Page 1346 – RTO Insider

February 7, 2017

SPP RSC Leaves Safe-Harbor Thresholds Unchanged

By Tom Kleckner

DALLAS — SPP’s Regional State Committee last week accepted a working group’s proposal to leave unchanged the criteria used to exempt load-serving entities from transmission project costs in service requests.

The Cost Allocation Working Group recommended that no modifications be made to the thresholds used to determine what project costs should be borne by LSEs making long-term transmission service requests (TSRs). The RSC, composed of 10 regulators from across SPP’s 14-state footprint, accepted the proposal but then directed the CAWG to conduct annual reviews of the aggregate study safe-harbor criteria.

safe-harbor thresholds spp rsc — SPP’s Regional State Committee January meeting | © *RTO Insider*

SPP’s aggregate transmission service study process combines all long-term point-to-point and designated network resource requests received during a specified time period into a single study.

The RTO splits the costs of transmission projects between the entire SPP footprint and LSEs purchasing transmission service for designated resources — those used to meet the LSE’s capacity margin requirement.

The safe harbor exempts LSEs from upgrade costs for a TSR when the aggregate studies’ waiver criteria are met:

Wind generation may not exceed 20% of designated resources.
TSRs must have a minimum five-year term.
Designated resources may not exceed 125% of forecasted load.

Utilities can also apply for an increase in the safe-harbor limit of $180,000/MW.

The CAWG approved the five-year and 125% thresholds unanimously, but it cleared the 20% wind limit by a 6-3 vote. Representatives from the Arkansas, Missouri and New Mexico commissions opposed the motion, while Iowa’s representative abstained.

Adam McKinnie, chief utility economist for the Missouri Public Service Commission and the CAWG’s chair, said he wanted to address wind energy’s operational issues in other ways than by determining who pays for which transmission projects.

“We felt something should be done, but I didn’t see this particular criteria as being the right tool for the job,” McKinnie said.

“Our state utilities had a lot of input to me on this,” said the Nebraska Power Review Board’s John Krajewski. “While I’m sympathetic and I understand the desire to eliminate this threshold, there are a lot of concerns with regard to the operations of thermal units and [SPP’s ability] to send proper signals to thermal units.”

Krajewski said the safe-harbor limits don’t prevent LSEs from adding wind above the 20% threshold. “If you exceed the threshold, then you would simply have to pay for any necessary transmission improvements,” he said.

McKinnie said the CAWG would next review and discuss the safe-harbor limit.

12% Planning Reserve Margin OK’d

The RSC also unanimously endorsed the Supply Adequacy Working Group’s recommendation to replace SPP’s capacity margin terminology with a 12% planning reserve margin requirement.

The revision request (RTWG-RR 187) was approved by the Markets and Operations Policy Committee in January. It incorporates previously approved policies that identify who is responsible for resource adequacy, the resource adequacy requirement and how and when the requirement should be met. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)

Personnel Moves

The committee also made several personnel moves. RSC Chair Steve Stoll, a commissioner with the Missouri PSC, announced Commissioner Kim O’Guinn (Arkansas Public Service Commission) and Board Member Dennis Grennan (Nebraska PRB) have been added to the Regional Allocation Review Task Force to fill their states’ seats.

Committee members unanimously agreed to establish a nominating committee for future RSC elections and to work out the details during their annual retreat in July.

February 7, 2017

CMS Touts Generation Reliability, Palisades PPA Replacement

By Amanda Durish Cook

CMS Energy reported that 2016 was its best year for generation reliability ever, as it retired more than half of its coal-fired facilities and announced plans to terminate a nuclear plant power purchase agreement.

The Michigan-based company last year retired seven of its 12 coal-fired generation units, representing about 1,000 MW.

generation reliability palisades cms — Palisades Nuclear Plant | *Palisades Power*

“Delivering operational success like this while at the same time transitioning our fleet so significantly requires a disciplined team,” CEO Patti Poppe said during a Feb. 2 earnings call.

The company boosted earnings for the year to $551 million ($1.98/share) from $523 million ($1.89/share) in 2015, although fourth-quarter earnings dropped to $77 million ($0.28/share) from $106 million ($0.38/share) a year earlier.

