Page 1335 – RTO Insider

January 10, 2017

FERC Conditionally Approves PJM’s Excess Capacity Plan

By Rory D. Sweeney

FERC has approved PJM’s proposal for selling back excess capacity in this February’s third Incremental Auction for the 2017/18 delivery year.

The commission, however, agreed with objectors on several points, prompting it to require key revisions to the plan (ER17-335).

“While we acknowledge deficiencies in PJM’s filing … we also agree with PJM that it is just and reasonable for PJM to alter the shape of its sell-back offer curve to a straight line, eliminating the potential that the relevant Incremental Auction could clear at or near $0/MW-day,” the commission said.

The proposal dealt with PJM’s transition to the Capacity Performance market construct, which was approved in 2015 and gradually implemented over the 2016/17 and 2017/18 delivery years. The RTO had already obtained capacity for those years under previous rules, so the approval also established two transition auctions to procure any additional capacity needed.

The transition auction for the 2017/18 delivery year saw the RTO procure 10,017 MW of previously uncommitted capacity. PJM holds three IAs following the initial Base Residual Auction for a specific delivery year, during which committed capacity resources can buy back their supply obligations and PJM can acquire or release capacity in response to updated load forecasts. The IAs for the transition years also covered the results of the transition auctions.

The methodology PJM used for releasing excess capacity from the 2016/17 delivery year resulted in 4,818 MW sold at an average price of $4.79/MW-day, and PJM warned that using the same process to release any of the 10,017 MW for 2017/18 would potentially result in an offer of $0/MW-day — with no money flowing back to load.

To better reflect the capacity’s value, the grid operator proposed an alternative approach that would identify any necessary changes to the amount of capacity the RTO had already procured and create a price curve for selling any excess.

pjm excess capacity — FERC modified PJM’s proposed sell-back curve for excess capacity for the 2017/18 Delivery Year to top out at the BRA clearing price for that year.

PJM additionally proposed that any excess that doesn’t sell at the auction would not be eligible to become excess-commitment credits. PJM creates the credits from excess capacity that doesn’t clear IAs and allocates them to load-serving entities, who can trade them or use them to replace existing capacity requirements. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)

FERC approved PJM’s plan but ordered several changes in recognition of objections made by American Municipal Power. The commission directed PJM to revise the price curve so that it begins at the lowest price point on the current sell-back offer curve and ends at the BRA clearing price for that delivery year. It also ordered allocating uncleared excess capacity as excess-commitment credits and consolidating separate capacity sellbacks into the single auction.

“Performing two auctions in this manner will result in creating two prices for the same product in the same auction, without any justification for the different price,” the commission said.

FERC clarified that the approved changes to the sell-back procedure only apply to the third IA in February.

PJM Independent Market Monitor Joe Bowring was surprised the commission put so much effort into what he felt was a minor detail, but he was still disappointed that his office hadn’t intervened in the docket. During discussions to secure stakeholder endorsement of PJM’s proposal, the Monitor repeatedly objected to the plan.

January 10, 2017

WAPA, SMUD Extend Scoping Period for Colusa-Sutter Project

By Robert Mullin

The Western Area Power Administration and Sacramento Municipal Utility District (SMUD) have extended the scoping period for a proposed transmission line intended to increase SMUD’s ability to import power from the Pacific Northwest and export from the Sacramento area.

The scoping period for the Colusa-Sutter (CoSu) line will be extended an additional 60 days, from Jan. 6 to March 7, to elicit public comment on environmental issues related to the proposed project, which would create a new 500-kV link between the California-Oregon Transmission Project (COTP) and SMUD and WAPA facilities on the east side of the Sacramento Valley.

colusa-sutter project — The proposed Colusa-Sutter transmission project is intended to improve SMUD’s access to Pacific Northwest renewable resources via the California Oregon Transmission Project. | *WAPA*

Federal power marketing agency WAPA sells power to publicly owned utilities such as SMUD, but its existing transmission facilities do not have enough capacity to meet SMUD’s increasing need for energy, the agency said. The new line would connect the COTP system in Colusa County with the Central Valley Project system in Sutter County, improving access to renewable energy generated in the Northwest.

