Page 1178 – RTO Insider

May 6, 2018

FERC, NERC Recommend Expanded Black Start Testing

By Rich Heidorn Jr.

Coal plant retirements have not caused a shortage of black start resources, but grid operators should consider expanded testing, FERC and NERC said last week.

NERC, its eight Regional Entities and the commission released a study May 2 based on information from a representative sample of nine volunteer registered entities, a follow-up to a 2016 joint report. (See Utilities’ Restoration Plans Pass FERC, NERC Review.)

black start resources NERC coal plant retirements — New York skyline when half the city was in blackout due to a power failure during Hurricane Sandy in 2012. Midtown, with the Empire State Building, is in the background with the darkened East Village and other parts of downtown in the foreground.

“Although some participants have experienced a decrease in the availability of black start resources due to retirement of black start-capable units over the past decade, the joint study team found that the participants have verified they currently have sufficient black start resources in their system restoration plans, as well as comprehensive strategies for mitigating against loss of any additional black start resources going forward,” the new report says. “The joint study team also found that participants that have performed expanded testing of black start capability, including testing energization of the next-start generating unit, gained valuable knowledge that was used to modify, update and improve their system restoration plans.”

A next-start unit is the first generator in the cranking path to be energized using power from the black start generator.

The report recommends that:

Black start generators dependent on a single fuel develop alternative fuel capability or take other steps such as signing firm pipeline contracts. “Furthermore, the joint study team recommends that these black start resource owners work with their regulators as necessary, to develop alternative solutions to address potential fuel constraints.”
RTOs and ISOs consider further study of the adequacy of compensation for black start and other resources supporting system restoration, “including any potential threat or impact on black start resource procurement and retention under current compensation mechanisms.”
Grid operators coordinate transmission and generation registered entities to verify model data and ensure the accuracy of black start simulations. “The joint study team recommends that registered entities performing simulations of their system restoration plans, especially those with cranking path auxiliary loads at a next-start generating unit that are large relative to the black start unit, closely coordinate with generator owner(s) to ensure that the associated modeling data used to perform restoration plan simulations [are] accurate. For instance, the dynamic simulations should include energizing the cranking path and next-start generating unit start-up, using generator and load models that have been verified against electrical data captured during various normal system operations or disturbances.”
Transmission operators perform expanded testing of black start cranking paths, including testing during planned maintenance outages.

The report emphasized that its recommendations — while “appropriate for all registered entities responsible for system restoration” — are voluntary and “not subject to mandatory compliance with the recommendations, separate and apart from any obligations of mandatory reliability standards.”

The report also noted “beneficial practices” used by some that may not be universally appropriate. “The joint study team recommends that registered entities consider incorporating these practices, or variations thereof, as appropriate,” it said.

These practices included:

Coordinating the use of black start facilities across multiple transmission service footprints, allowing a black start unit to aid an adjacent area’s critical load.
Providing additional personnel to staff substations and perform safety watches on transmission lines during expanded testing. “At control centers, additional operators would manage and coordinate expanded testing so that system operators can focus on essential system operations with minimal distractions.”
Having black start generators sign agreements with next-start units to facilitate expanded testing.

May 6, 2018

Peak Details Vision for ‘Transitional’ RC

By Jason Fordney

Peak Reliability last week outlined a vision for reworking its current structure and reducing costs as it tries to prevent a mass exodus of customers to CAISO.

The reliability coordinator (RC) said the cost reduction will require reducing the size of its board of directors to three members from six, cutting executive jobs, and eliminating some manual and administrative processes. Its current membership and board would need to approve the changes. Peak has been an RC since 2009 and had a $45 million budget for 2018.

After Peak announced last year it would attempt to establish a West-wide energy market in a partnership with PJM, CAISO said it would depart the organization to become its own RC and offer the services to other utilities in the West. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)

CAISO peak reliability — Peak’s vision and timeline for Transitional RC | *Peak Reliability*

An RC provides member utilities services that help them meet NERC standards and requirements, and is entirely different from a market operator. Choosing Peak as an RC would not prevent an entity from joining CAISO’s market, and vice versa.

