The Long Island Power Authority on Wednesday approved a contract for a 90-MW offshore wind farm, by far the largest such facility contemplated in the U.S.
The site, 30 miles off the island’s Southern Fork, is the first part of a wind development in federally leased waters that could support up to 1,000 MW of offshore wind.
Gov. Andrew Cuomo two weeks ago proposed the state develop 2,400 MW of offshore wind in various sites off Long Island to support the goal of 50% renewable energy by 2030. He also prompted the LIPA Board of Trustees to act on contract negotiations that had stalled since the summer. (See Cuomo Proposes 2,400 MW of Offshore Wind by 2030.)
The wind farm could provide enough electricity to power 50,000 homes. If the Cuomo proposal is realized, as many as 1.25 million homes could be powered.
The wind farm developer, Deepwater Wind, built the nation’s first offshore wind farm off Block Island in Rhode Island, which was commissioned last month.
The LIPA board approved a contract submitted by Deepwater Wind for the South Fork Wind Farm after a yearlong process. Offshore wind was the lowest-cost option in the request for proposals from LIPA, beating out natural gas generation.
Neither LIPA nor Deepwater released contract terms on Wednesday.
The 20-year power purchase agreement includes a pay-for-performance clause, which allows LIPA to only pay for delivered energy, eliminating operating and construction risk, the authority said. LIPA said technology improvements reduced the project’s “all-in” energy costs to be competitive with other renewable energy sources.
“Depending on the schedule for permitting, construction could start as early as 2019, and the wind farm could be operational as early as 2022,” Deepwater spokeswoman Meaghan Wims told RTO Insider.
LIPA CEO Tom Falcone said in a statement, “We are confident this is the first step to developing the tremendous potential of offshore wind off Long Island’s coast and meeting Gov. Cuomo’s Clean Energy Standard. This project is the right size, at the right location and demonstrates how smart energy decisions can reduce cost while providing renewable energy and clean air for all of Long Island.”
Elizabeth Gordon, director of the New York Offshore Wind Alliance, said, “LIPA’s 90-MW South Fork project moves New York to the forefront of offshore wind development in America. Major progress on what will be the nation’s largest offshore wind project, combined with Gov. Cuomo’s 2,400-MW commitment, makes it clear that New York is entering a new energy era — one where offshore wind power is poised to play a key role in meeting downstate’s electricity needs.”
FERC last week approved NYISO’s revised demand curves but said the ISO must eliminate the assumption that new peaking plants in the New York Control Area (NYCA) will require emissions controls (ER17-386).
The Jan. 17 order approved NYISO’s Nov. 18 proposal on all but one of nine contested issues. The new demand curves will take effect with the ISO’s capacity auction for the 2017/18 capability year beginning May 1 and will be the basis for auctions through the 2020/21 delivery year. (See IPPNY: Demand Curve Reset ‘Top Priority’.)
The ISO will continue to use the F class frame peaking turbine as the proxy unit for setting the cost of new entry. It also continued the requirement that peaking plants include dual-fuel capability and selective catalytic reduction (SCR) emissions controls for the New York City, Long Island and G-J Locality demand curves.
But the commission rejected the ISO’s proposal to extend the SCR requirement to the NYCA, where gas-only designs were permitted.
The curves, calculated for NYISO by consulting firm Analysis Group, suggest increased prices in most zones, with Zones G-J starting at about $22/kW-year, up from less than $20 for 2014/15. Long Island’s curve starts at almost $25, versus about $21 in the previous curve. The New York City curve is virtually unchanged with a $26 starting point.
The NYCA curve would have jumped from a starting point of about $14 to almost $20.
In its last demand curve reset, the ISO proposed that the NYCA peaking plant operate under an annual operating hours limit in lieu of installing SCR emissions controls. FERC said that assumption still holds, despite the ISO’s contention that peakers without the controls risk not obtaining necessary air permits.
“It is undisputed that SCR emissions controls are not required for peaking plants located in load zones C and F in NYCA,” the commission said. “In addition, NYISO admits that the F class frame turbine can meet the New Source Performance Standard requirement to limit nitrogen oxides emissions while operating on natural gas without SCR emissions controls.”
The ISO acknowledged that F class turbines can meet New Source Performance Standards for carbon dioxide emissions without SCR controls by limiting their operations to 3,300 hours annually, a capacity factor limit of 38%.
The Independent Power Producers of New York joined the ISO in calling for the SCR inclusion, contending that increasing concern in New York over fossil fuels will pressure the state’s Siting Board to require tougher controls.
FERC said their position was “speculative,” quoting from its order in the last reset that “while there is always a risk that regulations will change in the future, we cannot base the finding of viability on speculation that the EPA or New York state regulators will act at some point in the future.”
It noted that the demand curve reset process takes place every four years “so that changed circumstances, such as new regulations, can be taken into account.”
“We find more compelling the statements from [the New York State Department of Environmental Conservation] and evidence that New York state has issued air permits and Article 10 certificates for electric generators without SCR emissions controls in recent years. Specifically, NYSDEC stated in its comments to the NYISO Board of Directors that its permit reviews are fact specific, so SCR emissions controls to limit nitrogen oxides emissions “may not be required or appropriate in every case, such as where other control measures are available or where a facility accepts federally enforceable permit conditions to limit emissions below the applicable thresholds.
