulk Electric System warrants commission action at this time, including efforts to conduct critical GMD research,” the commission said.
GMDs, caused by solar events that disrupt the planet’s magnetic sphere, are considered “high-impact, low-frequency” events.
Response to Comments
FERC’s original Notice of Proposed Rulemaking questioned certain aspects of NERC’s proposed standard, TPL-007-1, including its reliance solely on spatial averaging to calculate the size of the impacted area in the benchmark event.
In comments submitted in response to the NOPR, NERC and other industry stakeholders defended the standard’s methodology for the benchmark definition, but FERC said they did not provide any new information.
“NERC and industry comments largely focused on the NOPR’s discussion of one possible example to address the directive” to modify the calculation so that it did not rely solely on spatially averaged data, FERC said. “However, while the method discussed in the NOPR is one possible option, the NOPR did not propose to direct NERC to develop revisions based on that option or any specific option.”
The commission gave NERC 18 months to make those revisions, as well as to modify the standard to require that data from geomagnetically induced current monitors and magnetometers be made public and to establish specific deadlines for mitigation plans.
In a few cases, FERC declined to direct NERC to make revisions it had considered in the NOPR, instead including them as part of NERC’s study homework.
For example, the commission had questioned whether the benchmark definition should also be modified to reflect that GMDs could have pronounced effects on lower geomagnetic latitudes. While it said that commenters who defended the original calculations did not provide any new information, the commission declined to direct NERC to revise the latitude scaling factor, saying it found “sufficient evidence to conclude that lower geomagnetic latitudes are, to some degree, less susceptible to the effects of GMD events.”
The final rule represents the second stage of the commission’s effort to protect against GMD, an effort that began in May 2013 with Order 779. The first stage, approved in June 2014, dealt with developing operating procedures for responding to GMDs and mitigating their effects.
Data Lacking
Commissioner Cheryl LaFleur called last week’s order “a milestone reflecting over five years of work by the commission, our staff, NERC, industry and stakeholders to address the threats posed” to the grid by GMDs. “It’s not the beginning of the end but the end of the beginning. We still have a lot of work to do.”
LaFleur said the rule “appropriately balances the need for action on this important issue with a recognition that our understanding of the science around GMD events and their operational impacts on the grid is still evolving.”
“One of the things we found frustrating in our tech conferences in developing the final rule was that so much of the magnetometer and monitoring data was from Canada or Europe when in fact we have one of the most highly developed electric grids in the world and very little public data on which to base our analysis.”
Situational Awareness Requirements
The commission also gave final approval to reliability standards IRO-018-1 and TOP-010-1, which specify requirements for the real-time reliability monitoring and analysis capabilities of reliability coordinators, balancing authorities and transmission operators (RD16-6).
The standards implement Order 693, which specified operators’ minimum capabilities, as well as the recommendations contained in a 2008 NERC best practices report and the joint FERC-NERC report on the 2011 Arizona-Southern California outage.
FERC noted that inadequate situational awareness was identified as one of the key causes of the 2003 Northeast blackout.
The joint report on the Arizona-Southern California outage recommended that entities “should take measures to ensure their real-time tools are adequate, operational and run frequently enough to provide their operators the situational awareness necessary to identify and plan for contingencies and reliably operate their systems.”
NERC said the new standards build on existing requirements by requiring applicable entities to provide them with indications of the quality of information being provided by their monitoring and analysis capabilities and notify them of real-time monitoring alarm failures.
Frequency Control Standards
The commission also gave preliminary approval to NERC’s proposed standard BAL-005-1 (Balancing Authority Control) and FAC-001-3 (Facility Interconnection Requirements), which it said would clarify and consolidate existing frequency control requirements (RM16-13).
The commission said the proposed standards “support more accurate and comprehensive calculation of reporting area control error (ACE) by requiring timely reporting of an inability to calculate reporting ACE and by requiring balancing authorities to maintain minimum levels of annual availability of 99.5% for each balancing authority’s system for calculating reporting ACE.”
