Page 1226 – RTO Insider

July 2, 2019

Tx Incentives NOI Brings Calls for Broader Reforms

By RTO Insider Staff

FERC’s request for comments on its transmission incentives produced predictable splits between transmission owners and load interests, as well as calls for new policies to increase the efficiency of existing lines and mandates on interregional planning.

Dozens of entities submitted comments in response to the Notice of Inquiry the commission opened in March. The commission asked whether it should change its method of calculating returns on equity for electric transmission and natural gas and oil pipelines (PL19-4). It also solicited input on whether transmission adders should continue to be granted based on a project’s risks and challenges or the benefits that it provides (PL19-3). (See FERC Opens Inquiries into Tx Incentives, ROE Policies.)

Below, based on RTO Insider’s review of more than 50 of the comments, is a summary of the feedback FERC received.

TOs Support Incentives

Since it issued Order 679 in 2006, FERC has granted adders to base transmission ROEs for a variety of reasons, including the formation of a transmission-only company (transco) and joining an RTO or ISO. It also has permitted recovery of 100% of prudently incurred costs for projects canceled because of factors that are beyond the TO’s control.

TOs generally supported the current incentives, with some, such as Consolidated Edison and Eversource Energy, saying the abandoned plant incentive and including 100% construction work in progress (CWIP) in the rate base should become automatic and no longer discretionary on FERC’s part. Eversource said removing any incentives would be an unfair “bait and switch.”

Eversource Energy said removing any transmission incentives would be an unfair “bait and switch.” | *Eversource Energy*

Con Ed said recent transmission rate settlements for public policy transmission projects proposed by New York Transco and NextEra Energy Transmission New York illustrate that incentives can be a cost management tool. The two companies will receive incentives depending on how much they are able to reduce costs below project estimates. “The settlements also include disincentives should the projects’ final costs exceed the project cost estimates,” Con Ed said.

WIRES, whose members include TOs and transmission equipment makers, said the current incentives “are potentially not sufficient to support the level of infrastructure investment and development the nation is likely to need.” It called for additional incentives for projects aiding resilience, energy storage and advanced technologies for existing facilities.

Load: Prune Incentives

Load interests generally opposed expanding the incentives, with some, such as the Oklahoma Corporate Commission’s Public Utilities Division, urging the elimination of the risks-and-challenges and transco adders.

Massachusetts Municipal Wholesale Electric Co. (MMWEC) and New Hampshire Electric Cooperative filed joint comments calling for the end of the RTO membership adder, as it is “no longer just and reasonable.”

The Organization of MISO States said adders should only be granted in “extraordinary circumstances and for specific projects.” The organization said it worried that “overly incenting” transmission construction might lead to planners overlooking non-transmission alternatives. “The commission should reduce its reliance on ROE incentive adders because much of a company’s transmission risk is already accounted for in the company’s base ROE,” it said.

Transmission-dependent utilities, including Golden Spread Electric Cooperative and North Carolina Electric Membership Corp., said the commission should eliminate or minimize the use of existing ROE adders. They said there has been no “systematic study” evaluating the incentives’ effect on transmission investment, “and thus there is no evidence demonstrating that ROE-adder incentives are needed to get new transmission built.”

They also said there is also no evidence that the RTO adder is needed to encourage participation in RTOs, nor that its elimination “would result in an exodus of transmission owners from RTOs.”

Risks or Benefits?

The New England States Committee on Electricity (NESCOE) opposed proposals to change the incentives policy to focus on expected project benefits. It also opposed tailoring incentives for projects based on expected reliability benefits, targeting interregional transmission projects or geographic areas where projects would enhance reliability or have economic efficiency benefits.

“The possibility that a project can benefit consumers does not establish the need for consumers to fund incentivized investments through regulatory recovery beyond what is provided through the base ROE and cost-of-service ratemaking,” NESCOE said.

CAISO said FERC should continue to award ROE incentives based on the risks of a project rather than focusing on its benefits.

“The CAISO believes there is no direct correlation between the net benefits a project approved in a regional transmission planning process provides or the type of transmission need a project meets, and the ROE adder that is necessary to attract capital or encourage a developer to build the project,” it said.

The California Public Utilities Commission questioned the continuing need for incentives. “In the [CAISO] control area there are no systemwide, chronic, long-term transmission reliability or congestion issues that warrant the continued award of electric transmission incentives,” it said.

The National Rural Electric Cooperative Association also was skeptical, saying FERC’s questions “raise concerns that the commission is contemplating going down a path of adding new incentives without having any concrete sense as to whether its existing incentives are achieving their desired goals.”

But the Transmission Access Policy Study Group, an association of TDUs from more than 35 states, said the incentives under Order 679 “successfully reversed the long-term decline in transmission investment that spurred Congress to enact Section 219” of the Federal Power Act — the legislation that led to Order 679. It said there was no need for a “fundamental reform” of the incentive policies.

Americans for a Clean Energy Grid, a coalition of utilities, TOs and transmission equipment manufacturers, said FERC should expand the definition of transmission benefits “beyond economics and reliability to include resilience, ability to serve demand for sustainable energy, ability to meet public policy requirements and other benefits.”

The commission should encourage “low-cost, high-benefit” new transmission technologies, it said. “Existing incentives to transmission providers do not help at all in getting a new project accepted for planning, sited, permitted or its costs allocated, because they do not motivate the decision-makers involved.”

Performance-oriented Incentives

The Energy Storage Association called for a shift to a “performance-oriented” incentive policy to increase transmission capabilities and reduce costs. “ESA recommends that the commission create a specific incentive that rewards maximization of value, delivery of cost-savings or both, through investments that increase flexibility and other operational capabilities of transmission facilities.”

It also said the commission should open a separate docket to address barriers to storage as transmission assets (SATA). “Energy storage is for the most part absent from consideration in transmission planning processes. As a result, even if a SATA resource might be cost-effective and viable to meet RTO/ISO transmission reliability needs, there is not an adequate means to identify it in the planning process,” it said.

The National Electrical Manufacturers Association also supported performance-based ratemaking in considering incentives, noting the commission is required to do so under Section 219. “A performance-based approach would encourage transmission owners and operators to adopt the latest technologies to drive performance outcomes.”

Advanced Technology

David Patton, president of Potomac Economics | © *RTO Insider*

Several commenters recommended FERC take steps to incent TOs to employ dynamic line ratings and other advanced technologies to increase the capacity of existing infrastructure.

Potomac Economics, which provides market monitoring services for MISO, ERCOT, NYISO and ISO-NE, said FERC should allocate to TOs the “congestion surplus” — the shadow price of the constraint ($/MW) multiplied by the difference between the dynamic line rating and the static seasonal rating. Potomac President David Patton also said the commission could improve outage scheduling by allocating outage costs to TOs and that it should consider incenting topology optimization — reconfiguring the system based on line loadings and contingencies to reduce flows on highly congested facilities. It also should encourage investment in additional transmission by allocating rights related to the congestion benefits and capacity market benefits of the expanded capacity, he said.

Oklahoma regulators called for FERC to reinstate the advanced transmission technology adder, which the commission abolished in 2012. The current rules incentivize utilities to build more expensive projects and discourage “much cheaper” advanced transmission technologies, it said, recommending the commission direct utilities “to optimize the current [bulk electric system] before upgrading the current system or building new transmission lines.”