“A recent California Energy Commission study makes the case for projects like this that enhance transmission capability to import valuable out-of-state renewable resources for California to meet its 50% renewable energy goals by 2030,” WAPA and SMUD said in a statement.

That study pointed out that a shortage of available transfer capacity on the California-Oregon Intertie would inhibit California’s ability to import additional carbon-free energy from the Northwest. (See California Tx Policy Must Foster Resource Diversity, Report Shows.)

WAPA and SMUD said the project will provide additional bidirectional transmission capacity to improve SMUD’s ability to participate in CAISO’s Western Energy Imbalance Market (EIM).

SMUD last October announced its intent to enter negotiations with the ISO to join the EIM, the West’s only real-time energy market. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)

The extended scoping period for the line will include review of an additional study area located about 20 miles south of the three other study areas previously scoped over the past couple years. The newly considered corridor would connect to the COTP in Yolo County and terminate near the Elverta Substation in northwestern Sacramento County, crossing directly into SMUD’s service territory.

“The new study area will help us make a more informed choice about how to best meet our future energy needs, while minimizing impacts on the environment and surrounding communities,” said Kim Crawford, SMUD’s California Environmental Quality Act project manager.

Six public meetings about the line are planned for January and February. Comments received during the meetings will be considered in the preparation of the draft environmental impact report. Any other comments must be submitted by March 7.

WAPA said it will take no action on the proposed project until after the environmental review is completed in 2020.

January 10, 2017

DOE Issues Recommendations on Cyberattack Protections

By Ted Caddell

When the Obama administration released its first version of the Quadrennial Energy Review two years ago, it addressed a hypothetical concern about threats to the nation’s oil and natural gas pipeline infrastructure.

The second review from the Department of Energy, released last week, turned its attention to risks facing the nation’s electric grid — progressing from the hypothetical to the real.

“In the current environment, the U.S. grid faces imminent danger from cyberattacks,” the report said. “Widespread disruption of electric service because of a transmission failure initiated by a cyberattack at various points of entry could undermine U.S. lifeline networks, critical defense infrastructure, and much of the economy; it could also endanger the health and safety of millions of citizens.”

The review is especially timely, coming amid a national discussion about the possibility that cyber breaches influenced the 2016 presidential election. It noted examples of such attacks in the electricity sector, including attacks on three Ukrainian utilities in December 2015 that left 200,000 customers without power, and highlighted the need to take decisive action to enact protections.

The report called for using the Federal Power Act to “develop preparation and response capabilities that will ensure [FERC] is able to issue a grid-security emergency order to protect critical electric infrastructure from cyberattack,” as well as from natural threats such as geomagnetic storms.

cybersecurity doe — Graphic illustrates the many ways in which utility IT systems leave the electricity grid vulnerable to cyber attacks, including unpatched networks, exposure to the public internet and insider threats.

The department also calls for an expansion of FERC authority to modify NERC-proposed reliability standards or develop its own standards “to protect national security in the face of fast-developing new threats to the grid.”

FERC’s expanded role in developing grid safety standards would supplement the department’s efforts at implementing protective measures in times of emergency.

“This approach would maintain the productive NERC-FERC structure for developing and enforcing reliability standards but would ensure that the federal government could act directly if necessary to address national security issues,” the report said.

“FERC should consider having existing regional organizations undertake such planning, as it deems appropriate,” the review said. “FERC should evaluate whether the costs of implementing security measures identified in the integrated electricity security plan are appropriate for regional cost allocation, where such measures are found to enhance the security of the regional transmission electric system.”

However, the department would not saddle grid operators with full financial responsibility for fulfilling the recommendations. Noting that the cost of protecting the nation’s grid against cyberattacks could run as high as $500 billion, the report calls for federal assistance in the form of an expanded DOE loan guarantee program used to encourage innovative grid technologies, going beyond the current emphasis on loans for new generation methods.

