Northern Indiana Public Service Co. last week asked federal regulators to dismiss a complaint by two wind farm operators alleging they were overcharged by the utility for transmission upgrades to reduce congestion-related curtailments.
NIPSCO’s request, filed Jan. 12 with the Federal Energy Regulatory Commission (EL15-34), says the Fowler Ridge and Meadow Lake wind farms are improperly trying to piggyback on a complaint filed last June by E.ON Climate and Renewables North America.
The Indiana utility charged Fowler Ridge, Meadow Lake and seven other wind farms $50.4 million to build transmission upgrades, plus another $35.8 million to operate them over 35 years.
E.ON alleged that a 1.71 multiplier NIPSCO used to calculate operating costs of E.ON’s Pioneer Trail and Settlers Trail wind farms is too high (EL14-66).
On Dec. 8, FERC ruled that the multiplier was unreasonable and instructed E.ON and NIPSCO to enter into settlement proceedings to determine a new rate. Fowler Ridge and Meadow Lake filed their complaint Dec. 23. (See Two More Indiana Wind Farms Join NIPSCO Complaint over Tx Upgrades.)
In its request for dismissal of the Fowler Ridge and Meadow Lake complaint, NIPSCO said the farm operators took no position in the transmission complaint filed by E.ON and now, six months later, seek a refund.
“The complainants’ participation in the E.ON complaint proceeding to date has been that of a bystander, at best,” NIPSCO said.
Different Terms
NIPSCO also said there are differences between the transmission upgrade agreements (TUAs) it struck with the two farms and the one it reached with E.ON.
Fowler Ridge and Meadow Lake paid their initial upgrade costs in a lump sum shortly after the agreement was accepted by FERC, last February, “without any conditions, contingencies or exceptions.”
Conversely, E.ON agreed to make installment payments for the initial upgrade cost amounts, NIPSCO said.
“The commission is barred, via the filed rate doctrine, from retroactively refunding [Fowler Ridge and Meadow Lake] for the rates they already paid in full under the TUA,” the utility argues.
NISPCO also argues that while the two wind farm operators in Indiana have claimed the multiplier results in excessive charges of more than $1 million, they offer no support or justification for how they determined the alleged excess charges.
Congestion at Root
In its complaint, E.ON said its Illinois-based Pioneer Trail and Settlers Trail wind farms, with a combined capacity of 300 MW, lost between $9.8 million and $11.7 million in 2013 when grid operators forced them to curtail output due to congestion.
The 600-MW Fowler Ridge is jointly owned by BP Wind Energy North America and Dominion Resources. The 526-MW Meadow Lake is owned by EDP Renewables North America. The farms make up 73% of Indiana’s total wind capacity, according to the U.S. Department of Energy.
Negotiators trying to hammer out a contract to keep an upstate New York nuclear power plant financially viable have been given a three-week extension by state regulators.
Constellation Energy Nuclear Group and Rochester Gas & Electric had faced a Jan. 15 deadline to complete talks for a reliability support services agreement (RSSA) that would likely raise rates for customers.
The New York Public Service Commission in November ordered the RSSA in an effort to save the 580-MW Ginna Nuclear Power Plant on Lake Ontario, 20 miles east of Rochester. NYISO and RG&E said the plant is needed until at least 2018 to maintain system reliability in western New York.
Constellation said the plant has lost $100 million over the past three years and would be mothballed without better financial terms. The RSSA would provide electricity to RG&E at a guaranteed price when called upon.
The two companies jointly asked for an extension until Feb. 6.
“Although significant progress has been made, GNPP and RG&E have not yet finalized an agreement that satisfactorily resolves all of these issues,” the petitioners wrote. “A brief extension will permit GNPP and RG&E to continue to work together in an attempt to develop a more considered RSSA that best satisfies the commission’s requirements as well as the needs of GNPP, RG&E and all interested parties.”
