Page 1258 – RTO Insider

April 7, 2019

FERC Asks RTOs for more Details on Storage Rules

By RTO Insider Staff

FERC staff last week issued deficiency letters to all six jurisdictional RTOs and ISOs over their proposed energy storage rules, pressing for definitions, tariff citations and details on issues including metering, make-whole payments, and self-scheduling.

The grid operators are facing a December deadline for compliance with Order 841, which requires them to revise their market participation models to allow storage resources 100 kW and larger to provide capacity, energy and ancillary services within their technical ability.

The deficiency letters by the Division of Electric Power Regulation ranged from eight to 11 pages.

U.S. energy storage deployments by segment | *Wood Mackenzie U.S. Energy Storage Monitor 2018 Year in Review*

Jeff Dennis, general counsel of Advanced Energy Economy, said in a tweet that the detailed questions “demonstrate that FERC is looking for real compliance with the [requirements] to open the markets to storage, and not just paper compliance. Overall, I think this is a positive development.”

“They have some hard questions that go to the particular issues raised by commenters,” agreed Earthjustice attorney Kim Smaczniak.

Below is a summary of the issues raised by staff. The grid operators have 30 days to respond.

FERC Challenges CAISO on Storage Minimum

FERC cited seven major areas of concern regarding CAISO’s proposal (ER19 –468).

Staff wanted the ISO to explain, for instance, how it could reconcile the difference between its own minimum size requirement for storage resources of 500 kW, as noted in a Tariff appendix, with Order 841’s minimum size of 100 kW.

The commission also asked the ISO to explain if “it is CAISO’s position that each of the three participation models — the non-generator resources (NGRs) model, pumped storage hydro units model and demand response model — considered on its own, complies with all of the requirements of Order No. 841.”

FERC then asked the ISO to explain its eligibility requirements for storage resources to provide “all other services the CAISO procures on behalf of its market, including CAISO’s backstop capacity procurement mechanism.” And it requested CAISO elaborate on how it allows storage resources to derate their capacity to meet minimum run-time requirements.

Next, FERC asked CAISO to for an explanation of how “NGRs can be dispatched as supply or demand, set marginal price, self-schedule and otherwise participate fully in CAISO’s markets … [and] that pumped storage hydro resources can be dispatched as supply and demand, set wholesale market clearing prices, and submit bids and self-schedules.”

It asked the ISO to further describe its mechanisms for dealing with conflicting dispatch signals and for incorporating bidding parameters.

Then it ordered CAISO to cite Tariff provisions that ensure storage resources are charged the LMP for electricity stored for “later resale back to the market” and that the resources’ “charging is accounted for as negative generation” as required by Order 841.

Metering and accounting practices for charging energy rounded out the commission’s concerns.

“Please explain and provide citations to the relevant proposed Tariff language that demonstrates whether the NGR and pumped-hydro storage participation models prevent electric storage resources from paying both the wholesale and retail rates for the same charging energy,” it wrote.

– Hudson Sangree

Questions to ISO-NE Touch on Reserves

FERC Accepts ISO-NE Storage Tariff Revisions.)

The commission’s deficiency letter (ER19-4 7 0) asked the RTO to explain whether a continuous storage facility, if dispatched for reserves rather than energy and as a result experiences lost opportunity costs, would be compensated for its lost opportunity costs.

In addition, FERC asked the RTO to explain its “modified mechanism to permit electric storage resources with one hour or less of energy to provide only energy and not reserves,” and also how the RTO “will implement such mechanism prior to Dec. 3, 2019, the effective date of ISO-NE’s compliance filing.”

FirstLight Power Resources owns the largest pumped-storage hydroelectric plant in New England, the 1,143-MW Northfield Mountain Project on the Connecticut River in Massachusetts. | *FirstLight Power Resources*

Regarding the physical and operational characteristics, the commission questioned the RTO’s use of the term “maximum discharge time,” saying it “is not a characteristic defined by the commission or defined by ISO-NE.” FERC asked the RTO to either define the term or “confirm that ISO-NE intended this to be written as maximum run time, as defined by Order No. 841.”

The commission also asked whether some continuous storage facilities may have start-up or no-load costs, such as costs for cooling a storage facility that is online but not dispatched. “Could such costs be accounted for through non-zero values in the start-up or no-load cost parameters, similar to other resources that participate in ISO-NE markets?”

The RTO was also asked “to provide specific citations to the relevant existing and/or proposed Tariff sections that demonstrate that binary storage facilities and continuous storage facilities will not receive conflicting dispatch signals to charge and discharge simultaneously.”

— Michael Kuser

Staff Seeks Details on MISO Phased Participation

In an April 1 letter requesting more information on the plan, FERC said it could not process MISO’s Order 841 compliance filing until it clarifies several points regarding its phased participation approach, proposed commitment statuses, complexities for storage resources on the distribution system, conflicting offers and bids, and make-whole payments (ER19-465). MISO has 30 days to respond.

MISO and its stakeholders spent the better part of last year negotiating rules that culminated in a 1,300-page filing. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.) The RTO said it “anticipates significant uncertainty and risks related to the ability of MISO’s system and software to handle the participation of large numbers of very small” energy storage resources. It asked for a “phased approach in the accommodation of very small” storage resources that would limit participation of small storage resources to 50 in the first year of compliance and 150 in the second year.

MISO said that approach would give it time to “further develop and fine-tune its system and software to be able to handle potentially increasing numbers of very small” storage resources.

Harding Street Energy Storage in MISO | *AES*

But FERC directed MISO to specify what year it expects to provide market access to all storage resources that meet the 100-kW minimum threshold.

MISO must also explain how its must-offer requirement is affected when storage resources elect to use the RTO’s proposed dispatch status of “not participating” or other commitment statuses, the commission said. MISO’s filing proposed that owners of storage resources could choose between several commitment modes, including charge, discharge, continuous, available, not participating, emergency charge, emergency discharge and outage. MISO has said its discharging, charging and continuous modes will carry must-run designations.