“A relatively low-cost permanent federal financing system could be established by setting up a revolving loan fund with one-time seed capital,” the report states. A loan guarantee program would be crucial for smaller utilities that lack the access to capital, unlike larger companies.

In all, the 494-page report makes more than 70 recommendations for policymakers to consider. It remains to be seen how many will be undertaken. The first QER outlined 63 recommendations — 21 of which were enacted by Congress.

January 10, 2017

PJM Analysis on Artificial Island Project Delayed Again

PJM announced that its comprehensive analysis and recommended solution for issues related to Artificial Island won’t be ready until April.

Staff had expected to present the plan at the February meeting of the RTO’s Board of Managers.

“While PJM’s analysis is progressing well, during discussion of preliminary results with stakeholders, several questions and considerations were raised,” PJM’s Steve Herling said in an emailed announcement. “More time is needed to evaluate and respond to these questions and considerations.”

Following complaints over cost allocation and a near doubling of the estimated costs, the board suspended the Artificial Island project, PJM’s first Order 1000 competitive solicitation, pending a “comprehensive” staff analysis to be completed by next month. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)

PJM presented preliminary results of its analysis at its Planning Committee meeting in December and concluded that several elements of the scope of work would change. Stakeholders raised concerns about the changes and questioned whether PJM planned to re-evaluate all of the proposals in light of the updated criteria. Herling said at the time that the RTO was only “realistically” focused on the finalists. (See “PJM Review of Artificial Island Bid Elements Completed,” PJM Planning/TEAC Briefs.)

Independent Market Monitor Joe Bowring characterized the decision as a “tough call” and said the extra two months “is not that big a deal.”

– Rory D. Sweeney

January 10, 2017

MISO Reliability Subcommittee Briefs

MISO told stakeholders last week that its own data set might have been partly to blame for generators not responding efficiently to dispatch instructions.

Steve Swan, MISO senior manager of dispatch and scheduling, said part of the problem was the timing of the RTO’s unit dispatch system, which previously captured generator output measurements prior to the end of a five-minute settlement interval in order to inform the next dispatch. Swan said MISO moved the timing forward about 40 seconds — but still prior to the end of the five-minute period — to ensure that results contain the most up-to-date dispatch information to avoid improperly restricting generator movement.

The RTO hopes the new timing will reduce the likelihood that a generator mistakenly appears to be lagging based on a dispatch estimate that lacks the most up-to-date information. The change took place Dec. 15.

“I don’t know if it’s going to solve all of the problems, but at least now when they see a generator not moving at the offered ramp rate, it’ll not be because of MISO instructions,” Swan said during the Jan. 5 Reliability Subcommittee meeting.

MISO currently marks generators off-control — online but not dispatchable — if they fail to follow set point instructions and do not move on their offered ramp rate.

Swan said MISO will compare data before and after the change to determine whether any lags remain and the RTO needs to pursue the issue further.

Independent Market Monitor staff member Michael Wander said that — even after the change — there will be some degree of lag that will be “practically impossible” to eliminate. Still, he thinks the change will bring an improvement.

The Monitor’s 2012 State of the Market Report suggested that MISO develop better tools to identify units that are derated or not following dispatch so that they may be placed off-control. That suggestion was included among other recommendations for improving thresholds for uninstructed deviations. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)

MISO Reports Successful November

MISO reported a smooth November in its latest monthly operations roundup, with markets performing as expected.

Above-average temperatures during the month contributed to an average 68 GW of load and a peak load of 81.9 GW on Nov. 21. November gas prices averaged $2.44/MMBtu, down 16.2% from October.

The month was free from any minimum or maximum generation events or warnings, but MISO on Nov. 12 earned the lowest unit commitment performance rating for the month, with committed but unnecessary resources remaining online to meet minimum run-times.