The NOPR also seeks the retirement of standards FAC-001-2 (Facility Interconnection Requirements) and BAL-006-2 (Inadvertent Interchange).
The commission said it was uncertain whether to support NERC’s proposal to also retire requirement 15 of standard BAL-005-0.2b (Automatic Generation Control), which requires the maintenance and periodic testing of backup power supplies at primary control centers and other critical locations. “Depending on the explanation received in comments, the commission may issue a directive in the final rule to restore the substance of requirement R15 in the reliability standards,” it said.
An executive for power plant developer Competitive Power Ventures, two former aides of Gov. Andrew Cuomo and seven others were named in a broad bribery indictment by federal authorities in New York on Thursday.
Kelly Source: CPV
Peter Galbraith Kelly Jr., CPV’s head of external affairs and government relations, was named in the indictment. CPV is only identified as “the energy company” in the indictment, and the company itself was not a named defendant.
One of the former aides, Todd R. Howe, has already pleaded guilty to several charges, including extortion, wire fraud and conspiracy, and has agreed to testify against the others. According to the indictment and Howe’s plea arrangement, Howe arranged bribes to be paid by CPV and another company, COR Development.
The bribes allegedly came as CPV was arranging to build the 650-MW Valley Energy Center in Orange County, a combined cycle plant that was granted a certificate of public convenience and necessity a little more than two years ago. It is still under construction and is seen as necessary to relieve downstate transmission constraints.
The top target in the indictment is Joseph Percoco, who formerly held a $169,000-a-year post as Cuomo’s executive deputy secretary. He left the state payroll in January, taking a position at Madison Square Garden.
According to the indictments and a release issued by Preet Bharara, the U.S. Attorney for the Southern District of New York, Percoco is accused of taking more than $315,000 in bribes from Kelly and two executives with Syracuse developer COR Development, Steven Aiello and Joseph Gerardi.
Kelly did not return calls for comment by press time.
“CPV takes the charges handed down today very seriously,” the company said in a statement. “We are extremely disappointed in the alleged conduct, which is in direct contradiction to CPV’s core values and expectations of our staff. Braith Kelly is no longer employed at the company. We will continue to cooperate fully with this investigation until a final determination is made.”
The indictment also names Alain Kaloyeros, president of the State University of New York Polytechnic Institute, as being involved in what federal authorities called “two overlapping criminal schemes involving bribery, corruption and fraud in the award of hundreds of millions of dollars in state contracts and other official state benefits.”
According to the statement from Bharara, Percoco was experiencing financial problems at the time that CPV was seeking New York’s approval of the power plant. Kelly gave Percoco “expensive meals and a Hamptons fishing trip” in the beginning. But later, at Percoco’s request, CPV hired Percoco’s wife at about $90,000 a year for a job that didn’t require much work.
In exchange, according to the charging document, Percoco used his official position to help CPV get lower-cost emissions credits from the state for a plant the company was building in New Jersey, and he helped arrange a power purchase agreement with New York. As a result, CPV was expected to save about $100 million in development costs.
Artist rendition of CPV Valley Energy project Source: CPV
The indictment says Kelly hid the monthly payments to Percoco and his wife through a CPV consultant. Percoco is also accused of lying when he told CPV that he had received an ethics opinion from Cuomo’s office approving his wife’s hiring. He also hid the payments he received from CPV, failing to list them on financial disclosure forms.
News of the investigation broke earlier this year. (See CPV Power Plant Ensnared in Federal Corruption Probe.) At the time, CPV was named as a company that made payments to Percoco, but it wasn’t identified as a target of criminal charges.
Thursday’s indictment identifies Kelly as a co-conspirator, saying he “willfully and knowingly did corruptly give” Percoco bribes “in order for Percoco to influence regulatory approvals and funding related to the development of a power plant in Orange County, N.Y., and take other official action to benefit” CPV.