FERC said MISO must clarify whether it proposes to levy transmission charges on storage resources when they are charging to resell energy later. MISO must also explain how it will help storage on the distribution system from making double payments — at both retail and wholesale — for charging energy.

The commission also asked if MISO would propose metering practices to manage the “complexities” of selling energy to a storage resource that will then resell the energy at the wholesale LMP.

MISO’s proposal requires storage owners to secure agreements with distribution companies that can deliver stored energy to the transmission system. FERC asked if MISO would require the same agreements when energy is moved from the transmission system to distribution-level storage, and it asked the RTO to explain a provision that prohibits distribution-level storage resources from pseudo-tying into a different balancing authority.

The commission also told MISO to cite Tariff provisions that will allow owners of storage resources to self-manage their state of charge.

FERC additionally said if MISO were to rely on existing Tariff provisions for a storage participation model, it should provide the commission with citations to the applicable market rules and pseudo-tie requirements for transmission-level resources. MISO must also describe how its filing will give storage resources access to all capacity, energy and ancillary service markets, as well as non-market services such as black start, primary frequency response and reactive power.

The commission told MISO to explain how its filing will prevent the same resource from submitting conflicting supply offers and demand bids for the same market interval. It also seeks to know if the participation model allows for make-whole payments when a resource is dispatched as load and the wholesale price is higher than the bid price and when a resource is dispatched as supply and the wholesale price is lower than the offer price. It also asked if resources available for manual dispatch will be eligible for make-whole payments.

Finally, FERC asked MISO to cite how it will allow storage dispatched as supply and demand to set the wholesale market clearing price as both a wholesale seller and buyer, as Order 841 dictates. The commission also asked for citations to support that storage resources can set the price in the capacity market, that MISO will accept wholesale bids from storage owners and that self-scheduled storage resources can participate in the market as price-takers.

– Amanda Durish Cook

NYISO Asked to Explain Dispatch-only Model

NYPSC Expands Storage, Energy Efficiency Programs.)

The commission’s letter asked NYISO to explain how its dispatch-only model will allow energy storage resources to reflect commitment costs in their bids consistent with other generators, and whether there are any circumstances that could preclude such a resource from effectively managing its capability to meet obligations through bidding (ER19-467).

NYISO said that energy storage resources will not be eligible for dual participation until the ISO develops and implements additional Tariff changes at an unspecified date.

Commission staff also asked whether resources with “limited commercial obligations” such as seasonal retail commitments or other contracts for a portion of the resource’s capacity would be prohibited from participating in the ISO’s markets. Staff also questioned whether a resource could register only a portion of its capacity as storage with the ISO and reserve the remaining capacity for other customers.

FERC’s questions ranged from basic — whether energy storage resources that have start-up costs will have an opportunity to recover these costs — to extremely technical.

For example: “Recognizing that the dispatch-only model alleviates some of the time it takes security-constrained unit commitment (SCUC) to develop a solution, what proportion of the additional time required to solve the SCUC is a result of using a dispatch-only model versus managing these parameters? In other words, could the amount of time saved by foregoing management of these parameters allow for the SCUC to make commitment decisions with an acceptable solve time?”

— Michael Kuser

PJM Queried on Pump Storage, 10-Hour Minimum

The commission cited 10 deficiencies within PJM’s proposal, mostly surrounding how existing Tariff language supports its proposed model for energy storage resources (ER19-469).

The RTO must first clarify how pumped storage hydro resources comply with Order 841, as well as whether a “capacity storage resource” is included in the definition of a “generation capacity resource” and whether one unit can serve as both.

Earthjustice’s Smaczniak said the question indicates FERC is “pushing back” on PJM requirement that storage offering capacity would have to continuously supply energy for 10 hours, which critics have called onerous. ISO-NE sought a two-hour supply, while NYISO proposed a four-hour minimum.

“So I read this as a very positive development for Order 841 implementation!” Smaczniak said.

The commission also wants existing Tariff citations that detail how the RTO will manage electric storage resources, including eligibility for nonsynchronous reserves; exemption from the day-ahead scheduling reserve process; participation in Tier I synchronized reserves; and eligibility for reactive service.

Invenergy’s 31.5-MW Grand Ridge Energy Storage project is 80 miles southwest of Chicago. | *Invenergy*

The RTO must also clarify whether a capacity storage resource is included in the definition of generation capacity resource as detailed in Schedule 9 of the Reliability Assurance Agreement. The commission wants more information on the “rules and procedures [that] specifically recognize the unique characteristics and capabilities of capacity storage resources and their relative ability to ‘maintain output at stated capability over a specified period of time.’”

PJM must also explain why storage resources deemed “out of charge” wouldn’t be considered an outage.

FERC wants to see the specific Tariff language detailing the process for dispatching and self-scheduling energy storage, as well as how the resources can participate as price-takers. Definitions for charge, discharge and continuous mode must also be submitted.

PJM must also detail the annual process energy storage resources must undergo when selecting a participation model and the corresponding Tariff revisions. FERC staff requested more detail regarding how the RTO will avoid conflicting dispatch and how resources in “continuous mode” will serve as demand and supply simultaneously.

FERC also seeks insight into how PJM determines which energy storage resources are eligible to receive make-whole payments, as well as how the RTO’s proposed model accounts for minimum state of charge, maximum state of charge, minimum charge time, maximum charge time, minimum run time and maximum run time in existing bidding procedures.

PJM must also explain how operators will use telemetered state of charge in day-ahead and real-time markets and why the RTO believes market sellers don’t have to submit minimum charge time, maximum charge time, minimum run time and maximum run time for situational awareness. FERC wants to know if resources can self-manage their state of charge and the penalties for deviating from their dispatch schedules.

The commission also appears skeptical over PJM’s position that metering requirements found in Manual 14D apply to energy storage resources because the cited language focuses specifically on telemetry for generators.

