Page 1299 – RTO Insider

April 4, 2017

Texas PUC Briefs

The Public Utility Commission of Texas last week approved an ERCOT request to share confidential generator-specific information with Lubbock Power & Light as the municipal utility determines how to integrate its load with the ISO.

LP&L has said it will transition about 430 MW of its load from SPP to ERCOT in June 2019. LP&L and the two grid operators are each conducting studies on how the move will affect their systems and stakeholders. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)

As part of its study, LP&L asked ERCOT for data the ISO is only authorized to give to transmission or distribution service providers. ERCOT asked the commission to approve a confidentiality agreement so it could provide the information to LP&L (Docket 45633).

ERCOT texas puc ERS local blackouts — Anderson | © *RTO Insider*

“I think the process ERCOT has proposed is not only acceptable, but the right thing to do,” Commissioner Ken Anderson said during an open meeting Thursday.

ERCOT said LP&L’s planned move creates “unique” procedural questions that are not clearly defined in any rule or protocol. It concluded “it would be appropriate to provide generator-unit specific data to certain LP&L representatives in advance of the anticipated contested case because this is data that ERCOT is using in preparing its commission-requested study, and thus would likely be necessary to any similar study conducted by LP&L.”

The Texas ISO’s legal counsel, Chad Seely, told the commissioners that ERCOT will file a market notice informing all resource entities of the discussion before the PUC and asking for their feedback on the draft confidentiality agreement.

The PUC has delayed a decision on who will pay for studies related to the planned move. LP&L requested the delay, saying study costs shouldn’t be assigned until ERCOT and SPP finish their separate cost-benefit studies, which are expected to be finalized by midyear. (See Texas PUC Delays Assignment of LP&L Study Costs.)

An ERCOT analysis completed last June indicated it will cost $364 million and take 141 miles of new 345-kV transmission to incorporate LP&L into the Texas grid.

PUC Chair Donna Nelson referenced the March 23 announcement by LP&L and Xcel Energy subsidiary Southwestern Public Service that they had agreed to a two-year extension of a 400-MW power purchase agreement through May 2021. The contract would have expired May 31, 2019.

“Not that we should slow our process down,” Nelson said pointedly.

The announcement followed months of negotiations and more than a year of research by LP&L management to secure a “seamless transition” beyond the current PPA’s expiration. Utility officials said the extension allows the city more time to evaluate its future options and “not be pressured by the calendar.”

The “transition contract … is an important step in securing affordable and reliable power for our customers as we work toward achieving our long-term power supply goals,” said David McCalla, LP&L’s director of electric utilities, in a statement.

LP&L has been a total requirements customer of SPS since 2004, with 100% of its power purchased from SPS through the West Texas Municipal Power Agency. The utility will replace that contract with capacity and energy through a 170-MW partial-requirements wholesale contract signed with SPS in 2010; a 100-MW wind contract through its membership with the West Texas agency; 114 MW of LP&L-owned generating plants; and the 400-MW transition contract, according to the Lubbock Avalanche Journal.

Lubbock Mayor Dan Pope called the extension an “important milestone” for the city, saying it would provide “a stable and cost-effective source of power for LP&L customers while we work to join the majority of Texas as participants in the ERCOT market.”

LP&L is the third largest municipal utility in Texas, behind Austin Energy and CPS Energy, with a peak load of about 605 MW. It serves more than 104,000 meters and owns and maintains 4,936 miles of power lines and three power plants in and around the city.

Entergy Texas Compliance with MISO Control Order Nearly Complete

The PUC accepted staff’s recommendation to close one docket (Project 40979) and focus on another (Project 46397) related to Entergy Texas’ transfer of operational control of its transmission assets to MISO.

Staff told the commissioners Entergy Texas has met almost all of the commission’s material requirements from a 2012 change-of-control order approving the company’s MISO membership. Staff opened Project No. 40979 to track the utility’s and MISO’s compliance with the order.

Entergy Texas is working on the final requirement, a cost-benefit analysis of the first five years of MISO membership. The PUC’s Margaret Pemberton said a draft study is expected in August, with the final version to be filed in November.

The utility will perform two types of analyses: backward-looking, to assess actual benefits from participation in MISO, and forward-looking, to assess the project benefits of remaining in MISO rather than leaving after the first five years.

Anderson said he hopes staff looks “very carefully” at the study’s assumptions, which include comparisons with membership in SPP.

“We need to test the assumptions … in SPP and what requirements, if any, there are on load-serving entities to maintain a particular reserve margin … and how that’s enforced,” Anderson said.