The rest of the indictment has to do with other attempts to subvert the state regulatory process, according to the release. The primary focus of the investigation is the so-called Buffalo Billion economic development program championed by Cuomo. Bharara’s probe began last fall. A centerpiece of that program is $750 million in direct state aid and tax credits to SolarCity, which is building a 1-GW solar panel factory, the largest of its kind in the Western Hemisphere, according to the state.
ERCOT will continue its reliability-must-run agreement with NRG Energy’s Greens Bayou Unit 5 after a solicitation produced no viable alternatives.
The Texas grid operator had solicited proposals for must-run alternatives (MRAs) after it entered an RMR contract with NRG Texas Power for its Houston-area unit, a 371-MW gas-fired plant, on June 2. (See ERCOT Seeks Alternatives to Houston-Area RMR Unit.) The contract is projected to cost the market $60 million.
ERCOT said the proposed MRAs it received by the Aug. 24 deadline would not “adequately meet the reliability need served by the Greens Bayou 5 unit.” The ISO received eight offers from four qualified scheduling entities (QSEs) with a combined capacity of 385.9 MW for most of the contract months, but it said some of those offers did not qualify as eligible MRA resources and the others did not provide an “acceptable solution to the reliability concern” necessary to replace Greens Bayou.
Greens Bayou Source: NRG Energy
The Greens Bayou RMR agreement addresses reliability concerns on a Houston-area transmission line. Under the agreement, the unit will remain available during summer peak demand periods through June 2018 to support system reliability under certain critical operating conditions.
ERCOT has said the $590 million Houston Import Project, scheduled to be completed by summer 2018, will solve the reliability concern.
RMR Rule Changes Proposed
Meanwhile, the Protocol Revision Subcommittee last week advanced three nodal protocol revision requests (NPRRs) related to ERCOT’s RMR procedures. They will be taken up next week by the Technical Advisory Committee, which in July rejected an NRG request to allow the economic dispatch of RMR units. (See “Pricing Change on RMR Units Rejected, Appealed to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)
NPRR788 modifies the RMR planning studies to include forecasted peak loads and introduces a new requirement that a potential RMR unit must have “a meaningful impact on the expected transmission overload” to be considered for an agreement.
NPRR795 creates a mechanism to refund capital expenditures funded by ERCOT under an RMR agreement, if the agreement is terminated. The refund would be based on the expenditures’ depreciated book value if the resource returns to commercial operations; otherwise, it would be based on the salvage value.
NPRR793 would clarify the reliability unit commitment process to ensure RMR units are not accidentally committed as a reliability unit before other resources. The revision request adds several responsibilities for RMR unit owners, revises RMR formulas and adds further clarifications.
Luminant, Calpine Notices
ERCOT, which already has more than 81,000 MW of capacity to meet the fall and winter’s expected peak demand of less than 59,000 MW, recently got news of an additional resource.
Luminant notified ERCOT on Sept. 14 that its 805-MW coal unit at Martin Lake in East Texas, which had been running only from May to late September, will now be available for year-round dispatch. The status change is effective Oct. 1.
The Texas grid operator has also reviewed Calpine’s notice that it would be suspending operations at its 400-MW, gas-fired Clear Lake Power Plant and determined the five steam and gas turbines are needed to support transmission system reliability. ERCOT will issue a final determination by Oct. 10.
ALBANY, N.Y. — A Rochester-area farm family scored unusual concessions on Thursday when state regulators approved a plan for a substation and power lines that removed previously approved facilities from their property (11-T-0534).
The New York Public Service Commission approved a modified Certificate of Environmental Compatibility and Public Need for the Rochester Area Reliability Project south of the city. The original plan approved by the PSC in 2013 would have taken arable land out of production from the Krenzer family farm, according to the family’s rehearing petition.
The plan also would have taken the most valuable land on the property used for farm infrastructure, according to the family. The family grows wheat, corn and soybeans on more than 3,000 acres.
$37M Increase
Avangrid, whose Rochester Gas & Electric is building the project, said the delays and changes will increase the project’s cost by $37 million to $291 million. The company said $23 million is related to changes in site costs, routing and structure types, with $14 million linked to the delay and extended construction timeline.