The Natural Resources Defense Council said “utilities all too often ignore cost-effective advanced technology and other solutions to optimizing capacity and power flows of the existing system.”

The American Council on Renewable Energy said FERC should shift from a “risks and challenges” to a “benefits” framework, which, it said, “can unlock private sector investment with minimal regulatory reform.”

“Transmission incentive reform should be augmented with transmission planning reform to more effectively promote new transmission. The incorporation of grid optimization and advanced technologies in the planning process, more standard and broad cost allocation, and increased inter-RTO transfer capability will lead to a more robust and efficient electric grid. …

“Newly available grid operations technologies such as more advanced dynamic line ratings, power flow control systems and topology optimization can reduce this congestion and curtailment for less cost than new lines. Currently, utilities earn little to no money from the process of delivering more over existing wires.”

Interregional Transmission

Where incentives are really needed is for interregional transmission projects, according to R Street Institute, a think tank that promotes “free markets and limited, effective government.”

“The commission should acknowledge that [the lack of interregional projects] is a political economy problem and induce cooperation across seams through financial incentives that face the transmission-owning members of ISOs,” said R Street’s Director of Energy Policy Travis Kavulla. “These transmission owners exercise significant stakeholder influence over ISOs. Providing incentives to obtain efficiency gains across ISOs’ footprints could therefore reduce the insularity of the wholesale markets.”

Travis Kavulla, R Street Institute’s director of energy policy | © *RTO Insider*

Kavulla said TOs should receive incentives for projects that cross an RTO/ISO seam and be “incentivized to dedicate their existing facilities to a co-optimized market between two ISOs.”

NRDC said commission-approved transmission planning and cost allocation policies “are providing disincentives to meaningful investment that financial incentives alone cannot counteract.”

“For that reason, we encourage the commission to examine more broadly the barriers to the continuing development and optimization of the bulk power system. Many of these barriers are well known, including, for example, limited accounting of transmission benefits, the ‘triple hurdle’ required for approval of interregional projects and the discriminatory status accorded to projects necessary to meet system needs driven by public policy requirements (i.e., planners must only ‘consider’ needs driven by public policy requirements).”

Expanding the Definition of Benefits

The Union of Concerned Scientists said FERC should clarify that operational constraints on congested interfaces should be used in congestion and economic studies rather than only the planning limits of such interfaces. It cited New England’s challenge with unbottling Maine’s wind resources.

An ISO-NE study that used the planning limits — modeling the system with the maximum transfers that can only be assumed if all the best conditions are met for all hours — concluded there would be minimal economic benefit from a proposed increase in the capability of the Orrington South interface. “However, the particular interface is limited to lower … levels for most of the year,” said UCS’ Michael Jacobs. “In a study of the congestion that comes closer to approximating actual system congestion and potential benefits, the typical range of hourly operating limits must be used, rather than a fixed upper planning limit.”

Joint Ownership Incentive

MMWEC and the New Hampshire co-op said they’d like a new incentive for companies that are jointly owned by jurisdictional utilities and nonpublic utilities “in recognition of the risk-reducing benefits of these arrangements.”

GridLiance, whose business plan is built on that joint ownership model, also called for such an incentive for projects approved by a regional or local transmission planning process that are at least 15% owned by nonpublic utilities.

ROE Methodology

In docket PL19-4, the commission asked for comment on whether it should adopt as policy the new ROE formula it outlined in an October 2018 ruling regarding the New England Transmission Owners (NETOs). In that order — issued in response to the D.C. Circuit Court of Appeals’ remand in Emera Maine v. FERC — the commission said it would no longer rely solely on the discounted cash flow (DCF) model it has used since the 1980s and would instead give equal weight to results from the DCF and three other techniques: the capital asset pricing model (CAPM), expected earnings model and risk premium model. (See FERC Changing ROE Rules; Higher Rates Likely.)

PJM TOs expressed support for the new methodology.

“It makes sense to use multiple models to establish ROEs because, as the commission has noted, investors use multiple models, in addition to the discounted cash flow model, to inform their investment decisions,” they said. “Moreover, the use of multiple approaches provides a hedge against the shortcomings of any one approach in particular financial conditions.”

The NETOs said they spent most of this decade litigating their ROE and want the commission to stand by the 2018 order, including the establishment of an evidentiary screen to dismiss some ROE complaints. The commission said it would dismiss ROE complaints if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile unless the presumption is “sufficiently rebutted.” The new threshold came in response to complaints by TOs over “pancaked” ROE complaints being filed while prior cases remained pending. (See EEI White Paper Calls for End to ‘Pancaked’ Rate Cases.)

But TDUs and state regulators said they opposed at least portions of the new methodology.

OMS said the four-model approach “broadens the scope of potentially contested issues in ROE proceedings, making it even more difficult for analysts to predict the outcome on any ROE litigation.” It asked the commission to give the DCF model “substantial weight” over any other models.

“Should the commission choose to ignore the overall cost impact to customers, the just and reasonableness of the resulting ROE will be called into question and might lead to more complaints and less regulatory certainty,” Alliant Energy warned.

TDUs said the two-step DCF analysis should remain the primary, “if not the exclusive, method” for ROE determinations.

“While the [CAPM] and risk premium models can, when properly applied, corroborate the results of the DCF analysis, they should not be relied upon as primary analyses and should not dilute the DCF results,” they wrote. “Under no circumstances should the non-market-based expected earnings model be used.”

The TDUs also said FERC shouldn’t deviate “from its current policy by imposing additional burdens on complainants bringing an action against an existing ROE” under FPA Section 206.

The Maryland Office of People’s Counsel opposed the idea of using a “vintage approach” that fixes ROEs for the life of the asset at the time that each asset is completed. “Such an approach could lead to erratic investments in that investors, if they believe returns will increase in the future, may delay making critical infrastructure improvements so they could lock in relatively high returns for the life of the asset,” it said.

R Street said FERC’s ROEs are unduly generous. In 1980, it noted, the average ROE in the U.S. was about 200 basis points above the 30-year U.S. Treasury bond yield. “Today, the gap has widened to approximately 600 basis points, even as many transmission owners enjoy regulatory devices such as formula rates that serve to diminish financial risk,” it said. “There is little reason to believe that widely available incentives are necessary to promote necessary, but routine, capital investment in commission-jurisdictional infrastructure.”

Pipeline ROEs

The Natural Gas Supply Association, which represents natural gas producers and marketers, said the commission should not abandon use of the DCF model in determining pipeline ROEs. “While the discounted cash flow methodology is not perfect, no capital market evaluation technique is. But the DCF methodology is the soundest, most robust, most accepted and most reasonable methodology the commission has for determining investor-expected ROEs for natural gas pipelines.”

The American Gas Association, which represents more than 200 local distribution companies, said it did not favor a review of FERC’s pipeline ROE policy.

“Matters related to pipeline ROEs are likely to raise issues that differ from those addressed by the court in Emera Maine. Therefore, the commission should not presuppose issues exist in the natural gas industry before fully examining the matter,” it said.

The Interstate Natural Gas Association of America (INGAA), which represents most of the interstate pipeline companies in the U.S., said it “continues to believe that the DCF methodology should be used to determine gas pipeline ROEs but recognizes that the performance of the DCF model, like the other models discussed in the NOI, is not precise and may be distorted by unusual capital market conditions.”