Peak said its funding amount will fall to $28.7 million if CAISO leaves and all other funders stay; it would be $31.2 million if CAISO remains with Peak under the transitional structure. If CAISO departs, remaining members would see a 10% cost reduction under the transitional RC, but if the ISO remains, all members would see a 30% cost reduction.

Peak spokeswoman Rachel Sherrard told RTO Insider that “the [transitional RC] is not a separate organization. It is how Peak would be structured and funded post 2019. It is not a dramatic change in terms of the tools and services that we as the RC currently provide.”

When asked last week about the likelihood of CAISO remaining with Peak, ISO spokesman Steven Greenlee said, “We are moving ahead with our plans to become a RC and offer those services to other entities in the West.”

Peak would operate under the transitional RC structure in 2020/21 and have a $23.5 million operating budget for 2020. It would offer core RC services that ensure reliability and meeting NERC standards, as well as optional services such as Hosted Advanced Applications and the WECC Interchange Tool, which validates E-Tags and confirms power transactions throughout the region. It would also offer interconnection-shared services that support reliability in the West, such as the Reliability Messaging Tool and Enhanced Curtailment Calculator.

After 2021, Peak and PJM would offer bundled market and RC functions, as well as RC-only services at a reduced price.

Peak CEO Marie Jordan last week provided stakeholders a presentation explaining the transitional structure. She also sent an April 27 letter to the organization’s funding parties, member advisory committee and reliability member representatives, touting its experience maintaining reliability of the entire Western Interconnection.

“Over the past decade, in collaboration with its stakeholders, Peak Reliability has built and operated that RC,” Jordan said in the letter. “CAISO has not. SPP has not.”

Peak said it will issue a straw proposal on May 21 that will describe how the transitional structure could be implemented.

CAISO said it expects to begin shadow operations with Peak in May 2019 and become the RC of record for its balancing authority by the end of June 2019.

May 6, 2018

MISO Reliability Group Examines Order 841 Impacts

CARMEL, Ind. — FERC’s extensive energy storage order has handed MISO’s Reliability Subcommittee a new set of to-dos, including devising a storage capacity accreditation process and deciding whether storage will be subject to a must-offer requirement.

MISO Reliability Subcommittee FERC energy storage FERC Order 841 — Harding Street Energy Storage interior | *AES*

The subcommittee will also vet a proposal that will determine whether energy storage owners or MISO will manage the state of charge for resources. The group will additionally consider broader issues around storage, including:

What information MISO needs about batteries to manage real-time operations;
The risks of allowing market participation of energy storage at times when it’s not dispatched; and
Whether MISO should employ reliability improvements to mitigate risks of storage use.

Finally, the group could lay out rules to clarify that energy used for charging is not considered “station power,” which MISO defines as the power a generating facility uses for operating electrical equipment. MISO’s current definition of station power does not include energy used for pumping at a pumped storage facility.

The items were handed down from MISO’s Steering Committee based on recommendations made from the Energy Storage Task Force after discussions on Order 841 and storage’s potential in the RTO.

MISO Reliability Subcommittee energy storage FERC Order 841 — Harding Street Energy Storage exterior | *DOE*

At a May 3 RSC meeting, MISO Market Design Manager Kevin Vannoy said the RTO will bring storage participation straw proposals to a June 6 joint meeting of the RSC, Resource Adequacy Subcommittee and Market Subcommittee. He said MISO will vet storage proposals throughout summer to prepare for a December compliance filing.

Vannoy said MISO still hopes FERC will allow it to set a limit on the number of storage resources that can participate in its markets. FERC’s order set a 100-kW minimum size requirement for participation, causing RTO staff to worry that small resources will flood markets with finite capabilities.

— Amanda Durish Cook

May 6, 2018

Maine Lawmakers Signal Opposition to NECEC

By Michael Kuser

The leaders of two key Maine legislative committees told Massachusetts regulators Friday that they oppose a proposed transmission project that would cross Maine to deliver a large amount of Canadian hydropower to Massachusetts.