“We are more persuaded by NYSDEC’s comments and N.Y. Siting Board precedent than speculation about future public involvement in [plant] certification proceedings,” the commission said.
The commission ordered the ISO to file a revised Tariff within 30 days removing the SCR requirement for NYCA.
FERC otherwise approved the ISO’s filing as is, siding with it on the choice of the F class turbine, peaking plant costs, property tax treatment, natural gas forecasts, and incorporation of shortage pricing into the net energy and ancillary services revenues assumptions.
The auction for the 2017 summer capability period (May 1- Oct. 31) will be conducted March 30-31, with results posted April 4.
Two energy sellers that engaged in market manipulation during the Western Energy Crisis of 2000/01 will be prohibited from using the costs associated with illegal trading activity to offset the amount of money they’re expected to refund back to California, FERC has ruled.
The commission will also hold an evidentiary hearing to determine which cost offset claims submitted by Shell Energy North America and Hafslund Energy Trading stemmed from crisis-period trading practices such as “false exports,” “phantom ancillary services” and “false load scheduling” — all of which contributed to the widespread manipulation that bilked California ratepayers for billions of dollars (EL00-95-295). (See related story, FERC Denies Multiple Energy Crisis Rehearing Requests.)
Bankrupted by high wholesale electricity costs during the 2000-01 Western Energy Crisis, Pacific Gas and Electric is party to the ongoing proceedings related to market manipulation during the period.
“We find that sellers should not be permitted to offset their refund liability by the costs incurred while engaged in activities in violation of the then-effective tariffs,” the commission said in its Jan. 23 order.
Under the commission’s refund methodology, prices for all short-term sales into CAISO and the now-defunct California Power Exchange are to be capped at a specific “mitigated market clearing price,” with sellers expected to refund amounts above that level.
The commission initially allowed generators who believed that the mitigated price did not cover their operating costs to file cost-of-service rates in order to recover full costs, a provision that was later extended to energy marketers such as Shell and Hafslund for recovery of costs associated with their transactions.
FERC’s decision comes after California petitioned the 9th U.S. Circuit Court of Appeals to contest the commission’s previous acceptance of cost offsets submitted by Shell and Hafslund, a petition that the court held in abeyance.
The California parties — which include the state’s attorney general, the California Public Utilities Commission, Pacific Gas and Electric and Southern California Edison — later filed a brief with the commission contending that the two companies’ offset claims included costs associated with illegal trading activities.
The commission last year took up the issue on voluntary remand after getting approval from the 9th Circuit.
FERC’s decision reopens the record on the proceeding and allows participating parties to supplement existing information. The commission also encouraged the parties to reach a “mutually acceptable” settlement ahead of a new hearing.
“We note that there have been numerous settlements already filed and approved by the commission in the refund proceeding and related proceedings,” FERC said.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
A. Manual 11: Energy & Ancillary Services Market Operations and Manual 12: Balancing Operations. Revisions to account for the updated regulation requirement developed by the Regulation Market Senior Issues Task Force. (See “Regulation Requirement Changing from ‘Peak’ to ‘Ramp,’” PJM Operating Committee Briefs.)
4. Underperformance Risk Management Senior Task Force (URMSTF) (10:00-10:15)
Members will be asked to endorse proposed revisions to the Tariff and Reliability Assurance Agreement specifying requirements for external resources seeking qualification under Capacity Performance rules. (See No End in Sight for PJM Capacity Market Changes.)
5. Energy Market Uplift Senior Task Force (EMUSTF) (10:15-10:45)
Members will be asked to endorse a Phase 1 proposal endorsed by the task force and to discuss whether to proceed with a vote on the Phase 2 proposal in light of FERC issuing a Notice of Proposed Rulemaking on the topic last week. (See related story, FERC Proposes More Transparency, Cost Causation on Uplift.)
Members will be asked endorse proposed Tariff, Operating Agreement and RAA revisions that clean up definitions.
Members Committee
Consent Agenda (2:20-2:25)
Members will be asked to endorse:
B. Operating Agreement revisions associated with residual auction revenue rights enhancements.
C. Revisions to the Tariff resulting from discussions at special Planning Committee sessions regarding new service request cost allocation and study methods. (See PJM Considering Injection Rights for Demand Response.)
D. Tariff and Operating Agreement revisions developed by the GDECS.
2. Underperformance Risk Management Senior Task Force (URMSTF) (1:40-2:00)
Members will be asked to endorse proposed Tariff and RAA revisions specifying requirements for external resources seeking qualification under CP rules. (See MRC item 4 above).
DALLAS — During an unusually animated meeting last week, SPP’s Strategic Planning Committee eventually agreed that it was the correct body to take up the contentious issue of cost shifts when new members join existing transmission-pricing zones.
“I think this is a policy decision all the way, and this is where [the discussion] should be held,” SPP Director Harry Skilton said.
Skilton’s comments were echoed by other members — and by staff — and helped wrap up an hour-long discussion that revisited charges over whether SPP had circumvented the stakeholder process last October, when Kansas City Power & Light’s proposal to revise the zonal-placement criteria was pulled from the Regional Tariff Working Group and given to the SPC. (See SPP Moves to Head off KCP&L Measure on Tx Cost Shifts.)
After several stakeholders said the stakeholder-driven process had been overridden when KCP&L’s revision request had been “arbitrarily” pulled from the RTWG, SPP CEO Nick Brown grabbed a microphone.