INGAA said it supports the consideration of some of the other models but that the commission should not adopt a formulaic averaging of the models and should “retain the flexibility to place appropriate weight on, or exclude, any of the models in light of prevailing financial conditions at that time and the facts and circumstances of each case.”

It opposed use of the risk premium model, saying it “cannot be applied to determine sufficiently reliable interstate natural gas pipelines’ ROEs due to the absence of data required by the model.”

Public Citizen and environmental groups, including the NRDC and Sierra Club, said FERC’s current policy provides incentives to overbuild capacity. “For many natural gas pipelines, applicants often involve self-dealing contracts between pipeline developers and their regulated utility affiliates. These utility affiliates can then pass costs onto its captive ratepayers. This affiliate abuse is then combined with FERC’s high rates of return,” Public Citizen said.

“The commission’s allowance of a 14% ROE for gas pipeline investments is a much higher profit margin than regulated utilities receive for other capital-intensive investments such as electric transmission — up to 40% higher,” the environmental groups said. “State public service commissions on average have granted utilities a 9.92% ROE in recent years. A review by the Edison Electric Institute shows that the average ROE granted to utilities in 56 new rate cases filed in 2017 was approximately 9.7%. Financial markets have changed since FERC began granting the 14% ROE to new pipelines over two decades ago, including declining corporate bond rates and lower interest rates.”

Tom Kleckner, Christen Smith, Rich Heidorn Jr., Michael Kuser, Hudson Sangree and Amanda Durish Cook contributed to this article.

July 2, 2019

Stakeholder Soapbox: Design for Rapid Decarbonization

By Robbie Orvis

America’s wholesale electricity markets are at a turning point.

Their rules, products and software were developed in the late 20th century around a fossil fuel-based resource mix in which large central station plants are dispatched to meet unalterable demand. Marginal cost dispatch, in large part determined by fuel costs, has been the principle factor supporting prices and revenues; helping introduce competition into a growing system composed of large baseload power plants with high fixed costs and low production costs; and more flexible power plants with lower fixed costs and higher production costs.

But the 21st century electricity mix is evolving in significantly different ways from the 20th century system. The share of non-fuel resources like wind and solar is growing thanks to falling costs and states like California, Nevada and New York setting 100% clean energy goals. These resources differ in several important ways:

They typically have near-zero production costs, creating implications for market prices and plant revenue.
Newer resources tend to have smaller minimum unit sizes and can be deployed more quickly and in smaller sizes.
These resources have different production characteristics than many existing plants (e.g., output tied to sunlight). Operating the grid around resource availability is not a new concept, but doing so daily for many resources is pushing operators to consider new rules and products.
These resources can provide services better or cheaper than older ones — such as creating (very) fast frequency response using power electronics as a replacement for inertia.

Meanwhile, technological barriers limiting demand-side flexibility are disappearing through smart thermostats, water heaters and the “Internet of things.” Serious technological changes are upon us, but concomitant changes in market incentives and rules are lagging behind.

Given these changes, a new series of research papers by energy policy think tank Energy Innovation seeks to answer the question of whether and how wholesale electricity markets must evolve by asking: “Which market design provides the best framework for reliably integrating clean energy at least cost?”

A Vision of the Future for Wholesale Electricity Markets

Future market designs must answer several important questions as the resource mix evolves; for example, how can sufficient investment signals be maintained, and how will new resources be efficiently financed? Similarly, how will markets expose the value of important system characteristics, such as flexibility, through this transition? Finally, given the trend in state policy, how can future market designs address carbon policy?

Two pathways have emerged in conversations that aim to answer these questions about future markets. The “Robust Spot Market” model emphasizes improving today’s markets for energy and services, eschewing capacity markets, and relying on voluntary decentralized bilateral contracting. The “Long-Term Plus Short-Term Markets” model envisions complementing those improved energy and services markets with an advanced, centralized, forward market for needed resources and services.

Both pathways agree on important features for modern markets:

Competitive wholesale electricity markets are a good thing: Trading over a diverse portfolio of resources augments reliability and decreases overall costs. The larger the market, the greater the benefits.
Wholesale electricity markets need to work with external (state or federal) policies governing the electricity system, not work against (i.e., mitigate) them.
Shorter dispatch intervals and multiperiod optimization can make markets more efficient.
The capacity markets in use around the U.S. today, which largely trade capacity without much regard to the operational characteristics of the energy resources being traded, should be fundamentally transformed or eliminated.

But important differences exist between the pathways, driven in part by differing views on key questions:

How big of a risk is political interference in markets?
How much do we expect the “real world” to behave as theory suggests?
How strong are the counterparties in markets, and how strong do we expect them to be in the future; i.e., can we expect utilities or other load-serving entities to be able to buy flexible and well hedged smart energy resource portfolios to serve customers over the long term?
What extent can factors other than strict production costs set LMPs; i.e., congestion in the transmission system, ancillary service needs or other opportunity costs? If those other factors do play a substantial role setting LMPs, what is the risk that real-world prices (which may be in part driven by uneven retirements) are too low to attract needed flexibility resources or too high to expose their value?
Is keeping voluntary bilateral markets (which already underlie centralized wholesale electricity markets) decentralized the best approach, or would centralizing and organizing those bilateral contracts be more beneficial?

Wholesale electricity markets will evolve differently in various regions, but the macro issues facing markets are extremely important for grid managers to study and deliberately consider as the electricity system decarbonizes.

Robbie Orvis is the Director of Energy Policy Design at Energy Innovation, where he works on the firm’s Energy Policy Solutions and Power Sector Transformation programs.

July 2, 2019

PJM MRC/MC Briefs: June 27, 2019

Ott’s Last MRC

WILMINGTON, Del. — PJM CEO Andy Ott attended his last Markets and Reliability and Members committee meetings on Thursday, capping more than two decades with the organization.

Ott announced his retirement last month — the second top executive to leave PJM this year. (See PJM CEO Andy Ott to Retire.)

“He’s been instrumental in the development of our markets,” MC Vice Chairman Steve Lieberman said. “PJM has really been a leader in these markets, and we certainly appreciate that and his decades of service to PJM. You will leave a very good legacy.”

Lieberman then presented Ott with an inscribed compass on behalf of the membership that read, “To Andy, with appreciation, for your service to PJM.”

PJM — Members Committee Vice Chairman Steve Lieberman bids CEO Andy Ott farewell. | © *RTO Insider*

Fuel Security Charter

Stakeholders unanimously endorsed the charter for PJM’s Fuel Security Senior Task Force.

The MRC reluctantly endorsed a problem statement and issue charge in March after some doubted the necessity to discuss the fuel security issue and even contended that PJM already had a solution in mind. (See PJM Stakeholders Reluctantly OK Fuel Security Initiative.)

Tim Horger, PJM’s director of energy market operations, said the task force remains on track to report its recommendations on the first four key work activities at the September MRC, including: providing education on the issue; quantifying the risk of selected scenarios that could risk fuel security; defining fuel/energy security; and determining whether there is a quantifiable and/or locational requirement for fuel/energy security.

RTEP Removal Language Deferred a 3rd Time

Voting on language that alters the way PJM manages supplemental projects in the Regional Transmission Expansion Plan was delayed a third time.