CMS plans to spend $18 billion over the next 10 years in capital expenses: $8 billion on gas infrastructure and maintenance; $4 billion on maintaining and building generation, including renewables; and $6 billion to upgrade its electric distribution. The company said it could spend an additional $3 billion on improving gas infrastructure, grid modernization, additional renewables and replacement of PPAs. Rate increases to pay for the capital improvements will be limited to 2%, CFO Tom Webb said.

Poppe said CMS will improve its financial position by terminating the Palisades nuclear plant PPA in favor of employing more energy efficiency, demand response, renewable power and coal-to-gas switching. (See Entergy, Consumers Announce Closure of Palisades Nuke.) According to CMS, the plan will save customers $172 million over four years.

Poppe said the substitute capacity plan for the Palisades PPA is “solid” and replaces a “single, big-bet capital project for many smaller options” with less risk. She said CMS could make more PPA replacements in the future by building new plants.

“We’ve long said that an inflexible, above-market PPA is not a cost-effective option for our customers and provides no long-term value for our investors. At the same time, we want to assure that we have sufficient resources to serve the load in Michigan,” Poppe said.

February 7, 2017

WEC Earnings Call Highlights Natural Gas Efforts

By Amanda Durish Cook

While year-over-year net income climbed about $300 million thanks to its Integrys acquisition, WEC Energy Group’s fourth-quarter earnings call focused largely on the company’s natural gas initiatives.

WEC reported net income of $194.4 million ($0.61/share) for the fourth quarter of 2016 compared to $179.3 million ($0.57/share) in fourth quarter 2015. Net income for the year was $939 million ($2.96/share) compared with $638.5 million ($2.34/share) for 2015, CEO Allen Leverett said during a Feb. 1 conference call. (See WEC Energy Shows $183M Profit After Integrys Deal.)

Leverett would not say whether the company plans to file a rate case with the Wisconsin Public Service Commission this year, saying only that its 2017 strategy is to keep rates flat while managing costs.

WEC projects 2017 earnings per share of $3.06 to $3.12, assuming normal weather. The company plans to continue its focus on natural gas distribution systems and infrastructure improvements.

The company signed an agreement Jan. 30 to acquire Michigan-based Blue Water Gas Holdings for $230 million. Blue Water, which owns an underground natural gas storage facility in Michigan, could provide up to one-third of the storage needs of WEC’s three gas distribution companies in Wisconsin through long-term service agreements as a subsidiary.

Leverett said WEC would file with the Wisconsin PSC for approval of service agreements for the storage. Leverett said the company chose the service agreements structure so the commission would not have to approve an out-of-state acquisition and WEC’s state-regulated companies would not be directly involved in an interstate natural gas business.

“I believe this investment will bring very meaningful customer benefits,” Leverett said, adding that there “certainly is room” for WEC’s own storage projects in the future.

UMERC Seeks OK for 2 Generators

New subsidiary Upper Michigan Energy Resources Corp. (UMERC) filed with the Michigan Public Service Commission on Jan. 30 to build two natural gas generating stations in Michigan’s Upper Peninsula. (See Michigan Upper Peninsula Getting its Own Utility.)

UMERC plans to pay about $275 million to build 180 MW of natural gas generation in two Upper Peninsula counties. If approved by the Michigan commission and MISO, construction will begin late this year or early in 2018.

“We are targeting commercial operation in 2019. At that time or soon after, we expect to be in a position to retire our coal-fired Presque Isle power plant. This should give significant savings in operations and maintenance expenses as well as reduce carbon emissions,” Leverett said.

WEC earnings natural gas — Presque Isle Power Plant | *WEPCo*

WEC’s five-year capital spending plan has increased from $9.2 billion to $9.7 billion with the spending on natural gas storage and Upper Michigan’s new gas generation. Leverett said the revised plan does not include $1.7 billion of capital investments in subsidiary American Transmission Co.

On Jan. 30, ATC’s development company and Arizona Electric Power Cooperative entered a joint operating agreement to create ATC Southwest. The new transmission company will develop transmission projects in Arizona, California and other parts of the Southwest. “The largest opportunities outside of the footprint are in the West,” Leverett said.

