The Federal Energy Regulatory Commission has approved Minnesota Power’s plan to build a 200-mile transmission line from Manitoba to Grand Rapids, Minn.
The 500-kV Great Northern Line will run from the Canadian border near Roseau, Minn., to a substation near Grand Rapids. The total cost is estimated at $560 million to $710 million. MISO has included the line in its transmission expansion report.
The line will be a joint project by Minnesota Power and Manitoba Hydro, and 383 of its 883 MW of transmission capacity will be used to deliver hydro power purchased by Minnesota Power for its customers. Minnesota Power will be the line’s majority owner.
Obama Administration Announces Plan to Cut Methane Emissions
The White House announced that it will implement a combination of regulations aimed at reducing methane emissions from oil and gas drilling, a significant source of greenhouse gases that affect climate change.
The administration said the new regulations aim to cut industrial emissions of methane by 40 to 45% over the next 10 years. Methane, a major component of natural gas, is emitted at gas wells and pipelines.
The Environmental Protection Agency is expected to set requirements for new or modified oil and gas wells and natural gas facilities. The rules are expected to be rolled out in the spring or summer.
FERC Scheduling Hearings on PennEast Pipeline Project
The Federal Energy Regulatory Commission is hosting a series of five public meetings on the proposed PennEast natural gas pipeline in Pennsylvania and New Jersey.
FERC will collect comments that will be used in the final determination on whether the pipeline will be built and what route it will take. The pipeline, financed by operating units of UGI and four major New Jersey gas utilities, is estimated to cost $1 billion. It would deliver Marcellus Shale gas from northeastern Pennsylvania to a pipeline interconnection near Trenton, N.J.
Opponents are already organizing. “The environmental impacts are very significant, very serious,” said Maya van Rossum of the non-profit Delaware Riverkeeper Network. “This environmental impact statement is critically important. We have seen uniformly in pipeline projects FERC not fully considering the impact.”
FERC, DOE Release Final Version of Data Code of Conduct
The final version of the Voluntary Code of Conduct for smart grid data privacy, designed to protect information gathered by smart meters and other technology, was released Friday.
The code protects customer data, including account information and records of energy usage. Under the code, data can be collected and used by service providers, third parties and contracted agents. President Obama held up the code as an example of privacy and cybersecurity during a speech last Monday.
DOE Energy Efficiency Standards Promise $78 Billion in Savings
The Department of Energy released its energy efficiency standards for fluorescent lamps and commercial ice makers, the last two such standards completed in 2014.
The standards for general-service fluorescent lamps alone are expected to save $15 billion in electricity bills and 90 million tons of emissions. Together, the 10 standards approved in 2014 promise energy savings of $78 billion through 2030 and reductions of more than 435 tons of emissions.
Report Claims Offshore Wind Industry Could Provide Double the Energy of Gas, Oil
A report by environmental group Oceana says that Atlantic offshore wind energy industry has the potential to generate twice the number of jobs and twice the amount of energy as offshore drilling for oil or natural gas.
“If we commit ourselves to developing offshore wind resources, it could definitely surpass all that we have with oil and gas,” said Andrew Menaquale, author of the report. “And also, keep in mind, once that oil and gas runs out, it’s gone. Offshore wind, well beyond that, will keep producing energy and will continue to power coastal communities.”
Millstone at Risk of Possible NRC Enforcement for Violation
The struggles of Millstone Power Station to repair a cooling pump has prompted the Nuclear Regulatory Commission to cite the Connecticut facility with a finding of low to moderate safety concern.
The NRC dispatched a team of inspectors to Millstone after problems emerged in 2013 and again in 2014 with a pump used to cool the reactor in the event of failure of both offsite power and backup generators. The findings were not publicized because of security concerns.
Dominion Resources, owner of Millstone, has said that policies and procedures are being changed as a result of the inspection findings.
