FERC last week denied requests for changes to Order 807, which granted a blanket waiver from Open Access Transmission Tariff requirements to owners and operators of generator tie lines (RM14-11-001).
The commission’s April order also allowed generators to reserve excess capacity on their tie lines, or “interconnection customer’s interconnection facilities (ICIF),” for the first five years of operation. (See Generator Tie Lines Exempted from OATT Rules.)
The commission denied a rehearing request from the National Rural Electric Cooperative Association (NRECA) and a second filed jointly by the American Public Power Association (APPA) and the Transmission Access Policy Study Group (TAPS).
Safe Harbor
NRECA asked the commission to reconsider its presumption that an ICIF owner has plans to use its capacity when the third-party requesting transmission service is a load-serving entity.
NRECA noted that renewable generating resources are often located in remote areas and require long tie lines to connect to the interstate grid. The group said it would be more efficient for an LSE to contract with an ICIF owner to counterflow power over the line rather than to build a new facility to serve its native load.
It said the tie line owner should have the burden of proving it has specific plans to use the excess capacity that would prevent it from providing LSEs access.
FERC said it disagreed with NRECA’s contention that the five-year safe harbor period “impinges upon the reasonable needs of LSEs.”
“Because of the case-specific nature of any request under sections 210 and 211 to use certain ICIF, we cannot … state exactly what evidence would be strong enough to overcome the rebuttable presumption during the safe harbor,” FERC added.
Open Access
FERC also rejected the allegation by APPA and TAPS that the rule grants tie line owners vertical market power over access to their facilities. The groups said FERC unfairly ruled that third parties would not be unduly burdened by pursuing transmission service under Federal Power Act sections 210 and 211.
The commission said its rule “does not foreclose access” to tie lines but sought to reduce unnecessary regulatory burdens for owners that may plan to use excess transmission capacity for future phases of generation construction.
“Without such reasonable assurance, there would be little incentive for a developer to shoulder the extra expense of ICIF sized larger than the initial phase of the project,” the commission said.
Clarification
The commission clarified that no commission proceeding is necessary for a blanket waiver to be revoked if the public utility acquires additional transmission facilities that are not ICIF or otherwise no longer qualifies for the exemption. FERC said the waiver would be automatically revoked and the owner would be required to file an OATT within 60 days.
FERC also clarified that non-public utility ICIF owners may also take advantage of the blanket waiver and safe harbor period.
“Although the determination in the final rule does not explicitly state that non-public utility ICIF owners may take advantage of the blanket waiver, this omission was unintentional,” the commission said. “The intent of the final rule was to make the package of reforms equally available to nonpublic utility ICIF owners.”
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
3. PJM Manuals (9:25-9:35)
Members will be asked to endorse the following manual change:
Manual 14B: PJM Region Transmission Planning Process. Establishes criteria for reliability studies focused on meeting winter peaks from Dec. 1 through Feb. 28. Includes assumptions for the input power flow models and parameters for the analytical studies to be performed. (See “Winter Study Criteria, Uplift Added to Planning Manual,” in PJM Planning Committee Briefs.)
4. TIER 1 COMPENSATION (9:35-9:55)
The committee will be asked to approve manual and Tariff language changing compensation of Tier 1 synchronized reserves. Under the new scheme, Tier 1 synchronized reserve resources will be obligated to respond in emergencies and subject to penalties if they can’t. It retains Tier 1’s ability to receive compensation outside of synch reserve events when the non-synch reserve market price is more than $0. Units could opt out of the performance obligation, but by doing so they would forfeit any credit they would have received outside of responding to an event. The changes will go before the MC on Nov. 19 and would be implemented no earlier than February. (See “Tier 1 Compensation Language Approved,” PJM Market Implementation Committee Briefs.)
5. REGULATION PERFORMANCE IMPACTS (9:55-10:10)
The committee will be asked to endorse revisions to Manual 11: Energy & Ancillary Services Markets Operations implementing changes to reduce over-procurement of RegD resources. The solution would move the benefits factor curve to the left so that it is at zero at 40%. A cap of 26.2% also would be implemented during identified excursion hours — hours when dispatch frequently moves the regulation signal manually. It also features tie-breaker logic to rank RegD self-schedules or zero-cost offers. (See “Solution, Task Force Proposed to Curtail RegD Resources,” in PJM Markets and Reliability Committee Briefs.)
6. REGULATION MARKET ISSUES SR. TASK FORCE (rmistf) (10:10-10:20)
Members will be asked to endorse a draft charter for the Regulation Market Issues Senior Task Force. The task force will be tasked with addressing modeling problems that are causing PJM’s regulation market to purchase too much RegD megawatts at times. (See agenda item 5 above.)