PUC Approves ERS, RMR Rulemakings

The PUC approved two rulemakings related to emergency response service (Project 45927) and reliability-must-run contracts (Project 46369).

The ERS amendment will allow those resources to participate in must-run alternative (MRA) arrangements, replacing RMR generation resources.

The commission decided not to allow ERS resources to be used in local transmission emergencies. The commissioners asked staff in early March to revise the rulemaking, saying it did not favor expanding the program to prevent local load-shed events. (See Texas PUC Wary of Using ERS to Avoid Local Blackouts.)

The RMR rulemaking adjusts the notice requirements and complaint timeline applicable to suspending a resource’s operation. It also gives ERCOT the discretion to decline to enter into an RMR agreement based on the economic value of lost load, requires ERCOT approval of RMR and MRA agreements and requires refunds in some instances for capital expenditures related to those agreements.

— Tom Kleckner

April 4, 2017

Millstone to Enter FCA 12; No Closure Likely Before 2022

By Michael Kuser

The Millstone nuclear power plant will bid into ISO-NE’s 12th Forward Capacity Auction next year, indicating owner Dominion Energy expects it to continue operations into at least 2022.

Despite questions about Millstone’s profitability, Dominion did not inform ISO-NE by the March 24 deadline of its intent to retire the plant. Assuming Millstone clears the auction, it would be obligated to operate through May 2022, the end of the 2021/22 planning year.

Dominion’s decision has implications both for New England’s wholesale market — the plant’s delisting would have created upward pressure on capacity prices — and the company’s hope for support from Connecticut lawmakers.

In March, Connecticut legislators unveiled a bill that would allow Millstone, the state’s only nuclear generator, to bid into the state procurement process now reserved for renewable energy resources. (See Connecticut Moves Closer to Equating Nuclear with Renewables.)

Matt Fossen, spokesman for the Stop the Millstone Payout coalition, said Dominion’s failure to file a delist bid by the March 24 deadline undermines the claims of Dominion lobbyists who “make it sound like there is a dire, impending threat to the plant’s existence.” This could not be true, he said, if the plant can continue operating for the next five years.

“Dominion will always meet its obligations in the markets in which we operate, but we do have the ability, within the current market rules, to cease operations if a facility is no longer economically viable,” responded Kevin Hennessy, Dominion’s state policy director for New England. “The dirty fossil fuel generators who oppose CT Senate Bill 106 are threatened by the state smartly choosing to purchase power from clean, reliable, carbon-free sources of electricity like Millstone. Connecticut consumers pay the highest retail electric rates in the country. SB 106 would reduce those rates by cutting out the middle man and allowing the state to buy directly from Millstone.”

ISO-NE spokesman Matt Kakley wanted no part of the dispute. “As the administrator of the region’s competitive markets, the ISO does not comment on the business decisions of individual market participants,” he said.

Is Millstone Profitable or Not?

Hennessy said Dominion does not release profits or loss data on individual units. But in its earnings call for the fourth quarter of 2016, CFO Mark F. McGettrick indicated Millstone, which will have two refueling outages this year, would be a drag on earnings and that it will be “challenging” for the company to meet its historical earnings growth rate. “Now that we have hedged most of Millstone’s 2017 expected output, we estimate a $10 to $12/MWh reduction in realized energy prices versus last year, impacting 2017 earnings by about 15 to 20 cents/share,” he said, according to a transcript by Seeking Alpha.

The company, which had operating earnings of $3.80/share in 2016, is projecting $3.40 to $3.90/share for this year.

However, in projecting operating earnings for 2018, McGettrick said that the Connecticut nuclear power station would likely contribute to earnings, as only “one fuel refueling outage at Millstone should add another 10 cents/share to year-over-year results.”

The company said the net capacity factor for its six units was 93% last year, the highest since 2013 and the second highest since Millstone was acquired in 2001 from Northeast Utilities for $1.28 billion.

Greg Gordon, head of power and utilities research at investment advisory firm Evercore ISI, asked officials on the call to confirm whether Dominion “did not contemplate any change in regulatory scheme in Connecticut or Massachusetts, as it pertains to clean energy credits for Millstone.”

McGettrick responded that the “only thing we’ve factored into our growth rate and for 2018 is a very modest increase in power prices in the Northeast just because we think they’re extraordinarily low right now. It was not a reflection of any legislative effort that would be out there, but just … a normal slow recovery in the Northeast on power.”

Michael Weinstein, a broker at Credit Suisse Securities, asked about the possibility for Massachusetts legislation to support nuclear and what form it might take.