RG&E began eminent domain proceedings in 2011 to route the project through the farm.
The family says it was unaware of the proceedings for about a year, a charge RG&E denied. The family said it had informal meetings with RG&E representatives in their home in November 2011, but no definitive plans were discussed that indicated their property would be condemned.
The utility said it had a series of meetings with family members to discuss the project and produced a June 2011 letter sent to a family member that indicated financial compensation for the acquisition of the substation site.
After granting rehearing, the PSC appointed an administrative law judge in 2013 and conducted hearings in 2014, but efforts to negotiate a compromise were unsuccessful.
Negotiations restarted earlier this year, which culminated in a joint proposal filed in July. It was endorsed by the family, RG&E, PSC staff, and the state departments of Environmental Conservation and Agriculture and Markets.
Marie Krenzer told RTO Insider that Thursday’s order prompted “a lot of mixed emotions, but we were pleased with the outcome.” The family spent “well into six figures” on attorneys’ fees and other costs through the process, she said, money that they will not recoup.
“We didn’t know what we were taking on when we started this, but we knew this wasn’t right,” she said.
‘An Example of Government Working’
PSC officials lauded the outcome as an example of regulators responding to competing interests in a difficult case. “This is an example of government working,” PSC Chair Audrey Zibelman said at the meeting. “The commission listened to the Krenzers and took their concerns seriously” while also fulfilling its obligation to preserve system reliability.
“We didn’t really understand the nature of the local opposition,” Commissioner Gregg Sayre, a Rochester-area native, said at the meeting. “But once we did, I think we came up with a good result.”
Several local and state officials became involved, including U.S. Sen. Charles Schumer.
The affected property would have totaled about 670 acres. The substation would have taken 12 acres, while the remaining land would have been used for a “zig-zag” pattern of transmission lines across the farm’s productive fields, which would have cut the farm in half.
The order approved Thursday moves the substation from the Krenzer farm about 1 mile east to vacant land across the Genesee River. The routing of two new 115-kV lines eliminates the zig-zag route through the property and instead will go through land with a U.S. Department of Agriculture conservation easement to reach an existing New York Power Authority line.
The project calls for the construction of approximately 23 miles of new 115-kV transmission lines, reconstruction of 2 miles of an existing 115-kV line, a new 1.9-mile 345-kV line, a new 345 kV/115-kV substation and the improvement of three existing substations.
The new substation site will damage or destroy existing wetlands, so 17 acres of the Krenzers’ property will be used for site mitigation.
Maine regulators last week proposed a 15-year phase-out of net metering for current rooftop solar systems and a 10-year limit for new systems.
The proposal came as a part of a rulemaking process that the Maine Public Utilities Commission hopes to complete by the end of the year and implement in 2017.
“In light of changes in the technology and costs of small renewable generation, particularly solar PV, we felt that opening a rulemaking process to consider changes to the rule was the prudent course of action to ensure that all ratepayers are treated fairly,” Chairman Mark Vannoy said in a statement.
The rulemaking also proposes gradually reducing compensation for new solar customers, increasing the size of an eligible customer facility by more than 50%, from 660 kW to 1 MW, and additional consumer protections.
House of Representatives Assistant Majority Leader Sara Gideon, a solar proponent who helped craft a compromise solar power bill that was vetoed by Gov. Paul LePage in April, blasted the PUC proposal.
“Maine needs a comprehensive solar policy. Unfortunately, the PUC’s narrow focus on a single part of the broader solar policy doesn’t help our state’s ability to open new markets that create jobs and lower costs for homeowners, businesses and communities,” Gideon said. “This past session’s solar bill did not simply look at net metering in isolation but was crafted to help our constituents who are clamoring for access to community, commercial and municipal solar. That responsiveness and broad view is why policymaking should be left to lawmakers.”
The net metering review was automatically triggered by a PUC rule after solar exceeded 1% of Central Maine Power’s installed capacity. The utility reported solar at 1.04% at the end of 2015.
