Page 1221 – RTO Insider

January 21, 2018

PJM MRC/MC Preview: Jan. 25, 2018

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.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:50)

Members will be asked to endorse the following proposed manual changes:

A. Manual 14F: Competitive Planning Process. Revisions developed to incorporate construction cost caps, the subject of special Planning Committee sessions. (See “Cost Cap Discussion Continues,” PJM PC/TEAC Briefs: Jan. 11, 2018.)

B. Manual 38: Operations Planning. Revisions developed from periodic review to include protection system/relay communication outages and PJM assessment of impact.

C. Manual 40: Training and Certification Requirements. Revisions developed to accommodate new exams and other training changes.

3. Gas Pipeline Contingencies (9:50-10:20)

Members will be asked to approve a problem statement and issue charge at their first reading to address how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as oil or a different pipeline. (See “Emergency Pipeline Switching Instructions Sparks Rights Debate,” PJM MIC Briefs: Jan. 10, 2018.)

4. RERRA Review of Energy Efficiency Participation (10:20-10:40)

Members will be asked to endorse Tariff and Reliability Assurance Agreement revisions associated with the Demand Response Subcommittee proposal for the relevant electric retail regulatory authorities (RERRA) review of energy efficiency resource participation in the capacity market. (See “Rules Endorsed for Enforcing Regulator Requirements on EE,” PJM MIC Briefs: Jan. 10, 2018.)

5. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (10:40-11:30)

PJM management will discuss its recommendation to the Board of Managers that the RTO file with FERC a capacity repricing proposal. Members will be asked to endorse proposed Tariff revisions for the Independent Market Monitor’s MOPR-Ex proposal to extend the minimum offer price rule to all resources. (See PJM Going it Alone on Capacity Repricing Plan.)

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to endorse:

B. Tariff revisions related to the procedures associated with the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)

1. FTR Modeling, Performance & Surplus (FTRMPS) (1:25-1:40)

Members will be asked to endorse revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. (See “FTR Changes in the Works,” PJM MIC briefs: Dec. 13, 2017.)

2. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (1:40-2:10)

Members will be asked to endorse proposed Tariff revisions associated with the proposal developed by the CCPPSTF. (See MRC item 5 above).

3. Incremental Auction Senior Task Force (IASTF) (2:10-2:25)

Members will be asked to endorse proposed Tariff and Operating Agreement revisions for proposal A”, which would reduce the number of Incremental Auctions from three to two following each Base Residual Auction. PJM says the change will reduce the opportunities for BRA sellers to “shop” for the cheapest replacement capacity while allowing them to cure a physical inability to satisfy their commitments. (See “Incremental Auction Revisions Endorsed,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)

4. RERRA Review of Energy Efficiency Participation (2:25-2:40)

Members will be asked to endorse proposed Tariff and Reliability Assurance Agreement revisions for the RERRA review of energy efficiency resource participation in the capacity market. (See MRC item 4 above).

— Rory D. Sweeney

January 21, 2018

House Panel Considers Bills on PURPA, LNG Exports

By Michael Brooks

A House Energy and Commerce Committee panel Friday heard testimony from federal officials and stakeholders on Republican legislation to expand LNG exports and revise the Public Utility Regulatory Policies Act. Support for the bills, introduced late last year, fell along party lines at the hearing.

PURPA Modernization

The PURPA Modernization Act of 2017 (H.R. 4476), introduced by Rep. Tim Walberg (R-Mich.) in November, would substantially reduce the number of PURPA qualifying facilities from which utilities would be forced to buy power.

Currently, QFs of 20 MW or larger are presumed to have nondiscriminatory access to the wholesale competitive markets and are thus ineligible to invoke utilities’ must-purchase obligation. The bill would reduce this threshold to 2.5 MW.

It would also make it harder for QF developers to game FERC’s 1-mile rule — the presumption that QFs located 1 mile or more apart from each other are separate facilities — by making that presumption rebuttable.

State regulators also would be allowed to exempt utilities from having to purchase from QFs if they determine that the utilities have no need for their power, or if utilities use integrated resource planning and conduct competitive procurement processes.

The provisions in the bill mirror solutions that critics suggested at a subcommittee hearing in September. (See Witnesses Offer Alternate Realities on Need for PURPA Reform.)

Testifying on behalf of the National Association of Utility Regulatory Commissioners, Montana Public Service Commission Vice Chairman Travis Kavulla praised the bill. “This legislation is an important and significant leap forward in providing us with the ability to secure a reliable and affordable energy future for the nation,” he said.