7. INCREMENTAL AUCTION TARIFF CLEAN UP (10:20-10:30)
A Tariff provision up for endorsement would allow PJM to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auctions for the 2016/17 and 2017/18 delivery years. (See “PJM Seeks Tariff Change to Release Excess Capacity,” in PJM Markets and Reliability Committee Briefs.)
8. 2015 IRM STUDY RESULTS (10:30-10:45)
The results of the 2015 installed reserve margin study will be presented for endorsement. It increases the IRM for delivery year 2016/17 to 16.4% from 15.5% in the 2014 study. IRMs also rose for 2017/18 and 2018/19. (See “IRM, FPR Rising; PJM Methodology Challenged,” PJM Planning Committee Briefs.)
9. GOVERNING DOCUMENTS ENHANCEMENT AND CLARIFICATION SUBCOMMITTEE (gdecs) (10:45-10:55)
The committee will be asked to approve a draft charter for the Governing Documents Enhancement and Clarification Subcommittee, which will be tasked with identifying, reviewing and resolving inconsistencies among PJM’s governing documents and manuals. It also will offer revisions to correct ambiguous or confusing language.
Members Committee
ENDORSEMENTS (1:25-2:00)
CONSUMER ADVOCATES OF PJM STATES (CAPS) (1:25-1:55)
Members will be asked to vote on a proposal to fund a $450,000 budget for the nonprofit Consumer Advocates for the PJM States through an assessment on electric customers. It would amount to about 0.8 cents annually for a residential customer using 12,000 kWh. (See Consumer Advocates’ Funding Request Sparks Sharp Words.)
ELECTIONS (1:55-2:00)
Members will be elected for the Nominating Committee for 2015-16. The sector representatives are:
Electric Distribution Sector: Lisa McAllister, American Municipal Power
End Use Customer Sector: Ruth Ann Price, Division of the Public Advocate of the State of Delaware
Generation Owner: Joe Kerecman, Calpine
Other Supplier Sector: Marji Philips, Direct Energy
Transmission Owner Sector: John Horstmann, Dayton Power & Light
FERC last week upheld its Nov. 28 order accepting PJM’s changes to its capacity auction demand curve and related parameters, denying rehearing requests by a broad group of interests (ER14-2940).
PJM said the changes to the variable resource requirement (VRR) curve and related pricing inputs, including the cost of new entry (CONE), were identified in the RTO’s triennial review as being necessary to meet evolving market conditions.
The new, more conservative curve results in the procurement of more capacity and carries an estimated 1% cost increase (about $216 million).
PJM uses the curve to gauge how much capacity it needs to meet the one-in-10-year loss-of-load standard. A lower-cost VRR curve identified by The Brattle Group, the independent consultant that conducted the study, would fail to meet the needs of a one-in-five-year event 13% of the time, PJM said.
In the November order, the commission agreed with PJM that the changes to the VRR curve were needed to ensure reliability “in light of evolving market conditions and anticipated supply shifts,” including the planned retirement of 26,000 MW of coal-fired generation. The order accepted the explanation of PJM’s expert witness, economist Paul M. Sotkiewicz, who argued that, due to the anticipated changes, PJM’s prior modeling assumptions were no longer appropriate.
A coalition comprised of the Maryland Public Service Commission, the New Jersey Board of Utilities and PJM load-serving entities challenged PJM’s assessment of evolving market conditions, saying that most of the coal retirements have already occurred and that the region has added 17,000 MW of natural gas-fired capacity in the last three years.
The commission rejected the challenge, saying that its acceptance of the new VRR curve “was not based on the specific timing of these retirements, but on the inability of PJM’s prior modeling construct to capture these evolving conditions and thus on the resulting need for a more conservative VRR curve.”
The PJM Power Providers Group (P3) and Public Service Enterprise Group disputed PJM’s use of an 8% cost of capital used in CONE calculations, saying it was too low because it relied on corporate-level data for publicly traded independent power producers and did not reflect riskier, project-level financing. (See PJM Generators Seek Support for Capital Boost.)
The commission said that in addition to IPP data, it also relied on market- and transaction-based cost of capital data.
“This evidence was verifiable and reflects the market’s required compensation for the specific, systemic operating risks attributable to merchant generation, and the willingness of borrowers to bear these risks,” the commission said.
Market participants in New York are concerned that their proprietary information might not be adequately protected as NYISO plans to bring the RTO’s reporting system for renewable energy generation into compliance with state law.