While negotiations continued during the original 60-day period, PSC staff requested financial information from the companies. Ginna and RG&E have asked that the commission keep those documents confidential as they contain protected trade information. That has led to complaints from consumer groups who seek more disclosure.
“Despite the potential for major cost increases for the public in the Rochester area, this PSC proceeding has been marked by an unusual lack of information available to the public,” the Alliance for a Green Economy and the Citizens’ Environmental Coalition wrote in a Jan. 13 letter to the commission. “Today we are writing to flag this problem for the commission as an issue of major concern.”
New York utilities have proposed revised transmission upgrades that would add 1,000 MW of capacity to relieve congestion in the Hudson Valley without obtaining new rights of way.
The proposals conform to a recent order by the New York Public Service Commission to use existing rights of way or other utility property to replace aging infrastructure and upgrade older technologies.
The Dec. 14 order (13-M-0457) directed the utilities to revise their previous applications to improve the transmission corridors, with an emphasis on minimizing the visual impact of the lines. The PSC said it was responding to more than 2,000 public comments, many of which opposed the use of new rights of way.
National Grid, Central Hudson Gas & Electric and New York State Electric and Gas filed their revised plans Jan. 7. They, along with an affiliate of Consolidated Edison and Orange and Rockland Utilities, are part of a new organization, New York Transco, which will develop and own the projects once approved by regulators.
The PSC opened the proceeding in November 2012 to press for upgrades to relieve transmission congestion in some areas of upstate New York, particularly interconnections that move power from central New York to within the Hudson Valley. Transmission congestion also prompted the creation of a new capacity zone in areas north of New York City, raising prices for customers in the Lower Hudson Valley.
The utilities filed their original plans in October 2013.
Nine Options
In addition to a modified version of their original proposed project, the utilities’ new filing lists eight alternatives created to address choke points between upstate New York and southeastern New York and other congested transmission lines within the Hudson Valley region. There are four UPNY/SENY Interface alternatives and four UPNY/SENY & Central-East Composite alternatives.
Seven of the nine proposals meet the objective of adding 1,000 MW of capacity to the Hudson Valley region.
The UPNY/SENY alternatives cost less because they address only transfer points at the interface. They range from an estimated $102.5 million to $525 million.
The four composite alternatives are more costly, as they provide system benefits by replacing aging transmission infrastructure. They range in estimated cost from $764 million to nearly $1.19 billion.
The PSC said it will evaluate each of the proposals and determine which ones meet its criteria; not all will be built.
All of the proposed projects would begin construction by 2017 or 2018, with completion of all of the work by the end of 2020.
Concerns over Cost Overruns
On Jan. 15, the transmission owners filed a petition asking the PSC to clarify that current cost estimates are not binding.
In the December order, the PSC said staff recommendations for a risk-sharing approach are “generally consistent with FERC precedent” and that “this approach will ultimately be subject to FERC’s approval.”
The TOs said the PSC’s approach may not conform to FERC policy, putting them and other developers “in a precarious and untenable position.”
“Accordingly, the NYPSC should clarify that it is not mandating that developers adhere to any specific cost estimate or risk sharing mechanism but rather will consider any risk sharing proposal submitted as part of project proposals along with all other factors in determining the best project to meet the public interest.”
A subsidiary of Sumitomo Corp. was temporarily suspended from the New England wholesale energy market this month due to a default on its financial obligations.
Pacific Summit Energy, which trades electricity, natural gas and crude oil from offices in Newport Beach, Calif., and The Woodlands, Texas, was suspended on Jan. 5 by ISO-NE. The grid operator notified the Federal Energy Regulatory Commission by letter on Jan. 12.
“Pacific Summit has cured the default and the company is currently meeting all of its obligations under the ISO New England Tariff,” ISO-NE Spokeswoman Marcia Blomberg said Friday.
Declining to discuss specifics of the case, Blomberg added: “In general, suspensions are a result of a participant not maintaining a minimum amount of collateral and/or not complying with other financial assurance and billing requirements.”
She also declined to say when PSE was returned to good standing.