LNG Exports FERC PURPA — From left to right: Travis Kavulla, Montana PSC; Timothy Sparks, CMS Energy; Karl Rabago, Pace Energy and Climate Center; Paul Cicio, Industrial Energy Consumers of America; and Charlie Riedl, Center for Liquefied Natural Gas. | *Travis Kavulla*

Kavulla said PURPA forces state commissions to essentially guess a utility’s avoided costs, which usually results in overstated rates. Responding to a question by Rep. Bill Flores (R-Texas), Kavulla said, “The smaller the consumer base of the utility, the greater the potential magnitude of erroneous price forecasting from the regulator would be.” In the case of small municipalities and cooperatives, the city or county councils that regulate them “are probably even in less of a good position than I am to try to guess about the future market prices of energy for the purpose of establishing a rate.”

Karl Rabago, executive director of the Pace Energy and Climate Center, said the bill “proposes three significant and problematic changes to PURPA and should be rejected in favor a more measured and competition-friendly approach to addressing perceived concerns about electricity markets.”

“The real problem today is the need for modernization of the utility business model that is now more than 100 years old,” Rabago said.

LNG Exports

The Unlocking Our Domestic LNG Potential Act (H.R. 4605), introduced by Rep. Bill Johnson (R-Ohio), would amend the Natural Gas Act of 1938 to eliminate the Department of Energy’s role in approving requests to export and import gas. The NGA requires the department to determine whether import/export agreements are in the public interest before approving them. Trades with countries that have free-trade agreements with the U.S. are automatically considered in the public interest.

The bill leaves intact FERC’s jurisdiction over siting LNG terminals, as well as the president’s power to prohibit trade with countries under U.S. sanctions.

Republicans repeatedly emphasized the need to capitalize on the country’s supply of natural gas.

“We literally have more natural gas production capability in the United States than we know what to do with,” Rep. Joe Barton (R-Texas) said. The legislation “is simply an acknowledgement of that and says, ‘let’s use this economic resource that we have to benefit the rest of the world and create more economic benefit in the United States.’”

Democrats were less enthusiastic.

“I fail to see the need for almost any of the policy changes,” said Rep. Frank Pallone (D-N.J.), ranking member of the subcommittee. The bill “removes longstanding consumer protections and prevents DOE from ensuring exports of liquefied natural gas to non-free-trade-agreement countries are consistent with the public interest.”

So was Paul Cicio, president of the Industrial Energy Consumers of America, who said domestic gas supplies are not as abundant as commonly thought. Increased LNG exports could harm U.S. consumers by raising prices, he said. He called DOE studies used to determine whether trades with non-FTA countries were in the public interest “woefully inadequate.”

Cicio’s claims about the amount of domestic supply were challenged by Charlie Riedl, executive director of the Center for Liquefied Natural Gas, who said Ohio alone added 5 Tcf of proved reserves in 2016. (See No Agreement on Tipping Point for LNG Exports.)

“When we talk about a supply situation, it’s driven by market demand,” Riedl said. “As market demand continues to increase, we’re able to respond to that with supply.”

The other members of the panel, including those who only came to testify on the PURPA bill, agreed that there was no short-term threat to gas supply.

Steven Winberg, DOE assistant secretary for fossil energy, told the subcommittee that the Trump administration has taken no position on the bill. President Trump, however, has repeatedly emphasized expediting LNG exports, and Energy Secretary Rick Perry and EPA Administrator Scott Pruitt have traveled abroad to promote U.S. natural gas.

January 21, 2018

FERC Approves CAISO Resource Adequacy, MRTU Revisions

FERC last week issued decisions related to CAISO’s resource adequacy program and markets, as well as transmission service in the Pacific Northwest.

The commission approved six tariff revisions related to CAISO’s resource adequacy program (ER18-1). The order allows resources in a local capacity area to provide substitute capacity based on how that capacity is reflected in resource adequacy plans. It also accepted the ISO’s proposal to cap a load-serving entity’s monthly local capacity and system requirements at the same levels.

FERC CAISO resource adequacy winter reliability program — FERC granted Wheatridge Wind Energy’s request for an order directing Umatilla Electric Cooperative to interconnect with Wheatridge’s proposed wind energy project

The order is a follow-up to FERC’s October 2015 acceptance of a CAISO filing regarding updates to its reliability services initiative stakeholder process. The filing included criteria for qualifying capacity values of certain resource adequacy resources, must-offer obligations and other modifications.

