PJM acted properly in its solicitation of bids to fix a stability issue at the Artificial Island nuclear complex, the Federal Energy Regulatory Commission has ruled, denying a request by losing bidder Public Service Electric and Gas seeking to have the project reposted.
While the commission found that PJM was not required to use its Order 1000 solicitation rules because the call for bids predated that measure, Commissioner Cheryl LaFleur said the case presented an opportunity to consider the order’s competitive solicitation procedures more generally.
“One of Order No. 1000’s key goals was to harness the benefits of competition in transmission development for customers, and it is important that, as regions implement their Order No. 1000 procedures, we do not lose sight of that goal: facilitating the identification, development and ultimately the construction of more efficient or cost-effective transmission projects that are better for customers,” she wrote in a separate note included with the ruling (EL 15-40).
PSE&G had accused PJM of failing to follow its own rules by unilaterally modifying finalists’ proposals and allowing LS Power – the winning bidder – to modify its proposal more than a year after the proposal window closed. (See PSE&G: PJM Broke the Rules in Artificial Island Solicitation.)
If PJM did not believe that any one proposal represented the most efficient or cost-effective solution, PSE&G said, it should be required to repost the solicitation.
PJM countered that such an interpretation of the rules “would result in PJM engaging in interminable, never-ending solicitations until the perfect project was proposed, with the inevitable result that PJM would have to default to assigning many projects to incumbents due to time constraints.” (See PJM: PSE&G’s Remedy for Artificial Island Bid Process ‘Draconian,’ ‘Self-Serving.’)
In addition, it said, that type of thinking “would turn the Order No. 1000 solicitation process into a strict bidding process of the type that would govern homogenous products such as the purchase of paper clips.”
PJM also noted that without the authority to combine and modify proposals, “it would be left with accepting a proposal four times as expensive as the combination it is considering.”
FERC concluded, “PJM followed its commitment to evaluate Artificial Island proposals using its then-effective transmission planning process and to incorporate its new Order No. 1000 proposal window into that process ‘to the extent feasible and practicable.’”
PJM planners announced April 28 that they would recommend to the Board of Managers that LS Power build a new 230-kV transmission line from New Jersey’s Artificial Island to Delaware at a cost of $146 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.) PSE&G and Transource Energy were chosen for necessary connection facilities.
PSE&G initially was picked for the job last summer, but the Board of Managers reopened the bidding following an outcry from losing bidders, New Jersey officials and environmentalists.
The Board of Managers once again will be asked to decide the issue at their meeting July 29. Prior to that, PJM planners will present their recommendation to the board’s four-member Reliability Committee.
With just seven weeks until PJM conducts its first Base Residual Auction incorporating the newly approved Capacity Performance product, stakeholders gathered last week for a peek at the comprehensive changes Manual 18 must undergo before resources begin submitting offers.
But there were more questions than clarity at the specially called Markets and Reliability Committee meeting. It was scheduled for three hours but went on for more than six, as tempers ran high and patience low.
“I’m frustrated and I’m crying,” said Old Dominion Electric Cooperative’s Ed Tatum during a discussion of unit-specific parameters. “This is really complicated.”
At issue was whether units adhering to their parameters were safe from penalty in an emergency situation. The answer? No.
“It governs what we will pay in uplift cost, and that’s not what we wanted either,” Mike Kormos, senior vice president for operations, told Tatum. “But it will not govern whether you are in a penalty or not. It is not what we filed. It is the order we got.”
Dozens of scenarios were presented: What can be used for replacement capacity? When does the force majeure provision go into effect? What difference does it make if it’s a transition year? How do we know why we weren’t called? What happens if you choose to self-schedule? And most commonly, when and how are non-performance charges assessed?
Stakeholders have one more education session on Wednesday before the red lines to the 235-page manual are presented for endorsement to the MRC the following day. (The Members Committee, which follows the usually short MRC gatherings, has been canceled.) (See FERC OKs PJM Capacity Performance: What You Need to Know.)
PJM staff urged stakeholders to send their questions to capacityperformance@pjm.com to be considered in Wednesday’s training.