The RTO on Nov. 28 hit a new 13.3-GW wind production record, which was surpassed Dec. 7 when output reached 13.7 GW.

FERC Liaison: No Commission Disruptions

Chris Miller, FERC liaison to MISO, told stakeholders that the commission will continue to operate as a three-person panel in the near term.

“They all work very well together and have gotten a lot of work done,” Miller said of commissioners Norman Bay, Colette Honorable and Cheryl LaFleur.

Honorable’s term ends in June, but she is eligible to serve until the end of the year under a grace period if the Senate is unable to confirm a replacement, Miller noted. He said FERC staff are prepared for the impending leadership change, and as direction changes are the norm at the commission, the agency expects no delays in work output. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)

— Amanda Durish Cook

January 9, 2017

UPDATE: Entergy to Shut Down Indian Point by 2021

By William Opalka

The embattled Indian Point nuclear plant will close by 2021, owner Entergy and New York Gov. Andrew Cuomo said Monday morning.

An agreement between the governor’s office and Entergy calls for the company to shorten its pending license renewal applications to six years, with both sides ending litigation they have filed against each other as part of the deal. The state reserved the right to begin new litigation if necessary.

Unit 2 would shut down in April 2020, followed a year later by the closure of Unit 3.

“For 15 years, I have been deeply concerned by the continuing safety violations at Indian Point, especially given its location in the largest and most densely populated metropolitan region in the country,” Cuomo said in a statement. “I am proud to have secured this agreement with Entergy to responsibly close the facility 14 years ahead of schedule to protect the safety of all New Yorkers.”

Cuomo said that his administration has been “aggressively pursuing and incentivizing the development of clean, reliable energy” and that the state is “fully prepared” to replace Indian Point’s output at a “negligible cost” to ratepayers.

An agreement to close the two units — which combined have more than 2,000 MW in generating capacity — was first reported by The New York Times on Friday.

Entergy said energy economics driven by low natural gas prices forced the closure, which will mark the company’s exit from the merchant power generation business.

“Key considerations in our decision to shut down Indian Point ahead of schedule include sustained low current and projected wholesale energy prices that have reduced revenues, as well as increased operating costs,” Bill Mohl, president of Entergy Wholesale Commodities, said in a statement. “In addition, we foresee continuing costs for license renewal beyond the more than $200 million and 10 years we have already invested.”

Mohl noted that regional power prices have fallen by about 45% over the past 10 years to an average of $28/MWh, largely the product of record low gas prices stemming from increased supply out of the Marcellus Shale formation.

“A $10/MWh drop in power prices reduces annual revenues by approximately $160 million for nuclear power plants such as Indian Point,” Mohl said.

The agreement would allow the plants to operate for two additional two-year increments — with final closure slated for 2025 — if an emergency affected reliability in the New York City area.

Both units, whose permits expired in 2013 and 2015, have applied for 20-year license extensions from the Nuclear Regulatory Commission, which has granted the extensions pending review. Under the agreement, Entergy will instead apply for a six-year license renewal.

The plant has had a series of mishaps in recent years, intensifying pressure from state officials.

“Shutting down the Indian Point power plant is a major victory for the health and safety of millions of New Yorkers and will help kick-start the state’s clean energy future,” Attorney General Eric T. Schneiderman said.

Among the many challenges he has filed against the facility, Schneiderman has sought to deny Indian Point state water quality permits. (See Loss on Water Permit a Setback for Indian Point Extension.) New York will issue a coastal zone certificate and water quality permit for the plant as part of the settlement.

Schneiderman and environmental group Riverkeeper were also parties to the settlement.

“This agreement is a win for the safety of our communities and the health of the Hudson River, and it will pay big dividends in new sustainable energy sources and the well-paying jobs that come with them,” Riverkeeper President Paul Gallay said in a statement.