Blomberg said there is no requirement for notification to FERC when a suspension is lifted.
PSE, created by Japanese conglomerate Sumitomo in 2012, did not return calls seeking comment.
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 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 03A: Energy Management System (EMS) Model Updates and Quality Assurance (QA) — Includes updates and formatting changes to improve consistency and readability; new table added for important links.
C. Manual 18: PJM Capacity Market – Updated to reflect revisions recently approved by the Federal Energy Regulatory Commission to the shape of the Variable Resource Requirement Curve, gross cost of new entry values, and the Net Energy & Ancillary Services Revenue Offset methodology. (See PJM Board Orders Filing on Capacity Parameter Changes.)
D. Regional Transmission and Energy Scheduling Practices document — Changes made to comply with FERC Order 676H and North American Energy Standards Board standards. PJM is primarily impacted by FERC requirements for “Service Across Multiple Transmission Systems” (SAMTS). (See FERC Proposes Revised Communication, Business Rules.)
Members Committee
2. CONSENT AGENDA (11:05-11:10)
B. Tariff and Operating Agreement (OA) revisions developed by the Demand Response Subcommittee to change the way PJM measures and verifies residential demand response.
The revisions allow statistical sampling and clarify rules for all residential customers. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25.)
C. Tariff revisions to remove seller credit, a form of unsecured credit, from the credit policy, which RTO officials say is no longer necessary.
D. Tariff and OA revisions related to data availability for the bus distribution factors for zonal and residual metered load aggregates utilized by the day-ahead energy market. In the event technical limitations restrict PJM’s ability to obtain the load distribution factors from the 0800 snapshot one week prior to the operating day or if the data is unavailable, the load distribution factors from the most recently available day of the week that the operating day falls on will be used. (See “Tariff Revisions to Metered Load Aggregates” in Markets and Reliability Committee Briefs, Dec. 22.)
Illinois legislative leaders haven’t decided on their next move following a report that offered options for improving the finances of Exelon’s nuclear power plants.
“The report just came out. We’re still examining it,” Steve Brown, spokesman for House Speaker Michael Madigan, said Friday. Madigan, a Democrat, introduced Resolution 1146, which passed with bipartisan support last spring, asking state agencies to investigate “potential market-based solutions to guard against premature closure of at-risk nuclear plants and associated consequences.”
The resulting 269-page report, released Jan. 8, advised legislators that they could keep the status quo; establish a cap-and-trade program with other states; tax fossil fuel-burning generators; adopt a low-carbon portfolio standard; or embrace a sustainable power planning standard. (See Illinois Considering Carbon Tax, Cap-and-Trade to Save Exelon Nukes.)
All of the options are likely to result in higher power prices for consumers.
Asked whether there would be meetings or public hearings, Brown said, “I don’t know if any of that has been decided yet.”
Brown said the recent turnover in the state’s executive branch will play a part in what happens next. Republican Gov. Bruce Rauner took office last week, replacing Democrat Pat Quinn.
“I’d say later rather than sooner regarding the timetable,” Brown said, adding that it was premature to say which of the five options will gain traction.
“I have not heard any discussion suggesting that there’s a consensus around any of the different ideas,” he said. “It’s an important issue and will take some time to sort out.”
Likewise, the office of House Republican Leader Jim Durkin, who co-sponsored the resolution, offered no timetable for a response to the report.
Exelon has said that its nuclear generating stations in Byron, Clinton and Quad Cities are unprofitable in the current market and that government subsidies and tax credits afforded the wind and renewable energy sectors have created an unfair market advantage for its competitors.
The nuclear power giant argues that its stations should get credit for producing carbon-free electricity.
While Exelon lauded the report as validating its view, others interpreted it differently.
“These reports clearly demonstrate that the economic situation for multiple nuclear facilities is much more manageable than originally thought. The report also finds that the retirements of the Illinois nuclear fleet will not cause reliability problems with the state’s electric supply, except under extreme scenarios never before seen in U.S. energy markets, including PJM,” said David Gaier, spokesman for NRG Energy.