“I take issue with the use of the word ‘arbitrarily,’” Brown said. “From a strategic perspective and a regulatory perspective, and in many board members’ view, we were heading down a road that would not have been good for our reputation. We would have been using the wrong tools, and there were a lot of people involved in that debate.”
“This characterization that we have hijacked the process is just false,” said Michael Desselle, SPP’s vice president of process integrity. “We have followed the process.”
Several members pointed a finger at South Central MCN’s Noman Williams, who chaired the Markets and Operations Policy Committee last year, for taking KCP&L’s proposal (RR 172) away from the RTWG. Williams did not attend last week’s SPC meeting, but he later said that he and RTWG Chair David Kays, of Oklahoma Gas and Electric, discussed where the revision request belonged.
Kays “recognized the potential for broader policy issues,” Williams told RTO Insider. “I agreed and said I thought there were broader policy issues that had historically resided at the SPC and board, and that I would suggest that the RR also be presented and reviewed at the October SPC to determine if there needed to be additional discussion and guidance.”
Denise Buffington, KCP&L’s director of energy policy and corporate counsel, said her preference was to send RR 172 back to the RTWG and then the MOPC and Board of Directors.
She is also open to other ideas.
“If someone can bring me a better solution that solves my equity issue and cost-shifting issue, I’m all ears,” she said. “I’m willing to negotiate or take someone else’s ideas. I don’t want to spend another six, eight or 10 months in a working group or task force to try and solve a problem that’s a real problem today.”
Buffington said KCP&L would probably file a complaint at FERC and “get a change made there” should the SPC not resolve RR 172 “to our satisfaction and in a timely manner.”
“I agree this is an issue that needs to be resolved. I agree with the urgency,” Brown responded, suggesting the process would drag out further if the RTWG continued to handle KCP&L’s proposal. “You could file a [Section] 206 [complaint] with FERC today. My response to FERC would be, ‘Please give us the opportunity to resolve this through the stakeholder process. Every time we’ve done that in the past, [our request has] been granted.”
“We are open to having it resolved [in the SPC], but we are not interested in it being paralyzed by the SPC,” Buffington said Monday.
Buffington agreed to keep KCP&L’s proposal within the SPC, but she said she wants a discussion and vote if no progress has been made before the April MOPC meeting. “There is a process in place, and I want it followed,” she said.
The SPC agreed to schedule another meeting within a matter of weeks to continue its discussion of RR 172 and review specific policy language from staff, but no date has yet been set.
The committee in October agreed to defer action on RR 172 pending alternative proposals from SPP. Staff returned last week with a straw proposal for zonal placement criteria for existing facilities. That plan limited the scope to integrating existing facilities with the zonal annual transmission revenue requirement (ATRR) costs under Schedule 9 of the RTO’s Tariff, or a current transmission owner’s purchase of existing facilities that would be included in its zonal ATRR.
The SPC agreed unanimously to codify SPP’s criteria for determining whether to put transmission facilities and the ATRR into an existing pricing zone or create a new one, but there was some disagreement on whether or not staff’s current criteria will be sufficient.
Those criteria include:
Whether the new TO’s ATRR is less than that of an existing zone with the smallest ATRR;
The extent to which a new TO’s facilities are embedded within a pre-existing zone;
The extent to which a new TO’s facilities are integrated with (including number of interconnections) an existing TO’s facilities; and
The extent to which the new TO’s facilities substantively increase the SPP footprint.
KCP&L said its proposal is designed to strike a balance between attracting new transmission-owning customers to SPP and eliminating the unnecessary and unfair potential for new members to shift costs to existing members by codifying SPP’s zonal selection criteria in the Tariff. The revision is intended to establish a bright line between the costs of legacy transmission and new facilities planned by SPP.
Buffington said its revisions to RR 172 provides a bidirectional approach to protect both new TOs and new and existing transmission customers from paying for facilities that were not jointly planned. Following the new TO’s integration into the RTO, all SPP-studied and approved projects would be allocated in accordance with its Tariff, she said.
KCP&L has been driven by SPP’s decision to put the City of Independence, Mo., into the utility’s transmission pricing zone, a move Buffington last year said “blindsided” the utility and led to a multimillion cost shift to its customers. The KCP&L zone has some of the lowest transmission costs among SPP’s 19 zones, thanks to the Kansas City area’s load.
“The crux of the problem for KCP&L is there’s a price impact to us when someone comes into our zone,” Buffington said. “We tried to put a bright line out there so people know what to expect going forward and so people can know what to expect when they become a member of SPP.”
“I don’t want to build walls to prohibit people from coming in,” American Electric Power’s Richard Ross said, “but I don’t want to do things that cause detriment to our existing customers.”
Several stakeholders have spoken out against the proposal’s hold-harmless provisions, in which new TOs would have their facility costs allocated to their load and current zonal TOs and customers would have the costs of their facilities allocated to their load. They assert this gets away from SPP’s concept of transmission providing value to the SPP system, not those who built it.
Brett Hooton, vice president of business development for South Central MCN, called RR 172’s hold-harmless provisions “anti-competitive, unduly discriminatory and a logistical nightmare.” He also said the proposal’s “unintended consequences” have yet to be vetted and discussed.
“This impacts all segments of SPP membership,” Hooton said. “The focus should be on areas with broad stakeholder agreement [zonal placement criteria and informational requirements], rather than forging ahead with a controversial hold-harmless proposal that is also contrary to the principle that networked transmission can provide value to the Bulk Electric System.”