ATC’s return on equity is still in flux, Leverett reminded shareholders. In September, FERC approved a 10.32% base ROE for MISO transmission owners. (See FERC Cuts MISO Transmission Owners’ ROE to 10.32%.) ATC qualifies for a 50-basis-point adder and is currently recognizing a 10.82% ROE. However, in another pending docket, the same FERC administrative law judge who first lowered the return said MISO TOs’ ROE should be lowered further to 9.7% (EL15-45). With adder points, the decision could bring ATC’s ROE to 10.2%. Leverett said he expects an order by the end of June even with former FERC Chairman Norman Bay’s resignation and the current lack of a commission quorum.

February 5, 2017

FERC Sides with Wind Generators, Rejects SPP Reactive Power Filing

By Rich Heidorn Jr.

In a victory for wind energy advocates, FERC last week rejected SPP’s proposed method for measuring generators’ reactive power, saying it said would result in excessive and unnecessary costs (ER17-107).

The commission rejected the RTO’s October compliance filing in response to Order 827, which revised the pro forma large and small generator interconnection agreements to add reactive power requirements for all newly interconnecting nonsynchronous generators.

ferc spp reactive power filing — Smoky Hills Wind Farm in Kansas

Although the order required grid operators to ensure compliance by measuring reactive power at the “high-side” of the generator substation, SPP sought an “independent entity variation” allowing it to conduct measurements at the point of interconnection.

SPP said the variation was justified because its transmission system is dispersed over a wide geographic area and that many interconnection customers use longer generator lead lines to the point of interconnection to reach optimal parts of the transmission system.

The RTO said that measurements at the generator substation will not reflect “the charging or impedance” on the generator lead lines between that substation and the interconnection, creating a risk of excessive high and low voltages on the transmission system. SPP said that reliability standards would require the installation of reactive power compensation devices, at additional cost to transmission customers.

The proposal brought protests from several renewable generators and the American Wind Energy Association, which said the commission had considered the potential for long generator lead lines in their deliberations on Order 827. They also said SPP was not unique in having high-voltage nonsynchronous generator lead lines of 20 miles or longer.

The commission agreed, noting that Order 827 found that “requiring fully dynamic reactive power capability at the point of interconnection may result in significantly increased costs for nonsynchronous generators.”

Although setting reactive power requirements at the point of interconnection “would provide the greatest amount of reactive power to the transmission system,” the commission said, “the costs associated with providing that level of reactive power do not justify the added benefit to the transmission system.”

“In Order No. 827, the commission carefully considered the appropriate point at which to measure reactive power and ultimately found that ‘measuring the reactive power requirements at the high-side of the generator substation reasonably balances the need for reactive power for the transmission system with the costs to nonsynchronous generators of providing reactive power.’”

FERC also said SPP was not unique in its geography and had failed to provide information to support its reliability concerns. “Like SPP, other ISOs/RTOs have nonsynchronous generation interconnecting with the generator terminals located a significant distance from their point of interconnection. Similarly, SPP faces the same growing penetration of nonsynchronous generators as other ISOs/RTOs that in part resulted in the commission issuing Order No. 827,” the commission said.

It ordered the RTO to submit an additional compliance filing within 30 days.

February 5, 2017

FERC OKs Pipelines, Delegation Order Before Losing Quorum

By William Opalka

Preparing for the loss of its quorum, FERC last week issued an order delegating additional authority to staff and approved two massive natural gas pipelines that could have languished for months after former Chairman Norman Bay’s resignation.

The commission granted a certificate of public convenience and necessity (CPCN) on Thursday for the 510-mile Rover Pipeline, which would transport 3.25 million dekatherms/day from eastern Ohio to southern Michigan (CP15-93). On Friday, the commission approved a CPCN for Transcontinental Gas Pipe Line Co.’s Atlantic Sunrise pipeline, which would transport 1.7 million dekatherms/day from Pennsylvania to South Carolina (CP15-138).

The approval of Rover prevented a yearlong delay in construction. Tree-clearing on the project is prohibited between March 31 and Oct. 1 in Michigan, Ohio and Pennsylvania, and between Nov. 15 and March 31 in West Virginia, to protect the endangered Northern Long-eared bat, according to its environmental impact statement.

The commission also approved two smaller pipeline projects late last week:

A 99-mile pipeline proposed by National Fuel Gas Supply and Empire Pipeline to connect McKean County in north-central Pennsylvania to an existing main line in Erie County, N.Y. The project includes an interconnection to the TransCanada system at the Canadian border west of Buffalo. Empire will be able to transport 350,000 dekatherms/day into Ontario (CP15-115).
A 12.9-mile pipeline loop in Wayne and Pike counties in eastern Pennsylvania to serve Tennessee Gas Pipeline’s mainline that runs into New England (CP16-4).