NYISO last week asked the Federal Energy Regulatory Commission to exempt competitive transmission, including the Champlain Hudson project, from the ISO’s buyer-side mitigation rules.
The ISO and other stakeholders filed comments last week in response to a December complaint by transmission owners, who said NYISO’s market power rules are being misapplied to unsubsidized, competitive projects entering the ISO’s capacity market (EL15-26).
In its response, NYISO essentially asked FERC to order a rule change it was unable to achieve through its stakeholder process, where it was blocked by opposition from generators.
The transmission owners — Consolidated Edison of New York, Orange and Rockland Utilities, New York State Electric and Gas, Rochester Gas and Electric and Central Hudson Gas and Electric — told FERC on Dec. 4 that NYISO should amend its Tariff to include a competitive entry exemption in its BSM rules. The exemption would ensure that projects that did not have contracts with, or receive financial support from, any New York distribution companies, municipalities or the state government are not subject to an offer floor in the ISO’s capacity auctions.
TDI Holdings filed a separate complaint Dec. 16 asking FERC to exempt its high voltage, direct current Champlain Hudson project from the BSM rules after NYISO said it would be subject to the offer floor (EL15-33). The $2.2 billion project would deliver 1,000 MW from the Canadian border to the New York City metropolitan area. TDI said subjecting the project to the offer floor — a minimum clearing price — would jeopardize its commercial viability “because generation supply in Canada may be unwilling to execute transmission service agreements with TDI.”
Supporting TDI’s filing, the transmission owners said the project “emphasizes the need for the commission to grant the [TOs’] competitive entry exemption complaint.” At the same time, the group asked FERC to put off ruling on TDI’s complaint until it ruled on theirs, saying that if it were successful, TDI would not need a project-specific exemption.In their complaints, both the TOs and TDI say they recognize the need for BSM rules in preventing market power.
Buyer-Side Mitigation
NYISO’s rules are similar to PJM’s minimum offer price rule (MOPR).
The rules, approved by FERC in 2013, are intended to prevent state and local governments and large net buyers of capacity — market participants whose load dwarfs the amount of capacity they own — from subsidizing the entry of “uneconomic” generation projects into the capacity market in order to artificially lower prices.
A project is considered economic if its average forecasted price exceeds its net cost of new entry (CONE), or if the annual forecasted revenues in NYISO’s Installed Capacity (ICAP) Spot Market Auction exceed the default net CONE in the project’s locality. The default net CONE is defined as 75% of the net CONE of the reference unit used to determine that locality’s ICAP demand curve.
Uneconomic projects are subjected to the offer floor, defined as the lower of either its net CONE or the default net CONE.
Responses to Complaints
NYISO stakeholders filed comments both in support and in protest to the complaints last week.
In its comments, NYISO said it supported the TOs’ complaint, save for a few minor details. The ISO had proposed a competitive entry exemption last February, but it failed to gain the necessary 58% sector-weighted vote from the Management Committee.
“The NYISO asks that the commission: (i) replace certain proposals in the complaint with alternatives previously advanced by the NYISO in its stakeholder process; and (ii) direct the NYISO to adopt additional Tariff language that will be needed if the competitive entry exemption is to be legally effective and practicably implementable,” the ISO wrote.
It also echoed the TOs’ response to TDI, saying the company should wait until FERC rules on the broader exemption.
NYISO said that BSM rules are intended to prevent uneconomic entry, not protect market participants from competition. The ISO “believes that the BSM rules provide necessary protections to the market and that adding a competitive entry exemption would be entirely consistent with their purpose,” it said.
NYISO’s Market Monitor also supported the exemption, noting that it has proposed such a measure in its past three State of the Market reports.
New York City also voiced its support. “For many years, and in multiple proceedings before the commission and at the NYISO, the city has argued that the NYISO’s buyer-side mitigation rules are overbroad and serve more as a barrier to new entry than a protection against market abuses,” the city said. “Indeed, incumbent generating companies have wielded the mitigation rules as a sword (to strike against potential competitors) and a shield (to block new entry).”