Other aspects of the agreement include:

Annual safety inspections by the state, along with the transfer of used fuel to protective storage in dry casks, the preferred method of safely storing spent fuel;
A commitment by Entergy to offer plant employees new jobs at other facilities, while the state will offer employment assistance and worker retraining, including for new skills needed for employment in the renewable energy sector; and
A requirement that Entergy establish a new emergency operations center in nearby Dutchess County, as well as create a $15 million fund for environmental projects.

Entergy’s previous agreements to make payments in lieu of taxes to local government entities and school districts will continue through 2021. Those agreements will persist before being gradually stepped down at a negotiated level following shutdown. The state will also work with local communities to address potential revenue shortfalls, enacting programs similar to those implemented for other communities affected by plant closures through the existing fossil fuel plant retirement fund.

New York has committed to a 50% renewable energy power mandate by 2030, with nuclear power seen as a bridge until clean power sources can be built at sufficient scale.

“With the news that the Indian Point nuclear power plant will close by 2021, New York should look to wind power, solar power and offshore wind to meet electricity needs, rather than relying more on natural gas,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. “New York essentially has five years to get new renewable energy online to meet this demand, and the renewable energy industry is more than ready.”

The state Public Service Commission has said the closure will have minimal impact on customer bills, with adequate resources expected to be online by 2021. Transmission upgrades and energy efficiency measures totaling 700 MW are already in place, officials said. (See FERC OKs Settlement for NY TOTS Projects.)

“The NYISO is required to perform an electric system reliability impact analysis after receiving an official retirement notice for any bulk system generation asset,” NYISO spokesman David Flanagan told RTO Insider. “Additionally, the NYISO’s Comprehensive Reliability Plan, to be issued in July 2017, will consider future grid reliability needs and generation capacity margins over a 10-year time horizon under expected system conditions.”

Indian Point’s closure will mark Entergy’s exit from the merchant power business. In little more than two years, the company has shuttered the Vermont Yankee nuclear plant in Vermont and announced the closures of two other nukes, including Pilgrim in Massachusetts and Palisades in Michigan. The sale of New York’s James A. FitzPatrick nuclear plant to Exelon is pending. The company has also sold a natural gas-fired power plant in Rhode Island.

Entergy said it will record a non-cash impairment charge of approximately $2.4 billion pre-tax and $1.5 billion after-tax in the fourth quarter of 2016. It also expects additional charges totaling about $180 million for severance and employee retention costs by the end of 2021.

The company said it has invested $1.3 billion in Indian Point in the 15 years it has owned the plant.

January 9, 2017January 18, 2024

Mountain West to Explore Joining SPP

By Robert Mullin

Mountain West Transmission Group has said it will enter discussions with SPP to explore the possibility of joining the RTO.

The announcement comes eight months after Mountain West issued a request for information to CAISO, MISO, PJM and SPP regarding tariff administration and market operator services to support a new — and independent — organized market for the region. (See Mountain West RTO Could Pose Competition for CAISO.)

“By exploring membership with an existing RTO, the Mountain West participants would have the advantage of an existing electricity market design,” the group said in a statement issued Friday.

“We have enjoyed working with the Mountain West Transmission Group on preliminary analysis and look forward to the next phase of more detailed discussions on specific terms of membership in the SPP organization,” SPP CEO Nick Brown said.

An independent effort would put Mountain West in direct competition with CAISO’s plans to expand into the interior West through the possible inclusion of PacifiCorp as a member. SPP’s westward movement could have a similar impact on CAISO’s expansion.

Mountain West — a partnership consisting of seven different transmission-owning entities within the Western Interconnection, including the Western Area Power Administration’s Loveland Area Projects and Colorado River Storage Project — has been investigating the benefits of implementing a common transmission tariff across multiple states and developing an organized market.

Mountain West’s footprint covers most of Colorado and Wyoming, along with smaller areas of Arizona, Montana, New Mexico and Utah. WAPA operates nearly 5,000 miles of transmission lines within the area.