Gaier said the best course of action would be to keep the status quo. “Allowing the market to work, which means no ‘subsidy legislation,’ will save ratepayers more than $120 million per year,” he said.
Much of the Illinois report addresses the potential costs to the state if the plants are retired, which would result in the loss of jobs and tax revenue and the possibility of having to burn more fossil fuels to replace the lost generation.
It was produced by the Illinois Commerce Commission, the Illinois Power Agency, the Illinois Environmental Protection Agency and the Illinois Department of Commerce and Economic Opportunity.
The Federal Energy Regulatory Commission will accept comments until Feb. 19 on price formation in RTO and ISO energy and ancillary services markets.
“With proper price formation, the RTO/ISO would ideally not need to commit any additional resources beyond those resources scheduled economically through the market processes, and load would reduce consumption in response to price signals such that market prices would reflect the value of electricity consumption without the need to curtail load administratively,” the commission said in its notice (AD14-14).
“In reality, RTO/ISO energy and ancillary services market outcomes are impacted by a number of technical and operational considerations. … Notwithstanding the foregoing technical limitations and operational realities, the commission believes there may be opportunities for RTOs/ISOs to improve the energy and ancillary service price formation process.”
The commission held technical workshops on the subject Sept. 8 (uplift workshop); Oct. 28 (shortage pricing/mitigation workshop) and Dec. 9 (operator actions workshop). (See PJM Under Scrutiny at FERC Uplift Hearing.)
The commission’s notice solicits questions in 12 categories:
MISO has asked the Federal Energy Regulatory Commission for a rehearing of the commission’s Dec. 12 order requiring the RTO to modify the way it calculates the “hurdle rate” for determining whether to allow power flows between its north and south regions.
The RTO said FERC’s directive would cause the hurdle rate to soar by 4.5 times the current rate of $9.57/MWh, making transfers between the regions of more than 1,000 MW — the maximum allowed by SPP without paying additional transmission charges — uneconomic (ER14-2445-002, ER14-2445-003).
MISO began limiting flows last spring between its northern and southern regions after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW physical contract path. SPP has billed MISO more than $35 million for flows exceeding 1,000 MW.
While seeking to resolve the dispute with SPP, MISO last July asked FERC for permission to implement the $9.57/MWh hurdle rate — an adder to the LMPs of the importing sub-region — to establish market signals indicating when the savings from avoided redispatch costs exceed SPP’s additional transmission charges.
MISO anticipated the hurdle rate could result in about $34 million in annual production cost savings, benefitting consumers.
‘Irreparable Harm’
But MISO told FERC this month that the new method of calculating the hurdle rate ordered by the commission, and SPP’s Service Agreement charges, mean its ability to use its 1,000 MW of contract path rights “is significantly limited and its market is suffering irreparable harm.”
MISO claims that the SPP-MISO Service Agreement assesses charges for every hour of the 24-hour day for even a 30-second, unintentional “incursion” over the threshold.
The RTO “continues to see that redispatching generation is more economic than incurring hurdle rate charges at $9.57/MWh,” MISO said. “When the hurdle rate soars to almost $42/MWh as a result of the commission’s order, it is clear that MISO’s market participants will not be able to realize the economic benefits of allowing flows to be dispatched in excess of the 1,000-MW threshold even though there is available uncongested capacity above 1,000 MW.”
FERC said it agreed with Madison Gas & Electric and WPPI Energy that “by dividing the hourly approximation of the SPP Service Agreement charges by all intra-regional flows, MISO’s proposed hurdle rate is too low and would allow flows when the economic benefits of such transfers would be less than the SPP Service Agreement charges.”
The hurdle rate has not been universally accepted within MISO’s footprint. The Mississippi Public Service Commission contends that the hurdle rate could distort energy prices and effectively treat MISO’s north and south regions as separate RTOs.