— Christen Smith

SPP Queried on LSE Rules

SPP’s initial response to Order 841 noted that it does not have a capacity market, but that load-serving entities are subject to a resource adequacy requirement. It said LSEs may designate capacity resources, including storage resources, to satisfy that requirement if the resource meets “the continuous run time requirement applicable to all resource types.”

The commission asked SPP to define the “continuous run time requirement” and to identify and describe any additional technical, operational or performance requirements resources must meet in order to qualify as a capacity resource “satisfying an LSE’s resource adequacy requirement” (ER1 9 -460).

SPP also told FERC that it does not “directly meter” facilities as the order requires to ensure a storage resource resells energy back to the market at the wholesale LMP. Instead, the RTO said, meter agents submit settlement meter values directly to SPP, and it proposed that, “consistent with the handling of pseudo-tied resources, the actual meter values of distribution-sited market storage resources may be split among the retail and wholesale use by the meter agent in both real time and for settlement.”

The commission requested SPP explain how its “metering and accounting practices” would comply with Order 841 by ensuring the energy would be resold back to the market at the wholesale LMP and that storage resources would be prevented from paying twice for the same charging energy. FERC also asked how the handling of metering and accounting for distribution-sited storage resources would be “consistent with the handling of pseudo-tie resources.”

The commission asked SPP to address deficiencies in three other areas, including storage resources’ participation in the markets as simultaneous supply and demand. SPP’s proposed tariff revisions would have storage resources “not continuously dispatchable across 0 MW” choose between offering supply or bidding in demand for a given market interval.

FERC requested SPP define a market storage resource that is “not continuously dispatchable across 0 MW,” and to explain why including the resources’ start-up time constraints in their offer parameters does not allow the RTO to accommodate resources’ simultaneous supply offers and demand bids in a given market interval.

The commission asked SPP to clarify how a storage resource will “self-charge” in the Integrated Marketplace, given that the RTO said it does not have a mechanism to explicitly manage their state of charge and “that it does not propose to add any such mechanism.” FERC also asked for clarification on whether proposed provisions to “decommit self-committed charging resources” to address insufficient capacity in the day-ahead and intraday reliability unit commitment processes apply to all storage resources or only to “market storage” resources.

– Tom Kleckner

April 7, 2019

FERC Denies NYDEC Rehearing on Northern Access

By Michael Kuser

FERC last week denied requests by New York state officials and the Sierra Club for rehearing and stay of its determination that the state had waived its authority to issue or deny a water quality certification for the Northern Access natural gas pipeline (CP1 5 -115-004).

National Fuel Gas Supply’s proposed 97 miles of pipeline would be capable of carrying about 500 MMcfd of gas from western Pennsylvania to the Buffalo area and also interconnect with the TransCanada pipeline.

The commission last summer ruled that the state Department of Environmental Conservation had waived its authority to issue or deny a water quality certification under Section 401 of the Clean Water Act by failing to act within one year of receiving National Fuel’s application.

Map shows facilities in a portion of the proposed Northern Access pipeline. | *National Fuel*

The case hinges on the date of receipt of the application, which FERC asserts was March 2, 2016, but which the DEC contends was changed by agreement with National Fuel to April 8, 2016. The department denied the application on April 7, 2017.

In its April 2 ruling, the commission faulted the DEC for citing cases that address waiver of rights in criminal proceedings, saying, “by contrast to the statutory schemes at issue in the cases cited by New York DEC, the Section 401 deadline cannot be waived by agreement.”

The commission cited Hoopa Valley Tribe v. FERC, in which the D.C. Circuit Court of Appeals considered whether waiver occurs when there is a written agreement to delay water quality certification. The court concluded that such an agreement constituted a failure and a refusal to act under Section 401.

“Hoopa Valley Tribe determined that a ‘deliberate and contractual idleness’ not only usurps the commission’s ‘control over whether and when a federal [authorization] will issue’ but would contravene Section 401’s intended purpose, i.e. to prevent a state’s ‘dalliance or unreasonable delay,’” FERC said.

National Fuel remains “committed to the project” and intends “to request a notice to proceed from FERC once all necessary authorizations are secured,” including permits from the U.S. Army Corps of Engineers, company spokeswoman Karen Merkel said.

The project faces a number of legal challenges that are currently pending in different venues. The targeted in-service date is 2022, Merkel said.

Cattaraugus Creek in western New York is one of 192 streams crossed in the state by the Northern Access pipeline route. | *National Weather Service*

In denying the DEC and Sierra Club their motion for a stay of the waiver order, the commission said, “The movant must substantiate that irreparable injury is ‘likely’ to occur. The injury must be both certain and great, and it must be actual and not theoretical. Bare allegations of what is likely to occur do not suffice.”

The commission also dismissed the DEC’s assertion that a state environmental assessment’s finding that the pipeline would have no significant impact — and a subsequent conditional certificate authority — were no longer valid given the department’s denial of the water quality certification. The DEC had argued that the environmental assessment assumed the existence of certain mitigation measures, including those set out in a future water quality certification.

“On balance, the Northern Access 2016 project, if constructed and operated in accordance with the application and environmental conditions imposed by the certificate order, would not significantly affect the quality of the human environment and would be an environmentally acceptable action,” the commission said.

April 7, 2019

SPP Seams Steering Committee Briefs: April 3, 2019

The SPP–MISO Joint Planning Committee has voted to begin a new coordinated system plan (CSP) this year, SPP staff told the RTO’s Seams Steering Committee last week.

The JPC, composed of planning staff from both RTOs, conducted the vote in March. The CSP is the first step in determining whether to build transmission projects that address interregional needs.

SPP Interregional Coordinator Adam Bell in February | © *RTO Insider*

SPP Interregional Coordinator Adam Bell told the SSC during its Wednesday meeting that the RTOs’ planning staffs are exchanging solutions submitted through their regional processes for the CSP “joint” needs. Staff are also finalizing a draft CSP study scope, he said.