PJM must make a compliance filing to the Federal Energy Regulatory Commission by July 9.
“We need to get this manual out there and discussed,” PJM’s Dave Anders said. “We do not have the luxury of time to go through multiple iterations.”
The new Capacity Performance product is a response to poor generator performance during the polar vortex of January 2014. It aims to strengthen grid reliability by rewarding overperforming participants and charging under-performers penalties.
The changes will be phased in over the 2018/19 and 2019/20 delivery years.
The Federal Energy Regulatory Commission last week denied a request by Ameren that its native load in the “Bootheel” region of southeastern Missouri be considered part of MISO’s Ameren Missouri transmission pricing zone rather than the Entergy Arkansas zone.
The commission rejected Ameren’s request for a declaratory order (EL14-46).
FERC said while sections of a 2004 service agreement exempted Ameren Missouri from MISO charges for the bundled retail load, the agreement also requires Ameren to pay for services it does not provide itself, such as the transmission service provided by Entergy Arkansas. The commission said that “a fundamental tenet of contract interpretation is that a contract provision should be interpreted … as consistent with the contract as a whole.”
The Bootheel load refers to Ameren Missouri’s native load customers in the corner of the state south of St. Louis. Until 1991, that load was served by Entergy Arkansas’ predecessor, Arkansas Power & Light. In 1991, APL sold its distribution system serving retail customers in Missouri to Ameren but retained its transmission facilities.
As a result, the Bootheel load is connected to Entergy Arkansas’ transmission facilities in Missouri and has no direct interconnection to the Ameren Missouri grid.
Ameren Missouri, which joined MISO in 2004, served that load until December 2013 with network integration transmission service from Entergy Arkansas. A grandfathered agreement between the two companies was in effect until 2009, when a new agreement was entered.
FERC was not persuaded by Ameren’s argument that denying its petition would take jurisdiction over the transmission component of its bundled retail load from the Missouri Public Service Commission. “The Missouri commission did not have the ability to set the rate for transmission service to the Bootheel load … prior to Entergy Arkansas’ integration into MISO [in 2013], and Entergy Arkansas’ integration into MISO does not change that.”
In a statement, Ameren said, “While Ameren Missouri is disappointed with the Federal Energy Regulatory Commission’s decision, we have decided to accept the decision.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:40-10:00)
Members will be asked to endorse the following manual changes:
Manual 19: LoadForecasting and Analysis — Makes change to residential measurement and verification rules approved in November. Provides a solution for the issue that some electric distribution companies (EDCs) are prohibited from sharing personally identifiable information about residential customers participating in demand response programs. EDCs may use unique ID numbers instead.
Manual 03: Transmission Operations — Requires a separation between emergency and load dump ratings. In the event they are the same, the emergency rating submitted by the transmission owner shall be, at a minimum, 3% lower than the load dump rating. If this change results in a normal rating that is higher than the long-term emergency (LTE) rating, the TO shall, at a minimum, make the normal rating equal to the LTE rating.
Manual 3A: Energy Management System Model Updates and Quality Assurance — Continues effort to streamline sections regarding model updates. Most significant change is new section on sub-transmission model submission requirements. Appendix A revised to clarify business rules and tool interaction.
3. CAPACITY PERFORMANCE (10:00-11:30)
Manual 18: PJM Capacity Market — Changes introduce new Capacity Performance products; outline transition; address resource adequacy and demand in the Reliability Pricing Model; describe supply resources in the RPM; explain demand resource requirements and RPM auction credit rates; outline the CP must-offer requirement; address intermittent and capacity storage resource sell offers; describe resource performance assessments, non-performance assessments and expected performance vs. actual performance; outline fixed resource requirement alternative; and review CP transitional Incremental Auctions. Members will be asked to endorse changes so PJM may complete its compliance filing, due July 9 to the Federal Energy Regulatory Commission. (See related story, PJM Stakeholders Rush to Figure out What’s Changing for the BRA.)
Kent County Gears up for Fight Against Wind Project
The Kent County Commission and area residents are preparing for a fight against the proposed Mills Branch Wind Project that would include up to 35 towering turbines on farms in the Eastern Shore county.