Other Fallout from Seams Spat
The flow dispute with SPP has had other effects. Last month, FERC approved MISO’s request to suspend action on long-term transmission service requests (TSRs) between its north and south regions through April 1.
The order (ER14-2022) also allows MISO to waive Tariff requirements and North American Energy Standards Board standards involving flows exporting from MISO South to PJM. MISO told the commission that the waiver request would affect 10 pending long-term firm TSRs from a single customer totaling 2,831 MW.
That waiver request provided some insight into MISO’s thinking in integrating Entergy before the dispute with SPP arose.
Originally, MISO said it anticipated that the primary restrictions on flows between its north and south regions would be set under the Operations Reliability Coordination Agreement (ORCA), a seams agreement with SPP.
MISO also said it thought it would have extra time to negotiate seams agreements governing flows between those regions.
The need for a 1,000-MW limit on flows between north and south was a “sudden and unexpected development,” MISO told FERC.
DALLAS — The Markets & Operations Policy Committee approved the following measures at its two-day meeting last week. The issues will next be considered by the Board of Directors.
MARKET WORKING GROUP
Transitional ARR Allocation Process OK’d
The MOPC approved without opposition a rule that will allow transmission owners that are new to the Integrated Marketplace to participate in an auction revenue rights allocation prior to the monthly allocation if they are unable to participate in the annual one (MPRR 221).
Revised LTCR Process Approved
Members approved a response to an Oct. 28 FERC order finding SPP not in compliance with guidelines 3 and 5 of Order 681, which set the rules for long-term firm transmission rights (MPRR 227).
FERC ordered SPP to create a process for offering long-term congestion rights (LTCRs) for transmission upgrades to “any party” and to allow load-serving entities to nominate candidate LTCRs prior to a simultaneous feasibility test to determine the availability of the nominated LTCR.
SPP’s response proposes a transmission planning study process that would grant candidates incremental LTCRs in lieu of Tariff Attachment Z2 credits for sponsored transmission upgrades. It also would allow LTCRs and incremental LTCRs to be nominated prior to the simultaneous feasibility test instead of selecting them after the test.
Bill Dowling of Midwest Energy, a customer-owned utility in western Kansas, was among several members who voted no. He said it is unfair for entities that make relatively inexpensive transmission upgrades, such as replacing a wave trap, to be entitled to LTCRs, “competing with those who have invested hundreds of thousands or millions” on bigger improvements.
“We just flat-out think FERC got it wrong,” he said.
American Electric Power’s Richard Ross said he shared Dowling’s concerns but that the proposal was a “reasonable response” to the FERC order.
“We’re not going to convince FERC they got it wrong,” Ross said. “We have to do something.”
Action on Day-Ahead Must-Offer Rule Deferred
(Click to Zoom)
The committee approved a Market Working Group recommendation that it defer action on changes to the current limited day-ahead must-offer rule.
In November, the working group voted to recommend that no action be taken on the rule until the deadline for reporting to FERC on how it is working. The vote followed a presentation by SPP staff in October on results of a six-month evaluation of the rule’s impact. The analysis found that almost $362,000 in penalties were issued for shortages in 128 hours between March 1 and Sept. 30.
The majority of the working group said having no day-ahead must-offer rule was preferable to the current limited one and that there was no need to address changes to the current rules now.
The report to FERC is due 15 months after the Integrated Marketplace went live last March 1 and will incorporate 12 months of market data.
Resource Hubs Process Revised; New Hub Created
The committee endorsed an initiative to eliminate discrepancies between the market hubs establishment process in the Marketplace Protocols and that in the Tariff, approving without opposition a compliance filing in response to a 2013 FERC order (ER13-1173).
The vote included approvals of six current resource hubs that have not been previously made official — GRDA_HUB; GRDA_HUBSA; UCUHUB; GSPR2014HUB; OMPA_GENHUB; and KCPLHUB — and one new hub, GSPR2015HUB.