In a letter to the Massachusetts Department of Public Utilities, the chairmen of Maine’s joint Environment and Natural Resources Committee and Energy, Utilities and Technology Committee objected to Central Maine Power’s (CMP) New England Clean Energy Connect (NECEC) project on economic and environmental grounds.

The Avangrid subsidiary is set to sign a contract this month with Massachusetts for the state’s 9.45-TWh clean energy solicitation, which was awarded to NECEC — a partnership between CMP and Hydro-Quebec — after the original winner, Eversource Energy’s Northern Pass project, was rejected by siting officials in New Hampshire. (See Mass. P i cks Avangrid Project as Northern Pass Backup.)

The Maine lawmakers wrote that recent expert testimony to their state’s Public Utilities Commission “indicates that Hydro-Quebec will not produce any additional hydroelectricity for NECEC and will instead divert power it now sells to other markets, such as Ontario and New York, to Massachusetts. In fact, NECEC may result in increased greenhouse gas emissions if markets like Ontario or New York have to use dirty fuel mixes to replace the lost electricity from Hydro-Quebec.”

The lawmakers also faulted NECEC for planning to build its line across the Kennebec Gorge, a “world renowned” whitewater rafting and fishing area.

clean energy solicitation NECEC ISO-NE — New England Clean Energy Connect (NECEC) shown in orange | *Central Maine Power*

“It has not proposed burying any portion of the 53 miles of new transmission line, even at this iconic spot that is critical for Maine’s tourism economy,” said Republican Sens. Tom Saviello and David Woodsome, and Democratic Reps. Ralph Tucker and Seth Berry.

AC Better than DC

Among those testifying to the Maine PUC on April 30 was Stephen Whitley, former NYISO CEO and ISO-NE COO, who appeared on behalf of NextEra Energy Resources.

Whitley said that, unlike other proposed HVDC transmission lines in the region, CMP’s project is completely overhead, and that it would be much more useful to build an AC line “that can be looped, serve load and interconnect other renewable generators.” A DC line would not support interconnecting multiple generators located at different points of interconnection along its route, he said.

In addition, Whitley said, NECEC is not traditional utility transmission, but a merchant project dependent on the market. If contracted by Massachusetts, it will execute only a 15- to 20-year power purchase agreement with the electric distribution companies for a DC transmission line that has at least a 40-year life.

“Thus, even if one accepts the purported needs and benefits CMP attributes to the transmission line for Maine and Massachusetts, there is a cliff on those needs and benefits once the PPA expires,” Whitley said.

Fair and Equal

The Maine lawmakers also faulted CMP for offering “far less to Maine than Eversource offered New Hampshire during the Northern Pass process.”

New Hampshire would have received more than $210 million in benefits from Northern Pass, they said, while the TDI New England Clean Power “project would have resulted in direct payments of $372 million to Vermont for clean water, habitat conservation and clean energy development. CMP has not offered comparable mitigation for Maine.”

They cited other testimony before the PUC that the NECEC project “will suppress existing and future renewable energy generation in Maine due in part to increased congestion on the transmission system.”

The lawmakers concluded: “We are unwilling to sacrifice future development of Maine’s solar and offshore wind industries, which would provide real greenhouse gas benefits and more jobs for Maine citizens, just to provide Hydro-Quebec the ability to market its electricity in Massachusetts.”

Hydro-Quebec partnered separately with Eversource, Avangrid and TDI-NE on three different transmission projects for the MA 83D clean energy solicitation last summer.

May 6, 2018

CPUC Cautions of Return to Bad Old Days

By Jason Fordney

California could return to the conditions preceding the energy crisis of the early 2000s if the transition to fragmented decision-making and electricity procurement is not managed correctly, the Public Utilities Commission said in a report issued last week.