The Eastern Shore Land Conservancy, the Kent County Farm Bureau, the Queen Anne’s Conservation Association and a group called Keep Kent Scenic organized a standing-room-only meeting at the Kennedyville fire house last week to brief opponents. “We are not unfriendly to green industries,” said Bill Graham, an organizer of Keep Kent Scenic. “We are definitely pro-green energy. We just feel that certain energy sources — like 500-foot-tall turbines — don’t comply with Kent County zoning and the comprehensive plan.”
Apex Clean Energy has approached property owners and is gathering data, but it has yet to submit an application with the Public Service Commission for a Certificate of Public Convenience. Although it doesn’t have the power to block the project, the opinion of the three-member County Commission, composed of the county’s legislators and executive, has to be taken into consideration by the PSC when the regulatory agency reviews the project.
Several hundred residents in Western Massachusetts and state and local officials attended a Department of Public Utilities hearing to blast a plan for local utilities to tap into a controversial gas pipeline expansion. Berkshire Gas, along with Columbia Gas and National Grid, are seeking DPU approval to purchase natural gas carried through the proposed Kinder Morgan pipeline, extending from New York state across Massachusetts to Dracut.
Berkshire Gas has said it will not accept new customers or expand natural gas delivery services to existing customers until the pipeline has been completed. The project would take three and a half years to build if Federal Energy Regulatory Commission permits are obtained.
Eversource Starts ‘New Hampshire First’ Jobs Program
Eversource Energy has launched a “New Hampshire first” initiative to partner with local contractors and electrical workers’ unions to help construct and maintain proposed energy projects throughout the state.
Eversource has three major projects that are planned to begin in 2016 that represent a more than $2 billion investment in the state’s electrical grid, the company said. The most notable and controversial project is Northern Pass, a proposed $1.4 billion transmission line to deliver hydroelectric power from Quebec to New England.
Eversource anticipates the projects will create almost 2,000 jobs in the state.
Controversial Pinelands Gas Pipeline Proposal Reappears Before BPU
A proposal to run a natural gas pipeline through the Pinelands that was blocked by the Pinelands Commission last year has reappeared, this time before the Board of Public Utilities. South Jersey Gas wants to construct the pipeline to deliver Marcellus Shale gas to the B.L. England generating station, which needs to switch from coal to natural gas or shut down.
The new proposal, which moves the pipeline connection point outside the protected Pinelands and restricts the line from adding any other natural gas customers, would go to the Pinelands Commission for consideration if it is approved by the BPU. The new proposal, amended as a “private development” project, would only need staff approval.
The Pinelands Commission deadlocked 7-7 in a January 2014 vote. But since then, Gov. Chris Christie named new members to the panel, a move seen by some environmentalists as a way to smooth the way for the project.
The company has said the project was amended to address concerns by environmentalists, but activists are already crying foul. “They’re trying to do an end around the Pinelands Commission,” said Doug O’Malley of Environment New Jersey. “This whole process has been extraordinary. The level of Christie administration influence is astonishing.”
Audrey Zibelman, chair of the Public Service Commission, is giving up her stock in Viridity Energy, the Philadelphia energy start-up she helped create and once led. Zibelman’s ownership of Viridity stock and her past professional connections to energy firms doing business in the state were the subject of a story published Tuesday by Capital New York.
Zibelman had previously disclosed her ownership of Viridity stock in state financial disclosure forms, where she valued the shares at more than $1,000. She told Capital New York that the shares had no “book value” and she received neither dividends nor any compensation from Viridity, which is privately held. She relinquished ownership of the shares for no compensation, her lawyer said.
Zibelman, a former PJM executive, left Viridity in 2013 to join the PSC. Viridity makes software that monitors energy usage for companies to help them reduce their energy costs. Zibelman was not required to give up her shares in Viridity under state law, but a letter to the company said she was surrendering them now “due to her current position.”
The Public Service Commission’s annual staff report found that most major electric and gas utilities in the state provided a satisfactory level of customer service in 2014.