ST. PAUL, Minn. — MISO’s 2016 Transmission Expansion Plan recommends 394 projects totaling $2.8 billion.
The preliminary MTEP 16, unveiled at the Sept. 13 System Planning Committee of the Board of Directors, proposes:
114 baseline reliability projects valued at $734 million;
27 generator interconnection projects at $123 million, nine of which will be cost-shared;
One transmission delivery service project at $350,000;
One market efficiency project, the Huntley-Wilmarth 345-kV line project in southern Minnesota projected to cost $81 million; and
251 other projects driven by local needs at $1.8 billion.
Vice President of System Planning and Seams Coordination Jennifer Curran said the top 10 priciest projects in MTEP 16 are evenly distributed between MISO North and MISO South. Spending under MTEP 16 includes more projects than MTEP 15’s 334, but total spending would be $6 million less.
The projects are spread across all MISO quarters, with 33% in MISO South, 39% in MISO West (in parts of northwestern Illinois, Montana, South Dakota and Michigan’s Upper Peninsula and all of North Dakota, Minnesota, Wisconsin and Iowa), 22% in MISO East (in northern Indiana and Michigan’s Upper Peninsula) and the remaining 6% in MISO Central (in parts of Missouri, Illinois, Indiana and Kentucky).
The projects are also varied by type, with 44% of projects dedicated to upgrading substation equipment, 28% dedicated to transmission line upgrades, 20% dedicated to the installation of new transmission lines, 5% dedicated to transformer upgrade and replacement and 3% dedicated to voltage control improvements.
Curran said the lone market efficiency project submitted for approval, the Huntley-Wilmarth 345-kV line, will accommodate wind additions in Iowa and Minnesota. Curran said the cost of the project, which was recommended by North/Central Market Congestion Planning Study and has benefit-to-cost ratio of 2, would be spread 20% across the MISO North and Central regions, with the rest allocated to the local zone. MISO South does not yet share in cost allocations for market efficiency projects.
Board member J. Michael Evans asked why the project wasn’t built 20 years ago if it was meant to handle wind power. Curran said the project will be constructed primarily for new wind buildout.
Board Chair Judy Walsh asked if the MTEP would always involve an expensive bundle of transmission upgrades that chases new generation locations. Vice President of Transmission and Technology Clair Moeller said MISO’s multi-value project category seeks to predict the location where transmission is most needed.
Curran said if approved, MTEP 16 may contain a hitch because the $80.9 million Huntley–Wilmarth line project is located wholly inside Minnesota, which has a right-of-first-refusal statute. Curran said that while the project “by definition is eligible for the competitive transmission process,” Order 1000 and MISO’s Tariff respect state and local laws.
MTEP 16 also includes four economic projects resulting from MISO’s South Market Congestion Planning Study:
An $88 million 230-kV line and substation in southeastern Louisiana with a 1.96 to 3.40 B/C ratio, to be in service by 2022;
The $1.9 million Minden–Sarepta 115-kV line upgrade in northwestern Louisiana with a 1.83 B/C ratio to be in service by 2020;
The $7.6 million Trumann–Trumann West 161-kV line project in northeastern Arkansas with a 13.4 B/C ratio to be in service by 2018; and
The $6.7 million Lakeover 500/230-kV transformer upgrade in southeastern Louisiana with a 1.4 B/C ratio to be in-service by 2020.
Costs for the four projects will be assigned to the local zones that they benefit.
MISO’s Planning Advisory Committee members will vote on the MTEP 2016 report in October. A MISO review of sector feedback will begin in November before the board votes at its December meeting.
“You know, Ernest Hemingway wrote his best novels when he was young, but MTEP keeps getting better. MTEP 16 is better than MTEP 15,” Evans said.
Summer 2016 was the hottest in four years for PJM, but increased energy efficiency and behind-the-meter solar dampened loads.
PJM called 23 hot weather alerts during June, July and August, and Philadelphia, D.C., Richmond, Va., and Louisville, Ky., each recorded more than 30 days above 90 degrees. D.C. led with more than 50 days.