The report on California retail electricity choice, entitled “An Evaluation of Regulatory Framework Options for an Evolving Electricity Market,” is meant to guide the discussion as the CPUC, state lawmakers and other entities work to manage the disaggregation of energy procurement from traditional utilities to an environment with much more residential rooftop solar, community choice aggregators (CCAs) and private electricity sellers through the state’s Direct Access program, which allows nonresidential customers to purchase directly from a competitive supplier.

According to the paper, decision-making around reliability, affordability and safety is splintering from central authorities such as the CPUC to multiple entities.

“In the last deregulation, we had a plan, however flawed,” the report says. “Now, we are deregulating electric markets through dozens of different decisions and legislative actions, but we do not have a plan. If we are not careful, we can drift into another crisis.”

The paper examines how electric delivery can remain reliable as the market fragments, particularly from the growth of CCAs. It expresses concerns about reliability, affordability and ability to decarbonize the electric system if the transition is not managed effectively.

CPUC energy crisis direct access program — | *California PUC*

During the energy crisis, market design flaws, insufficient monitoring and “gaming” by market participants caused price spikes, collapse of competitive suppliers and rolling outages. The state became the model for how not to manage electricity restructuring and received much attention, particularly regarding the artificial shortages created by the Enron energy trading firm.

Splintering Model

The current model was developed after the crisis, with load-serving entities required to demonstrate each year that they have contracted for adequate energy supply. The paper poses the question of whether there needs to be a single entity responsible for policymaking, implementation and enforcement.

It also explores how new technologies could be financed, how to reduce the use of fossil fuels such as natural gas and how to properly compensate utilities. It also asks whether there should be a state entity to manage “behind-the-meter” generation and other entities that are not under the jurisdiction of the CPUC, as well as evaluating other regulatory models that evolved in New York, Illinois, Texas and Great Britain.

“I think there are solutions to a lot of the potential problems, although there is not a single or a dominant design to target them,” CPUC President Michael Picker told RTO Insider last week. He added that some customer choice models are built around a particular technology such as rooftop solar, battery storage, demand response or natural gas fuel cells that can be obtained through small generator incentive programs.

“We have to do something to address the disaggregation of supply and the splintering of decision-making,” Picker said. About 13% of load across the state is provided through the Direct Access program to commercial and industrial customers.

It’s not the CPUC’s job to get in the way of CCA growth, Picker said, but “we do have to do something to respond to the growing disaggregation.”

CCAs Respond

The CPUC got pushback from CCAs in February when it approved an order implementing a registration process for them along with other changes to the regulatory structure. (See CCAs Oppose CPUC Decision, Process.)

In a statement Thursday, the California Community Choice Association said the CPUC report “wrongly asserts today’s energy system lacks regulation and adequate planning.”

“Highly regulated locally controlled CCAs were designed to help correct the problems from the energy crisis, and they are performing as intended — delivering reliable, affordable and clean energy to local customers, while exceeding the state’s [greenhouse gas] goals,” Executive Director Beth Vaughan said. “It is important to recognize in this report that other states use energy-choice program models that differ widely from those used by CCAs in California.” She said CCAs are committed to “reliability, affordability, decarbonization and social equity.”

The CPUC said the report is not meant to advocate specific policy actions but seeks instead to “jumpstart a conversation.” Comments on the report are due on June 4, which can be filed at customerchoice@cpuc.ca.gov, and the commission has also set up a webpage for the initiative.

May 6, 2018

NRG Posts Q1 Profit on Asset Sales, Cost Savings

By Michael Kuser

NRG Energy is transforming itself by “right-sizing” its generation fleet, reducing costs and expanding its retail business, the company’s chief executive said during an earnings call Thursday.

NRG earned $233 million in the first quarter, compared with a loss of $169 million in the same period last year.

CEO Mauricio Gutierrez said the improved results were driven by $80 million in cost savings and higher energy prices caused by cold weather in Texas and the Northeast.

NRG continued to reduce its generation fleet last quarter, closing on the $42 million sale of its 154-MW Buckthorn Solar project to NRG Yield. The company also announced the sale of its Canal 3 peaking plant in Sandwich, Mass., for approximately $130 million, with the deal expected to close in the third quarter. It expects to close $3 billion in asset sales this year.