All electric utilities met or exceeded the standards for performance on the measures of customer service with the exception of two utilities owned by National Grid. KeySpan Gas East will pay a negative revenue adjustment of $8.9 million while Niagara Mohawk will pay $2.54 million.
PSEG Long Island is pressing the Long Island Power Authority for a bigger performance bonus in addition to its $45 million annual management fee.
Under contract terms with the state, PSEG is eligible for the bonus if it meets 20 different service metrics. PSEG last year met 19 of the 20. The company maintains that excess points earned in other categories should be applied to the one in which it fell short. The request would result in a bonus payment of $5.76 million — $288,417 more than the power authority believes it should pay.
The contract’s performance standards include average speed to answer phone calls, timely billing and customer satisfaction, among other measures. Under the contract, the maximum incentive payment is scheduled to increase next year to $8.7 million. PSEG’s management fee is also scheduled to increase to $73 million.
County Votes to Take Duke Coal Ash in Exchange for $19M
Chatham County officials voted 3-2 to accept a payment of nearly $19 million from Duke Energy to not oppose a landfill that will take coal ash from the utility, which is under political pressure to find a home for the estimated 150 million tons stored on 14 of its properties.
“I don’t think anyone is especially happy,” Commission Chairman Jim Crawford said. “This agreement gives the county a measure of control that it otherwise wouldn’t have.” The county says it might spend some of the proceeds on long-term insurance to protect itself from environmental problems caused by the coal ash after the landfill’s eventual closure.
The agreement will give the rural county south of Chapel Hill the right to demand groundwater sampling before and after the ash is moved to the landfill in Moncure. Duke has already agreed to pay another county $12 million to store ash at a second landfill site.
Solar advocacy group NC WARN has built a 5.2-kW solar array on the roof of a Greensboro church and is selling the power back to the church at half the rate charged by the local utility to test the state’s laws prohibiting solar energy sales to anybody but the local utility.
The group wants the Utilities Commission to find the arrangement to be a public service, allowing the church to avoid the upfront solar installation costs. The organization’s executive director, Jim Warren, says his group will go to the courts if the NCUC denies its request.
Duke Energy spokesman Randy Wheeless said NC WARN’s attempt to win third-party status appears as though it “wants to get into the electric utility business but is asking the commission for a free pass to avoid the rules and regulation that come with being a utility.”
Regulators Deny Xcel’s Application to Charge Customers for Minn. Solar
The Public Service Commission denied Xcel Energy’s application to make state customers pay for the cost of solar projects mandated in neighboring Minnesota.
Xcel’s application for an advanced determination of prudence, or ADP, for 187 MW of solar from three Minnesota projects would have allowed some of the costs to be passed through to North Dakota customers. The projects were designed to meet a 2013 Minnesota renewable energy mandate.
The commission ruled that Xcel did not prove that the solar projects were cost effective and that North Dakota customers would benefit from them. “I don’t believe North Dakota customers should have to pay for the result of policies in a state that they didn’t have a say in passing,” PSC Chairwoman Julie Fedorchak said. Xcel included the costs in its rate cases for customers in Minnesota, North Dakota, South Dakota, Wisconsin and parts of Michigan.
High Court Will Hear Appeal of Ruling that Kept PPL Records Secret
The state Supreme Court has agreed to hear an appeal of an open-records ruling that kept the details secret of a $60,000 fine paid by PPL Electric Utilities.
The Public Utility Commission fined PPL after a whistleblower complained that the utility diverted work crews to restore customers during a storm outage in 2011, forcing other customers to endure a longer outage. An appeals court upheld the PUC’s decision to reject a request by news media outlets to disclose details of the incident.
Legislation is moving forward that would remove a restriction preventing the Public Utilities Commission from taking into account how decoupled revenues from energy usage are affecting a utility’s cost of capital.
The bill, sponsored by state Sen. Susan Sosnowski, is aimed at National Grid and would allow possible lower costs of capital to be considered in determining the profits the company is allowed under the decoupling statute. Decoupling was approved by the legislature in 2010 to encourage more aggressive energy efficiency programs. If the bill is passed, it could come into play the next time National Grid proposes a rate increase. National Grid is not opposed to the change, according to a spokesman for the company.