The RTOs have not yet scheduled a meeting to share initial results with stakeholders, but they have identified six potential economic projects along the seam. (See MISO, SPP Seek Coordinated Plan in 2019.)

“We’ve identified modeling inconsistencies, but our models are always going to be different,” Bell said. “Once we posted the needs, that’s when both sides began looking into the models.”

The study could result in a first-ever interregional transmission project for the RTOs, which conducted CSP and regional reviews in 2014 and 2016. They were unable to reach an agreement on interregional projects both times.

Switchable Generation Plan with ERCOT Almost Complete

Staff told the committee that SPP will be executing a coordination agreement with ERCOT Board of Directors Meeting: Feb. 12, 2019.)

The grid operators have been working since 2016 on a new agreement to cover the four resources capable of switching between SPP and ERCOT. The plan applies only to the operations of the reliability coordinators and does not address financial obligations of the SWGRs directed to switch in emergency conditions, RTO staff said.

SPP’s Market Working Group will be responsible for developing new commitment statuses and a mechanism to uplift financial obligations of SWGRs instructed to switch to SPP from ERCOT.

Two of the resources belong to Golden Spread Electric Cooperative and have historically operated in SPP. The other two resources belong to Tenaska and operate in ERCOT.

M2M Payments Soar to $3.33M in February

SPP recorded $3.33 million in market-to-market (M2M) payments from MISO in February, the highest amount since last March and the ninth-highest since the two RTOs began the process in March 2015.

February also marked the 23rd month in the last 29 in which M2M distributions have flowed in SPP’s direction. SPP has now amassed $58.6 million in net payments from MISO.

Permanent flowgates along the SPP-MISO seam were binding for 244 hours, and temporary flowgates were binding for 245 hours. That resulted in $1.98 million and $1.35 million in payments, respectively.

Casey Cathey, the RTO’s manager of reliability planning and seams, told the SSC that staff hope to discuss with MISO potential changes to the M2M process. “My personal view is to optimize the system for congestion, rather than this clunky process,” he said.

— Tom Kleckner

April 7, 2019

Entergy Lays out New Carbon Reduction Goals

By Amanda Durish Cook

Having met its current carbon reduction goal ahead of schedule, Entergy now says it plans to further slash emissions over the next decade to well below levels seen 20 years ago.

In a report issued Wednesday, Entergy said it is “intensifying” its efforts, pledging to reduce its CO₂ emission rate to 50% below 2000 levels by 2030. If achieved, the company would produce about 24.6 million short tons of annual emissions, compared with 36 million short tons in 2017.

The announcement was rolled into Entergy’s 2018 Integrated Report, which combines the company’s annual shareholder report with its sustainability report. The company has already surpassed its previous commitment to reduce emissions to 20% below 2000 levels by 2020.

“The broad consensus of current scientific data on climate change indicates that, as an industry, we must do more to reduce our footprint and that of our customers and communities. Entergy sees this not as a choice but as a responsibility and an opportunity,” Entergy CEO Leo Denault wrote in a letter to stakeholders. “Speaking plainly, this means that for every unit of electricity we generate in 2030, we will emit half the carbon dioxide we did in 2000.”

In 2018, Entergy’s utility-only CO₂ emission rate was 763 pounds/MWh, lower than the national average of 1,009 pounds/MWh. The 2018 emissions rate represented a 28% reduction from 2000.

Since announcing its portfolio transformation strategy in 2002, Entergy says it’s replaced almost 30% of its older generating assets. Natural gas-fired generation now represents 60% of the company’s more than 25 GW in generating assets.

While Entergy is not releasing a supply plan, it did say the new goal could mean a supply mix that’s 60% natural gas, 32% nuclear, 7% renewable and slightly more than 1% coal.

Entergy estimates it currently has about 1 GW of renewable projects in “various stages of development.”

Denault added that Entergy’s 8.8-GW nuclear port f olio is a “critical source of safe, large-scale and virtually emission-free baseload power” that could make or break the company’s sustainability goals. Preserving the plants is crucial, he said.

Those statements come at a time when Entergy is seeking to offload two nuclear units outside its service territory to a subsidiary of Holtec International. Entergy expects to complete the sales of the Pilgrim plant in Massachusetts by the end of 2019 and Palisades plant in Michigan by the end of 2022. The sales are part of the company’s strategy to exit the merchant power business and re-establish itself as a pure-play regulated utility.

Entergy also released a separate analysis and risk assessment on climate change. The company concluded it should focus on coastal wetland restoration, renewable generation, grid modernization, emergency response, energy efficiency and electric vehicles. It also said it’s designing facilities that can withstand flooding and extreme weather events.

The company is simultaneously planning for load reduction, as customers invest in distributed resources, and load growth, from increased demand for cooling and refrigeration. It expects climate change impacts to be “especially pronounced” in coastal Louisiana and Texas, where risks from sea level rise, damaging storms and coastal erosion are highest. The company also predicted “potentially disproportionate” impacts for its low-income customers.

None of the four states in Entergy’s utility service territory has passed carbon emissions regulations, though Texas has a renewable portfolio standard and New Orleans has published a climate action plan aimed at halving emissions by 2030. However, Entergy predicts that a federal carbon tax will soon become a reality.

Entergy said it would hold off on making plans around any technologies it might adopt until they prove cost-effective.

“Some of the technologies viewed as necessary to reduce greenhouse gas emissions consistent with a 2-degree [Celsius] scenario do not exist today. Others currently are not commercially viable and would require significant resource investments to adopt at a scale that is cost-competitive with conventional generation resources,” Entergy said.

The company also said simply halving its total emissions by 2030 isn’t feasible. To meet a 50% net reduction in emissions by that time, the company said it would have to increase its zero-carbon generation from the current 37% of the fleet mix to nearly 55% by 2030. One analysis showed Entergy would have to add 9.8 GW of solar capacity and 5.3 GW of battery storage in order to achieve the reduction, a scenario the company deemed unrealistic.