NRG last quarter also spent $210 million acquiring supplier XOOM Energy, expanding the company’s retail sales capabilities and presence in the East.

Texas Shines

While the company has in recent years highlighted the significant risk of retirements and the slowdown in new builds in ERCOT given persistently low power prices, Gutierrez pointed out the situation is showing signs of reversal.

“Last year, we finally saw the retirement of about 4,200 MW of uneconomic coal generation, which tightened reserve margins,” Gutierrez said. “As a result, we are entering this summer with the lowest reserve margin on record at around 10%. Prices have responded accordingly with summer on-peak prices currently trading at about $150/MWh.”

NRG Energy Inc. capacity auction earnings q1 2018 — NRG Headquarters in Princeton, NJ. | *NRG*

Asked whether he expects Texas to see an increase in either new gas-fired generation or more utility-scale solar coming online in response to the high peak prices, Gutierrez said one season does not mean much when deciding on a 25-year investment.

“So far, what we have seen is only the expectation on one summer of high prices,” Gutierrez said, adding that in an energy-only market such as ERCOT, “price is everything,” providing the “right signal and incentive” for developers to invest capital in the market. “So, you need to see two things: You need to see them high enough and you need to see them long enough to attract this capital investment.”

PJM Capacity Auction

Gutierrez also highlighted the PJM capacity auction for planning year 2021/22 being held this month, with results scheduled to be posted May 23.

“Last auction saw a slowdown in new builds and over 7 GW of announced retirements added to the PJM deactivation list this year,” he said. “But there is still uncertainty on how these will play out in terms of market tightening. As you are aware, some generators are seeking compensation for plants that are not needed for reliability and not economically viable.

“While some entities are grasping a bailout in the short run, we see capacity rationalization as a necessary first step towards a healthy market,” Gutierrez said. “And we are confident that there will be continued support for the competitive market value proposition. Beyond PJM, our risk portfolio is well-positioned given our fuel diversity and location near load pockets.”

Gutierrez referred to the “uncertain” effect of “all these out-of-market conversations that are happening today.”

But, he said, “I am encouraged by seeing FERC and the different ISOs take a very specific stance in terms of the protection of competitive markets and making sure that they don’t negatively impact those markets.”

Quotes courtesy of Seeking Alpha.

May 6, 2018

Con Ed Braces for Possible Regulatory Storms

By Michael Kuser

Consolidated Edison’s first-quarter earnings jumped more than 10% on an increased rate base and a weather-related boost in steam revenues, but the company noted Thursday that it faces regulatory scrutiny for its role in subway power outages, its tax accounting and its storm response preparedness.

The company earned $428 million in the first quarter, compared with $388 million in the same period a year ago.

“While we continue to face challenging weather events, we remain focused on our long-term strategy of providing customers with the technology and options they need to live and work today,” CEO John McAvoy said in a statement accompanying Con Ed’s May 3 earnings release.

Regulatory Update

A company presentation pointed out that, in a proceeding investigating a New York City subway power outage last April, the New York Public Service Commission last year issued orders requiring Consolidated Edison Company of New York (CECONY) to upgrade the electrical equipment that serves the subway system. The utility plans to complete the required actions this year.

The PSC in January also initiated an audit of the income tax accounting of certain state utilities, including CECONY and sister utility Orange and Rockland Utilities (O&R), which serves customers in southeastern New York and northern New Jersey (18-M-0013).

Con Ed earnings Q1 2018 NYPSC — ConEd plant on the East River at 15th Street in New York City

Con Ed noted that two storms in March damaged its utilities’ electric distribution systems, interrupting service to approximately 209,000 CECONY customers, 93,000 O&R customers and 44,000 Rockland Electric customers. Con Ed said the recovery of $106 million in storm-related costs is subject to review by the PSC and the New Jersey Board of Public Utilities, both of which are investigating utilities preparation and response to the storms, and may penalize them.

O&R last month updated its January rate filing with New York PSC, asking to increase its electric rates from $20.3 million to $22.5 million.