Other stakeholders opposed the rule change.
“At first blush this proposal may seem harmless, but it would in fact create a myriad of new opportunities to artificially suppress capacity pricing in NYISO where out-of-market interference in the markets already is pervasive,” Entergy Nuclear Power Marketing said in its protest to the TO’s complaint.
“While couched in the guise of simply permitting ‘purely private investment’ to risk its own money, review of the proposed Tariff revisions reveals that blanket exemptions would be granted to projects that are not, in fact, purely private. The commission should protect the wholesale NYISO capacity market and reject the complaint.”
The Independent Power Producers of New York said “NYISO’s proposal, which was soundly rejected in the stakeholder process as part of a package of exemptions last year, is fatally flawed.”
The BSM rules were proposed by NYISO as a way of dealing with New York’s ongoing struggles with transmission congestion due to the heavy load imposed by the city. The U.S. Department of Energy has called New York City “an epicenter of transmission congestion.”
This also led to a controversial decision by NYISO to combine its five Lower Hudson River Valley capacity zones into one. The move attracted criticism from ratepayers and attention from the state’s U.S. senators. NYISO, however, claimed vindication when it announced last month that the new zone had led generators to reopen 1,900 MW in shuttered power plants. (See Coal-to-Gas Conversions, New Capacity Zone Ease NYISO Reliability Concerns.)
Michael J. Pacilio, president and chief nuclear officer of Exelon Nuclear, was promoted to executive vice president and chief operating officer of Exelon Generation, the business unit overseeing all of Exelon’s generating stations. Bryan Hanson, Exelon Nuclear COO, will assume Pacilio’s previous roles.
Dynegy Betting on Edwards Station, Commits to Emissions Investments
Dynegy said it plans to upgrade pollution controls at the E.D. Edwards coal-fired plant in Bartonville, Ill., rather than shut the 695-MW plant down in response to more stringent emissions standards. It told Illinois officials that the improvements would reduce Edwards’ noxious emissions by 90%.
As part of the agreement reached with state environmental authorities, Dynegy will continue its 10-year practice of burning low-sulfur coal.
Environmental groups were pleased with the news, but they cautioned that the plant would still produce waste. “While Dynegy’s announcement represents one step in addressing one type of coal plant emissions, there are still many harmful pollutants emitted from the coal plant’s stacks and dumped into its ash ponds on a daily basis,” a Sierra Club spokesperson said.
Exelon Appealing Valuation of Byron Nuclear Station
Byron Generation Station (Source: Exelon)
Exelon often touts the value of its nuclear generating stations. But not for tax purposes.
For the third straight year, the company is appealing Ogle County’s assessed value of its Byron Generating Station in Illinois. The county’s Supervisor of Assessments puts the value of the nuclear plant at $509 million. Exelon says it should be set at $212.6 million.
The company appealed assessments in 2012 and 2013, but both times the Ogle County Board of Review upheld the valuations — $449 million in 2012 and $509 million in 2013. Exelon’s appeals are still pending before the Illinois Property Tax Appeal Board.
PPL is asking for more time to meet Federal Energy Regulatory Commission conditions to win approval of the spinoff of its generating assets to Talen Energy.
In December, FERC set a series of conditions to increase market competition for the spinoff. PPL told FERC last week that it would be unable to complete the plan by the Jan. 20 deadline and asked for an extension of 10 days. Talen Energy would combine the generating assets of PPL and Riverstone Holdings.
PPL and Riverstone are still determining which plants to divest to meet the FERC conditions. PPL spokesman George Lewis said an extension would not delay completion of the deal.
JD Power: PSE&G Ranks Highest in Customer Satisfaction Among Large Eastern Utilities
Public Service Electric & Gas topped the list for business customer satisfaction among large Eastern electric utilities, according to the latest survey by J.D. Power.