April 7, 2019

NY Examines VDER Capacity Value Compensation

By Michael Kuser

New York officials, utilities and solar energy advocates are trading comments through the state’s Public Service Commission on what constitutes appropriate compensation for the capacity value of distributed energy resources (VDER) (Case 15-E-0751; 15-E-0082).

The comments come after the PSC in December issued a staff white paper regarding capacity value compensation and in January ruled that John F. Kennedy International Airport could have a solar project up to 5 MW compensated under the VDER program while having other solar projects dedicated to serving on-site load (Case 18-E-0766). (See NYPSC Clarifies Value Stack Capacity Limits.)

In the value stack white paper, Department of Public Service staff recommend replacing the market transition credit (MTC) model, a value based on installed capacity estimates, with a new “community credit” model to compensate participants of community distributed generation (CDG) projects.

The commission’s original VDER order in March 2017 directed that the state’s compensation scheme for eligible DER transition from net energy metering (NEM) to the value stack, which bases compensation on provided benefits. The PSC’s Jan. 17 declaratory ruling said, “The rated capacity of projects used solely for serving on-site load and not seeking compensation under the value stack or net metering should not be counted towards the rated capacity limit.”

Rate Design

The DPS’ Utility Intervention Unit (UIU) filed comments that addressed rate designs for post-NEM mass market customers — those with eligible on-site generation.

“The proposed rate relies in part on advanced metering infrastructure (AMI) capability, which New York utilities have not yet fully implemented,” the UIU said. “Thus, to the extent that AMI is required to participate in this rate, the proposal appears premature.”

The Clean Energy Parties (CEP) — an ad hoc group including the Solar Energy Industries Association, Coalition for Community Solar Access, Pace Energy and Climate Center, Natural Resources Defense Council, New York Solar Energy Industries Association and Vote Solar — filed com m ents supporting DPS staff’s recognition “that some aspects of the tariff, such as DRV [demand reduction value], were achieving a false sense of accuracy and recommends changes that will better align the financial signals sent to customers with the benefits they can provide to the distribution system.”

A 2-MW solar project at Mohawk Valley Community College was supported by a grant from the New York State Energy Research and Development Authority. | *NYSERDA*

The group said that for more than a year they have “made the case that the current tariff does not accurately reflect the value of distributed energy resources or provide stable enough compensation.” The state’s utilities show “a surprising misunderstanding of the development process for medium-sized to larger-sized solar energy facilities,” it said.

Utilities — including Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas and Electric — dismissed New York City’s advocacy of a higher MTC for Con Ed as unnecessary.

In addition to the 18 MW of projects identified in Tranche 0/1 as of March 1, 2019, Con Ed’s interconnection queue contains an additional 84.7 MW of eligible projects, including 42.5 MW of fuel cell projects, the utilities said. Because fuel cells are expected to operate at capacity factors in excess of 90% and achieve a high coincidence with the DRV, they will have the same cost impact as roughly 255 MW of solar installations, they said.

Resource Eligibility

The PSC last September expanded the eligibility of DER to be compensated under the state’s value stack tariffs, particularly standalone storage systems with 5 MW or less of capacity, including crediting to any clean generation technology that qualifies as a Tier 1 resource under the Clean Energy Standard (CES).

The new rules also make resources eligible for compensation that would qualify for Tier 1 but for their start date before Jan. 1, 2015, and also authorize interzonal crediting, allowing DERs receiving value stack compensation to apply credits to the bills of customers in the same utility territory but different NYISO load zones. (See NYPSC Takes Subway into Value Stack.)

In responding to the white paper, the utilities suggested that, rather than exposing customers to long-term commitments that provide limited customer benefits, DRV compensation should be tied to DER production during each utility’s service territory-specific peak hours.

“To the extent that the current 10-peak-hour window creates more volatility than is deemed necessary to support development of eligible resources, a modest expansion to 50 hours may be appropriate,” the utilities said. “Similarly, the [state’s] Office of General Services argues that behind-the-meter generation should also be eligible for value stack compensation. This proposal should be rejected as customers using generation to offset their usage are already avoiding distribution and energy charges.”

The utilities opposed creating a community credit, but if one is established, they also oppose the recommendation by large commercial and industrial end-users that its costs be allocated only to residential customers, favoring instead the same methodology as the MTC, which allocates costs to those customer classes that receive the benefit.

They also recommended that the PSC reject the CEP’s suggestion to establish a Distribution Planning Advisory Committee, saying that “such a committee is unnecessary and would duplicate the existing Distributed System Implementation Plan Advisory Committee” and also create an additional burden on stakeholder resources.

April 7, 2019December 13, 2023

Texas PUC Briefs: Week of April 1, 2019

Texas regulators last week praised ERCOT for its response to stakeholder criticism over how it handled an early March cold-weather event that prompted it to ask generators to reschedule planned outages.

Market participants publicly aired their concerns with ERCOT during a Technical Advisory Committee meeting March 27, arguing that the grid operator did not give the market a chance to work and that it had not adequately shared its insight into the market. (See ERCOT Generators Upset over Early March Weather Event.)

Since then, ERCOT has begun assembling a task force that will consider improvements to communications and procedures during anticipated emergency conditions; increasing the market visibility of ERCOT forecasts; reviewing how planned outages are delayed or withdrawn; and whether to develop cost-recovery mechanisms for outages postponed or canceled because of reliability reasons.

That was enough for the Texas Public Utility Commission to wave off a presentation by ERCOT Senior Director of System Operations Dan Woodfin during its open meeting Thursday. Woodfin had planned to deliver the same presentation he gave during two hours of discussion before the TAC.

“I’m happy to see you have a process now and you’re working on it,” Commissioner Arthur D’Andrea told Woodfin. “That’s promising to restore some confidence in the market and make some changes.”