Both RTO staff and LS Power’s Sharon Segner pushed for the 30-day deferral, telling the MRC that stakeholders at the special Planning Committee sessions have four more issues to resolve before seeking a vote. (See “RTEP Poll,” PJM PC/TEAC Briefs: June 13, 2019.)

Segner gave a brief description of the four outstanding issues: conversion and how supplementals become baseline projects without undergoing the Order 1000 planning process; the displacement of supplemental projects through the regional planning process; ensuring that supplemental projects do not undermine the integrity of the Order 1000 process; and PJM’s authority to remove supplementals from the RTEP once permits have been denied.

“Folks are trying to focus on principles here rather than just wordsmithing the manuals,” she said. “At the heart of the issue is PJM’s fundamental authority over its RTEP, especially as it relates to removing supplementals from the plan.”

Capacity Interconnection Rights

Carl Johnson, on behalf of the PJM Public Power Coalition, presented a first read of a problem statement and issue charge that forms a task force to discuss the rights and responsibilities of stakeholders with capacity interconnection rights (CIRs).

“You may recall this issue got tangled up in the must-offer exception process,” he said. “It became very clear that we didn’t all agree what rights they convey or what they meant or what their value was.” (See Showdown Set on PJM Must-offer Exceptions.)

The issue charge divides the work into two phases that will potentially culminate in revisions to section 230 of the Operating Agreement and Manual 14G.

Johnson said stakeholders will consider if CIRs should:

Continue to be the proper mechanism for conveying the rights and responsibilities associated with them, or whether they should be modified or a new mechanism introduced.
Should be returned to system capability due to being unutilized in the capacity market by a resource.
Create an obligation for a resource to participate in the capacity market.

Manuals Endorsed

Manual 14G: Clarifies requirements for term of site control, NERC-accepted stability models and corrections to references and links.
Manual 6: Cover-to-cover review that aligns with parts of the OASIS refresh and removes financial transmission rights credit business rules from section 6.7 and refers readers to Tariff/credit overview and supplemental documents on PJM’s website.

Stakeholders Bid Farewell to Wilmington

PJM’s Markets and Reliability Committee met for the last time at the Chase Center in Wilmington, Del., on June 27, 2019. | © *RTO Insider*

The MRC and MC will no longer meet at the Chase Center in Wilmington after voting to move all subsequent meetings to the PJM Conference and Training Center in Valley Forge, Pa.

– Christen Smith

July 2, 2019

NEPOOL Participants Comm. Briefs: June 25-27, 2019

NEWPORT, R.I. — A new effort by the New England Power Pool could give ISO-NE’s most “senior” board members a longer shot at keeping their positions rather than aging out of eligibility.

The NEPOOL Participants Committee on June 25 approved a motion to ballot all members on a proposal to amend the Participants Agreement to allow people older than 70 to serve on the RTO’s Board of Directors.

Members will specifically vote on authorizing the Joint Nominating Committee to waive the current 70-year-old age limit for candidates to stand for election or re-election, just as it now is authorized to waive the limit on three consecutive full terms.

According to a memo from PC Counsel Pat Gerity, RTO representatives told NEPOOL officers that the age limit reduces the pool of qualified candidates, risking the loss of “highly qualified and broadly supported board members” who turn 70. Without a waiver, Director Roberto Denis would age out next September after serving only two terms.

Janice Dickstein, ISO-NE vice president for human resources, said that while corporate boards increasingly rely on age limits rather than term limits, the RTO’s age cap is more restrictive than 90% of organizations. She noted that most people serve on boards in their retirement, and that it takes time to get new board members up to speed on the issues specific to the region.

The PC approved the motion to issue the ballots with 76.88% of sectors in favor (Generation, 11.19%; Transmission, 16.79%; Supplier, 13.59%; Alternative Resources, 16.04%; Publicly Owned Entity, 16.46%; and End User, 2.81%).

For the PC to approve the amendment, the returned ballots need to represent at least half of fixed voting shares in each of a majority of NEPOOL sectors and achieve an overall 70% vote in favor.

The PC also approved balloting members on changing a sector definition, with Gas Industry proposed to become Fuels Industry. Subject to a positive vote and FERC acceptance, the American Petroleum Institute may apply to join NEPOOL as a Fuels Industry participant.

No Easing of Credit Requirements

The PC voted down a motion to change ISO-NE’s Financial Assurance Policy (FAP) to allow market participants to use affiliate parent guarantees to obtain “an unsecured market credit limit or transmission credit limit” or use surety bonds “as an acceptable form of financial assurance.”

The vote was 45.13% in favor (Generation, 16.79%; Transmission, 0%; Supplier, 11.55%; Alternative Resources, 9.44%; Publicly Owned Entity, 7.35%; and End User, 0%).

The proposal was sponsored by Calpine Energy Services, Direct Energy Business, Dominion Energy Generation Marketing, Exelon, Massachusetts Municipal Wholesale Electric Co., NextEra Energy Resources and PSEG Energy Resources & Trade.

The PC in 2004 voted to eliminate surety bonds from the FAP and in 2010 to eliminate parent guarantees.

ISO-NE opposed the proposal mainly as a threat to its ability to clear the markets because of reduced liquidity. It also feared that introducing weaker forms of financial assurance could result in substantial or even catastrophic losses to the RTO and its market participants.

Nested Capacity Tariff Changes Approved

The PC unanimously approved Tariff changes to accommodate the new modeling concept of nested export-constrained capacity zones in the Forward Capacity Market, starting with Forward Capacity Auction 14 to cover the one-year capacity commitment period beginning June 1, 2023.

The revisions address those cases where it’s necessary to distinguish between a parent and nested zone (which represents a sub-zone within a parent zone), such as when capacity clearing price calculations differ slightly between the two.

Most of section III.13 of the Tariff already recognizes nested capacity zones, while other sections do not specify the type of zone when dealing with reconfiguration auctions or many settlement provisions.

The first set of changes accommodate nested export-constrained capacity zones in the FCM, while the remainder clarify certain data submittals of costs and revenues for static delist and export bids in the FCM.

The RTO developed the changes, which were recommended by NEPOOL’s Markets Committee.

ISO-NE CEO/COO Reports

ISO-NE CEO Gordon van Welie told the PC that the grid operator recognizes the market has to be adapted to the changing power system.

He said the region is rapidly catching up with California and Europe in the deployment of energy storage resources, but that there are few places as constrained as New England. Nonetheless, the region has a good track record in solving problems, he said.

COO Vamsi Chadalavada reported that the RTO has so far received a record “show of interest” for FCA 14: more than 700 applications, compared to 250 for the last auction.

NEPOOL — New generation and new demand resources show new entry dominated by natural gas and energy efficiency. | *ISO-NE*

New capacity resource qualification is ongoing, and approximately 336 MW are available for the renewable technology resource exemption, he said.

The existing capacity resource qualification is complete, with about 258 MW of retirement delist bids and 21 MW of permanent delist bids received on March 15. Static delist bids were due June 13.

Chadalavada said the region has enough resources to replace the 690-MW Pilgrim nuclear plant, which retired at the end of May, largely with new resources coming into the market in southeastern Massachusetts.

FERC Update

FERC Commissioner Cheryl LaFleur, who is leaving the commission at the end of August, spoke of three broad themes facing the commission: resources for reliability, how to pay for them and needed infrastructure. She said the commission has the choice of regulating in a planned way by giving authority back to the states, or in an unplanned way by letting the market be cannibalized.