PSE&G scored 685, above the segment average of 659 for electric business customers. PPL came in at 681, while Exelon’s PECO scored 644, dropping in rankings from fourth to ninth. Pepco Holdings’ Delmarva Power & Light ranked highest among mid-sized utilities. All three of Duke Energy’s utilities — Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida — came in at the bottom of the Southern region rankings.
NRG Concentrating on Solar as Energy Generation Prices Droop
NRG Energy is taking aim at the rooftop solar installation market in the face of declining profits in the conventional power generation industry.
NRG President David Crane said his company wants to move up the charts among domestic solar installers. SolarCity Corp. current ranks first in the U.S., according to GTM Research, and NRG ranks fifth. “We expect to convincingly persuade our investors that NRG has an embedded SolarCity within it,” Crane said.
The company plans to install 250 MW of home solar systems this year, 875 MW by 2017 and 2,400 MW by 2022. Market leader SolarCity installed 520 MW last year. “Everyone is beginning to believe that residential solar is this trillion-dollar market that currently has about 1% market penetration,” Crane said.
DALLAS — SPP members last week approved spending $270 million on transmission improvements over the next five years, but not before stakeholders expressed misgivings about the investment — which comes after the RTO spent $1.8 billion on upgrades in 2014.
Several members of the Markets & Operations Policy Committee complained that the spending was benefitting wind exporters rather than internal loads and that the RTO’s load projections — driven in part by oil and gas producers — might prove too high.
Members also rescinded approval for a controversial project in the Ozarks in the face of falling demand projections and split one project in two, agreeing to consider generation alternatives to a local voltage problem.
Doubts about Load Projections
Burton Crawford of Kansas City Power and Light declined to endorse the 2015 Integrated Transmission Plan 10-year (ITP10) assessment, which was approved by voice vote with some nays and multiple abstentions.
Crawford said the assessment predicts wholesale sales 50% higher than his company’s internal estimates. “We’re a little concerned with the calculations behind this,” he said.
“We’re concerned that the load forecast is way off,” said the Empire District Electric Co.’s Bary Warren, who noted that much of the growth is based on anticipated demand from oil and gas producers. With the continued fall in oil prices, he said, “we need to determine if these projects will be needed.”
“What if oil goes to $20 a barrel and everyone stops drilling? Or there’s more earthquakes in North Texas and that affects fracking?” he added. “Things have changed in the last six months.”
But Jay Caspary, SPP director of research, development and special studies, noted that while spot prices have fallen to $45 a barrel, futures prices remain above $80, suggesting the price drop may be short-lived.
Several speakers also noted the volume of existing wind generators and oil producers that are unable to connect to SPP.
Xcel Energy’s Southwestern Power System (SPS) area in North Texas and eastern New Mexico is showing the worst potential problems in SPP’s reliability studies.
“They’re out there pumping oil. So there’s additional load that we could add to our system if we had the infrastructure in place,” Caspary said.
Caspary said there has been no significant drop in activity in the SPS territory, noting that The Wall Street Journal recently reported that rigs are being redeployed from the Eagle Ford shale zone in south Texas to the Permian Basin, an SPS territory in southeast New Mexico.
Bill Grant of Xcel Energy said there is at least 80 MW of load that wants to be served, including 30 MW of requests that were denied service and 53 MW of distributed generation.
Warren said the near-term prospects will become clearer this spring when oil producers announce their capital spending plans.
Cost Allocation, Modeling Complaints
SPP’s cost allocation and modeling methodology also came under criticism.
“We’re getting allocated these reliability benefits [for improvements] nowhere near our system,” Crawford said.
In abstaining on ITP10, Warren cited concern about how benefits are calculated.
“We need to think about whether there are some fundamental problems with the way we model our system,” commented Richard Ross of American Electric Power.
Jason Atwood of Northeast Texas Electric Cooperative voted against the 2015 Integrated Transmission Plan Near-Term assessment (ITPNT), which was endorsed with several abstentions. “I don’t want my load to pay for transmission to move power outside the footprint,” he said.