SPC Agrees to Reconstitute Congestion Hedging Group
The SPC also agreed to reconstitute the Congestion Hedging Task Force to address the large amounts of wind energy and other renewables that could come online in the future. SPP has 21,535 MW in its interconnection queue, on top of 15,728 of installed wind energy.
The CHTF would report to the MOPC. The committee’s chair, Paul Malone of the Nebraska Public Power District, said he would work with staff to move the task force forward.
DALLAS — SPP’s Markets and Operations Policy Committee last week overwhelmingly approved a Tariff revision request that would replace the old capacity margin terminology with a 12% planning reserve margin requirement, the RTO’s first such change since 1998.
The Regional Tariff Working Group’s (RTWG) RR 187 also incorporates previously approved policies that identify who is responsible for resource adequacy, the resource adequacy requirement and how and when the requirement can be and should be met.
The Capacity Margin Task Force, which spent two years developing the policies, expects that lowering the planning reserve margin (PRM) from 13.6% will reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See SPP to Cut Planning Reserve to 12%, Reduce Capacity Needs by 900 MW.)
The policies will become effective this summer pending final approval from the SPP Regional State Committee and the Board of Directors/Members Committee next week and a filing at FERC, with the exception of the resource adequacy assurance policy, or the enforcement mechanism. That policy requires entities short on their PRMs to make payments to entities with excess capacity, based on forecast information.
The RTWG suggested using 2017 as a trial run.
A deliverability study is currently being prepared for the summer. It gives load-responsible entities another option to use “deliverable” capacity on a short-term basis for meeting their planning requirements, instead of requiring firm transmission service. Firm service is still required for load and available for PRM capacity.
“This is a super set of work by the task force and the RTWG, and we need to move forward with it,” American Electric Power’s Richard Ross said. “If somebody needs to fix something, they can prepare a revision request and send it through the [stakeholder] process.”
Tenaska cast the lone dissenting vote against the measure, while nine other members abstained. Eight members abstained when the revision was voted out of the RTWG.
The policies were established by the Capacity Margin Task Force, which then turned the work of drafting a revision request over to the RTWG. The working group estimated that it spent 93 meeting hours on its work, with 20 to 25 attendees at every meeting.
Regional Cost Allocation Remedies Rejected
Ross said he would use the same stakeholder process to appeal the MOPC’s rejection of a business practice that documents the potential Regional Cost Allocation Review (RCAR) remedies and clarifies the process to be used when implementing a remedy.
The measure failed when it received only 58.5% favorable votes, against 17 opposing votes and 12 abstentions.
Ross said he would take his appeal to the board next week.
“I’m comfortable where it is, personally, for my company,” Ross told the SPP Strategic Planning Committee on Thursday. “But we shouldn’t kill it at that stage without other [Regional State Committee] members and the directors having a chance to weigh in on it.”
Originally written as a Tariff revision and rejected by FERC over a lack of detail, RR 155 outlines the processes for analyzing, approving and implementing potential remedies for transmission-pricing zones that fall below the RCAR process’s approved threshold.
Several working groups passed the revision request, but with opposition. Some stakeholders felt the practice was “deficient” in how remedies would be implemented, Ross said. The remedies include accelerating planned upgrades, zonal transfers to offset costs or a lack of benefits to a zone, and changing cost-allocation percentages.
“The major concern was if it’s put in the Tariff, it would simply be implemented without an ability to object,” Ross said. “Putting it in a business practice should not take away the rights to object at FERC.”
“Turning it into a business practice remains our major opposition to this,” said Southwestern Public Service’s Bill Grant. “We protested this at FERC. We don’t think it’s needed. We would prefer going through the regular planning process and if there’s a solution there, to go forward with it.”
Speaking for the city of Springfield, Mo., which has been hampered by a low benefit-to-cost ratio in its zone, Jeff Knottek said he would support the measure.
“This language has been around for a number of years,” said Knottek, the city’s director of transmission planning and compliance. “We’re putting our trust in the process and hopefully we’ll get some relief with the transmission-expansion process.”
Variable Demand Curve Approved
The MOPC endorsed the SPP Market Working Group’s (MWG) revision request to use a variable demand curve that moves SPP toward “a more robust valuation of regulation and operating reserve” and more accurately addresses and values operating and energy shortages during scarcity events.
Ross, the MWG’s chair, said RR 198 would mitigate stakeholder concerns related to FERC Order 825, which established settlement interval and shortage-pricing requirements for organized markets.
Golden Spread Electric Cooperative’s Mike Wise cast the lone opposing vote, once again expressing his concerns over SPP’s use of reliability unit commitment to avoid scarcity pricing situations. Shell Energy abstained. (See “RUC, Shortage Pricing Practices Challenged,” SPP Board of Directors/Members Committee Briefs.)
“It’s a step in the right direction, but it’s not far enough,” Wise said. “SPP operations is mitigating all of this anyway. The inappropriate use of RUCing is destroying shortage pricing and pricing around intervals, which isn’t allowing the correct market signals.”
Responding to Wise, Ross said the MWG had listened to Golden Spread’s concerns and those of others, and changed both the size and number of steps in the process. “It’s best we move forward at this point,” he said.
SPP Stakeholders pulled a compliance-driven revision request from the consent agenda before unanimously passing the measure.