LaFleur said she looks forward to seeing NYISO’s carbon pricing proposal when it is submitted and also suggested to the industry that now is not the time to submit filings containing open-ended legal questions, but rather agreements that parties have worked out among themselves.

She congratulated NEPOOL on being vital to the region, but she noted that the organization was not without controversy, mainly concerning its transparency, as evidenced by congressional hearings earlier in June, when Rep. Joe Kennedy III (D-Mass.) told her that “unless you are a member, you can’t even observe any meetings or proceedings, let alone talk about it publicly.” (See FERC Probed on RTO Governance, Market Issues.)

Jette Gebhart, deputy director of FERC’s Office of Energy Market Regulation, told the PC that commission staff are busy now working through energy storage compliance filings.

EMM Report

ISO-NE last year had the highest energy prices of any RTO because of high natural gas costs, as well as the highest net revenues because of higher capacity revenues, External Market Monitor David Patton said, highlighting his still unpublished 2018 assessment of the ISO-NE markets.

The assessment shows ISO-NE had about one-tenth the congestion of other RTO markets because of substantial transmission investments over the past five years. However, transmission service costs were more than double the average rates in other RTO markets, Patton noted.

The first 13 FCAs reflect the retirement of nearly 5 GW of nuclear, coal and older steam turbine capacity, with increased reliance on gas-fired capacity. Fuel security concerns are heightened by the potential retirement of Exelon’s Mystic Generating Station and the Distrigas LNG facility, Patton’s report noted.

The EMM’s baseline scenario fuel security evaluation for a two-week severe winter period shows very high utilization of oil inventory capacity and the need for LNG import capability, while load shedding would occur in a scenario with major reductions in natural gas availability.

The RTO’s operational fuel security analysis (OFSA) last year also found tight fuel supply margins that could result in load shedding in the winters of 2022-2023 and 2023-2024, and in March ISO-NE filed an interim proposal with FERC to address winter energy security for those commitment periods. (See NEPOOL MC Debates Energy Security Models.)

Consent Agenda

The PC approved four rule changes on the consent agenda, following unanimous approvals at lower committees:

OP-14 Appendix B (Reporting Requirements for Asset Related Demands and Dispatchable Asset Related Demands): Revisions to establish reporting requirements and cleanup changes to improve document flow. Recommended by the Reliability Committee.
Tariff Section III.1.5.3: Revisions to include all dynamic resources in reactive capability audit requirements and specify criteria for such resources to perform such audits. Recommended by the Reliability Committee.
Tariff Section I.2.2, OP-23 and OP-23G: Revisions related to reactive resources required to perform reactive capability auditing. The PC approved them with the understanding that two additional Tariff definitions would go back to the Reliability Committee, which recommended the measure.
Revisions to Tariff Section II Schedule 2 to accommodate introduction of energy storage facilities and other administrative changes. Recommended by the Transmission Committee.

— Michael Kuser

July 2, 2019April 22, 2024

Overheard at TREIA GridNEXT 2019

SAN ANTONIO — Grid safety and security were the focus of the Texas Renewable Energy Industries Alliance’s (TREIA) annual GridNEXT conference last week.

Speakers during the event Thursday addressed a variety of related topics, from protecting critical assets and safeguarding vital data, to the role renewables and microgrids will play in ensuring a more reliable and resilient grid.

TREIA board member Ingmar Sterzing, a vice president with renewable developer OnPeak Power, put things into perspective when he asked his panel, “Are you prepared to operate your business without electricity and cellphones?”

“You need a responsible plan for cybersecurity. You plan to have that event actually happen. You don’t plan for it not to happen,” Mike Allgeier, ERCOT’s director of critical infrastructure security, told attendees gathered at The International Center. “Prepare for the worst. If you don’t prepare for the worst, when the worst happens, it’ll be pretty bad. Plan for what you think is the worst, then double it.”

Allgeier warned that the “bad actors,” or hackers, operating online today are not to be underestimated.

“They’ve been around a while,” he said. “Typically, they’re dedicated and well-trained to do their job. It’s not the 15-year-old kid in the basement. They have goals and they’re measured. They have quotas.

“They’re not only looking at the big guys. They understand that if they can control a wide swath of resources, that can be just as damaging as getting into one large resource,” Allgeier said.

Speaking on the same panel, ABZ’s Trey Kirkpatrick emphasized the importance of raising awareness of cybersecurity issues among employees. He used Berkshire Hathaway’s three-strikes-and-you’re-out approach to phishing emails as an example.

“Their policy is if someone clicks on a phishing email three times, they’re gone. You don’t see that in every organization,” Kirkpatrick said.

Both Allgeier and Kirkpatrick bemoaned the difficulty of finding and retaining cybersecurity subject matter experts, with Kirkpatrick calling it “the biggest risk.”

“The consultants are getting busy; they’re highly paid, and they’re moving around,” Kirkpatrick said. “I know companies that can’t even find a cybersecurity manager, even with the money they are offering.”

Allgeier said he typically fills his cybersecurity staff with personnel that have financial and military backgrounds.

“From the financial side, because they’ve been doing this for a long time; and from the military sector, because they have been trained to fight our online enemies,” he said. “I can’t always compete with salaries the high-tech or financial firms can offer, so we try to keep them with competitive benefits and the collaborative nature of work, building the esprit de corps.”

Place for Storage, New Technologies

Panelists discussing the ability of renewable energy and smart technology to make the grid more secure and reliable suggested looking away from California, where mid-day solar energy peaks reduce demand for other sources, resulting in a “duck curve.” (See Report: Calif. ‘Duck Curve’ Growing Faster than Expected.)

“California has kind of become the sacrificial lamb,” Energy Storage Consultants CEO Judy McElroy said. “Storage is a good answer to that, but just throwing storage on your grid doesn’t make it more reliable.”

“As we integrate [battery storage and other technologies], we can make them more reliable, but there’s a cost,” said Dean Tuel, global vice president of microgrid and storage solutions sales for Aggreko. “We have a diverse portfolio of technologies we can provide at a cost the customer is willing to accept. We can accommodate this with today’s technology and reach a level of renewable penetration that gets us to the … reliability the customer is looking for.”

TREIA on Track for 50% by 2030 Goal

Buoyed by the large amount of wind and solar projects in ERCOT’s interconnection queue, Sterzing said TREIA’s goal of achieving 50% renewable energy in Texas by 2030 is coming into clearer focus.

Sterzing pointed to the 35.7 GW of wind projects and 58.6 GW of solar projects in the queue as of May as reason for hope. Only 14.3 GW and 7.6 GW of the respective wind and solar projects have signed connection agreements.

“Will it all be built? Hard to say, but that’s a huge industry movement either way,” he said. “There’s a lot of development coming into Texas. There’s certainly a lot more we can do as a state, with this kind of investment, to make Texas an energy center for the country.”

Sterzing noted Texas that has seen a “steady trajectory” over the last five years in renewable energy’s share of the fuel mix. Wind and solar energy accounted for almost 20% of ERCOT’s production in 2018. At the current rate of growth in the state, Sterzing estimated an additional 18 GW of wind energy and 39 GW of solar would help “maintain a reasonable mix and achieve the 50% goal.”

“That’s a huge, huge target, and enough to keep us all busy,” he said.