The New York State Energy Research and Development Authority (NYSERDA), which procures clean energy, was required by a 2012 law to develop the Generating Attribute Tracking System to ensure compliance with the state’s renewable portfolio standard.
Generators’ representatives raised concerns Wednesday when the NYISO Business Issues Committee discussed a proposed change in the ISO’s code of conduct that states the information would be confidential and that market participants will be notified of any requests for confidential data or any decision to disclose it.
The discussion came as New York Assemblyman James Brennan is petitioning the Public Service Commission to force disclosure of bidding information from power generators that they say is proprietary and threatens to disrupt the market if not protected. The PSC and the secretary of the state’s Department of Public Service last year dismissed a similar request under the state’s Freedom of Information Law. (See NYPSC Chair Zibelman Acknowledges Costs Concerns.)
Market participants fear that if the proprietary information from the traditional generators is disclosed, by either the PSC or by the courts following any legal action that the assemblyman may initiate, GATS information would be released as well.
“There’s a lot of concern about the release of information that everybody agrees is confidential,” said Howard Fromer, who represents PSEG Long Island.
NYISO would provide data on megawatts produced and consumed and on import and export transactions. No financial data on settlements and revenue would be included.
No trading is available in the self-contained New York renewable energy market, which officials said Gov. Andrew Cuomo wants to change. Renewable energy certificates (RECs) are traded in the neighboring jurisdictions of ISO-NE and PJM.
NYISO is negotiating an agreement with NYSERDA’s vendor, APX, which will keep data confidential except for identified purposes, NYISO said. APX runs several REC registries, including those in Michigan, North Carolina and New England.
Peter Keane, NYSERDA’s deputy general counsel, said that since the New York portfolio standard was set in 2004, only one request for private information has been made. That involved a dispute over lease payments between a property owner and the owner of wind turbines at the owner’s site. The dispute was resolved before a decision had to be made on the release of the information.
The proposed code of conduct change moves to the ISO’s Management Committee at the end of the month. GATS is expected to be publicly available in March.
The PJM Board of Managers last week directed staff to seek FERC approval for a package of rule changes related to financial transmission rights (FTRs) and auction revenue rights (ARRs) after the Members Committee nearly reached consensus on the proposal.
“In making this decision, the board took into account the near two-thirds consensus achieved through the stakeholder process,” PJM said in a release. “It also considered the need to address the equity issues associated with the current rules by which the transmission system is planned to ensure future feasibility of Stage 1A ARRs and revenue inadequacy is allocated among holders of both positively and negatively valued FTRs.”
The RTO said the filing would be made shortly, and FERC would be asked to take action by the end of the year to provide adequate notice prior to the 2016 annual ARR allocation and FTR auction.
The rule changes, proposed by Old Dominion Electric Cooperative, would redesign the FTR and ARR processes, combining recommendations from PJM and the Independent Market Monitor.
In August, the MC fell just short of a sector-weighted consensus on the proposal, which was backed by most members of the End Use Customer, Transmission Owner and Electric Distributor sectors but won support of only one-third of the Generation Owner and Other Supplier sectors. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)
The plan contains three elements.
One, drawn from a PJM staff proposal regarding the Stage 1A 10-year process, escalates the current ARR results using a zonal load forecast growth rate of +1.5%. The other two elements change the method of reporting the monthly payout ratio so that any negative target allocations are included as revenue, slightly increasing the reported payout ratio. It also treats each FTR individually, eliminating the netting of positively and negatively valued FTR positions in a portfolio prior to determining positively valued FTR payout ratios.
LITTLE ROCK, Ark. — Lubbock Power & Light’s recent announcement it was planning to take 400 MW of SPP load and join ERCOT hung heavy over the Strategic Planning Committee last week as it tried to determine what to do next.
Golden Spread Electric Cooperative’s Mike Wise, the SPC chair, teed up the issue by asking whether SPP staff should conduct a transmission study of the area to determine whether LP&L’s departure would result in stranded investment.
“Transmission is built for and paid for by everybody,” Wise said. “Will there be transmission infrastructure out there that wouldn’t be needed if LP&L leaves?”
“I can tell you no facilities were built just for Lubbock,” said Bill Grant of Xcel Energy, which currently provides all of the city’s energy (forecast to be 626 MW in 2019) through its Southwestern Public Service subsidiary.
Effective June 1, 2019, when LP&L will also begin receiving power as a member of ERCOT, Xcel will provide only 170 MW of Lubbock’s needs.
“What led to this, and what can we do about it? Will this be the first time or the last time it happens?” Grant asked.