RR 195 simplifies the process of SPP’s “data specification” document required by NERC Reliability Standards IRO-010-2 and TOP-003-3 and makes basic formatting changes to the RTO’s operating criteria document.
SPP’s Casey Cathey requested the revision be approved in order to begin making the formatting changes. He said staff’s intention is to come back to the MOPC in April for final approval of the document.
The nine other revision requests on the MOPC’s consent agenda, which passed unanimously, included:
BPWG-RR122: Clarifies how the Tariff’s re-dispatch costs are determined and settled through the Integrated Marketplace, deletes obsolete language and clarifies long-term congestion rights for service subject to re-dispatch, and updates the business practices to reflect current practices.
ORWG-RR134: Clarifies previously ambiguous operating criteria language for the initial submission and subsequent updates of unit de-rate information in SPP’s control room software system.
BPWG-RR143: Retires a business practice that managed congestion through the re-dispatch of firm service, which became obsolete with the Integrated Marketplace.
MWG-RR190: Corrects SPP’s definition of residual transmission system capability by adding a missing variable in the protocols and clarifies that previous awards are considered in annual and monthly FTR allocations and auctions.
MWG-RR191: Clarifies that there should not be a requirement to reprice the day-ahead and/or real-time markets for every data input/software error.
MWG-RR192: Removes the Violation Relaxation Limits (VRL) report’s quarterly reporting requirement, which is covered in greater detail through other means, such as monthly reports to the Market Working Group, the Market Monitoring Unit’s annual State of the Market report and the Operations Annual VRL report.
BPWG-RR194: Aligns network integration transmission service practices with the new OASIS functionality as of March 1, as required by FERC.
RTWG-RR197: Completes the MMU’s annual review of frequently constrained areas by updating the list of constraints and resources.
MWG-RR199: Quarterly settlement clean-up clarifying how some of the calculations work and allowing market participants to better shadow the calculations.
The consent agenda also included several annual charter changes for some stakeholder groups. The committee pulled a request to make the Competitive Transmission Process Task Force — charged with improving SPP’s FERC Order 1000 processes — a standing task force. MOPC Chair Paul Malone, with the Nebraska Power Public District, said he believed task forces should have a time limit and be folded into a working group should there still be a need for their work.
After a brief discussion, Grant, the group’s chair, agreed to a two-year extension for the task force.
“Hopefully, once we’ve gone through one or two [Order 1000] processes, we’ll have a good process,” he said. “We’ve only had one [Order 1000] process, and until we have a couple more, don’t be surprised if we don’t ask to be extended for another couple of years.”
DALLAS — SPP stakeholders last week endorsed $201.5 million in transmission projects as part of the RTO’s Integrated Transmission Planning process, despite objections from several entities.
The ITP’s final 2017 10-Year Assessment recommended 14 projects in the southern part of SPP’s footprint, clustered in the Texas-Oklahoma Panhandle and along its eastern seam. Staff said the projects have an annual production cost benefit of $59 million and will solve long-standing congestion issues in West Texas.
Bill Grant, director of strategic planning for Southwestern Public Service, pushed back against the Transmission and Economic Studies working groups’ recommendation to the Markets and Operations Policy Committee, saying a 90-mile, 345-kV line in SPS’s service territory is “the right project but the wrong time.”
The proposed $144 million project would run southwest of Amarillo to SPS’s Tolk Generating Station near Muleshoe. Tolk consists of two 350-MW coal-fired units that date back to the early 1980s. SPS is currently evaluating whether to keep the plant operating.
“We think it’s a good project, but it’s not a good economic project at this time,” Grant told RTO Insider. “We think it’s best as a long-term project. If we do shut the plant down, restudying the project makes sense.”
Grant said SPS will be making some “major resource decisions” over the next few years. He said one of his company’s customers will begin buying power from one of its own affiliates, an unnamed SPP member, leaving SPS in a “resource flux.” Grant said he expects the resource plan to “clarify the need for this line in time.”
Tolk was one of seven Texas coal plants targeted by EPA for affecting air quality in the Big Bend and Guadalupe Mountains national parks along the Mexican border. The agency in November withdrew a requirement that the plants reduce their emissions, but Tolk is still facing potential future water-supply shortages.
“The concern we have is the removal of [the] regional haze [rule] changes the outlook,” Grant said. “I’m not questioning the analysis, but I am questioning the timing of the recommendation, because there’s so much unknown at this time.”
The company sees a long-term need for a 345-kV line in that area but would “feel better” about a decision in the future, he said.
SPP staff said the project would ease congestion in the corridor but could also avoid potential costs of up to $120 million from incremental upgrades in future studies. Staff also said the Potter-Tolk line improves voltage stability limits in SPS’s south load pocket and would ease a generation interconnection queue filled with wind projects.
“There is a significant price difference between resources in the southern end and SPS resources in the north,” said Antoine Lucas, SPP’s director of transmission planning. “Cheaper energy is looking to flow south, but a lack of transmission is causing a constraint and driving costs up in the SPS zone.”
Grant cast one of seven opposing votes against the recommendation. Eight other members abstained.
“I’m just trying to caution [everyone],” Grant said. “I don’t want to go through another Walkemeyer, but that may be exactly where we’re headed.”