“I would like the market participants to work this out at ERCOT, like we typically do,” PUC Chair DeAnn Walker said. “ERCOT acknowledges they can do things better. I’ve told everyone I’m not interested in going back and punishing anyone for anything that happened. I don’t want anyone dwelling on putting more arrows in Dan, because he got more than he deserved at TAC.”

The PUC opened a proceeding on ERCOT’s outage scheduling processes (Project 49378) and was moved to action after South Texas Electric Cooperative filed a complaint. STEC said it received an instruction to reschedule an outage at its 400-MW, lignite-fueled San Miguel plant less than 12 hours before maintenance work was to begin.

“ERCOT exercised what amounts to a free capacity call option … at great risk to both those generators and the market that have to perform maintenance or risk being subject to forced outages during the period of the lowest reserve margins the ERCOT market has ever seen,” STEC said.

Oncor ARR Reduced by $218M

The commission consented to Oncor’s request to reduce its annual revenue requirement by $218.8 million as a result of the Tax Cuts and Jobs Act of 2017 (Docket 48325).

The PUC directed Oncor to apply a 3.25% carrying charge to the amount of federal income tax expense it collects above the amount it would have collected since Jan. 1, 2018.

The commission also consented to staff’s wholesale transmission service charges for transmission and distribution service providers operating in the ERCOT system (Docket 48928).

Sempra-Oncor-Sharyland Hearing

The PUC held a prehearing conference Monday to accept exhibits for its April 10-12 hearing on proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities, and Sharyland Distribution & Transmission Services (Docket 48929).

The companies in October announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)

AEP Texas, Oncor Propose Asset Swap

AEP Texas and Oncor have filed an application with the PUC requesting transfer to AEP Texas of Oncor’s distribution assets and associated certificate of convenience and necessity rights in the Rio Grande Valley cities of McAllen and Mission (Docket 4 9402).

Under the proposal, AEP Texas would acquire Oncor’s distribution assets, valued at about $18 million, and about 54,000 retail distribution customers. Oncor acquired the customers during an asset swap with Sharyland Utilities in 2017. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)

— Tom Kleckner

April 5, 2019

Judge Rejects Liability Release in FirstEnergy Reorg

By John Funk

AKRON, Ohio — A U.S. bankruptcy judge signaled Thursday he will not confirm a reorganization plan for FirstEnergy Solutions that would have absolved its parent company from liability for environmental damages from its coal and nuclear power plants.

Bankruptcy Judge Alan Koschik of the Northern District of Ohio ruled orally from the bench that the “disclosure statement” FES must send to creditors describes a reorganization plan the court would find “patently unconfirmable.”

In other words, the judge has — at least for now — ruled the reorganization plan as proposed will not be confirmed.

FES said late Thursday it will submit a revised disclosure statement.

“Working with our advisors, we have already initiated action to address the court’s ruling and will submit a new request to have the disclosure statement approved in a timely manner,” said FES CEO John Judge. “The company remains focused on a plan that will significantly strengthen its financial position and allow it to exit Chapter 11 in 2019.”

Koschik said the restructuring plan giving broad protection to parent FirstEnergy Corp. does not meet case law established by the Sixth Circuit Court of Appeals.

Environmental groups, including the Sierra Club and a coalition led by the Chicago-based Environmental Law and Policy Center, had challenged the attempt to limit parent FirstEnergy’s environmental liability for months. The Ohio Consumers’ Counsel had also weighed in.

“Judge Koschik correctly determined that debtor FirstEnergy Solutions’ extraordinarily broad releases of environmental liabilities and responsibilities make the proposed reorganization plan ‘patently unconfirmable,’” wrote ELPC Executive Director Howard Learner in a statement released after the hearing.

Attorneys representing EPA, the Nuclear Regulatory Commission and other agencies weighed into the case aggressively in recent weeks saying FES lawyers had ignored them.

They made it clear they consider FirstEnergy responsible for power plant environmental damages and labeled the reorganization plan a “scheme.”

Koschik initially was not certain the bankruptcy court had the broad powers ascribed to it by FES attorneys to protect the parent company far into the future.

Complicating the situation was the court’s approval of a settlement FirstEnergy and FES negotiated last summer, with the concurrence of the major creditors. In exchange for indemnity, FE agreed to pay FES $600 million in cash and about $400 in services and limited guarantees.

While the judge approved that settlement, separating the two companies, he explained since then he did not approve the details absolving FE from future claims for environmental damage.

But in the months following that September 2018 court ruling, FirstEnergy ballyhooed the approval as proof it would now be profitable as a fully regulated, delivery-only company. That news helped push FE’s share price to a high of $42.13 in the last 52 weeks.

The stock tumbled more than 4% Thursday afternoon, closing at $39.44 on the New York Stock Exchange.

In filings late last month, opponents said approval of the proposed restructuring would make it difficult or impossible to file claims against FE over coal ash or nuclear contamination.

The OCC argued that, under the proposed reorganization, “FirstEnergy would be shielded from any claims or causes of action related in any way to the debtors’ businesses and property, including from any liability for the costly decommissioning of its power plants.”

“Were funds for decommissioning to be inadequate, for example, consumers or taxpayers might be (unfairly) called upon to fund FirstEnergy and FES’s power plant decommissioning liabilities to federal and state governments,” the OCC said.

April 5, 2019

Study: Frequency Response OK in Eastern Interconnection

By Rich Heidorn Jr.

ATLANTA — Despite the ongoing shift to renewables, the Eastern Interconnection has sufficient inertia to maintain system frequency for at least the next five years, according to a study released Thursday.

The Eastern Interconnection Planning Collaborative (EIPC), a group of 20 planning coordinators, conducted the study in response to a request by NERC’s Essential Reliability Services Working Group.

The working group had cited concerns about the retirements of synchronous generators such as coal and nuclear, which respond automatically to a frequency reduction by slowing down and releasing more energy into the grid. Asynchronous wind and solar power generators do not respond in the same way unless their inverters have been programmed to provide frequency control.