Energy Industry, Military Collaborate on Grid Security

A panel focused on defense and grid security stressed the importance of the energy industry working closely with the military.

Melissa Miller, Avangrid Renewables’ regional development manager for the central U.S., said technological improvements have led to the construction of wind farms in areas they could not have previously been built. That has only increased the conflicts seen across the country between wind facilities — which are increasingly taller — and military flight paths.

“We’re more successful with wind almost everywhere, but all of a sudden, that creates an impact with military operations,” Miller said. “It’s really important we learn about their missions and what their objectives are, especially in the lower air space. The need to collaborate is so important.”

Shanna Ramirez, CPS Energy’s chief integrated security officer, said the San Antonio utility has long enjoyed a collaborative relationship with the military, which has four major installations and 250,000 retirees in the city. Ergo, the city’s trademarked nickname, “Military City USA.”

“We’ve been really successful about keeping the military aware of how we secure our mutual facilities,” Ramirez said. “We have more people at the table, we keep buying a bigger table.”

“There’s an acknowledgement we will not solve problems alone,” said Christian Delarosa, deputy base civil engineer for Joint Base San Antonio. JBSA is composed of the Army’s Fort Sam Houston and the Lackland and Randolph Air Force bases.

“The Air Force wants to keep focus on resiliency and low costs,” Delarosa said. “We’re still interested in saving energy, but we’re now focused on resiliency and grid operations. It’s going to take industry experts and academia to look at this problem and develop solutions.”

Renewables Enjoy Positive Legislative Session

Attorney Chris Reeder, a partner at Husch Blackwell, reviewed the recent 86th Texas Legislature, painting it as a success for the renewable energy industry despite the efforts of the conservative Texas Public Policy Foundation (TPPF).

Reeder said the TPPF was at the forefront of a “sustained and aggressive and hostile campaign” against renewable energy during the recent session, which ended in May.

“They’ve made it a centerpiece of their political strategy to oppose renewable energy,” he said. “When they say, ‘Level the playing field,’ others would call that a rollback. They have been very vocal and aggressive in shooting down our success to the economy of Texas.

“Any legislation with renewable energy attached to it automatically draws some level of opposition in our state House and state Senate,” Reeder said. “That tends to misread the true situation, in which there’s much more support out there than makes its way into the chatter you see in The Dallas Morning News or the trades.”

July 2, 2019

Exelon: PJM ‘Buried the Lede’ on Nuke Study

By Christen Smith

WILMINGTON, Del. — Exelon told PJM’s Markets and Reliability Committee on Thursday that the RTO “buried the lede” in its analysis of nuclear plant retirements in Ohio and Pennsylvania, suggesting instead that results prove the reactors offer value worth saving.

“We think the results show it makes sense to preserve zero-carbon sources and replace retiring coal units with gas units,” said Jason Barker, director of wholesale market development for Exelon. “The data shows better results than the response that PJM promoted. Frankly, it sort of buried the lede.”

Exelon manages the largest nuclear portfolio in the country, including the decommissioned Three Mile Island near Harrisburg, Pa. (See Exelon to Close Three Mile Island.)

The PJM study, published June 7, concluded emissions will drop regardless of whether FirstEnergy’s Perry and Davis-Besse facilities in Ohio and its Beaver Valley plant in Pennsylvania close or stay open — though the reduction would be significantly greater if the plants stay online. (See PJM: Nukes Keep Energy Costs Down, in Theory.)

Comparison of cost savings and emissions reductions in PJM’s first simulation, which preserves all three FirstEnergy nuclear plants | *Exelon*

Regulators in both states asked PJM to simulate the impact of losing the plants on the power grid and greenhouse gas emissions as subsidy plans pend in each legislature. Staff obliged the requests by creating five scenarios against which to compare what the RTO considers its base case: all three plants retire, and scheduled gas and renewable generators with an in-service date in 2023 come online, reducing net-load payments by $1.6 billion. Carbon dioxide emissions would likewise decrease by 4.3 million tons, while nitrogen oxide and sulfur dioxide emissions would fall by 37,900 tons and 18,200 tons, respectively, the analysis concluded.

Should all three nuclear plants stay operational and new generation enters the market as planned, net-load payments would decrease by an additional $474 million from the base case. In Pennsylvania, emissions of CO2, NOx and SO2 would decrease from the base case by 4.7 million tons, 5,000 tons and 3,300 tons, respectively. In Ohio, the additional emission reductions total 3.7 million tons, 2,400 tons and 3,500 tons, respectively.

The results are similar — net-load savings increase and greenhouse gas emissions decrease — when either just Beaver Valley or the Ohio plants stay online, PJM found.

“The data really reveals here the benefits” of keeping the plants open, Barker said. “The base case demonstrates coal to gas switching, and we think that will occur regardless of the fates of the nuclear plants. Simulation 1 is the real story … which is what are the impacts of maintaining these units.”

Critics have argued that PJM’s other simulations that reduce the number of gas units scheduled to come online by 50% as “more realistic” than the first scenario — a result of nuclear subsidies that could come to fruition and discourage market entry.

Barker argues that those scenarios “aren’t very credible” because PJM made no consideration of how many projects already had interconnection study agreements, where these projects were located or how committed developers were to completing them.

Exelon’s analysis of PJM’s data purports that even if developers canceled 4.6 GW of scheduled gas units, the combined impact of coal retirements, preserved reactors and renewable penetration would still reduce carbon emissions by 16.8 million tons and reduce energy costs $1.7 billion.

“PJM answers the wrong question,” Barker said. “The story is really in the difference between the base case and the simulation. We just unmasked the data.”

Stu Bresler, PJM’s senior vice president of operations and markets, said the RTO stands by its analysis.

“We think subsidization of significant generation of any type would lead to long-term reduction in entry,” he said. “Our intent was to throw it all out there … to let stakeholders apply whichever subsidy level they think is most appropriate.”

June 30, 2019

FERC Rejects PJM Rule Change on Price Responsive Demand

By Rich Heidorn Jr.

FERC on Thursday rejected a PJM proposal to reduce load-serving entities’ savings from price-responsive demand (PRD) programs (ER19-1012).

PJM had proposed changing the calculation of the “nominal PRD value,” used for determining the PRD credit, from the reduction in load during the RTO’s annual peak to the lesser of summer and winter load reductions. The rule change was approved by stakeholders in December. (See “PRD Review for Capacity Performance Requirements,” PJM MRC/MC Briefs: Dec. 6, 2018.)

The RTO said it was attempting to correct disparities between PRD and Capacity Performance resources. It said that although PRD is not required to perform annually, it can displace an annual CP resource in the capacity auction. It also said the trigger for nonperformance charges for PRD is a maximum generation emergency, a less frequent occurrence than an emergency action, the trigger for CP resources.

Under price-responsive demand, load-serving entities automatically reduce consumption in response to high energy prices. | *PJM*

Exelon and the PJM Power Providers Group filed comments supporting the change.

But the commission sided with protests by the Independent Market Monitor and environmental organizations, who said the rules for PRD must be consistent with how LSEs are billed for capacity service — based on demand during PJM’s annual peak — because PRD is not a supply resource. State and consumer representatives had earlier questioned the changes. (See PJM Grilled on Price-Responsive Demand Rule Changes.)

The commission noted that PRD is limited to customers using dynamic retail rates, advanced metering and supervisory control to ensure the committed demand reductions are achieved.