Grant was referring to SPP’s first competitive project under FERC Order 1000, which was awarded to the incumbent transmission owner but then pulled when changing load projections rendered the project moot. SPP staff will determine whether any of the 14 projects will be deemed competitive projects. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)
The Potter-Tolk line was one of two projects staff identified through an “alternative project analysis” to evaluate needs in support of SPP initiatives along the seams or solving congestion and operational problems.
That analysis also recommended a 345/161-kV transformer and 161-kV line upgrade in southwestern Missouri near Springfield. The line connects to an Associated Electric Cooperative Inc. substation in Morgan and could qualify as a seams project pending negotiations with AECI. (See “SPP-AECI Joint Study Recommends Two Projects,” SPP Seams Steering Committee Briefs.)
SPP staff also performed additional analysis to ensure that transmission model updates and the 2016 near-term projects were included in its recommendations.
The 2017 ITP10 considered three futures: regional and state approaches to carbon reductions as a result of the now-endangered Clean Power Plan, and a business-as-usual reference case.
Supplemental Analysis Incorporated into 2017 ITPNT
The MOPC unanimously endorsed the TWG’s supplemental analysis incorporating newly issued and withdrawn notices-to-construct (NTC) from the 2016 ITP Near-Term Assessment into the 2017 ITPNT. The additional analysis helped better inform the ITPNT decisions because the NTCs and withdrawals occurred after the 2017 ITP10 models had been completed.
Lucas said the supplemental analysis was done to help bridge the gap between the ITP’s new and old processes. A final near-term assessment will be conducted for 2018.
MOPC Chair Paul Malone asked Lucas whether SPP also analyzes the transmission systems of new members coming into the RTO.
“We look at the existing systems based on SPP criteria and ensure the necessary upgrades have been completed before they roll into the network,” Lucas said.
As part of its analysis, staff evaluated 420 detailed project proposals — down “significantly” from years past, Lucas said — and made 131 model corrections.
A draft 2017 ITPNT portfolio was issued Jan. 6. Transmission owners and interested competitive developers will have until Feb. 3 to provide study cost estimates to SPP. An updated project portfolio will be shared during a Feb. 23 planning summit, and a draft report and recommendations will be made for the April MOPC and Board of Directors meetings.
MOPC Approves Change to Renewables Modeling
The MOPC also endorsed a revision to the Transmission Process Improvement Task Force’s (TPITF) white paper that the committee approved last July. The TPITF has been charged with combining SPP’s various planning efforts into one annual cycle, set to begin in 2018.
In recommending a common planning model, the task force has first suggested modeling renewable facilities with firm service at their highest summer output over a three-year period, with off-peak and light load modeled at 100% of firm service.
The new language recommends those resources with firm service “be modeled in the summer peak base scenario model at each facility’s latest five-year average for the SPP coincident summer peak, not to exceed each facility’s firm service.” Non-firm service will be modeled at zero.
The measure passed with four abstentions.
Brian Gedrich, the group’s chair and executive director of development for NextEra Energy Transmission, said the change was necessary because SPP’s wind output has been approaching 100% firm transmission-service levels during summer peak conditions.
However, several MOPC members expressed their concern with their inability to use SPP’s financial hedging instruments to pay for congestion costs.
“We build to the specifics of firm transmission … but [financial transmission rights] are not happening. We have an obligation to manage that,” Grant said. “This proposal is a compromise — a good compromise — but our concern is not being financially hedged against projects where we’ve paid for an upgrade, and then [do] not get the hedge.”
“This impacts our customers,” said Oklahoma Gas & Electric’s Greg McAuley. “They’ve had to pay for firm service, and now they’re paying congestion charges and new transmission charges. As we’ve discussed here, we really don’t have a hedge. All this planning, yet customers are paying for all this congestion. We’re asking ourselves, how did we end up like this?”
“We’re on a journey. This is a first step,” Gedrich said. “We may find over time this five-year average is too generous, it’s too optimistic.”
Nearly $2B in Projects Completed, Approved in 2016
SPP staff reported that members completed 78 upgrades totaling $939 million in 2016, while NTCs were issued for another 138 projects worth an additional $992 million.
ITP projects accounted for $1.4 billion of the total: $582.3 million for 44 completed projects and $859.5 million in NTCs.
The projects are part of SPP’s Transmission Expansion Plan. The MOPC unanimously endorsed staff’s recommendation that the board accept the 2017 STEP report as documenting completion of the Tariff’s Attachment O transmission planning process.
WESTBOROUGH, Mass. — Stakeholders have until Feb. 25 to comment in ISO-NE’s first implementation of the public policy requirements of FERC Order 1000.
The RTO is seeking stakeholder comments on federal, state and local statutes and regulations that could require new transmission.
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It is the first of an eight-step process outlined to the Planning Advisory Committee on Wednesday that could result in a transmission study and a competitive procurement. Comments should be emailed to PublicPolicy@iso-ne.com.
The New England States Committee on Electricity (NESCOE) has until April 1 to identify federal and state policy requirements. The RTO also can identify such requirements, along with local (municipal and county) requirements. Stakeholders’ responses to NESCOE will be due 15 days afterward.
If transmission needs are identified as a result of the process, the RTO will provide a draft scope for a public policy transmission study.
Current rules call for ISO-NE to provide a draft scope for the study by June 1, although it is seeking a Tariff change to push the date back to Sept. 1.