CEO Thomas F. Farrell said, “What we’ve heard is more through the regulatory process in Massachusetts, but yes … all of this is in development. … It would be a similar approach to what Connecticut is considering. … It is an opportunity for us to fit into their clean energy program and compete with other clean energy sources.”

Angie Storozynski, an analyst for Macquarie Capital, asked how much the Connecticut legislation and other state efforts supporting nuclear would add to earnings. “Are we talking, I don’t know, 5 cents, are we talking 20 cents? I mean, just a rough estimate.”

“We have no estimate to give you,” McGettrick responded. “The legislation is not even out of committee. And the exact structure is still evolving, I think, so we don’t have any estimate or even a probability at this point whether there’ll be success in Connecticut. We would hope there would be, but we don’t have a number today at all.”

At 2,111 MW, Millstone is New England’s largest power plant, producing more than half of the electric power used in Connecticut and about one-seventh of New England’s. Unit 2 (883 MW) is licensed to operate through 2035, while Unit 3 (1,228 MW) is licensed through 2040.

April 3, 2017

RTOs Unfazed by Trump Climate Order

By Michael Brooks, Amanda Durish Cook and Tom Kleckner

While President Trump’s executive order rolling back the Obama administration’s efforts to combat climate change upset environmentalists, RTO officials are largely shrugging their shoulders, vowing to continue on without the federal government as market forces and state policies continue decarbonizing their generation mixes.

Their reaction to Trump’s order last week was largely the same long-term view as they expressed when the CPP was stayed in February 2016. (See RTOs, States Respond to CPP Stay.)

MISO Tx Planning Unchanged

MISO, for example, has spent the past several months treating the CPP like Schrödinger’s cat: alive and dead simultaneously.

miso board mtep — Curran | © *RTO Insider*

“We planned for the absence of any kind of federal carbon policy and the addition of any kind of federal carbon policy. We’re planning for both of these scenarios simultaneously,” Vice President of System Planning Jennifer Curran said in an interview. To MISO, “there is no more uncertainty today about the Clean Power Plan than there was yesterday. We’re having to execute transmission policy as if it would exist and as if it wouldn’t exist.”

MISO will soon reassess its futures weighting — or the likelihood that some futures will occur before others — but it has nothing to do with the CPP’s downfall, Curran said. At March’s board of directors meeting, Curran said MISO is currently testing for “gaps” in MISO’s overall futures development.

“When we think about the futures scenarios, what we do is try to capture the uncertainty that exists in state policy, in federal policy and in energy economics,” she continued. “We don’t know exactly what the future looks like, so we’re identifying … transmission projects that will perform well in a variety of scenarios and provide lower cost energy to consumers.”

All but three states in MISO’s footprint — Illinois, Iowa and Minnesota — joined the lawsuit to block the Clean Power Plan.

But despite state officials’ antipathy to the EPA mandate, MISO’s carbon emissions have dropped from just under 550 million tons/year in 2005 to 450 million tons/year in 2015. RTO officials say they expect coal plant retirements and increases in natural gas and renewable sources to continue reducing emissions regardless of federal regulations.

Other RTO officials agree that trends that are changing the generation mix will continue.

PJM: Regulatory Changes Less Important than Gas Prices

PJM unveiled a comprehensive analysis of the CPP in September and little has changed since then, the grid operator says, despite the recent instability of the federal rule.

“Our analysis indicated that regulatory [changes] didn’t have as much impact as … the price of natural gas,” PJM’s Mike Bryson said last week during a media briefing introducing a whitepaper on system resiliency. “That effect [of natural gas pricing] would have more to do with getting to the targets.” (See related story, PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)

MISO and PJM recently completed a joint CPP study that built on their previous individual studies. While these analyses may be moot, the RTOs credited them with providing “a good stress test” for the systems’ future. (See MISO, PJM Find Value in CPP Study, Despite Rule’s Likely Demise.)

SPP: Renewables Growth to Continue, Though Pace in Question

SPP conducted three assessments of the CPP’s various effects on its footprint, the last of which was released in July 2015. (See SPP: State-by-State Compliance Would Hike Costs.)

SPP’s most recent Integrated Transmission Planning 10-Year Assessment included two scenarios in which the CPP was in place and predicted more output from renewables and natural gas.

“Even after the plan was stayed at the Supreme Court — and most recently, the presidential order was issued — our members and stakeholders were still comfortable with the results of that study,” Lanny Nickell, SPP vice president of engineering, said in an interview. “That was primarily because of the assumption of higher renewables and an energy shift from high carbon-emitting resources to lower carbon-emitting and renewable resources, which is actually what we are already seeing.”