Other members of the group include Basin Electric Power Cooperative, Black Hills Energy, Colorado Springs Utilities, Xcel Energy’s Public Service Company of Colorado, Platte River Power Authority, and Tri-State Generation and Transmission, which together control about 11,000 miles of transmission.

“Participation in a regional market can provide operational efficiencies through economies of scale and increased opportunities to bring lower-cost renewables into our system,” Platte River CEO Jason Frisbie said.

“Like our decision to join SPP for our east-side power supply, this announcement reflects years of diligent work and analysis by our employees and the Mountain West team,” said Paul Sukut, CEO of Basin Electric.

Steve Beuning, Xcel’s director of market operations, said the discussions will be a “crucial step in evaluating the potential benefits of a regional energy market.” Xcel has been a strong advocate for an organized market in the interior West to improve integration of its generation portfolio heavy in wind resources.

Mountain West expects to reach a decision whether to join SPP by midyear and is targeting 2019 for market implementation, subject to stakeholder input and necessary approvals.

“While Mountain West is optimistic that an RTO may benefit its entire membership, each Mountain West participant will ultimately need to evaluate for itself whether potential membership makes sense,” the group said.

In the event that negotiations with SPP are unsuccessful, Mountain West could pursue similar discussions with MISO and PJM, the group said.

January 9, 2017

SPP Requests DOE Approval to Export Power to Canada

SPP has filed an application with the Department of Energy seeking permission to transmit electricity from the U.S. into Canada, using member Basin Electric Power Cooperative’s existing transmission facilities in North Dakota.

spp doe basin electric canada — SPP’s proposed exports to Canada would be transmitted via a North Dakota transmission line owned by Basin Electric Power Cooperative, which has previously been granted export authorization. | Basin Electric

The RTO wants to supply power on an emergency basis for five years, exporting surplus energy in excess of SPP’s load requirements. According to the filing, Basin Electric’s facilities were previously authorized by a presidential executive order and “are appropriate for open access transmission by third parties.”

SPP said Thursday that it wants to “address emergency assistance transactions,” but that it doesn’t normally purchase or sell power to or from “such external entities.” In December 2015, it completed its first — and only — international transaction when it imported power from Canadian electric utility SaskPower during an emergency situation in North Dakota. (See SPP, SaskPower Make First International Trade.)

SPP made the filing Nov. 14 pursuant to Section 202(e) of the Federal Power Act. It was published in the Federal Register on Jan. 4.

The Energy Department will evaluate environmental impacts and determine whether the proposed action will negatively affect U.S. electric supplies or reliability before issuing a final opinion. International energy transactions fall within the department’s jurisdiction.

In March, FERC approved the RTO’s request to recognize the U.S.-Canadian border as a point of sale for transactions with Canadian transmission providers. The ruling allows Canadian companies to register their resources with and make them available to the RTO under its market rules. (See “FERC OKs Canadian Border Point-of-Sale Filing,” SPP Briefs.)

SPP gained an interconnection with Canada when Basin Electric became a member in October 2015 as part of the Integrated System.

– Tom Kleckner

January 9, 2017

SPP Seams Steering Committee Briefs

SPP stakeholders agreed on Wednesday to amend a two-year-old policy paper and clarify when FERC approval would be needed to allocate costs for some seams projects between 100 kV and 300 kV.

The Seams Steering Committee voted 6-1 in favor of the change.

The change clarifies that the RTO will recover costs for seams projects greater than 300 kV under its regionwide highway cost allocation methodology. Costs for projects lower than 300 kV would also be allocated under highway funding unless the project meets certain criteria. In those cases, the Regional State Committee or Markets and Operations Policy Committee could recommend costs be allocated using SPP’s highway/byway methodology.

The highway/byway methodology considers facilities of 300 kV or above as highway facilities, with their costs allocated on a regionwide, postage stamp basis. Facilities between 100 kV and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide. Projects below 100 kV are allocated entirely to the host zone.

