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.)
MISO no longer faces a capacity shortfall next year, the RTO announced in releasing the results of its newest survey with the Organization of MISO States.
MISO said its newest results show a minimum 1.7-GW surplus for 2016 as a result of reduced load forecasts and an increase in resources committed to serving MISO load. The 2014 survey had projected a 2.3-GW shortfall next year.
The new survey predicts a regional surplus of 1.7 to 2.3 GW (representing reserve margins of 15.6 to 16.1%) for 2016, with sufficient zonal surpluses to offset zonal shortfalls through 2019. “Additional actions needed to ensure sufficient resources beyond 2019,” MISO said.
“The big change is in the increase of committed resources. There’s also a decrease in the reserve requirement as we continue to refine the calculations on exploiting the diversity of the footprint to minimize everybody’s obligation in reserves,” MISO Executive Vice President Clair Moeller said during a conference call with stakeholders Friday. “So going into 2016 we’re feeling very confident that we’re in good shape in terms of sufficient resources.”
The RTO said the survey projects an average annual load growth rate of 0.8% over the next five years, equal to the 2014 survey. However, because 2015 load forecasts were below previous projections, the growth was from a lower base level.
“At this point in time we see a shortage of physical machines to serve the load in 2020, premised on that 0.8% load forecast distributed across the footprint,” Moeller said. “So the question we’re trying to answer here is how tight will capacity supplies be in those out years so people can begin to make their decisions between purchase and build and demand-side management and whatever else they need to do to ensure they bring sufficient resources to the resource pool in these out years.”
Zonal Surpluses Can Offset Shortages in 2016
The forecasts also benefited from a 0.6-GW reduction in reserve requirements.
While the region will have sufficient capacity through 2019, according to the survey, Zone 6 (Indiana and Kentucky) and Zone 7 (Lower Michigan) will have shortfalls next year.
Generation owners, load-serving entities and regulators have been working to mitigate those problems, Moeller said. “We still have confidence they’ll figure out how to do that.”
By 2020, the survey forecasts regional capacity ranging from a surplus of 0.5 GW to a shortage of as much as 1.8 GW.
The RTO released its survey at its Annual Meeting in Milwaukee on Wednesday. Moeller said the survey would be explained in detail at the Supply Adequacy Working Group’s July 9 meeting.
The Federal Energy Regulatory Commission required several significant changes in PJM’s Capacity Performance proposal. PJM must make the changes in a compliance filing due in 30 days.
Below is a summary of the changes required, followed by the relevant paragraph numbers from the order.
Review of Sell Offers: The commission approved PJM’s proposed mechanism for reviewing and rejecting sell offers but required it to remove the phrase “to the satisfaction of the Office of the Interconnection” from Attachment DD, saying it was “too ambiguous and allows PJM too much discretion.” (¶92)
Good Faith Representation: The commission rejected PJM’s proposal that resources submitting Capacity Performance offers make a good faith representation that it has, or will make, necessary investments to ensure it has the capability to provide energy when called upon. Knowingly false representations would have been subject to penalties. The commission said it did not believe the representation “would provide any added value in incenting resource performance.” It also said the scope of the requirement was “inappropriately vague” and could create a barrier to entry for new resources. (¶94-5)
External Resources: FERC said PJM must add a requirement that an external generation capacity resource must demonstrate that it meets – or will meet by the start of the delivery year – the criteria for an exception to the Capacity Import Limit in order to offer as a Capacity Performance resource. (¶97)
Demand Resources, Energy Efficiency, Storage, Intermittent Resources: PJM must clarify that capacity storage resources, intermittent resources, energy efficiency resources and demand resources may submit stand-alone Capacity Performance sell offers in a megawatt quantity consistent with their average expected output during peak-hour periods. (¶100)
Environmentally Limited Resources: PJM must clarify that it will permit aggregated offers from environmentally limited resources. (¶101)
Aggregation Across Locational Deliverability Areas: FERC rejected PJM’s proposal to allow resources in different locational deliverability areas to submit aggregated offers, saying the RTO had not demonstrated why Capacity Emergency Transfer Limits should not be taken into account. “We are not persuaded that aggregation will be feasible across locational deliverability areas in all circumstances or would be able to provide the required resource adequacy during emergency conditions,” the commission said. In addition, it said the proposal was inconsistent with the Capacity Performance design, noting that several Capacity Performance rate parameters (non-performance charge rate, performance bonus payment rate, stop-loss limits, and default offer caps) are LDA-specific. (¶103)
Monthly Stop-Loss: The commission agreed with PJM’s request to withdraw its original proposal that the monthly stop-loss limit on penalties equal 0.5 times annual net CONE, which the RTO said would allow under-performance without consequence once a resource has reached the limit, equivalent to 15 performance assessment hours in a month. PJM acknowledged in its response to FERC’s March 31 deficiency letter that most performance assessment hours are likely to occur during a few peak months of the year. The commission said the monthly stop-loss limit would “severely dilute” PJM’s performance incentives. (¶165)
Non-Performance Charges: FERC required two clarifications to the language in proposed section 10A(d) of the Tariff “to avoid ambiguity or misinterpretation.” It said the proposed wording, “limitations specified by such seller in the resource operating parameters,” could be misinterpreted to mean only those operating parameter limitations that are less flexible than a resource’s pre-determined parameter-limited schedule. That, it said, could allow less flexible resources to avoid non-performance charges more often than more flexible resources. “We find that a clarification is warranted to make clear what parameter limitations are at issue in this provision.”