If the RTO decides to seek a transmission upgrade, it will invite qualified transmission project sponsors to submit proposals. After evaluating the proposals and PAC input, the RTO will narrow the “stage one” proposals to finalists eligible to submit more detailed “stage two” proposals, one of which will be selected as the preferred solution.
ISO-NE will monitor milestones until the project is completed and in service.
EPA’s Clean Power Plan, which was expected to result in transmission to connect renewable generation with load, is in jeopardy under the Trump administration. But New England states are expected to continue their efforts to decarbonize through power purchase agreements and potentially tighter emission caps under the Regional Greenhouse Gas Initiative — initiatives that could require transmission investments. (See New England to Charge Ahead on Clean Energy Makeover in 2017.)
FERC last week found that MISO and PJM have largely complied with commission directives issued in an order resolving a complaint by Northern Indiana Public Service Co. over interregional planning (EL13-88-001, et al.).
But the RTOs still face additional compliance filings to demonstrate better alignment of studies and cost allocation.
FERC last week accepted most of the joint operating agreement changes filed by the two RTOs and denied multiple requests for rehearing, including those from MISO and PJM themselves, as well as MISO transmission customers and NIPSCO.
At last week’s MISO-PJM Interregional Planning Stakeholder Advisory Committee meeting, transmission engineer Adam Solomon said the RTOs will conduct a legal review of the order and publicly post a summary and work plan next week.
Despite protests, FERC stood firm on its directive to scrap the previous triple benefit-to-cost ratio test, where projects had to meet a joint 1.25:1 ratio as well as the same calculation within each RTO.
The RTOs must now rely on a net value of the total benefits calculated for each RTO and are responsible for determining “whether the potential interregional economic transmission project meets its individual 1.25-to-1 benefit-to-cost threshold using each RTO’s share of the project’s total cost.”
Cost allocation is now based on each RTO’s pro rata share of the project’s total benefits. The commission rejected arguments by the RTOs and MISO transmission customers that an additional interregional benefit-to-cost analysis provides a “common” benefit metric to compare projects.
“Requiring MISO and PJM to each rely on their regional analysis to calculate both the benefits and costs of a potential interregional economic transmission project creates a more direct link between the costs allocated to each RTO and the benefits received,” FERC wrote.
FERC also found that a request by the RTOs to continue allocating costs of interregional transmission projects based on a joint economic benefit calculation still contained in the JOA would “create an untenable mismatch in the process for selecting an interregional economic transmission project and the process for allocating the costs of that project.”
MISO and PJM cannot “employ an additional interregional benefit-to-cost analysis that is calculated differently than either of their individual, regional benefit-to-cost analyses,” the commission said.
FERC upheld an earlier decision to replace MISO’s requirements that a qualifying project be at least 345 kV and meet a $5 million cost threshold with a 100-kV voltage minimum and no specified cost floor.
However, as pointed out by the Organization of MISO States, the commission realized it did not address MISO’s lack of Tariff language on cost allocation for sub-345 kV projects. Market efficiency projects in MISO are currently allocated 20% to all transmission customers and 80% to transmission customers in local resource zones. FERC gave the RTO 30 days to either include sub-345-kV interregional projects into the existing cost allocation or create a different allocation method.
Solomon said the order invalidates the need to create a joint model because FERC has accepted MISO and PJM filings that removed any references to such a model.
FERC last April directed the RTOs to explore the possibility of a joint model that uses identical assumptions and criteria to align their respective regional processes. In December, MISO staff said a joint model using identical assumptions would be difficult to accomplish. (See “MISO Says Common Assumption Set with PJM a No-Go,” MISO Planning Subcommittee Briefs.)
MISO will instead use regional metrics to independently quantify benefits and split project costs.
“It’s pretty clear what we need to do going forward,” Solomon said.
Not Applicable to MISO-SPP Seam
MISO members hoping that the NIPSCO order would be applied to the SPP seam will have to wait for a fresh docket. FERC said its NIPSCO directives “are limited to issues pertaining to the MISO-PJM seam.” The commission rejected ITC Holdings’ request that MISO also relax SPP interregional cost and voltage thresholds — still at $5 million and 345 kV — saying ITC brought no evidence forward to support the rule extension.
FERC accepted new JOA language that describes interconnection coordination procedures already in place in the RTOs’ governing documents, language stipulating that each RTO will monitor the other’s transmission system for potential impacts and include concerns in the system impact studies of the interconnection process. The RTOs will also exchange data at least twice each year to study the impact of the other’s interconnection requests on its own transmission system.
Coordinated System Plan Needs Work
However, FERC found MISO and PJM only “partially” complied with the commission’s directive to revise the JOA to describe how the RTOs will incorporate their respective transmission expansion planning processes into future coordinated system plan studies.
The commission directed the RTOs to submit another compliance filing detailing how the plans would be integrated and create “binding deadlines” for an annual review of issues and when to decide on whether they should embark on the studies. MISO and PJM had proposed an information exchange in the fourth quarter of each year that would lead to a joint review of regional issues the following January, but they did not provide specific deadlines.
FERC denied NIPSCO’s request that market-to-market payments be added to the JOA benefit calculation. The commission said the addition would double-count a portion of the congestion — an issue still under scrutiny in a separate complaint. (See PJM, MISO Go Quiet on Pseudo-Ties; Reach Interface Pricing Accord.) FERC also said market-to-market payments do not reduce production costs but are transfer payments between RTOs “that make the RTO that redispatched its system whole for the increased production costs that it experiences to allow the other RTO to exceed its firm flow entitlements.”