In another order, FERC (ER17-1459) addressed modifications it had directed CAISO to make regarding its 2006 Market Redesign and Technology Upgrade (MRTU). CAISO’s latest compliance filing was on April 21, 2017.

FERC considered six directives it had issued, saying “we find that CAISO has either complied with the outstanding directives in the September 2006 MRTU order or has provided information demonstrating circumstances have changed such that further revisions are not necessary.”

In the Northwest-related order, FERC granted Wheatridge Wind Energy’s request to direct Umatilla Electric Cooperative to interconnect with Wheatridge’s proposed 500-MW project and provide it with transmission service to the Bonneville Power Administration balancing area (TX17-1).

FERC CAISO resource adequacy MRTU — FERC made several CAISO-related decisions on Thursday | © *RTO Insider*

The project would serve a collector substation in the service territory of Columbia Basin Electric Cooperative, which had protested Wheatridge’s application, arguing that it must be the exclusive provider of transmission service to the project. Umatilla supported the Wheatridge filing.

— Jason Fordney

January 21, 2018

NYPSC Approves New CCA, 4th VDER Tranche

By Michael Kuser

New York regulators last week approved the state’s third community choice aggregation (CCA) program, authorizing energy consultant Good Energy to provide five upstate municipalities with bulk purchasing of electricity and natural gas.

The Public Service Commission’s Jan. 18 order allows the new CCA to serve the villages of Fayetteville and Minoa in central New York, along with the village of Coxsackie and the towns of Cairo and New Baltimore near Albany.

CCA NYPSC community choice aggregation aggregation — NY DPS Staff and audience at the January 18th PSC session | *NY DPS*

Authorized by the PSC in 2015 under Gov. Andrew Cuomo’s Reforming the Energy Vision, CCAs can provide communities with lower energy prices as well as clean energy options, according to the PSC.

“Residential and small business customers can reduce their energy bills, take advantage of renewable energy choices and enjoy other money-saving services thanks to the leverage enabled by the bulk purchasing available through these community-based associations,” PSC Chair John B. Rhodes said.

While the five towns represent Good Energy’s first programs in New York, the company has helped create CCAs for more than 60 communities in other states, serving nearly 400,000 households and providing 3.3 billion kWh annually.

The commission previously allowed 20 municipalities in Westchester County to form a CCA (14-M-0224), and last year it approved a CCA by the Municipal Electric and Gas Alliance for several towns in central and upstate New York.

CCA NYPSC community choice aggregation aggregation good energy — Burman | *NY DPS*

Commissioner Diane Burman supported the measure, but she urged that all stakeholders affected by the decision be heard, especially low-income residents and consumer advocates.

“Out of the seven states that have done community choice aggregation, New York is the only state that has done this outside of the legislative process,” Burman said.

Communities can pass local laws to join or establish a CCA, but they must ensure that residents and small businesses can choose to remain a customer of a utility or energy service company (ESCO). Good Energy will help each of the five communities select an ESCO to manage its CCA, which could begin operating during the second quarter of 2018.

PSC Approves 4th Tranche of VDER

The commission last week also approved implementation of the fourth tranche in its Value of Distributed Energy Resources (VDER) tariff, continuing the transition away from net energy metering (NEM).

The PSC’s VDER Phase I order of March 2017 (Case NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)

“Several transition mechanisms were in that order,” Ted Kelly, assistant counsel for the Department of Public Service, told the commission. “Onsite mass market customers such as rooftop solar continue to receive net metering for all projects built before Jan. 1, 2020. Mass market customers — that’s residential customers as well as small businesses —participating in community-generated distribution projects, community solar for example, receive a market transition credit, or MTC, on top of the value stack.”

The commission’s Jan. 18 order recognized that several utilities had exceeded the limits of their capacity allocations under the program. Orange and Rockland Utilities last April filed a letter notifying the commission that 85% of the total megawatt capacity for its tranches had been allocated, but the utility continued to assign projects to Tranche 3, which is now 28 MW over its original 12-MW size.

In December, Central Hudson Gas and Electric told the PSC that it had reached 85% of its total allocation, and then subsequently filed an update that Tranche 3 had exceeded its 19-MW capacity, with 29.7 MW currently allocated.

Burman supported the measure but said, “I continually have felt that we are doing a delicate dance of being unwilling to admit that we may have a problem in going from net metering to [VDER] and the transition of that and what that means for when we lift and completely get rid of NEM and the grandfathering issue.”

Burman nonetheless said she supported the majority position of not disrupting the distributed generation effort and agreed that REV should ultimately decide alternatives to net metering.