It also required PJM to make clear that if a capacity resource is not scheduled by PJM due to any operating parameter limitations submitted in the resource’s offer, any undelivered megawatts will be counted as a performance shortfall. The same penalty would apply to a resource that was not scheduled because its market-based offer was higher than its cost-based offer. (¶167-173)
Net Energy Imports: FERC required a clarification to avoid any ambiguity regarding how PJM will assess the performance of external resources, saying it agreed with the Market Monitor that the RTO’s proposal does not specify how PJM will assess performance for energy imports and when emergency action hours only occur within individual zones or sub-zones. “If an emergency action is limited to a zone or sub-zone region, transmission into the affected region is likely restricted, so including a system-wide measure of net energy imports would likely distort the balancing ratio,” the commission said. It also agreed with Panda Power Funds and the Coalition of Generators and Project Finance Resources (Essential Power, Lakewood Cogeneration, Moxie Freedom, CPV Power Development, NextEra Energy, Invenergy Thermal Development and Brookfield Energy Marketing) that, as proposed, the balancing ratio could exceed 1, causing capacity resources’ expected performance during a performance assessment hour to exceed their full cleared unforced capacity quantity.
It required PJM to submit revisions clarifying: the definition of net energy imports; how it will apply the performance assessment calculation to external resources with and without a capacity commitment when an emergency action is triggered PJM-wide; and that a capacity resource’s expected performance for any performance assessment hour shall not exceed 100% of its cleared UCAP quantity. (¶175-178)
Fixed Resource Requirement Entities: FERC said PJM’s penalties rate could unduly penalize Fixed Resource Requirement (FRR) entities because the physical penalty option lacks an hourly charge rate relative to the additional capacity per megawatt of non-performance. It required that PJM propose a penalty rate for the physical payment option in terms of additional capacity per megawatt-hour of non-performance. It also required the RTO to allow FRRs to choose between the physical non-performance assessment option and the financial non-performance assessment option at the start of the delivery year, rather than when the FRR submits its first capacity plan. “We find that this delay will allow a Fixed Resource Requirement entity to make its decision on the best information available.” FERC also said PJM may apply the Capacity Performance rules to FRR entities only after the conclusion of the FRR plans to which they are currently obligated. (¶208-212)
Exemption for Planned Generation Resources: FERC rejected PJM’s proposal to exempt planned generation capacity resources from the capacity market must-offer requirement until they become operational. “We are not persuaded by PJM’s concerns that continuing to apply the must-offer requirement to planned resources that have cleared at least one RPM auction would act as a barrier to entry. In addition, we are concerned that by clearing an RPM auction with a planned resource but not following through on its construction in a timely manner, a seller could effectively withhold capacity and deter a new entrant from taking its place,” the commission said. It noted that PJM’s current rules allow resources not expected to become operational as planned to seek an exception to the must-offer requirement. (¶ 353-356)
Credit Requirements: FERC agreed with PJM that the risk of non-performance is higher for resources that do not exist at the time a seller submits an offer but said its proposal did not acknowledge changes in the risk as a resource transitions through the stages of development. It required PJM to modify the proposed credit requirements for planned resources and financed resources, as recommended by Panda Power Funds, to allow the security requirement to be reduced as the project nears its in-service date. FERC also required PJM to revise its credit requirements to recognize LDA-specific net CONE values in determining a market seller’s auction credit rate. (¶382-383)
Operating Parameters: The commission rejected, in part, PJM’s proposed revisions to rules on operating parameters. FERC said PJM’s existing rules allow capacity resources to submit energy market offers with inflexible operating parameters that do not reflect their actual capabilities. As a result, generators could offer excessive minimum run times, resulting in unjust make-whole payments at ratepayers’ expense, the commission said. But it called PJM’s proposed changes “overly restrictive,” saying the RTO’s proposals for capping the minimum start-up and notification times for all resources and for capping the minimum down time of storage resources did not take into account unit-specific constraints.
It also found fault with PJM’s proposal that offers reflect only physical constraints, saying it barred resources from reflecting in their offers contractual limits, such as gas pipeline requirements that generators take uniform delivery throughout the day, which could result in longer minimum run times. The commission said including such constraints in a supply offer is reasonable and not an exercise of market power, as PJM had contended in proposing that resources that do so be denied make-whole payments. “We see no reason to treat costs associated with resource physical constraints differently than costs associated with other types of actual constraints,” the commission said.
It ordered PJM to revise the rules to allow make-whole payments based on “actual constraints.” However, the commission rejected arguments that a resource’s inability to perform due to such limitations should be excused when calculating capacity payments. “The revisions that we direct here ensure that resources are appropriately compensated for their operation in the energy market; they do not excuse a resource from failing to fulfill its capacity obligation,” the commission said. “Providing such an exemption from non-performance charges would blunt the incentives for providing energy and reserves during the hours when they are most needed. … Accordingly, it is reasonable for a resource that fails to perform because of parameter limitations to receive less net capacity revenue than a performing resource.” (¶437-440)
Maximum Emergency Offers: The commission said PJM had failed to make a case that its current rules regarding maximum emergency offers are unjust and unreasonable, rejecting its proposed changes. PJM said the rules allow a generation capacity resource to submit an uneconomic offer price, removing itself from the day-ahead energy market until PJM has declared a maximum emergency. FERC acknowledged that the rules may allow a capacity resource to avoid honoring its capacity commitment. “However, we conclude that proper application of non-performance charges, rather than revision of the maximum emergency offer designation, is the appropriate method of eliminating this concern,” the commission said. PJM’s proposal could unintentionally reduce the number of resources available during emergency conditions if the resource’s alternative action is to take a forced outage, FERC said. “There is, therefore, value in allowing a Capacity Performance resource to offer capacity on an emergency-only basis when it is subject to environmental limitations, fuel limitations, or temporary emergency conditions, or when it can provide its capacity on a temporary basis only.” (¶476-479)
The commission rejected Ameren’s request for a declaratory order (EL14-46).