Under the revised language, projects or tie lines of 100 kV or higher within a seams partner area could be allocated regionwide. Alternatively, based on the results of a seams project study, the RSC and the MOPC may recommend the Board of Directors approve cost allocation under the highway/byway cost allocation methodology, with the byway costs assigned to a zone expected to receive at least 60% of the project’s benefits. If the board approves such cost allocation, it would seek FERC approval on a project-by-project basis.

Within SPP, projects and tie lines of 100 kV or higher could also be allocated regionwide subject to FERC approval on a project-by-project basis, potentially expanding the number of projects that can be funded through the highway/byway methodology. FERC approval would be required only if the Tariff does not already allow such cost allocation.

Otherwise, based on the seams project study, the MOPC and/or the RSC can recommend the board approve highway/byway cost allocation if a single zone will receive at least 60% of the benefits. No FERC approval would be required.

SPP defines seams projects as non-interregional projects of 100 kV and above that benefit the RTO and one or more neighbors with a minimum cost of $5 million, and usually require a benefit-cost ratio of at least 1.0. SPP and the seams partner must agree to cost sharing.

ITC Holdings’ Marguerite Wagner cast the lone dissenting vote. Wagner and ITC contended the revisions would carve out seams projects from FERC’s Order 1000 process “without justification.”

Wagner expressed a preference for FERC-enforceable joint operating agreements to determine project cost allocation. David Kelley, SPP’s director of interregional relations, noted that would require the negotiation of a series of JOAs with multiple seams partners.

“I don’t know whether there’s a one-size-fits-all formula we can put down,” he said.

Two other committee members, the Northeast Texas Electric Cooperative and Xcel Energy, abstained.

The FERC filings would be necessary because the SPP Tariff does not currently allow highway/byway cost allocation of seams projects.

The policy changes reflect input from the board and RSC since the paper was originally approved in 2014. Staff said the paper will remain separate from SPP’s business practices and other governing documents and not require a revision request.

The revisions struck previous language that would have required seams projects greater than 300 kV to be recovered according to the highway/byway methodology. Those projects below the 300-kV threshold would have been recovered regionally through highway funding.

The committee will now send the policy paper to the Cost Allocation Working Group for its review. It hopes to have a finalized document for approval by the April meetings of the board, MOPC and RSC.

SPP-AECI Joint Study Recommends Two Projects

SPP and Associated Electric Cooperative Inc. staff are proposing two joint projects addressing thermal overloads and high-voltage issues along their seam in southern Missouri, according to a draft version of the biennial SPP-AECI Joint and Coordinated System Plan report released Friday.

The report identified a reactor in and/or around SPP’s 345-kV substation in the Brookline area and a new 345/161-kV transformer at AECI’s Morgan substation, along with an uprate of the 161-kV line between Brookline and Morgan, as being “mutually beneficial” to both entities.

Kelley told the committee the Morgan portion of the projects is “effectively” on the AECI system and will still have to undergo a regional review.

SPP and AECI evaluated 56 different potential transmission solutions to address the Brookline area’s needs. Staff looked at five targeted areas in all but determined one was no longer an issue and agreed the other three could be managed without joint projects.

Any final solutions will be coordinated with the SPP 2017 Integrated Transmission Planning’s 10-year assessment.

The joint study focused on predetermined target areas “to concentrate study resources on the geographic areas along the SPP-AECI seam most likely to benefit from mutually beneficial transmission projects.” Those areas were determined by historical analysis, operational experience, recent regional planning efforts and stakeholder feedback.

The SPP-AECI joint operating agreement requires a joint study be conducted every two years to ensure “reliable, efficient and effective operation[s]” along the seam.

Stakeholder comments on the report are due to SPP’s Adam Bell or AECI’s James Vermillion by Friday. That feedback will be incorporated in the final version of the joint study, which will be posted on SPP’s website.

Based in Springfield, Mo., AECI is owned by six regional generation and transmission cooperatives.