Before SPP created the hubs process in 2012 (Marketplace Protocol Revision Request 90), the Tariff had general “placeholder” language about market hubs, but the Protocols were silent. The MPRR made modifications to the Tariff and added several sections to the Protocols, with market hubs split into two categories — trading hubs and resource hubs — with separate approval processes.
The filed Tariff language referenced the approval process in the Protocols: the SPP Market Monitoring Unit reviews proposed resource hubs for consistency with the market hub criteria while the Markets Working Group and MOPC must approve trading hubs.
The FERC order rejected all changes to the hubs establishment section of the Tariff, leaving in place the original language, which requires all market hubs be recommended by MOPC and approved by the Board of Directors.
But the proposed changes had already been incorporated into the Protocols, and were not removed after the FERC order, resulting in the discrepancies between the Protocols and Tariff.
The filed Tariff language said that approved market hubs won’t take effect until they have been posted for 45 days, while the original Tariff language set a six-month posting requirement. The compliance filing will seek a waiver from the six-month posting requirement for the newly-created hubs.
Kansas City, NW Kansas No Longer Constrained Areas
MOPC approved the Market Monitoring Unit’s recommendation (TRR 149) to eliminate the Kansas City area and the Northwest Kansas area as frequently constrained areas (FCAs).
SPP’s Tariff defines FCAs as areas with one or more binding transmission or reserve zone constraints that are expected to be binding for at least 500 hours annually and within which one or more suppliers are pivotal.
As a result of transmission expansions, the MMU said, the two regions no longer experience high levels of congestion that left them vulnerable to market power by a dominant supplier.
SPP’s third FCA, the Texas Panhandle, is unaffected by the change.
The three FCAs were recommended by Potomac Economics, under contract with the MMU, before the Integrated Marketplace was launched.
REGIONAL TARIFF WORKING GROUP
Regional Cost Allocation Review Remedies Added
Members approved remedies for addressing problems identified in regional cost allocation reviews (TRR 131).
SPP’s Tariff requires the RTO to review the reasonableness of its regional and zonal allocation methodologies at least once every three years.
The revision adds to the Tariff potential remedies for correcting imbalances in cost allocations:
Acceleration of planned upgrades;
Issuance of Notifications to Construct (NTCs) for selected new upgrades;
Apply regional allocation to all, or a portion, of the cost of any project that otherwise would not qualify for regional allocation;
Recommend potential seams transmission projects;
Transfer zonal annual transmission revenue requirements (ATRRs) to the region-wide ATRR;
Exemptions from allocated costs associated with future transmission projects; and
Change cost allocation percentages as defined under Section III of the revision’s Attachment J.
Jeff Knottek, of the City Utilities of Springfield, Mo., said he was supportive of the changes but was concerned they don’t do enough to correct inequities.
Tariff Revised to Eliminate ‘Windfall’ Point-to-Point Revenues
The MOPC approved Tariff revisions to eliminate ambiguity in the application of credits for point-to-point (PTP) revenues (TRR 143). The revisions are intended to make the Tariff consistent with the incorporation of multi-owner zones that have both formula-rate and stated-rate ATRRs.
The changes clarify the transmission owner’s obligation to account for all point-to-point revenues beyond the TO’s allowed ATRR. If the TO’s formula rate template does not account for adjustments to the zonal ATRRs and Schedule 11 ATRRs for PTP revenue, the proposed Tariff revisions will allow SPP to reduce the charges in the settlement process.
“This is making sure there isn’t either a windfall” or a shortfall, said Regional Tariff Working Group Chairman Dennis Reed of Westar Energy. “This ensures that the target that SPP will try and hit [for PTP and other transmission revenue] is correct.”
Rules for Seams Transmission Projects Approved
MOPC approved additional Tariff language governing the rules for seams transmission projects, as outlined by the policy paper released by the Seams Steering Committee in September (TRR 144).
AEP’s Ross expressed misgivings about the changes, saying the Regional State Committee should know that “they may not be getting all they expected.”