SPP Director Harry Skilton echoed Grant, expressing a need to “understand [LP&L’s] motivation and whether we should be doing something to alleviate whatever incentive they had for moving.”
“Prices in the ERCOT area are lower than SPP’s. We can debate whether that’s temporary or not,” said Carl Monroe, SPP’s executive vice president and COO. “The second issue is we have a capacity-margin requirement, and ERCOT doesn’t.”
“Load will come and go. Businesses move from one location to another,” said Dogwood Energy’s Rob Janssen. “Let’s face it … ERCOT built transmission lines in West Texas that overlap with SPP’s, so some customers in the area have a choice as to which system to be on.”
Monroe said SPP has no withdrawal fees to discourage load from leaving the RTO. “The only withdrawal provisions we have today are for withdrawn transmission, not load.”
SPP Vice President of Engineering Lanny Nickell said SPP could run studies of the areas. He also said SPS, which has owned the transmission interconnection with LP&L since 1983, could also request re-evaluations of notifications-to-construct to determine whether planned projects are still needed.
Asked whether any projects with NTCs in the area might be affected by the withdrawal of LP&L’s load, Nickell said he “was not aware of any projects directly impacted by Lubbock leaving.”
Grant said Xcel has identified a couple of impacts on its radar screen, and it will “take a closer look when the projects get close to breaking ground.” But he cautioned that the committee might be getting ahead of itself, pointing out LP&L has only announced its intent to join ERCOT and that the Texas grid still must conduct a feasibility study.
“We’ll know when the studies are done … we’ll know way before June ’18,” he said, referring to LP&L and ERCOT’s final decision date. “We’ll know in time what we need to reflect in our own models.”
In the meantime, SPS has filed a Freedom of Information Act request to obtain LP&L’s feasibility study, Grant said.
“We have no idea what numbers they came up with, or how they came up with the numbers, or whether they’re feasible,” he said.
The New York Public Service Commission on Thursday temporarily lifted caps on the amount of net-metered solar energy that can be permitted on a utility system. The move was prompted by a July petition from Orange and Rockland Utilities seeking to suspend its net-metered installations because it had applications for interconnections that exceeded the limit it can accommodate under current state rules.
While the petition came from ORU, the commission ruled that all six investor-owned utilities in New York must file tariff revisions to the rules governing their net-metering caps by Oct. 30, which will become effective Nov. 6.
Under the state’s 6% cap, ORU said it would reach its 62-MW limit in the “near future” and should immediately be allowed to suspend interconnections at that time.
The commission, however, rejected ORU’s proposal for a “buy-all, sell-all” solution whereby a distributed-generation customer would sell all its generation output at a wholesale rate and purchase all the electricity it needs at the retail rate.
The PSC said the ceiling would float upward to accommodate all new applications until the commission can answer a key question: How much are distributed energy resources worth? That answer is expected by the end of next year, under New York’s Reforming the Energy Vision initiative (15-E-0407).
“Rather than engaging in another effort to arrive at the proper level of the ceiling that would anticipate perfect coordination with the implementation of REV, the ceilings shall be allowed to float in the interim until the calculation … affecting valuation of DER is decided,” the commission wrote. “That is, utilities shall accept all interconnection applications and continue to interconnect net metered generation without measuring the DG capacity against an artificially set ceiling level.”
The order said state law gave the commission discretion to adjust the caps in the current scenario. It also said momentum to attain the state’s clean energy goals need not be interrupted now. “The pace of development should be set by the NY-Sun program and other policies for promoting net metered generation, not by the level of the ceilings,” the order said. NY-Sun is Gov. Andrew Cuomo’s effort to spend $1 billion by 2023 to install 3 GW of solar generation.
Much of the commission’s discussion centered on whether lifting the cap may create a “gold rush” for residents who want to install rooftop solar.
To Commissioner Diane Burman, who opposed the move, the interim approach will entice potential customers to rush into the interconnection queue to reserve a place and be grandfathered into the system at the time the PSC determines what the cap ultimately should be.
“I don’t see what we’re doing today as helpful over the long term,” she said.
Commission Chair Audrey Zibelman said setting a higher hard cap now would have a similar negative effect, with residents hurrying to reserve a place in the queue before they are cut off when a utility’s limit is reached, creating a stop-and-go scenario for the industry.
“We have a burgeoning solar industry, and we must not allow the caps to become a barrier,” she said.
This is the second time in less than a year the commission has had to address the cap when a utility approached its limit. Last December the commission doubled the statewide cap from 3% to 6% when environmentalists and Central Hudson Gas & Electric petitioned regulators for an increase. (See New York Doubles Solar Net Metering Cap to 6%.)