The bill was among a flurry of legislation that was introduced this year after National Grid imposed hefty rate increases. Most of the retaliatory measures aimed at National Grid, such as proposals to cap rate increases, failed to make headway.
The developer of a transmission line that would be buried beneath the bottom of Lake Champlain said that it would pay $284 million to clean up the lake and to promote renewable energy in the state in exchange for an agreement from the Conservation Law Foundation to drop its opposition to the project.
TDI-New England plans to spend $1.2 billion to lay a 154-mile 1,000-MW power line from the Canadian border to the town of Ludlow by burying the cable at the bottom of Lake Champlain for most of its route. (See Lake Champlain Cable into New England Progresses.)
Previously, TDI had agreed to contribute more than $160 million to reduce the cable impact, which would stir up sediment and have minor effects on underwater life and human uses of the lake.
Board Softens Stance on Employees’ Work on Climate Issues
A state board that banned its nine employees from working on climate change issues after discovering that its executive secretary served on a global warming task force years ago has relaxed its stance after receiving intense public backlash.
The Board of Commissioners of Public Lands, a three-member body, voted 2-1 for the ban after learning about the climate change work of Tia Nelson, the board’s executive secretary and the daughter of Earth Day founder Gaylord Nelson.
Last week, Democratic Secretary of State Doug La Follette, who had cast the only dissenting vote on the ban, proposed relaxing the restrictions ban to prohibit staff only from advocating for global warming policy changes. “It is sensible for our staff to talk about climate change when appropriate,” La Follette said. “It’s just logical. We don’t want our staff to be advocating. We don’t want them on the stump.”
New York regulators approved Central Hudson Gas & Electric’s three-year rate plan in an order that also says one demonstration project the company filed in the state’s program to revamp the utility industry shows promise.
The New York Public Service Commission on Wednesday approved a joint proposal by the company, PSC staff and stakeholders that will increase electric rates by $43.4 million through 2017 (14-E-0318). The company had initially proposed a one-year plan with a $40.1 million increase.
Much of the commission’s discussion Wednesday focused on the state’s Reforming the Energy Vision. Utilities have been ordered to file demonstration projects by July 1, but Central Hudson jump-started the process by proposing six projects in a proceeding that ran parallel to its rate case that started last July. The proceedings are on separate regulatory tracks, however. (See Central Hudson Case Provides Early Test of NY REV.)
‘Non-Wires’ DR Plan
PSC staff said a “non-wires alternative” proposed by Central Hudson and its stakeholders in a status report filed in May met the criteria to move forward. The alternative is a demand response proposal in three congested areas of the service territory. The company was given 30 days to file additional details on proposed cost recovery and incentive mechanisms.
The PSC said a net customer benefit would have to be shown for approval, including “forgoing the capital investment associated with a traditional [transmission and distribution] solution.” To expedite implementation, the order defers cost recovery until Central Hudson’s next rate case — no sooner than June 2018.
That prompted concerns from Commissioner Diane Burman. “Is the rate case driving the policy, or is policy’s generic proceeding driving the rate case?” she asked.
Burman also complained that commission staff were driving the demonstration project approvals. “I really think that it’s an inappropriate delegation of authority for me to give up the review of that,” she said.
Chairman Audrey Zibelman said she understood the concern. But after “long conversations … I know staff ended up feeling this is the right process and I’m comfortable with it,” she said.
Rate Case
Distribution rates for Central Hudson have not changed since 2012. Its last rate case was approved in 2010, and the PSC’s 2013 approval of its acquisition by Canadian holding company Fortis included a two-year rate freeze that expires on July 1.
The rate order calls for graduated increases over the next three years beginning July 1:
In 2015, electric rates will increase $2.3 million, or 38 cents/month, for the average residential customer, a 0.3% increase based on the total bill.
In 2016, rates will increase $17 million, up 3.4% or $3.86/month.
In 2017, rates will go up $24.1 million, up 4.8% or $5.58/month.
The impact is softened over the three years by the use of $27 million in customer credits that Fortis provided during the 2013 takeover.