OTHER MATTERS
Staff to Update Wind Integration Study
SPP operations staff will update a 2010 study to evaluate the impact of increasing wind generation on the SPP system.
The original Wind Integration Task Force study, which was completed in January 2010, focused on balancing, forecast needs, tool development and transmission adequacy. Results were incorporated into the design of the Integrated Marketplace.
In the five years since, installed wind capacity in the RTO is approaching or has passed the levels forecast in the study.
“There’s a lot higher penetration of wind. There are more operational concerns and issues that we have to be aware of,” said Operating Reliability Working Group Chairman Jim Useldinger of Kansas City Power and Light.
“Just this week we went from 7,000 MW to 700 MW [of wind generation] in a short period of time,” one SPP staffer said.
A year ago, the working group presented a proposal to update the study to reevaluate transmission adequacy based on new wind capacity forecasts.
The MOPC asked the task force to revise the study scope based on what the RTO’s staff can provide without employing external analysts.
(Click to Zoom)
The task force’s revised proposal recommends staff use current and forecast wind installations to review the transmission adequacy assumptions from the 2010 study.
It also will look at operating characteristics and impacts including frequency response (Consolidated Balancing Authority needs vs. wind capability), reactive capabilities under low-wind and high-wind-low-load scenarios and the likelihood of wind events becoming contingency events.
The goal will be to determine the need for any new operational requirements on wind farms and provide inputs into transmission planning studies.
The study, which is expected to take about one year, will be split to provide initial results regarding operational concerns sooner because the transmission review could take longer.
Meanwhile, the Generation Working Group released its biannual report, which recommended no changes to SPP’s methodology for establishing net capability for wind and solar facilities.
Effort to Streamline Aggregate Study Procedures Wins OK
Members approved a measure to revise the Aggregate Study process in an effort to make it more efficient (TRR146). The revisions also consolidate the process into Attachment Z1. Members also approved BPR051, which documents the procedures for the new process.
Order 1000 Task Force Gets New Boss, More Members
The Competitive Transmission Process Task Force will expand its membership and report to the MOPC under a charter change outlined to the committee.
The task force will have at least at least six and as many as 15 members with experience and knowledge in electric transmission engineering design, project management and construction, operations and maintenance, rate design and analysis, and finance.
Larry Holloway of the Kansas Power Pool expressed concern that the charter didn’t list policy experience among the requirements for task force members. Holloway also said it needed diversity with viewpoints of those other than incumbent transmission owners.
Terri Gallup of AEP responded that “a lot of [current task force members] have policy titles within our companies” in addition to experience in the fields listed in the charter.
MOPC Chairman Noman Williams, of South Central MCN, said no committee vote was required on the charter change.
Minimum Design Standards for Competitive Upgrades Approved
Members approved without opposition minimum design standards for competitive transmission upgrades (MDS) with a correction noting that 230-kV circuits should have ratings of at least 1,200 amps, not 2,000 as shown in the MDS.
SPP Announces ‘One-Stop Shop’ for Tracking Document Changes
SPP is creating a Web page as a “one-stop shop” for finding the latest version of the Tariff, Marketplace Protocols, business practices and other documents subject to the RTO’s revision request process.
“You won’t have to go to four different Web pages to find them,” explained Debbie James, manager of market design.
The primary working groups will review all changes to the revision request process prior to MOPC approval of the changes.
SPP, MISO Agree on Revised Flowgate Process
SPP and MISO have agreed on a new process for coordinating tie-line flowgates. The two RTOs have agreed to begin using the new process even before filing it with FERC early this year as an addition to their Joint Operating Agreement.
The party with functional control over the most limiting equipment for the flowgate will be the managing entity and is responsible for available flowgate capability (AFC) calculations. New tie-line flowgates will initially be created as temporary and will not become permanent for 60 days after notification is posted.