MISO’s latest Order 1000 compliance filing — which revises the developer selection process and outlines a pro forma selected developer agreement (SDA) — has drawn criticism from developers and transmission owners seeking additional changes (ER15-2657).
MISO’s proposed Tariff changes, filed Sept. 16, include relaxing deadlines and participation requirements for the annual transmission developer qualification process to allow for “broader participation” in the competitive developer qualification and selection model. MISO prequalified 35 developers to bid on competitive transmission projects in 2014. This year, the RTO added 13 more developers.
Transource Energy, however, said that the changes to the selection process unreasonably grant MISO too much authority in transmission projects and their cost. The company said that under the revisions, MISO is allowed to unilaterally terminate developers’ SDAs and force them to bear the costs. Transource also accused the RTO of ignoring its feedback in the stakeholder process.
Similarly, Xcel Energy said that some of the changes “inappropriately expand the role of MISO.” For example, the company said, selected developers would be required to self-report any “potential violations” of federal or state law to MISO.
In a joint filing, International Transmission Co., Michigan Electric Transmission and ITC Midwest took issue with the requirement that developers submit projected revenue requirement information. This provision “could negatively impact an existing transmission owner’s ability to submit competitive bids because two developers with the same estimated costs will calculate different revenue requirements if one developer already has [a] plant in service in MISO.”
Little Rock-based Republic Transmission accused MISO of overlooking its duty to protect ratepayers in the interest of saving money for the RTO. The company said MISO ignored suggestions from stakeholders and provisions designed to cap or minimize the costs of projects in CAISO and PJM.
“MISO does not propose to ‘improve’ its developer selection process in a manner that protects MISO ratepayers by shifting its current minimal selection focus on cost to more heavily rely on the cost components of bids,” asserted Republic Transmission in its protest filing. “Much work remains in MISO for ratepayers to benefit from Order No. 1000.”
MISO seeks to implement the changes by Nov. 16, with the aim of posting its first competitive transmission project for bidding in January. Technically, MISO’s compliance obligations to meet Order 1000 ended on March 31, but the RTO elected to keep working with transmission owners and non-incumbent developers to refine Tariff language and develop a binding selected developer agreement.
“These enhancements and clarifications reflect MISO’s experience and discussions with stakeholders during the first year of the prequalification process as well as lessons learned from observing the processes of other RTOs,” MISO said.
MISO’s competitive transmission developer selection process has been the subject of four rounds of FERC compliance filings and, according to the RTO, 16 months of consultation with stakeholders. The RTO said it will make another compliance filing next month addressing other areas needing improvement.
LITTLE ROCK, Ark. — As expected, SPP staff brought a recommendation to the Markets and Operations Policy Committee for approval of one of three interregional projects coming out of the SPP-MISO coordinated system plan study.
“MISO has its own processes,” said David Kelley, SPP’s director of interregional relations. “So far, their analysis indicates they are not willing to move forward with any of the three.”
Staff recommended approval of the South Shreveport-Wallace Lake rebuild, an 11-mile 138-kV project addressing area congestion. SPP estimates the project has a cost of $18.5 million, of which it would fund 20% ($3.7 million), and a benefit-cost ratio of 11.86 — far exceeding the 1.0 threshold.
Kelley said three of the South Shreveport-Wallace Lake futures indicate the project yields “significant benefits,” 80% of which would go to MISO. He said the RTOs’ use the same B/C calculations, “but we use more benefit metrics to determine a project’s value than MISO does.”
SPP does not recommend approving the other two interregional projects evaluated as part of a regional review: the Alto-Swartz series reactor and the Elm Creek-NSUB 345-kV transmission line. Both could be reevaluated in a future regional or interregional study.
With MOPC members wondering how to proceed, Kelley said, “MISO still has [to conduct] a lot of robust discussions with stakeholders over its cost allocations … things we’ve already done.”
MISO has accepted SPP’s invitation to participate in a Thursday debrief of the study process, but Kelley sounded skeptical of a positive result. “Unless there are fundamental changes done with MISO’s stakeholder process, I don’t think [the South Shreveport-Wallace Lake rebuild] will be approved,” he said.
SPP Board of Directors Chair Jim Eckelberger said he would talk with his MISO counterpart, Mike Curran, to “see if the project can get legs and move forward.”
The two RTOs face a December deadline to come to agreement on the interregional projects, though the current six-month window can be extended. MISO’s Board of Directors meets Dec. 10 and will take up staff’s recommendation on the interregional projects at that time.