The EIPC’s study was released as a NERC standards development team (SDT) reviewing other aspects of frequency response issued a request for comment on continuing to rely on FERC Form 714 for data. (See “Comments Sought” below.)

Steven Judd, lead engineer in system planning for ISO-NE and chair of the EIPC Frequency Response Task Force, said the study provided reassurance in the near term and a foundation for future projects.

“This first effort to track the interconnection’s inertial response has established a framework and baseline for system planners to improve the system network models going forward, provide sufficient notice when the changing resource mix could have an adverse effect on frequency response and develop solutions to those adverse effects,” Judd said.

In order to prepare for the expected increase in nonsynchronous generation with reduced inertia, the rep o rt said planners will need improved frequency responsive power flow simulation models.

The report was based on several analyses, including benchmarking a historical frequency event with spring light load (SLL) cases, and concluded that about 45% of governors were providing primary frequency response, substantially higher than previous NERC studies, which pegged response at about 30%. Thus, for forward-looking frequency measures, 55% of the governors were disabled in the power flow model.

“It is expected future improvements to the modeling of governors through new compliance standards and updated simulation models from the software vendors will reduce the need for artificially disabling governor models to match historical performance,” the task force said.

FERC Order 842, issued in February 2018, requires all new generators seeking interconnections be equipped to provide primary frequency response. (See FERC Finalizes Frequency Respon s e Requirement.)

The EIPC task force tested three frequency events against the 2022 SLL Multiregional Modeling Working Group (MMWG) power flow case:

The loss of 4,500 MW of generation in 2007, the largest historical event seen on the EI;
The loss of 3,100 MW on April 27, 2011, the largest event within the past 10 years; and
The loss of 2,513.7 MW, the most severe single contingency for the EI as defined by NERC standard BAL-002-2(i) Requirement R2.2.

In all three events, frequency response fell no lower than 59.85 Hz, well above the 59.5-Hz initial set point that would trigger under frequency load shedding (UFLS).

Under a fourth benchmark — a 10,000-MW loss modeled to determine the margin available in the EI — the frequency dropped to a low of 59.64 Hz, still above the UFLS set point.

“In other words, the system inertia and primary frequency response will be sufficient even with expected retirements of synchronous generation and increases in nonsynchronous generation,” the report said.

The results of the analysis were submitted to NERC for inclusion in its 2018 long-term reliability assessment.

Comments Sought

On a related issue, the SDT for Project 2017-0 1 (Modifications to BAL-003-1.1) on Thursday issued a request for comments following a three-day meeting last week in Atlanta.

Phase II of the project is considering potential changes to make the interconnection frequency response obligation (IFRO) calculations and associated allocations more reflective of current conditions, considering load response and the generation mix.

The standard authorization request also requires the team to ensure that overperformance by one entity does not negatively impact the evaluation of performance by another and that measurements of primary frequency response are considered in addition to secondary frequency response.

“I think we’ve got a fairly balanced industry [view]” on the standard, said SDT Chair David Lemmons, of EthosEnergy. “Some people think things need to change. Some people are happy with where it is.”

The SDT aske d commenters to address the fact that load and generation data from Form 714 is two years old by the time it is applied to actual operations under the standard. In the interim, balancing authority (BA) footprints can change.

Rich Hydzik of Avista said Form 714 was adequate for use under the standard and expressed concern that more current data might be “less robust.”

“I don’t think we want perfection to be the enemy of good here,” he said. “What we’re looking for is a fair allocation on the interconnection and the BAs.”

Greg Park of Northwest Power Pool and SPP’s Daniel Baker noted Form 714 also does not include data from Mexico or Canada.

“I think [714] does an adequate job … 99% adequate,” Park said. “But that 1% is administratively burdensome.”

Hydzik suggested later the data source could be dictated by the “fundamental question” of whether it is generators alone that are responsible for meeting the frequency response requirement (FRR). He noted load reductions don’t provide much frequency response “unless generally you’re paying for load to drop.”

Including load strengthens the case for retaining Form 714, which includes load and generation data, he said.

“If you’re going to make the leap that energy-producing resources actually provide your FRR … then we kind of move into the situation where we look at generation-only numbers and … allocate that way. It starts to look a little bit like [Texas Reliability Entity] at that point. … They have shown us what it looks like to go with the generation approach.”

April 5, 2019February 5, 2025

SPP Solicits Interest in Western Real-time Market

By Tom Kleckner

SPP has cast a longing, yet casual, eye at Western markets for some time.

On Thursday, the Arkansas-based RTO made its long-held interest in the West official by “calling on interested utilities and other customers” to help build a real-time market “that will meet the electricity needs of the Western Interconnection.”

“We’re still a long way off from building anything,” SPP spokesman Derek Wingfield told RTO Insider. “We’re looking for people interested in an SPP market.”

Wingfield said the RTO, which has a footprint that stretches from Louisiana across the Great Plains to the Canadian border, has long had “casual conversations with some in the West” about the possibility of an SPP-designed market. Market services would be provided on a contract basis, allowing participants to maintain their independence from an RTO, Wingfield said.

SPP Region | SPP

SPP’s market would provide an alternative to CAISO’s Western Energy Imbalance Market, which was established in 2014 with the six-state PacifiCorp system as its first member. CAISO announced Wednesday it had added its first publicly-owned utility in the Sacramento Municipal Utility District and says its market has saved members nearly $565 million since it started. (See SMUD Goes Live in Wes t ern EIM.)

The RTO did not offer a timeline for its own imbalance market, saying once it found entities interested in market services, it would scope out the market’s needs before talking benefits and timelines.

Monroe would know. He has always been open to discussions with entities interested in joining markets, and he led SPP’s recent effort to absorb the Mountain West Transmission Group, an informal collaboration of 10 electricity service providers in the Rocky Mountains. That effort fell apart last spring, but it gave SPP a deeper insight into the Western Interconnection’s market needs. (See Mountain West, SPP Tout RTO Membership to Colo. P UC.)