MISO M2M Payments Total $1.2M in November

Staff’s monthly market-to-market update once again showed a large flow of dollars from MISO to SPP, primarily attributed to temporary flowgates between the two RTOs. MISO sent $1.15 million to SPP in November, with $879,305 coming from temporary flowgates, and it has now compensated its seams neighbor more than $12.4 million for M2M since March 2015.

Temporary flowgates incurred 265 hours of binding M2M, with permanent flowgates accounting for 92 hours binding.

– Tom Kleckner

January 9, 2017

MISO Aims for Improved Frequency Response Modeling

By Amanda Durish Cook

MISO is seeking stakeholder input on how to address declining frequency response capability within the RTO.

“Frequency response has deteriorated in the Eastern Interconnection over the years,” Michael McMullen, MISO director of regional operations, said at the Jan. 5 Reliability Subcommittee meeting. “It’s currently adequate, but we want to make sure it doesn’t get any worse.”

System operators must maintain the grid at a frequency of 60 Hz in order to maintain network stability. An uncontrolled drop in frequency increases the threat of cascading blackouts.

The RTO says it needs better modeling and is considering more in-depth data collection to support its efforts to improve response to frequency disturbances.

“There is something in the model that isn’t right,” McMullen said, adding that stakeholder involvement is “critical” to more accurate modeling.

McMullen said that MISO’s current post-disturbance modeling is too conservative in estimating the occurrence and length of frequency dips because of its reliance on inaccurate inertia parameters, which factor in the collective ability of generators to automatically respond to frequency changes based on the pull of load. Simulations show the system recovering too quickly when compared with real events, indicating “a need to fix overall governor parameters,” McMullen said.

MISO currently measures the frequency response of every generator within its system at 24 seconds and 60 seconds following a deviation by polling a megawatt change in output per 0.1 Hz of a frequency deviation. McMullen said the RTO could collect more measurements, including collecting frequency values themselves in addition to megawatt output, gathering data more frequently at two- to four-second intervals and cataloging local balancing authority and MISO frequency response events in order to identify trends.

Hwikwon Ham, a staffer with the Minnesota Public Utilities Commission, asked if the effort would require major software changes, or if the RTO simply needs to capture more data for better frequency response modeling.

Gathering more data is the first step in determining whether program improvements are needed, McMullen said.

“It’s getting enough data to be able to talk with entities,” he said.

MISO is also exploring incorporating its phasor measurement units — devices installed across the Eastern Interconnection to measure the electrical waves on the grid at a specific point in time — in the effort. Those devices can isolate a frequency event and identify specific responses by generators, although their use for model validation is currently in the “embryonic” stage.

The RTO is continuing its efforts to capture data and correlate the numbers to a disturbance, McMullen said. It must also work on providing phasor measurement unit data to member companies.

MISO agrees with FERC’s recently proposed rule mandating that all new resources connecting with the grid have frequency response capability as a precondition for interconnection, McMullen said (RM16-6). (See FERC: Renewables Must Provide Frequency Response.) However, he noted that the new rule is not tailored to an energy market and does not propose any compensation mechanisms for providing frequency response.

MISO Consulting Advisor Terry Bilke said MISO consistently performs above NERC’s frequency response standard (BAL-003-1).

“We don’t anticipate any frequency problems as long as there’s not a change in fleet,” Bilke said. “The [Notice of Proposed Rulemaking] requiring new interconnection agreements to [have a governor] will ensure there’s no backsliding.”

Responding to a request by RSC Chair Tony Jankowski that MISO release its 2016 frequency response data, McMullen said the RTO must first determine what information can be shared publicly.

In 2015, MISO met NERC’s frequency response requirement at an average of -475 MW/0.1 Hz, more than doubling the NERC obligation of -211 MW/0.1 Hz. Still, the results were not as good as in 2014. (See “MISO Frequency Response Doubles NERC Requirements,” MISO Reliability Subcommittee Briefs.)

McMullen said he would update the subcommittee on MISO’s progress on the matter in April.