January 21, 2018

FERC OKs Extended Window for MISO Capacity Auction

MISO obtained a one-time waiver of the deadline for its 2017/18 capacity auction after FERC last week agreed that technical difficulties on the RTO’s market platform was reason enough to extend the offer window.

While MISO normally closes the three-day offer window for its Planning Resource Auction at 11:59 p.m. ET, it said last year network connectivity issues caused by a hardware failure forced it to extend the window until 12 p.m. on April 1. Without the extension, at least one market participant would have been unable to submit or modify its offers during the final hours of the auction on March 31, according to the RTO.

MISO FERC waiver capacity auction market platform — | *MISO*

In its ruling last week (ER17-2113), FERC said that extending the offer deadline ensured “all market participants had the requisite time under the Tariff to submit their auction offers.” The additional time “provided sufficient, but not excessive, time for market participants to submit or modify offers,” the commission said.

MISO had assured the commission that the waiver will “not have undesirable consequences and that no third parties are harmed.”

All 10 zones in the RTO cleared at $1.50/MW-day during the 2017/18 Planning Resource Auction, a result of new supply and lower demand in the Midwest. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.)

Consumer rights watchdog Public Citizen questioned the waiver, claiming MISO failed to adequately describe what caused the connectivity issues or to explain what corrective actions it has planned “to avoid such disruptions in the future.” FERC disagreed with the group’s contention that MISO should have to provide additional evidence or detail any future plans stemming from the mishap.

― Amanda Durish Cook

January 21, 2018

Commission OKs SPP Price Corrections

FERC last week approved SPP’s request to issue price corrections and resettlements for a two-week period in December 2016, stemming from Omaha Public Power District’s retirement of its Fort Calhoun nuclear plant (ER17-2495).

After OPPD deregistered Fort Calhoun from SPP’s Integrated Marketplace on Dec. 1, 2016, the RTO established a replacement settlement location to recognize previously awarded transmission congestion rights (TCRs) at the plant. However, the market software did not model the replacement location’s correct shift factors, resulting in an overstated marginal congestion component and understated TCRs. The error was not corrected until Dec. 14.

FERC SPP Fort Calhoun price corrections — Fort Calhoun in 2016 | *OPPD*

In a September 2017 filing with FERC, SPP said the error did not affect other settlement locations. It requested commission approval for the repricing because it did not notify market participants of the contemplated price correction within five calendar days of the operating day, as required by its Tariff.

SPP told FERC the modeling errors were associated with the Fort Calhoun deregistration and were “human performance anomalies that have since been corrected.” The RTO said it can recalculate the prices “with accuracy,” ensuring that market participants that “unfairly suffered” from the error will be made whole and creating only a “minor monetary impact” for other participants.

The resettlements will amount to $145,000 in net payments to TCR holders at the location, and a net charge of $400 to the virtual transactions.

— Tom Kleckner

January 21, 2018

FERC: Ameren Illinois Formula Rate Stands

FERC on Thursday again rejected a challenge to Ameren Illinois’ formula rate while tamping down a rehearing request from Ameren itself (EL16-1169-001).

FERC Ameren formula rate — | *Ameren Illinois*

The ruling denying rehearing lays to rest a challenge by Southwestern Electric Cooperative and Southern Illinois Power Cooperative to Ameren’s 2015 $214.4 million projected net revenue requirement. FERC largely upheld the rate in a September 2016 order while ordering Ameren to change how it accounts for contributions in aid of construction; include net operating loss carryforward in its rate base; and exclude some charges for allowance for funds used during construction from its 2016 true-up. (See FERC Finds No Significant Problems in Ameren Rate Filing.)

Both Ameren and the cooperatives sought rehearing of the 2016 ruling, with the company arguing that FERC should have dismissed the cooperatives’ first challenge outright because of “nebulous and undocumented assertions.” The cooperatives said FERC had broken with commission precedent that allows “parties to challenge the inputs to the formula rate in the same way as they can challenge costs in a stated rate case” because the commission declined to investigate whether the challenged costs were recoverable.

FERC rejected both arguments. “The commission’s power to dismiss a pleading summarily is discretionary, and declining to exercise that power here is therefore not legal error,” it told Ameren. It told the cooperatives that their interpretation of commission precedent was inapplicable because they were challenging the rate itself and not seeking “after-the-fact corrections and updates.” Finally, the commission refused the cooperatives’ request to expand the proceeding into a broader investigation of Ameren’s expenses. Initiating such an investigation, FERC said, would be beyond the scope of the complaint.