“LSEs participating in PRD receive no energy payment other than reduced energy bills,” the commission said. “Similarly, LSEs receive a capacity service bill credit (the PRD credit) … based on nominal PRD value, which reflects the reduction in the LSE’s demand during PJM’s annual peak.”

The environmental organizations — the Natural Resources Defense Council’s Sustainable FERC Project, Earthjustice, Sierra Club and the Union of Concerned Scientists — offered an example to make their case: a PRD location with 100-MW peak summer load without PRD, a 75-MW summer load with PRD and an 85-MW peak winter load.

The location would get credit for reducing capacity needs by only 10 MW under PJM’s proposal, based on the lower winter load (85-75 MW), rather than the full 25-MW reduction.

“We find that PJM has not shown that it is just and reasonable to calculate the nominal PRD value and associated PRD credit based on the lesser of summer and winter load reductions,” the commission said. “We agree with the IMM and [environmental organizations] that PJM’s proposed approach would limit the amount of megawatts that PRD can commit and thereby inaccurately reflect PRD’s load-reduction capabilities.

“In light of our finding that it is unjust and unreasonable to calculate the nominal PRD value in a manner inconsistent with how an LSE’s capacity obligation is determined, we do not find it necessary to address the need for consistency between the PRD requirements and the requirements for capacity resources,” the commission added.

Tom Rutigliano, senior advocate for the Sustainable FERC Project, praised the ruling.

“A kilowatt of electricity saved is a kilowatt of dirty fossil-fuel energy not burned,” he said. “PJM has been trying to deny that demand response is a substitute for power plants, and the FERC decision today puts that wrongheaded argument to rest. FERC’s action keeps summer demand response in and removes the sword that’s been hanging over the market for this zero-emissions product.”

PJM spokesman Jeff Shields said the RTO is evaluating the order to determine its next steps. “PJM believes that consumers have benefited greatly from competition facilitated through its wholesale markets, and that all resources should compete on a level playing field,” he said. “This means that all resources competing in the market must provide the desired product on a comparable basis. PJM’s proposal would have leveled the playing field with respect to PRD as compared to demand response and generation resources.”

June 30, 2019

Minnesota Approves Huntley-Wilmarth Line

By Amanda Durish Cook

The Minnesota Public Utilities Commission on Thursday approved a proposal by ITC Midwest and Xcel Energy to build the Huntley-Wilmarth transmission project in the state’s south.

The project consists of a nearly 50-mile 345-kV line connecting Xcel’s Wilmarth substation and ITC’s Huntley substation in south-central Minnesota near the Iowa border (17-184 and 17-1 85).

Huntley-Wilmarth transmission line map — Huntley-Wilmarth project map | *Xcel Energy*

Estimated costs for the project, which will include substation upgrades, range from $88 million to $108 million, more than MISO’s original $81 million estimate.

Huntley-Wilmarth was part of MISO’s 2016 Transmission Expansion Plan, meeting criteria to qualify as a market efficiency project. As such, it would have been open to competitive bidding if not for Minnesota’s right-of-first-refusal law.

At the time, MISO respected the ROFR and declined to open the project to competitive bidding. (See Courts Uphold Minn. ROFR, MISO Cost Allocation.)

Xcel and ITC plan to start construction next year, with the line expected to be in service by the end of 2021. The utilities submitted applications for permitting to the Minnesota PUC in January 2018.

Xcel Energy-Minnesota President Chris Clark said the line will help facilitate Xcel’s goal to reduce carbon emissions 80% by 2030 and produce only carbon-free energy by 2050.

“The Huntley-Wilmarth project will provide several local and regional benefits including relieving congestion on the transmission grid, delivering clean, affordable energy to customers and increasing property tax revenues to local governments,” Xcel Senior Vice President of Transmission Michael Lamb said in a release.

In May, Administrative Law Judge Barbara Case found that “no more reasonable and prudent alternative has been identified to alleviate current and potential future transmission congestion in Southern Minnesota.” Case said the project will strengthen the area’s reliability, allow Minnesotans access to lower-cost energy and will lower emissions by tapping into renewable generation, allowing area coal plants to retire.

June 30, 2019

OMS Outlines Long-term Tx Planning Principles

By Amanda Durish Cook

The Organization of MISO States last week issued a set of principles intended to guide the RTO’s approach to long-term transmission planning.

The release of the document comes as MISO and its stakeholders are debating whether the RTO should launch a second regional transmission package similar to 2011’s multi-value project (MVP) portfolio. (See MISO Stakeholders: New Blueprint Needed for Tx Planning.)

“Considering the timeline associated with infrastructure planning and development, it’s important to get started now to ensure the grid we need in the future will be there to maintain reliability and support the evolving resource mix,” Minnesota Public Utilities Commissioner and OMS Vice President Matt Schuerger said in a statement.

OMS approved the eight basic principles in mid-June as part of a position statement, with support from 12 of its 17 regulator members.

Among the precepts laid out in the document, OMS states that MISO’s long-term planning must account for the changing resource mix based on “robust input from the states.” The group also wants the RTO to consider reliability requirements when planning transmission and to test transmission proposals “under a variety of system conditions and scenarios.”

OMS also asked for an exhaustive and transparent stakeholder process should MISO develop a new cost allocation for a long-term plan. It also said the RTO should move quickly to assess system needs if it’s planning on a new long-term transmission package “given the long time frames expected for infrastructure planning and development.”

Other principles for MISO to follow include:

Producing cost-effective solutions to “known physical and contractual system constraints.” Here, OMS specifically called out the MISO Midwest-to-South regional transfer limit.
Evaluating multiple transmission and non-transmission alternatives on a “level playing field.”
Publishing the cost impacts to subregions, including the costs of both moving ahead with or delaying transmission plans.
Ensuring that any state in the MISO footprint is not negatively impacted by a long-term transmission plan.

MISO executives at the Board Week meetings in June said the region must invest significantly in transmission investment to accommodate all the projects in the current 100-GW interconnection queue; however, RTO staff also expect several unprepared generation projects to drop out.

Opposition

Two MISO South states and the city of New Orleans came out in opposition to the principles, calling them “vague and overly broad” and lacking a “clear goal.”

“No one has demonstrated that these changes are needed or that MISO’s current long-range transmission planning process is unjust or unreasonable,” the Louisiana Public Service Commission, the Mississippi Public Service Commission and the New Orleans City Council wrote in a minority dissent.

They also said the principles won’t provide additional guidance because MISO already employs such principles in its long-term transmission planning.

“These principles are unnecessary and open to endless interpretation. To the extent MISO’s existing long-range transmission planning processes are unable to address a specific planning goal or object, interested stakeholders should raise those concerns within the MISO stakeholder process,” the opponents said.

The Illinois Commerce Commission chose not to take a stance on the document, and the Manitoba Public Utilities Board did not participate in crafting the principles.

At an Advisory Committee meeting June 19, Schuerger said the “common sense” principals were settled on after many months and the document represented “broad support” for “key positions and policies.”

“It was not a unanimous vote; not everyone agreed,” Schuerger said, but he noted that most states came together in agreement.

“We are working continually to bring all of our states together,” he added.