Under Capacity Performance rules, “we want to get these hot weather alerts out early, and probably a bit more frequently,” PJM’s Chris Pilong said.
Nevertheless, the peak load this summer — Aug. 11 — totaled only 151,293 MW, about 4% lower than the 157,509 peak for 2013 (July 18) despite similar temperatures and humidity.
Pilong said the drop likely resulted from conservation efforts, contributions from distributed resources and more efficient air conditioning, light bulbs and televisions.
Performance Assessment Hour Evaluation a Matter of Following Directions
Generators will maximize their revenues and avoid penalties during performance assessment hours by just doing what they’re told, PJM told the Operating Committee last week.
“Here’s the overall concept everyone should be taking away from this: You need to be following your regulation signal,” PJM’s Rebecca Stadelmeyer said.
PJM provides generating units with a signal in real time to follow regarding how much power they should provide. The closer that units stick to providing the requested amount, the better their performance assessment will be — even if the output is below the amount of capacity it cleared in the auction.
“If you’re following the signal to 100%, you will be adjusted to that signal even if we’re keeping that unit down,” Stadelmeyer said.
Stadelmeyer presented several hypothetical examples to explain how regulation bias factors can be used to determine a unit’s set point during an assessment hour. The factors adjust a unit’s assessment measure based on an average over the hour of the assigned regulation PJM sends to the unit. It protects generators from incurring penalties should PJM regulate a unit below its set point and defines bonuses for those regulated above their set points. However, units will not receive any bonus for operating beyond PJM’s scheduled or dispatched level, Stadelmeyer said.
The bias factor, which ranges from -1 to +1, hasn’t been used since PJM transitioned to performance-based regulation, which is more granular.
Preliminary 2017 Capital Budget Focused on Enhancing Reliability
PJM expects to spend approximately $38 million on capital projects in 2017, largely on enhancements and renovations to existing infrastructure. Of the total projected budget, nearly 82% — or about $31 million — is earmarked for software upgrades, application revamps and renovating the Technology Center.
PJM’s Jim Snow presented the proposed budget, which next gets presented to the Members Committee before going back to the Finance Committee for final recommendations. A final proposed budget is scheduled to go before the Board of Managers at its Oct. 17 meeting.
The investment in existing equipment is an increase over the 2016 budget, when $28 million was allocated to the same categories. The remaining $7 million in the proposed budget is allocated to interregional coordination and new products and services, which include funding to implement five-minute market settlements and a more user-friendly public data repository.
Nearly Year-Long Outage Planned for Line Replacement in Va.
Dominion Resources’ Elmont-Cunningham 500-kV line in the company’s north-central Virginia territory will go out of service for about a year for a rebuild starting in October. It is planned to briefly go back into service next summer and be fully in service by June 2018.
Elmont-Cunningham 500-kV Rebuild Map Source: PJM
The line has reached its end-of-life criteria, and continued operation could cause voltage and thermal violations. The outage — which will run from Oct. 23 to June 2, 2017, and then Sept. 6, 2017, to Dec. 30, 2017 — isn’t expected to force any reductions in generation capacity in the area, but it may cause minor thermal overloads and low voltages. Local capacitors will provide reactive support.
“We’re working with [transmission owners] to find some potential switching solutions that could resolve the issues,” PJM’s Lagy Mathew said.
ComEd to Remove Cordova Stability SPS
The special protection scheme (SPS) ensuring stability at the Cordova Energy Center is no longer required now that all 345-kV circuit breakers at Commonwealth Edison’s Quad Cities Station 4 have been upgraded to independent pole-operated devices, ComEd said
The system trips combustion-turbine units at the center for a three-phase fault within a roughly 3-mile zone of Quad Cities that persists for more than six cycles. With the upgrades, the generators are now stable for all faults specified by ComEd and PJM criteria, and the severity of a breaker failure following three-phase faults is reduced.
The SPS is targeted for removal by the end of 2016. The units also trip from Quad Cities’ multiline outage unit trip scheme, which will remain active.