The orders issued by FERC last week, Bay noted, added “more than several billion cubic feet of new gas pipeline capacity.” In all, the commission issued more than 60 orders last week, including issuances on capacity market rules in MISO, NYISO and ISO-NE, financial transmission rights in PJM, the Energy Imbalance Market run by CAISO and SPP’s measurement of reactive power.

In at least two of the orders, Bay issued statements recommending changes in FERC policies, including one criticizing the minimum offer price rule in capacity markets. (See related stories, Bay Calls for Review of Marcellus, Utica Shale Development.)

Loss of Quorum Sparks Fears

Bay resigned effective Feb. 3 after President Trump named Commissioner Cheryl LaFleur as acting chairman.

There were already two vacancies on the commission, so Bay’s departure left FERC with only LaFleur and Commissioner Colette Honorable — one member short of the quorum needed to resolve contested cases, including challenges to infrastructure projects. (See LaFleur Reinstates Morenoff as FERC General Counsel.)

A coalition of 14 energy trade associations representing the oil and gas industry, utilities, hydropower and nuclear interests wrote to Trump on Thursday urging him to fill the vacancies. “The absence of a quorum will leave the agency unable to tackle much of its important work promoting energy infrastructure for the benefit of U.S. energy consumers,” the letter said.

On Wednesday, U.S. Sens. Ed Markey and Elizabeth Warren, both Democrats from Massachusetts, expressed concern that rehearing requests for the recently approved Atlantic Bridge project would go unheeded. (See Atlantic Bridge Project Approved by FERC.) “We request that FERC immediately rescind the order authorizing the Atlantic Bridge pipeline project until such time as the agency has a newly constituted quorum in place that will allow it to hear an appeal of this project,” they wrote.

New Delegation Order

The commission on Friday delegated additional authority to staff to keep some cases moving (AD17-10).

Under the order, effective Feb. 4, Office of Energy Market Regulation (OEMR) Director Jamie Simler or her designee can:

Accept and suspend rate filings, and make them effective subject to refund and further order of the commission, or set them for hearing and settlement judge procedures. For initial rates or rate decreases submitted under Section 205 of the Federal Power Act, for which suspension and refund protection are unavailable, FERC staff has authority under FPA Section 206 to institute proceedings to protect customers’ interests.
Take “appropriate action” on uncontested filings seeking waivers of the terms and conditions of tariffs, rate schedules and service agreements (including waivers related to capacity release and capacity market rules) under the FPA, the Natural Gas Act and the Interstate Commerce Act.
Accept settlements not contested by any party or participant, including commission trial staff.

FERC staff also can extend the time for action on matters when permitted by statute. “By issuing the order today, the commission intends that to ensure that FERC staff has authority to prevent such filings from taking effect by operation of law during the no-quorum period,” the commission said in a statement.

The commission also said it would be guided by the 2012 Anti-Deficiency Act, which allows work to continue during a lapse in appropriations on activities the suspension of which would “imminently threaten the safety of human life or the protection of property.”

That ensures commission staff will continue inspecting and responding to incidents at LNG facilities and jurisdictional hydropower projects, FERC said.

All pre-existing delegations of authority to staff will remain in effect, FERC said. The temporary order will remain in effect until after the confirmation of a third member restores the quorum.

Because FERC commissioners are subject to Senate confirmation, that may not happen for months. Trump, focused in his first few weeks on filling out his cabinet and his Supreme Court pick, has not named any FERC candidates.

February 5, 2017

Bay Calls for Review of Marcellus, Utica Shale Development

By Rich Heidorn Jr.

WASHINGTON — Environmental activists opposing fracking and pipeline expansions regularly disrupted FERC meetings during Norman Bay’s two-and-a-half-year tenure as a FERC commissioner and chairman. On at least one occasion, activists took their protests to the street outside Bay’s D.C. house.

The activists contended FERC was shirking its responsibility by failing to consider whether the commission’s approvals of interstate natural gas pipelines were resulting in increased emissions. FERC has long insisted that such concerns are beyond its authority, as it doesn’t regulate the production of natural gas — a responsibility held by the states and the Interior Department.

marcellus utica shale norman bay — Protestors at Norman Bay’s home | *Beyond Extreme Energy*

But as it turned out, Bay had some misgivings about the commission’s legalistic reading.