Study Scoped for MISO-SPP Seams

In a separate development related to transmission planning, Independent Market Monitor David Patton last week revealed the scope of the joint analysis on seams issues requested by OMS and the SPP Regional State Committee. (See RSC, OMS Approve Monitors’ Seams Study.) Patton called MISO-SPP market-to-market coordination was his “No. 1 priority.”

The study scope focuses on eight areas for improvement: market‐to‐market coordination; possible creation of targeted market efficiency projects like those between MISO and PJM; more efficient interface pricing; optimization of interchange transactions across the RTOs’ interface; better management of the regional directional transfer limit; outage scheduling and day‐ahead coordination; elimination of rate pancaking; and possible joint dispatch.

“Some of these issues we’ve raised in our reports, and some the SPP Monitor has raised,” Patton said during a call hosted by the Board of Directors’ Markets Committee on Wednesday.

Patton said he thought analyses on rate pancaking and joint dispatch would be the least beneficial, the former because it would not reduce production costs, and the latter because it might require some merging of the RTOs.

“That one confuses me,” he said of joint dispatch.

Patton said the RTOs could see more economic benefits from optimizing their interchanges and better coordinating their market-to-market process. But overall, he praised the work between the MISO and SPP states.

“I actually think there are some issues on here where the states can help the RTOs come to a consensus, an agreement,” Patton said.

He said the goal is to complete the analyses before 2020. MISO executives said they may have to adjust their 2019 budget in order to compensate the Monitor and his staff for the extra work. Patton said he would come up with a statement of work soon.

The Markets Committee also addressed the study in closed session immediately following the meeting.

June 30, 2019

Carbon Pricing Study Navigates Shifting NY Landscape

By Michael Kuser

RENSSELAER, N.Y. — If you’ve ever seen a circus performer riding two horses around the ring, one foot on each, you have a good idea of the balancing act Analysis Group’s Sue Tierney had to execute in detailing the preliminary results of her firm’s carbon pricing study for NYISO.

Tierney’s performance came just days after the New York legislature passed the Climate Leadership and Community Protection Act (A8429), a development that could further complicate NYISO’s carbon pricing effort as it moves to a conclusion. (See “New Energy Law Could Affect CO2 Market Design,” NYISO Business Issues Committee Briefs: June 20, 2019.)

“We are looking at the carbon proposal as proposed by NYISO last December, although we are now revising our work to take into account the implications of shifting public policies in New York,” Tierney told NYISO’s Installed Capacity/Market Issues Working Group (ICAP/MIWG) on June 24.

The third-party study examining the impacts of pricing carbon into NYISO’s wholesale electricity markets is intended to augment the Brattle Group report process that concluded in December, and is underway just as the new bill makes statutory many of Gov. Andrew Cuomo’s environmental targets, such as requiring 70% of the state’s electricity to be generated by renewable resources by 2030.

“We are not going to advocate for one particular action or another, though our point of view may be obvious from our analysis,” Tierney said. The final results are expected to be previewed with stakeholders ahead of the ISO posting the technical report and a separate summary for policy makers.

The new law would nearly quadruple the state’s offshore wind energy goal to 9 GW by 2035 and target making the electric system carbon-neutral by 2040. The bill also doubles distributed solar generation to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030.

After presenting information about changes in NOx emissions that could be anticipated with a carbon price in the NYISO energy market, Tierney said such outcomes are important, “even with the peaker rule in New York City,” referring to the state Department of Environmental Conservation’s proposal to revise its Clean Air Act regulations. The changes to lower allowable NOx emissions from simple cycle and regenerative combustion turbines during the ozone season would go into effect May 1, 2023, with generator compliance plans due by March 2, 2020. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

In contrast, the new climate bill will take effect once it’s signed by Cuomo, expected soon. The bill will assign the responsibility of adopting and enumerating the new standards to the DEC; establish an environmental justice advisory group; and create a 22-member “New York state climate action council” that “shall consult with the climate justice working group … the Department of State Utility Intervention Unit and the federally designated electric bulk system operator.”

Price Signals

“The 70% renewables target in the new bill is consistent with what the governor has been saying about the electric sector since January,” Tierney said. “There’s going to be more demand for electricity because of these goals now established in the act.”

The power sector will play a key role, given the intent to convert transportation and building heating and cooling end uses to electricity, she said.

Adding that the bill will also include deeper energy efficiency measures, Tierney said the other forms of “beneficial electricity use” promoted in the statute would create pressure to increase electricity supply and demand.

“This is the yin and yang of more electricity use and better efficiency,” Tierney said. “If you go meet all these renewables goals and growing demand with long-term contracts for [renewable energy credits], it would mean an increasingly large — and potentially unsustainable — share of the NYISO market under out-of-market, [policy-driven] contracts. By contrast, a carbon price could lessen the reliance of certain renewables on out-of-market contracts.”

A carbon pricing mechanism could stimulate entry based on wholesale price signals and reduce risks associated with increasing quantities of supply under long-term contracts in FERC-regulated wholesale markets, the presentation said. It noted that by 2030, if all new renewables entered the market with long-term REC contracts, in addition to those already under contract, and if zero-emission credit contracts were extended for the FitzPatrick and Nine Mile Point 2 nuclear plants beyond 2029, roughly 50 to 60% of supply would be under contract.

Howard Fromer, director of market policy for PSEG Power New York, said, “The bill directs a significant portion of the state’s clean energy and energy efficiency dollars to environmentally disadvantaged communities … perhaps reducing the amount available for subsidizing renewable energy resources.”

“The point here is that carbon pricing complement and reduce the role of long-term or out-of-market contracts,” Tierney said. “Having as full a toolkit as possible will benefit policymakers. It could provide greater visibility in energy markets for the value of zero-carbon resources, and possibly even help the upstate nukes beyond 2029, when the ZEC program ends. I have no idea whether the nuke owners would act in response, but a price signal is better than nothing.”

The Brattle study and a separate analysis released in May by the ISO’s Market Monitor, Potomac Economics, both point to power production efficiency improvements, lower emissions (in environmentally disadvantaged communities in particular), public health improvements and reduction in overall use of natural gas, Tierney said.

Public Benefits

Regarding public health benefits and other impacts, “Brattle and the Potomac Economics study could understate some impacts … because of their underlying assumption that all of the renewables needed to meet the prior 50% target by 2030 would show up in any event in the base case at no apparent cost to consumers,” Tierney said.

She added that that level of clean power is not free: “So the question that is still unanswered is whether a carbon price would help reduce the overall cost of entry of renewables?

“A carbon price would affect the dispatch of fossil units, and that will reduce local air emissions, as well as carbon emissions,” Tierney said. “We wouldn’t have protests about power plants if there were no benefit in removing them.”

Mark Reeder, representing the Alliance for Clean Energy New York, said, “There are a number of benefits of carbon pricing that Brattle said will occur but which Brattle said were too hard to quantify, so [they] are set to zero … like the benefits of increasing the likelihood of life extensions of existing hydro, the financial benefit to [the New York Power Authority], etc.”

On the Market Monitoring Unit’s analysis of the impacts of carbon pricing, which for consumer price impacts considered the two scenarios of base case and repowering, Reeder pointed out that the first three years of a carbon charge would cost consumers, but the following seven years would save them money, and he asked why not average the effect.

Erin Hogan, representing the UIU, said it would be better not to average, that “people don’t dismiss three years of pain so easily. If any report should be balanced, this is the one.”