13 Revision Requests Approved
The MOPC approved 13 revision requests from the Market Working Group totaling about $11.5 million.
A request establishing a new incremental long-term congestion rights (ILTCR) allocation process passed the MOPC with 13 abstentions after clearing the MWG with one positive vote and 17 abstentions.
But, as MWG Chair Richard Ross of American Electric Power said, “We knew we had to move it forward. We have to do this.”
The revision was necessitated by FERC’s 2014 order finding fault with SPP’s interpretation of long-term congestion rights. The commission rejected multiple rehearing requests in July. (See FERC Rejects Rehearing on SPP Congestion Rights.)
The MWG’s new process will result in awards to market participants with ILTCRs when a transmission upgrade goes into service, instead of waiting until the annual LTCR allocation. Rights awarded in the initial allocation cannot be renewed; participants with candidate ILTCRs will be eligible to nominate in the same round of the next annual LTCR allocation as load-serving entity LTCRs.
A second revision request concerned the enhanced combined-cycle project, which was suspended last year to allow for a more thorough cost-benefit study and the Integrated System’s incorporation. The change is intended to ensure the ECC team implements the market-clearing engine’s logic on time and on budget by limiting combined-cycle configurations and offline supplemental offers.
The revision request received the SPP Market Monitoring Unit’s blessing and passed unanimously.
Other approved revision requests dealt with quick-start resource improvements, ramp-scarcity pricing and violation relaxation limits.
11 Transmission Projects Withdrawn in Quarterly Review
The MOPC unanimously approved staff’s recommendation to withdraw 11 notifications to construct (NTCs) as part of SPP’s quarterly review of transmission-expansion projects.
Two of those projects were among seven with out-of-bandwidth cost variances that had their NTCs suspended during the July MOPC meeting until further studies could be conducted. (See “Out-of-Bandwidth Projects Ordered Re-Evaluated,” in SPP BoD/Members Committee Briefs.)
Antoine Lucas, SPP’s planning director, said the additional analysis revealed there was not a reliability need for the Martin-Pantex North-Pantex South-Highland Park 115-kV rebuild (Southwestern Public Service) or the Labette-Neosho SES 69-kV rebuild (Westar). Lucas said a third re-studied project — the Iatan-Stranger Creek 345-kV voltage conversion (Westar/KCP&L Greater Missouri Operations) — should have its NTC reinstated, while the other four out-of-bandwidth projects require further analysis, as a need remains.
“We don’t want to continue to defer the [Iatan-Stranger Creek] project but reinstate the NTC because it’s still beneficial to the region,” Lucas said, referring to its inclusion as an economic project in the 2015 Integrated Transmission Planning 10-year assessment (ITP10).
The other nine withdrawn NTCs came from SPP’s re-evaluation of 24 projects at the transmission owners’ request. Lucas said staff did not have time to evaluate all of the projects; the 15 remaining projects require further analysis.
MOPC Approves ITP10 Scope
Members also approved a recommendation by SPP’s transmission and economic studies working groups to approve the 2017 ITP10 scope, following a discussion on the use of reliability standards.
Ross noted the scope didn’t take into account the North American Electric Reliability Corp.’s coming transmission planning (TPL) standards. “To do the analysis and not be aware of what’s coming would be a mistake,” he said.
Midwest Energy’s Bill Dowling urged incorporating the new TPL-001-4 standards, which take effect Jan. 1.
The committee approved the planning study’s scope with four ‘nay’ votes after inserting language requiring compliance with the TPL standards.
The study will consider three futures: a regional Clean Power Plan (CPP) solution, a state-level CPP solution and a solution assuming the CPP is not implemented. Each future also assumes competitive wind and solar development, high availability of natural gas due to fracking, expected load growth and inclusion of all statutory and regulatory renewable mandates.
The 2020 and 2025 models will include implementation of the Environmental Protection Agency’s interim CPP goals that begin in 2022 and 2025-2027 goals, respectively.
Work Continues on Transmission Planning Improvements
Completion of work to improve SPP’s transmission planning processes may slip from January to April, but the result will be a better product, NextEra Energy’s Brian Gedrich told the MOPC.
Gedrich said the Transmission Planning Improvement Task Force, which he chairs, needs more time despite adding meetings and conference calls to its schedule. “When I saw the only day we could double up on in December was the 25th, I decided maybe we needed more time,” Gedrich told the committee.