In a five-page statement accompanying the commission’s ruling approving a 99-mile pipeline through Pennsylvania and New York on his last day in office, Bay gave his perspective on the impact of the shale gas revolution, lauding it for helping reduce electricity prices and carbon emissions but expressing concern about methane emissions and the potential for pipeline overcapacity (CP15-115).

Although it is not required to do so by the National Environmental Policy Act, Bay called on the commission to “analyze the environmental effects of increased regional gas production from the Marcellus and Utica” shale regions.

“Despite the growing importance of Marcellus and Utica gas production — it was 22.5 Bcfd in 2016 and is projected to surpass 44 Bcfd by 2050 — the commission has never conducted a comprehensive study of the environmental consequences of increased production from that region,” Bay noted. He said FERC should consider “the downstream impacts of the use of natural gas and … a life-cycle greenhouse gas emissions study.”

“As important as infrastructure development is,” he said, “it must also occur through processes that continue to promote public participation, transparency and confidence.”

Bay also said the commission should consider its reliance on signed agreements with shippers to determine the need for pipelines.

While these “precedent agreements” are useful indicators of need, Bay said the commission should also consider whether capacity is needed to ensure deliverability to power generators, reliability benefits and concerns “that anticipated markets may fail to materialize.”

He noted that LNG import terminals built during the early 2000s became stranded as shale gas largely eliminated the need for imports. “Overbuilding may subject ratepayers to increased costs of shipping gas on legacy systems. If a new pipeline takes customers from a legacy system, the remaining captive customers on the system may pay higher rates,” he said.

Bay — who resigned effective Feb. 3 after President Trump replaced him with Commissioner Cheryl LaFleur as acting chair — also had a parting shot at the minimum offer price rule in capacity markets. (See Bay Blasts MOPR on Way Out the Door.)

February 5, 2017

NYISO ‘Roadmap’ Sees Dispatchable DER by 2021

By William Opalka

New York envisions a future when distribute energy resources can participate in wholesale energy and capacity markets as seamlessly as any conventional generator.

To help get there, NYISO on Thursday released the final version of its DER Roadmap, which seeks to create flexible pathways for distributed energy to participate in markets as the industry moves away from a model based on central power stations. A fall workshop laid out a broad outline of how these resources could optimize the grid. (See NYISO DER Workshop Ponders the Grid of the Future.)

distributed energy resources dispatchable DER NYISO — | *NYISO Distributed Energy Resources Roadmap*

The document released last week provides more specific guidance and includes timelines and interim steps that could lead to implementing dispatchable DER rules in 2021.

“The NYISO’s market enhancements will permit dispatchable DER with various capabilities to participate in the wholesale markets. Integrating DER in this manner will require enhancements to wholesale market design, system planning and grid operations to better align resource investments and performance with system needs and conditions,” the report states.

DER can consist of demand management, power generation, energy storage or different combinations of all three aggregated into a single entity.

“The NYISO’s vison for dispatchable DER also aligns well with Reforming the Energy Vision in that it offers the potential to engage or animate certain consumers in ways that optimize grid utilization while helping these consumers better manage their own energy needs and costs,” Mike DeSocio, senior manager of market design, said at a media briefing Thursday.

| *NYISO Distributed Energy Resources Roadmap*

Other goals of the roadmap include the integration of DER into the energy, ancillary and capacity markets. “More fully integrating dispatchable DER will provide a means for DER to take advantage of real-time scheduling,” the report said. “It is important for the NYISO’s real-time systems to access and dispatch these resources in response to price signals reflective of grid conditions and needs.”

Improved load forecasts are seen as essential, as supply of distributed resources must be balanced with demand.

The roadmap also seeks ways to align compensation with system performance. The ISO said it intends to develop compensation aligning the flexibility and measured performance of DER with system needs, treating DER comparably with other resources.

Many of the DERs will be connected to the distribution network, unlike traditional generators, which are connected to the bulk transmission grid. The report said to ensure bulk power system reliability, an accurate representation of DER impacts at their interface to the grid is essential.

NYISO said the Roadmap is a starting point for discussions with stakeholders to develop market rules and operational protocols. It is also working with utilities to develop a series of demonstration projects that will require coordination or integration of DERs into the bulk power system.