Other provisions include the shift from bimonthly to monthly billing and the creation of a “major storm reserve” — Central Hudson is the only New York utility without one. The fixed monthly service charge of $24 will not change. The company had sought a $5 increase.
Central Hudson is also allowed a 9% return on equity.
The Federal Energy Regulatory Commission last week denied wind generators’ rehearing request on its June 2014 order concerning SPP’s revisions to the RTO’s generator interconnection procedures.
FERC also conditionally accepted SPP’s compliance filing as a result of the June 2014 order, subject to a further compliance filing (ER14-781).
2009, 2013 Changes
SPP first revised its interconnection process in 2009, shifting it from a “first-come, first-served” approach to a “first-ready, first-served” approach. The changes streamlined the study process by including a fast-track approach for customers that met specific milestones and reduced the impact of suspended projects on other projects. They also sought to steer speculative projects into a preliminary interconnection queue and discourage them from entering the final queue by increasing deposits and requiring project readiness milestones.
In December 2013, the RTO proposed changing the way the interconnection queue priority was determined and revising milestones to execute a generator interconnection agreement (GIA). SPP also proposed requiring an interconnection customer to provide a deposit, upon execution of an interconnection agreement, of 20% of the interconnection facilities and network upgrade costs, or convert the previously provided financial milestone of $4,000/MW, whichever was greater.
FERC initially ruled the filing deficient but conditionally accepted SPP’s subsequent compliance filing response in the June 2014 order.
SPP not Unclear
The American Wind Energy Association (AWEA), the Wind Coalition and E.ON asked FERC for clarification or rehearing of the order, arguing SPP did not make it clear as to what constituted harm to interconnection customers when a higher-queued customer withdrew from the queue and had its deposit refunded.
FERC rejected their assertion, saying the complainants had misconstrued the interconnection process and took SPP’s statements out of context.
FERC also denied rehearing over revisions allowing SPP to withhold refunds. The commission said the “costs would not have been incurred without the higher-queued interconnection customer’s request for the interconnection capacity.”
FERC also rejected rehearing regarding transmission network upgrades funded by interconnection customers whose interconnection agreements are subsequently terminated by SPP. FERC said its June 2014 order found that “[i]nterconnection customers who execute a GIA and provide an initial payment for construction are undertaking a significant business risk” should they not meet their obligations.
“We find that their request would defeat the purpose of protecting lower-queued customers from increased costs,” FERC said.
FERC denied E.ON’s separate rehearing requests regarding SPP’s establishment of queue priority at the interconnection facilities study queue stage, and payment of interest on deposits, saying they were beyond the scope of the proceeding.
MILWAUKEE — MISO will reevaluate the metrics used in evaluating market efficiency transmission projects because of concerns they are unduly conservative and preventing viable solutions to congestion, officials said last week.
The Duff-Coleman 345-kV upgrade (right) is the only proposed market efficiency project that cleared MISO’s conservative 1.25-1 benefit-cost ratio in the North/Central region. Each dot represents a proposed project; some projects were the subject of as many as five proposals.
MISO requires economic projects to clear a 1.25-1 benefit-cost ratio, based on an assumed 20-year lifespan rather than the actual life of 40 years or longer. In addition, projects are discounted based on transmission owners’ cost of capital (currently about 8%) rather than a “societal” discount rate of about 3%.
“So essentially we have three layers of conservatism,” Clair Moeller, executive vice president of transmission and technology, told the Board of Director’s System Planning Committee meeting.
The issue came up during a briefing on MISO’s North/Central market congestion planning study, which analyzed 48 proposed projects, only one of which — the Duff-Coleman 345-kV project to reduce congestion in southern Indiana — cleared the 1.25 threshold.
“It appears to me there’s clearly congestion in three or four key zones,” said Director Thomas Rainwater, noting the number of rejected projects clustered together on MISO’s North/Central map. “Something looks to be broken when one out of 48 projects gets approved. It just strikes me by looking at it visually: Is the criteria right?”
Cost Concerns
Moeller said the difficult hurdle was the result of stakeholders’ cost concerns. “When we first had the notion of cost allocation, the constituency was very interested in us being very conservative. So there are several things inside the business case parameters that we’re required to follow inside the Tariff that causes … the economics of the projects to be fairly modest.”