Tax Cuts and Rates

Con Ed expects the federal Tax Cuts and Jobs Act of 2017 to result in customer rates likely being reduced to reflect the reduction in the corporate tax rate from 35% to 21%, elimination of bonus depreciation and the amortization of excess deferred federal income taxes the utilities collected from their customers that will not need to be paid.

The PSC opened a proceeding on the new law (17-M-0815), and commission staff on March 29 recommended that most utilities be required to begin to credit their customers’ bills with the net benefits of the tax cuts on Oct. 1.

The company expects a commission decision after the 90-day comment period expires in late June.

May 6, 2018

FERC, NERC Recommend Expanded Black Start Testing

By Rich Heidorn Jr.

Coal plant retirements have not caused a shortage of black start resources, but grid operators should consider expanded testing, FERC and NERC said last week.

NERC, its eight Regional Entities and the commission released a study May 2 based on information from a representative sample of nine volunteer registered entities, a follow-up to a 2016 joint report. (See Utilities’ Restoration Plans Pass FERC, NERC Review.)

A next-start unit is the first generator in the cranking path to be energized using power from the black start generator.

The report recommends that:

These practices included:

May 6, 2018

FERC Approves Dissolution of SPP RE

By Tom Kleckner

FERC on Friday approved the dissolution of the SPP Regional Entity (RE) and the transfer of its members to the Midwest Reliability Organization and SERC Reliability Corp., ending a reliability oversight role that had been a source of concern at the commission and NERC (RR18-3).

The commission found that a proposal submitted by NERC, MRO and SERC in March “reflects the transfers of registered entities will ‘promote effective and administration of bulk power system reliability’” in accordance with the Federal Power Act.

The order terminates the amended and revised delegation agreement between NERC and SPP, effective Aug. 31, and revises the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints. The transfer is effective July 1.

FERC said it was “satisfied” that the petitioners and SPP “have considered and established mechanisms to mitigate against the risk of material gaps in oversight of compliance and enforcement activities due to the transfer of registered entities.”

Most of the RE’s 122 registered entities have been reassigned to the MRO, with the remainder joining SERC. NERC will assume the compliance monitoring and enforcement of the SPP RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.

SPP was appointed by NERC as an RE in 2007. The RTO said last July it had reached an agreement to dissolve the RE, citing a mismatch between the RE’s footprint and SPP’s. FERC and NERC had both expressed concerns that SPP failed to ensure the RE’s independence from the RTO.

NERC approved the dissolution in February. (See NERC Board Approves Dissolving SPP Regional Entity.)

NERC, MRO and SERC filed the joint petition with FERC in March.

The RE said it will address transitional and wind-down costs using its approved 2018 statutory assessment funding. Any funds left over will be transferred to MRO and SERC, allocated according to the transferred load-serving entities’ relative net energy for load.

May 4, 2018

NYISO Study Identifies Key Areas of Tx Congestion

By Michael Kuser

Preliminary results from a biennial NYISO study show high congestion in three areas of the New York bulk power system, mainly in the eastern part of the state, ISO officials said Tuesday.

The 2017 Congestion Assessment and Resource Integration Study (CARIS) found congestion on the Central East interface, through the line eastward to Albany, and from the capital down the Hudson River Valley toward New York City.

“These are not necessarily surprising, being consistent with what we’ve seen in past studies,” said Timothy Duffy, the ISO’s manager of economic planning. “We also did find one interesting piece, which was a small line, referred to as Edic-Marcy, which we have found in the past year or so to have some significant contribution to congestion on the system.”

The Edic-Marcy line is located in the central part of the state.

System Resource Shift Transmission Congestion NYISO CARIS — Location of congested transmission | *NYISO*

The CARIS process requires planners to identify the top congestion elements on the system. “That’s obviously a key indicator of where developers ought to be thinking in terms of building additional transmission to provide value in terms of reduced congestion,” Duffy said.