February 5, 2017

FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests

By Rory D. Sweeney

FERC last week rejected rehearing requests over revisions to PJM’s financial transmission rights market, ruling in time for the RTO to implement the changes in its 2017 auction revenue rights allocation (EL16-6).

The commission’s Jan. 31 order upheld its Sept. 15 ruling that modeling assumptions PJM adopted to address FTR revenue inadequacy had resulted in unwarranted cost shifts between ARR holders and FTR holders. FERC also accepted PJM’s compliance filing in response to the commission’s requirement that it develop a method for allocating ARRs that doesn’t consider extinct generators. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)

PJM FERC FTR financial transmission rights — | *PJM*

Under the new rules, PJM will assign balancing congestion to real-time load and exports and regularly update its ARR allocations to reflect generator retirements. (See “Generators Displeased with FTR Adjustments,” PJM Market Implementation Committee Briefs.)

A variety of stakeholders, including the Independent Market Monitor, New Jersey and Delaware regulators, load-serving entities and the PJM Industrial Customer Coalition, had asked the commission to revisit the Sept. 15 order.

The requests focused on four points: netting the values of both positive and negative FTRs into a single portfolio for the FTR holder; allocation of balancing congestion; ARR Stage 1A overallocation; and PJM’s proposed 1.5% zonal load-forecast growth-rate adder to prevent infeasible ARRs.

On all four, FERC maintained its previous stance.

The commission rejected arguments that FTRs are meant to benefit only load. “FTRs were designed to serve as the financial equivalent of firm transmission service and play a key role in ensuring open access to firm transmission service by providing a congestion hedging function,” the commission said. “The purpose of FTRs to serve as a congestion hedge has been well established. … On the issue of cost causation, the commission found that while balancing congestion is currently allocated to FTR holders, FTR holders do not cause and cannot predict the level of balancing congestion.”

While the commission accepted PJM’s compliance filing, it rejected the RTO’s proposal to allocate any FTR overfunding surplus to ARR holders. FERC gave PJM 30 days to submit a compliance filing removing it.

“There was no finding in the Sept. 15 order that the current design with respect to surplus allocation is unjust and unreasonable, and there is no evidence that the changes required in the Sept. 15 order result in the current allocation of surplus funds as being unjust and unreasonable. Therefore, we find this aspect of PJM’s proposal as out of scope, without prejudice, and refer consideration of such changes to PJM’s stakeholder process,” the order said.

FERC accepted PJM’s requested effective dates, making replacement of historical source points for ARR allocations effective Feb. 1 and the Tariff provisions addressing PJM’s balancing congestion charge allocation effective June 1.

February 5, 2017

Bay Blasts MOPR on Way Out the Door

By William Opalka

FERC on Friday again rebuffed generators’ request to apply ISO-NE’s minimum offer price rule (MOPR) to 200 MW of renewable generation that were granted an exemption in 2014 (ER14-1639-005).

Although the order mainly rehashed old arguments, it offered Commissioner Norman Bay one last chance to blast the MOPR, which he did in a six-and-a-half-page concurrence.

ferc norman bay mopr — Bay | © *RTO Insider*

The commission rejected a request by NextEra Energy Resources, Public Service Enterprise Group and NRG Energy that it rehear its April 2016 order upholding the exemption. The 2016 remand order came after the companies challenged the exemption in the D.C. Circuit Court of Appeals. (See FERC Affirms ISO-NE’s MOPR Exemption for Renewables.)

The commission reiterated expert testimony and economic theory that it said indicated the renewables exemption was necessary to protect consumers from paying for excess capacity and did not suppress capacity prices. It said the results of Forward Capacity Auctions 9 and 10 in 2015 and 2016 — as well as the qualifying filing for FCA 11 on Feb. 6 — “substantiate the reasonableness of the commission’s original determination.”

Bay, whose last day at FERC was Friday, used the order to offer a parting shot at MOPR.

“Despite the best intentions of the commission, in my view, the MOPR has turned out to be unsound in principle and unworkable in practice,” Bay wrote. “No other market in the United States is subject to the same construct in which a federal agency reviews state action and imposes an administrative price floor on supply offers from certain resources that have received state support. This places the commission in direct and recurring conflict with the states, ignores the pervasiveness of state and federal policies that support resources in one fashion or another, and represents a significant intervention in the market that raises costs to consumers.”