In December, SPP will also become the reliability coordinator (RC) for more than a dozen Western entities. The RTO has been working closely with its new customers, future neighboring RCs and regulatory bodies to finalize the governance and operations plans for RC services.

“SPP understands Western utilities’ system needs and approach to business,” said SPP CEO Nick Brown. “Utilities have the daunting task of ensuring electric reliability and affordability for their customers. It’s been our experience that energy imbalance markets are a wonderful way to accomplish that.”

The RTO said its day-ahead market has provided participants more than $2.7 billion in savings since it launched in 2014, and it noted it has provided various services to “dozens of non-member organizations” on a contract basis.

“SPP has experience not only building and administering electricity markets but specifically doing it to meet the needs of a diverse group of customers,” Monroe said.

April 5, 2019February 19, 2025

Pa. Lawmakers Introduce 2nd Nuke Subsidy Bill

By Christen Smith

Pennsylvania lawmakers proposed another $500 million plan to subsidize the state’s nuclear industry and characterized as politically motivated ongoing criticisms that the effort represents a corporate bailout.

State Sen. Ryan Aument (R) introduced Senate Bill 510 on Wednesday, more than three weeks after a similar House of Representatives bill, HB 11, drew reproach for its perceived prioritizing of aging, expensive nuclear reactors over cleaner, cheaper forms of energy. (See Lawmakers Unveil $500M Nuke Subsi d y Bill.) Nuclear generation supplied about 42% of Pennsylvania’s net generation in 2017, compared with 4.5% for renewables, according to the Energy Information Administration.

“Powerful special interests have disingenuously branded any support for the nuclear industry as a ‘bailout,’ but in reality, current law stacks the deck heavily against Pennsylvania’s nuclear plants,” Aument sa i d. “Including nuclear energy in the state’s alternative energy plans will help level the playing field for the industry and ensure its long-term viability in Pennsylvania’s marketplace while simultaneously protecting ratepayers from higher electricity bills down the road.”

Three Mile Island

Like its House companion, SB 510 creates a third tier within the state’s Alternative Energy Portfolio Standard (AEPS) program, from which suppliers must buy 50% of their power by 2021. Unlike the House version, however, the Senate bill directs the Public Utility Commission to set credit prices and guarantee between 17 and 23% of Tier III sources purchased include non-nuclear suppliers, like wind and solar. The first two tiers of the AEPS include 16 renewable resource types with targets of 8% and 10%, respectively.

“Nuclear energy is the most efficient, carbon-free producer in our system,” Aument said. “The loss of Pennsylvania’s nuclear industry will inevitably lead to increased costs for ratepayers, a less reliable and resilient electricity grid, and a loss of billions of dollars for the state’s economy.”

Like its House companion, SB 510 looks to offset an estimated $4.6 billion in annual costs proponents claim would result from all five nuclear plants in the state shutting down: $788 million in higher electric prices; $2 billion in lost state GDP; and $1.86 billion in costs associated with carbon emissions and harmful criteria air pollutants, including SO₂, NO_X and particulate matter.

Exelon said it will begin the four-month process of closing Three Mile Island near Harrisburg in June if legislators don’t act. FirstEnergy has also scheduled Beaver Valley for early retirement effective 2021.

“Making long-term energy decisions based exclusively on short-term marginal cost would be foolish,” Aument said. “Far too often, Harrisburg is short-sighted and kicks the can down the road when faced with difficult economic choices. We have an opportunity now to do the right thing for ratepayers by preserving the role of the nuclear industry and avoid repeating the painful and expensive mistakes of the past.”

An analysis from ClearView Energy Partners determined the expanded carve-outs for non-nuclear resources in Tier III mean some of the state’s struggling reactors could still be priced out of the market. Both proposals require the PUC to rank resources based on environmental benefits, meaning low-generating reactors like TMI could be considered the “least beneficial” to operate, given SB 510’s additional targets in the third tier.

Skeptics Unsatisfied

Ryan Boop, Aument’s chief of staff, told RTO Insider the senator would not introduce a bill unless he was comfortable with the language.

“As such, we were very methodical in the drafting of SB 510 and took input from all six [Senate co-sponsors] and their staff members,” Boop said. “As a group, we sought feedback from the Public Utility Commission and various other sources. I think many of the differences in the two bills can be attributed to the additional time we had to draft the language and the additional input we received from the PUC and those other sources.”

But the modifications haven’t engendered any good will from the bill’s critics. Steve Kratz, spokesman for Citizens Against Nuclear Bailouts — a coalition of power generators and energy, business and manufacturing associations — characterized the long-awaited proposal as “disastrous.” He argued similar legislation in New York drove 99% of taxpayer funding for the program in 2017 directly into Exelon’s coffers.

“The ‘consumer protections’ and additional carve-out for renewables touted by the bill sponsors [are] a disingenuous attempt to distract away from the fact that this bill will irreversibly alter electric competition and force consumers to pay higher bills to benefit the special interests of Exelon, FirstEnergy Solutions and Talen Energy and shareholders,” he said.

PJM’s Independent Market Monitor said last month three of the RTO’s 18 nuclear facilities face revenue shortfalls through 2021, a natural reaction to competition. The three plants — Davis-Besse, Perry and TMI — each operate just one reactor, which is the source of their financial strain, the Monitor said. The remaining multiunit facilities, including the subsidized Quad Cities in Illinois, will remain profitable. Even without zero-emission credits, Quad Cities would cover its costs for the next three years, according to the Monitor. (See Monitor Says PJM’s Capacity Market not Competiti v e.)

The House Consumer Affairs Committee kicks off four weeks of hearings on HB 11 April 8. It’s unclear when the Senate will schedule meetings to discuss Aument’s bill, though it could come later this month.