The ISO’s Tariff calls for the CARIS to identify four solutions for each case study. Planners start with a generic solution such as transmission, demand response, energy efficiency and generation, then model those solutions and develop specific costs associated with them, calculating high-level cost-effectiveness tests and benefit-to-cost ratios.

The only benefit the CARIS process factors into its benefit-to-cost calculation is a reduction in statewide system production costs. While the study reports other benefits such as reductions in emissions, capacity market payments and consumer energy payments, it does not reflect them in the benefit-to-cost ratios.

“In terms of Phase I, there’s a whole host of data that’s presented,” Duffy said. “We look at historic, we look at its projected congestion on the system, we identify what the key drivers are, and we look at a number of different scenarios in terms of gas prices; for example, other load forecasts, other big macro changes on the system and how they affect system congestion.”

Six Studies

The ISO studied the three congested areas under six scenarios:

Study 1: Central East-Edic-Marcy
Study 2: Central East
Study 3: Central East- New Scotland- Pleasant Valley
Study 4: Study 3 with Edic- Marcy relaxed
Study 5: Study 3 under the System Resource Shift Case
Study 6: Study 5 with Edic-Marcy relaxed

Planners began with a “business as usual” (BAU) case consistent with past practices. In most such cases, the ISO is very constrained in terms of what it can model and assume, so the BAU results are of limited value, Duffy said.

A second set of results is more forward-looking, the product of the ISO “taking a step further, beyond the confines of the Tariff, in terms of the minimal amount of work required by the tariff,” Duffy said. “We created this system resource shift case, which essentially allowed us to use our judgment to identify a set of assumptions so that the results of the study would provide additional meaning.”

In including the system resource shift case, Studies 5 and 6 differed from the first four by modeling the Indian Point nuclear plant and all New York coal units as retired by 2020/21. In addition, the studies forecast that the state would meet its Clean Energy Standard 2030 goal of 50% renewable resources by 2026.

The study’s model included 4.6 GW of onshore wind, 10.8 GW of utility-scale solar and 250 MW of offshore wind in service by 2026, annually producing 28.5 TWh of renewable energy. ISO planners supplemented this with annual energy reductions of 10.5 TWh from energy efficiency.

Phase II of the CARIS process invites developers to propose specific transmission projects to address congestion on the system. The ISO will perform a benefit-to-cost analysis for each proposed transmission project to assess eligibility for regulated cost recovery.

While estimates of production cost savings will still dictate project eligibility, Phase 2 will examine zonal locational-based marginal pricing (LBMP) load savings to identify beneficiaries and determine cost allocation. The LBMP value used is net of transmission congestion contract (TCC) revenues and bilateral contracts.

To qualify for cost recovery under the ISO’s Tariff, a transmission project must have a capital cost of at least $25 million, benefits that outweigh costs over the first 10 years of operation and received approval to proceed from 80% or more of the actual votes cast by beneficiaries on a weighted basis.

Having met these conditions, the developer must also file with FERC for approval of the project costs and rate treatment.

Public Policy Tx

Switching gears from discussion about the CARIS process, Zach Smith, NYISO vice president for system and resource planning, said the ISO’s planning process has three core pieces: reliability, economic and public policy.

Among the steps taken so far on the public policy front, the ISO “last year selected the Western New York Public Policy Transmission project, and we’re currently going through stakeholder discussions on the AC transmission public policy, and we anticipate a selection of those projects in July this year,” Smith said. (See MC Approves Western New York Tx Proposal; NYISO Management Committee Briefs: Sept. 27, 2017.)

The proposed AC projects include the $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, which are intended to relieve downstate congestion by upgrading the AC transmission systems north and west of New York City. (See Downstate NY to Pay 90% of AC Tx Projects.)

Smith highlighted one change in the ISO’s planning process, noting that under FERC Order 1000, “an interregional transmission project can be proposed under any of our planning processes.”

An interregional project is one physically located in two regions, such as transmission that ties PJM to New York.

“That project could then get a joint cost allocation, where customers within the PJM system might bear some costs, and New York might bear some cost,” Smith said. “To date we have not had an interregional project, but there is that potential there.”