Bay appended a similar statement to another order on Friday that endorsed a MOPR exemption for demand response resources in NYISO capacity auctions.

February 5, 2017

MISO Ordered to Change Storage Rules Following IPL Complaint

By Amanda Durish Cook

FERC ruled last week that MISO’s Tariff unreasonably limits energy storage, directing the RTO to craft more inclusive Tariff language within 60 days.

The commission concluded Feb. 1 that MISO’s Tariff “unnecessarily restricts competition by preventing electric storage resources from providing all the services that they are technically capable of providing” (EL17-8).

While MISO includes stored energy resources in its regulation market, it does not allow them to participate in the capacity, energy, ramp capability and contingency reserve markets.

The order came in response to Indianapolis Power and Light’s Oct. 21 complaint that the 20-MW battery at its Harding Street Station was capable of performing as a load-modifying resource but that the MISO Tariff prevented its participation. The battery can deliver 5 MW for four continuous hours, according to IPL.

IPL/AES Harding Street Energy Storage - FERC, MISO — Harding Street Energy Storage | *AES*

MISO has until the beginning of April to make Tariff revisions that “accommodate the participation of all electric storage resources, regardless of the technology, in all MISO markets that they are technically capable of participating in, taking into account their unique physical and operational characteristics,” FERC said.

The RTO had asked for IPL’s complaint to be dismissed, saying it was working with stakeholders on new storage definitions. It also cited FERC’s Nov. 15 rulemaking that would require RTOs to remove barriers to entry (RM16-23, AD16-20). (See MISO Asks FERC to Dismiss IPL Storage Complaint.)

Storage NOPR

FERC said that while the commission’s final rule resulting from the Notice of Proposed Rulemaking could address IPL’s concerns, the company had nevertheless met its burden under Section 206 of the Federal Power Act to demonstrate that the existing Tariff is unjust. The commission also said the final rule from its storage NOPR could take precedence over MISO’s compliance filing.

“In the event that MISO’s Tariff revisions conflict with the required tariff revisions in any final rule resulting from the storage NOPR, MISO may be required to adjust its Tariff to align with the commission’s determinations in that final rule,” FERC explained.

The commission did not find merit in two other grievances contained in IPL’s complaint. The company argued that MISO should have a compensation mechanism for automatic frequency control; the company also claimed that MISO’s dispatch protocols are tailored to flywheel storage only. (See IPL Asks FERC to Force Update to MISO Storage Rules.)

Although FERC said it was aware of the Eastern Interconnection’s declining primary frequency response, it agreed with MISO that it is currently sufficient to meet reliability under NERC’s BAL-003-1 standard.

“We agree with Indianapolis Power that primary frequency response is a critical requirement for interconnected grid operations, and that the Eastern Interconnection has experienced a decline of primary frequency response as compared to historic values,” the commission said. It also said MISO was not discriminating against battery storage, as all other providers of primary frequency response are likewise uncompensated. IPL’s storage facility has been providing MISO with primary frequency response since May.

IPL claimed that MISO’s current storage resource offer parameters would significantly shorten its battery’s life because it would result in a “dispatch of its battery at half-capacity continuously for one hour and then send a negative signal for the following hour to charge.”

But the commission said IPL failed to prove that MISO’s dispatch instructions would harm the battery, saying it “failed to cite to any Tariff provisions or business practice manuals that support this claim.”

FERC said MISO has previously informed IPL that while the Tariff requires a regulation resource “to be available for 60 minutes to provide regulation service, the actual market clearing and deployment will not cause the resource to be charged for one hour and then be discharged for one hour.”

IPL Responds

Lin Franks, IPL’s senior strategist for RTO, FERC and compliance initiatives, said that while the commission’s order did not grant the company’s request to be paid for “essential” primary frequency response, the commission has already made frequency response service a condition of interconnection with the grid in last year’s RM16-6 rulemaking. Franks said she expected additional industry discussion on the topic as resource mixes shift further and battery benefits become more “universally understood.”

“Our hope is to bring awareness of both the benefits of lithium ion battery storage and [its] regulatory challenges,” she said.

Franks said IPL will continue to promote the benefits of battery storage. “Technological advances in this field happen rapidly [and] understanding benefits and the regulatory changes needed to realize all these benefits can take years,” she added.