The task force faces a January deadline to recommend changes to create more efficient planning processes. Gedrich said the group has already unanimously agreed upon an 18-month planning cycle, a common planning model and a standardized scope. It has also agreed upon a comprehensive planning process that combines the near-term, 10-year and reliability processes into a 10-year study looking at reliability, economic, policy and compliance needs. The current 20-year assessment would be separated from the annual planning cycle.
“We’ve come a long way and had a lot of great ideas,” Gedrich said. “I think it will be fine if we let it slip a little and make sure we get this right.”
Eckelberger supported the delay when Gedrich delivered the same message to the Strategic Planning Committee.
“I’m not speaking for the board, but if you need a little more time and you get it really right, let’s do that,” he said.
The task force envisions overlapping 18-month planning cycles that would produce an annual assessment, with the ensuing cycle’s modeling development beginning as soon as the previous one was completed. By using only three futures, Gedrich said, incremental, easier-to-manage changes would be made from one cycle to the next.
The task force will work with other working groups to confirm the feasibility of its recommendations and to identify any other potential issues and solutions. Gedrich said the earliest the new planning cycle could be in place would be April 2019.
Z2 Crediting Task Force Remains on Track
Stakeholders and staff working on the beleaguered Z2 credit project are still targeting January’s MOPC and board meetings as to when transmission owners will learn the amount of bills that could be as much as 10 years old. (See SPP Z2 Project Team Still Grappling with Problem’s Size.)
The project team is working to create software that would properly credit and bill transmission customers for system upgrades under Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.
“It would be helpful to see a number at some point,” said ITC Holdings’ Marguerite Wagner. “We know the historic stuff. We know how much has been paid by interconnection customers, but interest is accruing on this.”
Dennis Reed, director of FERC compliance for Westar Energy and chair of the Regional Tariff Working Group, estimated $750 million for creditable upgrades, with up to $90 million in transmission customer upgrades and the remainder from sponsored upgrades. He has said previously the Z2 team can’t produce an accurate number until the software is completed.
“We’re not going to be anywhere close to the final numbers, the real size, who’s owed and who owes until the first of the year,” Reed said. “That’s the only time I’ll be comfortable with saying how big the breadbox is.”
Software is being developed in three different modules (functionality, base calculations and settlement calculations) to help accelerate the process. At the same time, SPP staff has been reviewing previous aggregate transmission service studies dating back to 2005, developing a list of project sponsors and verifying final upgrade costs if the project is still in service.
The team expects to complete historic calculations and develop payment options by April 2016.
Capacity Margin Task Force
Stakeholders working on a task force updating SPP’s capacity margin requirements and methodology said last week its preliminary work indicates the RTO can reduce its planning reserve margin from 13.6% to about 10%.
“But we want to vet that with other stakeholders,” said Mid-Kansas Electric’s Tom Hestermann, who leads the group. “The last thing we want to do is recommend a reduction in planning reserves, and then several years later, have to re-do that.”
Hestermann said the task force is focused on bringing more value to the membership from its investment in transmission infrastructure and to provide a way for entities to meet shortages on a short-term basis. He said a preliminary loss-of-load expectation reserve margin study using existing models shows generation is available, “based on the robust transmission system we have.”
The task force has three white papers in various forms of completion, including one on deliverability and a second on load-responsible entities (accounting for the fact that not all SPP load is associated with load-serving members).
The third concerns a planning-reserve assurance policy. “We thought enforcement sounded kind of draconian,” Hestermann explained.
The team has also suggested a half-day workshop before the January MOPC meeting.
“When we finish our work as a task force,” Hestermann said, “we feel strongly someone should take ownership of this process.”
Integrated System Increases SPP System’s Ramp Rate
SPP’s C.J. Brown told members the Integrated System’s Oct. 1 integration was a “non-event,” with only some tagging and scheduling issues affecting a couple of new market participants. The integration brought on 2,400 MW of load during the transition, with 3,000 MW of generation online.
The system’s nearly 2,600 MW of hydro capacity nearly quadrupled SPP’s existing hydro. More importantly, Brown said, with its quick ramp rates, the hydropower has increased SPP’s rate ramp by 1 MW/minute.
“It may be a minute, but that’s a minute across the entire system,” he said.
Brown also noted SPP’s LMPs have been lowered with the integration, making the RTO more of an energy exporter than it was previously.
Mitigated Offer ‘Strike Team’ on Hold
SPP’s Matt Dillon told the MOPC a “strike team’s” work on mitigated offers is on hold following FERC’s recent rejection of what costs the RTO can include in mitigated offers. (See FERC Sides with SPP Monitor.)
Dillon said SPP has three options: 1) ask for a rehearing, 2) ask for a clarification of “short-run marginal cost” or 3) accept the commission’s decision.