Moeller said it was time “to take a look at those business case parameters and see what the appetite is for relaxing some of those now that we’ve had a better track record and a better understanding of how to model these things.”
“We will be doing the reevaluation because it’s a good idea,” he added. “Whether we end up changing the business case is an open question.”
In an interview after the meeting, Moeller said the review of the metrics will likely begin this fall at the stakeholders’ Planning Advisory Committee.
General Counsel Steve Kozey noted that states could authorize any transmission that would reduce their constituents’ costs “as long as it doesn’t hurt” MISO reliability. The question is whether load wants to pay for the upgrades, he said.
The fact that congestion remains on the system “doesn’t mean that there are a lot of super obvious projects,” he said.
Committee Chairman Michael Evans — who was surprised at the end of the meeting with a carrot cake to celebrate his 70th birthday — asked staff to provide a list of projects that would clear the threshold using a more realistic 40-year lifespan.
Competitive Solicitations Coming
The Duff-Coleman project, which has a benefit-cost ratio of 3.6 to 12.9 depending on assumptions used, is expected to be one of the first tests of the competitive solicitation process for nonincumbent transmission developers under the Federal Energy Regulatory Commission’s Order 1000.
John Lawhorn, director of regional and economic studies, told the board there is also a “50-50” chance that staff will recommend opening a competitive window under Order 1000 for a project in MISO South. He did not identify the project.
Board Chairman Judy Walsh said she feared MISO’s role in evaluating competing proposals was a “slippery slope.”
Rainwater and Evans also expressed misgivings. “We have a common concern about wading into this river,” Evans said.
Moeller said MISO has had difficulty attracting top-tier engineering firms to conduct evaluations because they prefer to pursue more lucrative work with the developers themselves.
Joint Study with ERCOT
Moeller also said MISO and ERCOT expect to begin a joint study in about six months to evaluate the potential for HVDC facilities to address seams issues in the Houston area.
Participants in evidentiary hearings will no longer have to provide paper copies of all exhibits introduced as evidence, under an order approved by the Federal Energy Regulatory Commission last week (RM15-5).
The commission said its administrative law judges recently adopted a practice requiring participants to file exhibits electronically. “Thus, it is no longer necessary or efficient to require all participants to provide the presiding judge and court reporter with paper copies of each exhibit introduced at the hearing,” the commission said. The order amends Rule 508 of the commission’s Rules of Practice and Procedure, which previously required participants provide one paper copy of each exhibit to the presiding officer and two paper copies to the court reporter.
The Federal Energy Regulatory Commission on Thursday accepted the results of ISO-NE’s ninth Forward Capacity Auction in February, turning aside the protest of a utility workers union (ER15-1137).
The Utility Workers Union of America Local 464 had challenged the results, charging that the Brayton Point Power Station illegally withheld capacity from the auction in order to drive up prices. (See Union: Void ISO-NE Capacity Auction Results.) The union tried unsuccessfully to make a similar complaint stick last year with the results of FCA 8.
“We are not persuaded by Utility Workers Union’s allegations that market manipulation affected FCA 9, as the record is devoid of any evidence to that effect,” FERC wrote.
The 1517-MW Massachusetts generator is slated to close in 2017. Energy Capital Partners, the plant’s former owner, did not offer it in the last two capacity auctions in New England, covering the 2017-2018 and 2018-2019 capacity commitment periods. Brayton Point was sold last year to Dynegy, which said it would close the plant on the previously announced schedule. (See Dynegy Becomes New England Player Overnight.)
The commission also said that Brayton Point was already prohibited from participating in FCA 9 having announced its intention to retire. The RTO’s Tariff prohibits re-entry into the capacity market “at market rates in years when market-based treatment is likely to produce more revenue, thus inappropriately toggling between cost-based and market-based compensation.”
The plant is located in the Southeast Massachusetts/Rhode Island zone, which failed to meet its minimum resource requirement, triggering administrative pricing. (See Prices up One-Third in ISO-NE Capacity Auction.)