The initiative began when SPP staff was assigned to research whether MISO had followed procedures in creating a new flowgate on a line between it and the Empire District Electric. [MISO FG #6257: Ozark 161 kV (EDE) to Omaha 161 kV (EES) for the loss of Osage 161 kV (EES) to Eureka 161 kV (CSWS)].
Empire officials were “surprised” by the flowgate, said David Kelley, SPP’s director of interregional relations.
“I think we’ve identified maybe a gap in our process,” Empire District’s Bary Warren said. There should be explicit criteria for establishing permanent flowgates, including a dispute resolution process, he said.
SPP staff will propose the new coordination process to Associated Electric Cooperative, Kelley said.
Project Pinnacle ‘Close to the Finish Line’
Barbara Sugg, vice president of information technology, told members SPP is “very, very close to the finish line” for Project Pinnacle, implementing Phase 2 of the Integrated Marketplace, including market-to-market rules, long-term congestion rights and regulation compensation.
CONSENT AGENDA
MOPC also approved the following items on the consent agenda with no discussion:
BPWG-BPR 065 BP 7250 Modification: Generator Interconnection Service
MWG-MPRR 209 Change Start-Up Offer from Daily to Hourly
Massachusetts needs additional natural gas pipeline capacity to avoid severe energy shortages in the next few decades, a study commissioned by the state concluded. Even if the capacity is built, winter price spikes caused by severe cold and competition for gas as a heating fuel will remain through 2019, according to the “Massachusetts Low Gas Demand Analysis” study by Synapse Energy Economics.
Measures like demand response, the ISO-NE Winter Reliability program and fuel switching to oil-fired generation will meet electricity demand, but price shocks will occur, Synapse said.
The study, ordered by former Gov. Deval Patrick, repeats many of the same claims from previous analyses by New England states and the regional power grid operator. Environmental advocates from The Acadia Center said the study was too limited in its scope and unnecessarily justifies construction of a controversial gas pipeline that would serve the entire New England region.
The Synapse analysis considered eight scenarios, including low and high natural gas prices, and whether up to 2,400 MW of Canadian hydropower would be available. The scenarios were evaluated from an economic and reliability perspective and assessed for compliance with state Global Warming Solutions Act (GWSA) targets.
Necessary pipeline additions by 2020 range from 25 billion Btu per peak hour for scenarios that assumed low gas demand and a combination of high natural gas prices and no incremental Canadian hydropower, to 33 billion Btu per peak hour for analyses that considered various combinations of gas price assumptions and whether Canadian hydropower was added. By 2030, the additions range from 25 billion Btu per peak hour to 38 billion Btu per peak hour.
The Acadia Center (formerly Environment Northeast), while supportive of the effort to explore alternatives, believes the study is incomplete. The group said it could be misinterpreted as support for a new subsidy that would shift multi-billion dollar risks from private corporations to the public.
A proposal by the six New England governors for a $3 billion taxpayer-supported pipeline transporting shale gas from Pennsylvania stalled in August due to cost concerns in Massachusetts. Patrick temporarily suspended the state’s support of the pipeline after the state legislature failed to act on additional transmission lines to import Canadian hydropower.
The transmission expansion and natural gas pipelines are seen by New England governors as integral parts of an overall regional energy strategy.
The study is limited to Massachusetts, which uses less than half of the energy required in New England and does not have nearly as much renewable energy potential as neighboring states, the center says. It also uses outdated prices for oil and liquefied natural gas, the group said.
“Massachusetts has taken an important but preliminary step toward thorough analysis of viable supply- and demand-side solutions to meet our energy needs,” Acadia Center President Dan Sosland said. “Because electric ratepayers across New England are being asked to subsidize the construction of a pipeline that could take decades to pay off, alternatives need to be examined in all New England states to ensure that we have an accurate, up-to-date picture of how to power the region while reducing risks to consumers and bringing down greenhouse gas emissions.”
Northern Indiana Public Service Co. last week asked federal regulators to dismiss a complaint by two wind farm operators alleging they were overcharged by the utility for transmission upgrades to reduce congestion-related curtailments.