Dillon said SPP remains undecided, and the strike team has no further action.
Nuclear Regulatory Commission Chairman Stephen Burns last week toured DTE Energy’s Fermi 2 nuclear generating station and said he was impressed with the upgrades made to the plant in the wake of the 2011 Fukushima disaster in Japan.
Fermi 2, which went into service in 1985, is equipped with the same type of General Electric Mark 1 reactor as the Fukushima plant, but it is 14 years younger than the Japanese reactor.
Burns and U.S. Rep. Tim Walberg (R-Mich.) toured the plant during a refueling outage. “The plant condition looks good,” Burns said. He was briefed mostly on upgrades to the plant’s ventilation system, a weak point in the Fukushima design.
NRC says Chatham House Report ‘Based on … Hearsay’
The Nuclear Regulatory Commission last week blasted a report by a British think tank asserting that U.S. nuclear power plants are at risk from cyberattacks. London-based Chatham House issued the report recently, saying the “risk of serious cyberattack on civil nuclear infrastructure is growing” because they rely on commercial “off-the-shelf” software.
NRC said the Chatham House report “is based on generalizations and hearsay.” It argued that “the NRC has been very forward-leaning on cyber security issues, and as a result the nuclear power industry is probably better protected than any other sector of our critical infrastructure.”
The Chatham House report did acknowledge that U.S. nuclear plant operators have taken steps to make them more secure from hacking but said more needs to be done.
Obama Administration Sends $15M to Bolster Coal State Economies
The Obama administration awarded $15 million in grants to fund workforce projects in coal-producing regions whose economies have suffered because of stricter federal environmental regulations.
The coal industry has shrunk and faces more pressure in the face of federal emissions regulations, low natural gas prices and the growth of renewable energy. The federal grants will fund retraining programs under Partnerships for Opportunity and Workforce and Economic Revitalization initiatives.
“These grants will help each community create new jobs, diversify its economic portfolio and better compete in the 21st century,” Commerce Secretary Penny Pritzker said.
The number of parties seeking to be heard concerning the PennEast Pipeline, which is planned to run from northeast Pennsylvania to New Jersey, is growing, according to FERC officials. The deadline for comments or to file for intervenor status is Oct. 29, a FERC spokeswoman said.
While FERC takes public comments into consideration, intervenors have legal status. There are 366 separate intervenor applications filed so far.
PennEast’s developers aren’t daunted by the number, however. A spokeswoman said there is a lot of community support for the proposed $1 billion, 114-mile natural gas pipeline. “There might be some people who are opposed to natural gas development, but there are a far greater number of people who want to receive clean, locally produced natural gas at reduced rates,” PennEast spokeswoman Patricia Kornick said. “They just aren’t on the docket.”
The Interior Department has announced it will suspend two upcoming auctions for offshore Arctic drilling rights, while rejecting the requests of two companies to explore for oil under their existing leases. The moves represent two more steps taken by the Obama administration to put the brakes on energy exploration in the region.
The department said it would cancel the previously scheduled auctions in 2016 and 2017 in the Chukchi and Beaufort seas, citing low industry interest and plunging oil prices. It also denied requests to extend leases by Shell and Statoil for parcels in the same areas, mirroring earlier actions taken against leases held by ConocoPhillips.
Secretary of the Interior Sally Jewell said the government was taking the action in response to Shell’s recent announcement that it was suspending exploration efforts in the Arctic, citing market conditions. “In light of Shell’s announcement, the amount of acreage already under lease and current market conditions, it does not make sense to prepare for lease sales in the Arctic in the next year and a half,” she said.
Application for Pennsylvania Hydro Project Submitted to FERC
A Pennsylvania developer has submitted an application to FERC for a preliminary permit for a hydropower facility to be built at the Blue Marsh Dam on a Delaware River tributary.
Developer Adam R. Rousselle II of New Hope wants to develop a hydropower project at an existing dam built in 1979 to control flooding of Tulpehocken Creek. The Delaware River Basin Commission had a preliminary permit to study such a facility at the same location, but that permit expired four years ago.
Rousselle is seeking a permit for a 2,500-kW generator. If the preliminary permit is approved, he will have three years to develop more studies on the project and submit a more detailed plan to FERC. The U.S. Army Corps of Engineer would also be involved in the approval process.
The commission’s April order also allowed generators to reserve excess capacity on their tie lines, or “interconnection customer’s interconnection facilities (ICIF),” for the first five years of operation. (See Generator Tie Lines Exempted from OATT Rules.)