― Amanda Durish Cook

January 21, 2018

Louisiana Regulators Question MISO South Max Gen Event

By Amanda Durish Cook

Louisiana regulators are questioning why MISO called a maximum generation event and issued instructions for conservative operations in its South region during an extreme cold snap last week.

Eric Skrmetta, chair of the Louisiana Public Service Commission, told The Advocate that he’ll seek an investigation into last week’s actions in MISO South, saying there was “no reason in the state of Louisiana for electricity to become short.” Commissioner Craig Greene said the agency would examine the electricity supply during the cold snap and look to identify ideas for better utility response in future frigid weather.

Reached by phone, a member of the PSC’s staff told RTO Insider that they were in the process of reviewing the event and declined to comment further.

MISO spokesperson Mark Brown said the RTO was able to maintain grid reliability even as extreme temperatures gripped the South and multiple generation outages posed challenges.

The RTO declared conservative operations and a cold weather alert for MISO South — which spans Arkansas, Louisiana, portions of Mississippi and part of eastern Texas — beginning Jan. 15, when most of Louisiana was under a winter weather advisory. It cautioned operators in the natural gas-heavy region to prepare for fuel restrictions.

The region set a new winter demand record of 32.1 GW on Jan. 17 as temperatures dipped to about 30 degrees Fahrenheit below normal and winter storm warnings were issued in Louisiana. The region’s all-time summer peak is 32.6 GW.

That same day, Entergy Louisiana reported that about 32,000 homes and businesses had lost power because of the winter storm, and it later thanked customers for responding to the conservation plea.

MISO South cold snap maximum generation event max emergency generation event — Entergy crews in snow | *Entergy*

The South region resumed normal operations late on Jan. 18, after the Louisiana PSC had issued a public appeal on behalf of MISO and Entergy Louisiana asking customers to conserve energy by lowering thermostats, sealing households against outside air as much as possible and postponing laundry and bathing during the unusually cold temperatures.

Louisiana tops all other U.S. states in energy consumption per capita, in part because of the number of oil refineries and manufacturing plants on the Gulf Coast, according to a report last year by the U.S. Energy Information Administration.

MISO South Executive Director of External Affairs Kent Fonvielle said the RTO shared the Louisiana PSC’s concerns about reliability.

“In extreme conditions such as this week’s bitter cold in the South, MISO delivers the value of a large footprint with a diverse energy mix and greater redundancies to address various challenges to operations,” Fonvielle said in an email to RTO Insider. “As the generation resources available to serve these extreme load conditions become strained, MISO has a set of procedures to ensure adequate supply and to keep the transmission grid stable.”

He added that, in such situations, MISO South calls on support from MISO Midwest and makes purchases from other RTOs. It’s also common for MISO to request that members activate their load control programs and issue public appeals for conservation, he said.

“It is rare for MISO to ask for conservation efforts, but ultimately those conservation efforts help protect the larger grid,” Fonvielle said. “Our role is to coordinate the best use of the power resources available across the MISO footprint so that it is reliable and cost-effective.”

Fonvielle said MISO appreciated the cooperation it received from South members, stakeholders and consumers to conserve energy during the peak conditions. He added that the RTO would perform its own review of the week’s events and have staff discussions on possible areas of improvement.

January 21, 2018

DC Circuit Rejects New England Scarcity Pricing Challenge

By Rich Heidorn Jr.

The D.C. Circuit Court of Appeals on Friday rejected New England generators’ challenge to FERC orders on scarcity prices, saying the commission had properly considered their complaints (16-1023, 16-1024).

The New England Power Generators Association had asked the court to review two FERC orders related to ISO-NE’s scarcity pricing rules and the peak energy rent (PER) adjustment, which is used to claw back some revenues earned by capacity suppliers when prices in the real-time energy market are very high.

Adjustment Events

ISO-NE each day calculates a strike price set just above the marginal cost of the RTO’s most expensive generation. It also estimates PERs — essentially the difference between the real-time energy price and the strike price — for any hour in which the real-time price exceeds the strike price (“adjustment events,” the court called them).

FERC ISO-NE scarcity prices NEPGA — Dynegy’s 827-MW Lake Road combined cycle plant, Dayville, Conn. | *Alstom*

The PER value is deducted from each capacity supplier’s monthly payments, regardless of whether it sold energy in the real-time market at the high price. NEPGA says most capacity suppliers clear their electricity offers in the day-ahead market, receiving the day-ahead market price, rather than the real-time price on which the adjustment is based.