Atwood said wind generation in SPP has never exceeded 1,000 MW during the summer peak, “and we’re modeling for 7,000” MW based on transmission service reservations.
Discussing SPP’s strategic initiatives later in the meeting, Michael Desselle, SPP vice president of process integrity and chief administrative officer, said the RTO’s highway/byway cost allocation methodology is “not appropriate” for exports.
Jeff Knottek, of City Utilities of Springfield, Mo., raised a more acute modeling issue, citing the occurrence of transmission load relief procedures on two flowgates between SPP and Associated Electric Cooperative.
“No one can seem to replicate this problem that occurs in real time. We need to dig down and find what the cause of the problem is.”
2015 ITP10
The MOPC approved a portfolio of $273 million in engineering and construction costs for projects based on the ITP10 assessment of a business-as-usual future and one that assumed up to 20% of hydro capacity and conventional generation — including most coal units under 200 MW — would be lost.
It included 166 miles of reliability projects estimated at almost $210 million and 94 miles of economic projects costing almost $70 million.
The MOPC’s approval also recommended the Board of Directors issue Notifications to Construct (NTCs) for 16 projects needed in 2019. These projects’ cost of $142 million was reduced when members amended the plan to split the largest project, totaling $36 million, into two.
The original project would add a new substation with a 345/115-kV transformer on the Hitchland-Finney 345-kV line; a new 1-mile, 115-kV line from the substation to the Walkemeyer 115-kV line; and a second 21-mile, 115-kV line from Walkemeyer to North Liberal.
Members voted to split the project in two based on differences in the needed in-service dates. Some members suggested studying whether converting the 76-MW Cimarron natural gas generator to a synchronous condenser would eliminate the need for the Walkemeyer-North Liberal line.
Other projects exceeding $10 million were an upgrade of the Iatan-Stranger Creek 161-kV line to 345 kV ($16.1 million) and the rebuild of the South Shreveport-Wallace Lake 138-kV line ($10.3 million).
2015 ITPNT
The 2015 ITPNT, which addresses reliability problems through 2020, includes 42 projects totaling $257 million. Eight of the projects also were identified in the 10-year plan.
More than half of the total is slated for New Mexico ($82.1 million) and Kansas ($50.7 million).
The MOPC separately endorsed two Consolidated Balancing Area projects in the 2015 ITPNT: an upgrade of 138-kV terminal equipment at Benton ($480,000) and a rebuild of the Southwestern Station-Carnegie 138-kV line ($13.4 million).
Ozarks Project Cancelled
Members also recommended the Board of Directors withdraw the NTC for the 41-mile Kings River-Shipe Road 345-kV line.
The NTC was issued following the 2007 Ozark Study as one of several 345-kV projects that would create a loop around Northwest Arkansas and extend eastward across northern Arkansas and into southern Missouri.
Southwestern Electric Power Co. opposed the route selected and requested rehearing. The project also was opposed by a citizens group, Save the Ozarks.
Lanny Nickell, SPP vice president of engineering, said a review last year showed a 50% drop in load growth rates in the area critical to the project’s need. There was a 54-MW drop in post-contingency loading on the East Rogers-Avoca 161-kV line, “a fairly large percentage of [the new line’s] capability,” Nickell said.
“We’re not seeing nearly the severity in the number of overloads that we saw the last time,” he 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 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.
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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.”
The Federal Energy Regulatory Commission has approved Minnesota Power’s plan to build a 200-mile transmission line from Manitoba to Grand Rapids, Minn.
The Federal Energy Regulatory Commission is hosting a series of five public meetings on the proposed PennEast natural gas pipeline in Pennsylvania and New Jersey.
The struggles of Millstone Power Station to repair a cooling pump has prompted the Nuclear Regulatory Commission to cite the Connecticut facility with a finding of low to moderate safety concern.