FERC also denied a request by a group of MISO generators that the RTOs better identify constraints and flowgates, saying it was not an issue raised in the original NIPSCO complaint since the complaint “made only incidental references to flowgates.”
Retirement Coordination Approved
In a separate order issued last week, FERC unconditionally accepted the MISO-PJM generator retirement coordination plan (ER16-1969-002) with little comment. The plan adds generator retirement study information-sharing and mutual evaluation rules to the RTOs’ JOA. (See MISO Outlines Retirement Coordination with PJM.)
2017 MEP Identification Underway
Ling Hua, MISO’s interregional economic transmission planning adviser, said MISO and PJM have begun work to identify interregional market efficiency projects. Both RTOs have opened issues submission windows that allow members to submit solution proposals until the end of February. From March to September, the RTOs will evaluate project proposals for year-end approval by their respective boards.
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The two RTOs have separately identified congested flowgates ripe for interregional efficiency projects, with MISO submitting 13 possible projects and PJM identifying four. The only potential project common to both lists is the Olive-Bosserman 138-kV project on the western Michigan-Indiana border in American Electric Power’s territory.
Solomon said he expects a learning curve this year in identifying interregional projects as RTO staff and stakeholders move to a new interregional process.
“We’ve kind of been stuck in between two interregional processes until yesterday,” Solomon said at the IPSAC meeting.
A day before the order issuance, at its Jan. 18 Planning Advisory Committee meeting, MISO reported that it considered all nine directives in the NIPSCO order completed as of Dec. 15.
FERC last week ordered American Electric Power and FirstEnergy subsidiary Allegheny Power to refund more than $7 million to ratepayers for the canceled Potomac-Appalachian Transmission Highline (PATH) project (ER09-1256; ER12-2708).
The ruling upheld most of the $10 million in refunds recommended in an initial ruling by Administrative Law Judge Philip C. Baten, backing the judge’s decision to deny recovery of $6.2 million in advertising, lobbying and “advocacy-building” costs. But the commission reversed Baten on his rejection of some legal costs and losses on the sale of properties the companies acquired for the project. (See FERC ALJ Rejects $10 Million in PATH Transmission Project Recovery.)
The commission also found that PATH’s base return on equity should be reduced from 10.4% to 8.11% and disallowed recovery of $1.1 million in expenses booked into a wrong account.
The companies have 60 days to submit revised information, including an updated Form 1 that recalculates costs of service and estimated refunds.
Approved in PJM’s 2007 Regional Transmission Expansion Plan, the $2.1 billion project would have run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md. PJM canceled the project in 2012 after determining it was not needed based on revised load forecasts.
The ruling was a victory for two PATH opponents from West Virginia who filed a pro se intervention challenging the companies’ recovery request for recovery of $121.5 million.
FERC Orders Investigation into Overcharging for Natural Gas Pipelines
The commission is investigating the rates charged by two natural gas pipelines, one of which delivers into the PJM footprint in Chicago (RP17-302 and RP17-303).
FERC believes Wyoming Interstate Co. and Natural Gas Pipeline Company of America, both Kinder Morgan subsidiaries, may have both been overcharging customers, based on reviews of their 2014 and 2015 FERC Form No. 2 annual reports.
FERC estimates Natural’s ROE for those calendar years to be 28.5% and 20.8%, respectively. Natural owns the Amarillo and Gulf Coast Lines, both of which terminate in the Chicago area.
The commission estimates WIC’s ROE for those calendar years to be 17.7% and 19%, respectively. WIC owns 850 miles of pipeline, including a mainline system between western Wyoming and northeast Colorado.
FERC says it’s concerned that both Natural’s and WIC’s level of earnings may exceed their actual cost of service, including a reasonable ROE. The commission ordered the companies to file full cost and revenue studies within 75 days.
ODEC Tariff Revisions Approved Subject to Compliance Filing
FERC last week approved a revised cost-of-service rate schedule that changes how Old Dominion Electric Cooperative collects demand costs from its 11 distribution cooperatives in Virginia, Delaware and Maryland.
The new formula replaces one that has been in place since 1992 that recovered demand costs based on each cooperative’s coincident peak (CP) usage. The new formula includes rates that ODEC said more accurately reflect market conditions and its costs under PJM’s methodology.
The commission affirmed the initial decision by ALJ H. Peter Young that found several portions of ODEC’s filing, including its four-year average “proxy rate” for PJM capacity costs and the 12 CP true-up mechanism for PJM capacity costs and third-party transmission costs, unjust and unreasonable.
It reversed the judge’s finding that ODEC’s proposed zonal averaging mechanism and the use of add-backs in 2014 were unjust and unreasonable.
The revisions were backdated to Jan. 1, 2014, and ODEC is required to make refunds and file a refund report (ER13-2483).
FERC Approves FE Companies’ Filings on Affiliate PPA Waiver
The commission last week approved tariff revisions filed by FirstEnergy Solutions and several affiliates to comply with a FERC order ruling that a power purchase agreement in which the company’s regulated utilities would buy energy from the company’s merchant generators would be subject to its affiliate abuse review (ER16-1807, et al.). FirstEnergy asked the Public Utilities Commission of Ohio to withdraw the PPA following the FERC ruling. (See FirstEnergy Foes Ask FERC to Step in Again in Ohio Dispute.)
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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.