The commission has acknowledged that this is a “potential inefficiency” and has approved elimination of the adjustment for the 2019/20 capacity commitment year.

Procedural Failure

The D.C. Circuit dismissed on procedural grounds NEPGA’s challenge to FERC’s May 2014 order rejecting a joint filing by ISO-NE and the New England Power Pool Participants Committee.

That “jump ball” filing contained two alternate proposals to address generator performance problems. The commission said neither proposal was sufficient alone, ordering ISO-NE to submit a modified version of its proposal along with increased scarcity prices suggested by NEPOOL (ER14-1050, EL14-52).

The D.C. Circuit said NEPGA lacked standing to seek review of the order because it had not previously sought rehearing from the commission.

Not Arbitrary or Capricious

The court did act on the merits of NEPGA’s complaint alleging that the interaction between the scarcity prices and the PER is unjust and unreasonable.

FERC said the group had not met its burden under Section 206 to prove that the existing Tariff provisions were unjust and unreasonable (EL15-25). The commission said NEPGA’s evidence — data from a Dec. 4, 2014, adjustment and a back-cast analysis — failed to consider the likelihood and size of future adjustments. It also said NEPGA did not address whether increases in day-ahead energy prices and capacity price floors might offset expected increases to the PER. (See FERC Denies Rehearings on ISO-NE Pay-for-Performance.)

The court said the commission’s rejection of the complaint was not arbitrary and capricious, noting that “because we are dealing here with technical and policy-based determinations, the commission’s judgment is entitled to judicial respect.”

Second Complaint

NEPGA said the court should overturn the commission’s rejection of its complaint because of the outcome of the group’s second complaint challenging the PER, filed in September 2016.

In that filing, NEPGA provided an additional 20 months of data in arguing that the PER had become unjust and unreasonable because of the increased scarcity rates.

The commission granted the complaint in part in January 2017 and set the case for hearing and settlement proceedings (EL16-120). (See ISO-NE Scarcity Rules Unfair to Generators, FERC Says.)

An uncontested settlement in that docket is pending before the commission. It would require ISO-NE to increase the daily PER strike price hourly based on the difference between actual five-minute reserve shadow prices and the pre-December 2014 scarcity prices for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively). The adjusted PER strike price would be effective Sept. 30, 2016, through May 31, 2018, when the PER is abolished.

“We note that any settlement would not fully moot this case because the second complaint proceeding has a refund effective date of Sept. 30, 2016, whereas the complaint in this case requested a refund effective date of Dec. 3, 2014,” the court said.

January 21, 2018

FERC Denies Louisiana PSC Clarification on Entergy ROEs

By Tom Kleckner

FERC last week denied the Louisiana Public Service Commission’s request for clarification on one matter related to a sprawling Entergy-related case before the federal commission.

The PSC was seeking to learn what specific proceeding would determine the return on equity that would apply to amended power purchase agreements that were the subject of an August 2016 order (ER16-1251). It requested the clarification following a January 2017 FERC order denying its request for a rehearing of the 2016 ruling. FERC had said the proceeding regarding the amended PPAs was not the right forum for determining the appropriate ROEs to be applied under a replacement tariff, finding the issues raised by Louisiana regulators to be outside its scope.

The PSC said “that if the appropriate ROE … is outside the scope of the instant proceeding, it does not appear the ROE will be addressed in any [FERC] proceeding.”

In its Jan. 18 ruling, FERC told the PSC it had explained in the 2016 order that issues concerning the application of ROE under Entergy’s unit power sales and PPAs are pending in the massive ER13-1508 docket. FERC also noted that it had already dismissed concerns by the PSC about applying a generic ROE to the amended PPAs.

FERC LPSC Entergy Power Purchase Agreements PPAs — MISO North and MISO South | *MISO*

FERC last week also approved an uncontested partial settlement related to adjustments in MISO Tariff transmission formula rate templates for Entergy’s operating companies (ER17-2579), directing the company to file a revised rate template in eTariff and terminating four related dockets (ER17-2579, ER16-1528, ER15-1453 and ER15-1436).

Entergy Services had objected to FERC trial staff’s October 2017 recommendation that it file a revised rate template for Entergy Gulf States Louisiana, but a settlement judge in November certified the partial settlement as uncontested.

The settlement memorializes adjustments to three items in the Entergy operating companies’ rate templates: excess accumulated deferred income taxes; certain permanent differences in income taxes; and the Entergy operating companies’ post-retirement benefit costs other than pensions for 2014 and 2015.