SPP has almost 17 GW of renewable generation and expects 22 GW by 2018, based on the resources in the generator interconnection queue.

“That growth hasn’t been driven by the Clean Power Plan, it’s been driven by market forces,” Nickell said. “The production tax credit has something to do with that too. We will continue to plan based on the expectations renewables will continue to grow. What we don’t know is — after the expiration of the PTC — will the growth rate we’ve seen be sustainable?

“What will happen in 2019, when we start the next 10-year assessment, is yet to be known. Will [renewables] be beyond 22 GW? We have another 30 GW of wind under study.”

Nickell said the pace of coal plant retirements may slow as a result of Trump’s action. “While we’ve seen a lot and we expect a few more retirements, I do expect that will stabilize somewhat,” he said.

California, New York Going it Alone

The RTOs’ planning has been based not only on the CPP but also on state and municipal carbon-reduction measures. Minnesota, for example, is on track to reduce emissions 40% by 2030 with or without the CPP. Late last year, Michigan passed a new energy policy that contains a nonbinding goal of meeting 35% of the state’s energy needs through renewables and energy efficiency by 2025.

Even Republican stronghold Carmel, Ind. — home of MISO’s headquarters — has pledged to continue energy efficiency and carbon-limiting measures. As The Washington Post reported, the city has shifted its vehicle fleet to hybrids and biofuel, installed low-energy LED streetlights, planted trees to absorb carbon dioxide and provide shade, and converted dozens of intersections into roundabouts — which help to conserve gasoline, reduce air pollution and eliminate the electricity demand of traffic lights.

New York and California, which account for about 10% of U.S. greenhouse gas emissions, vowed last week to continue working toward their aggressive climate goals, whose targets far exceed what would have been required under the CPP: 40% below 1990 levels by 2030 and 80% below 1990 levels by 2050. The states policies have largely driven planning by CAISO and NYISO.

In a joint statement, California Gov. Jerry Brown and New York Gov. Andrew Cuomo vowed to “help fill the void left by the federal government.”

The states are also part of the Under2 Coalition, a pact of 167 jurisdictions around the world that have committed to limiting the increase in the global temperature to 2 degrees Celsius.

And both states’ attorneys general are among a coalition that said it is considering legal action to uphold the CPP.

“Addressing our country’s largest source of carbon pollution — existing fossil fuel-burning power plants — is both required under the Clean Air Act and essential to mitigating climate change’s growing harm to our public health, environments and economies,” said the attorneys general. “We won’t hesitate to protect those we serve — including by aggressively opposing in court President Trump’s actions that ignore both the law and the critical importance of confronting the very real threat of climate change.”

ISO-NE

Among the attorneys general in the coalition are Connecticut, Maine, Massachusetts, Rhode Island and Vermont, four of the five states within ISO-NE. Far from considering a rollback in carbon-cutting efforts, New England stakeholders are deliberating over ways to incorporate state GHG policies into the wholesale markets. (See IMAPP Pondering 4 Options for Incorporating Clean Energy in NE.)

David T. Doot, counsel and secretary to the New England Power Pool, said that under Obama, FERC was “begging” New England to propose market rules that incorporate carbon policy. The commission has scheduled a technical conference for May 1-2 on the energy and capacity markets in PJM, NYISO and ISO-NE.

“Now, that was FERC before President Trump,” Doot told the Northeast Energy and Commerce Association’s 2017 Renewable Energy Conference on March 6. After Trump? “There’s just no way of predicting,” Doot said.

ERCOT

Similarly, ERCOT’s planning cannot ignore Texas’ anti-CPP stance.

“We’re heartened by the president’s latest action, which shows he’s serious about returning common sense and the rule of law to the EPA,” Texas Attorney General Ken Paxton said in a statement.

But the economics of renewables may be a bigger factor than state policy in Texas, which boasts the largest wind generation fleet of any state and is also increasing its solar capacity.

ERCOT’s Long-Term System Assessment, which is updated every other year, includes a range of regulatory scenarios that could occur. “As the assessment is developed for the next update in 2018, ERCOT staff and stakeholders will evaluate what likely scenarios would affect transmission planning within the next planning horizon,” spokeswoman Robbie Searcy said.

Searcy said it was unclear whether the Trump order will affect the pace of new renewable generation.

About 29 GW of new wind and utility-scale solar generation resources are under study in ERCOT, and more than 12 GW have interconnection agreements. “Our last Long-Term System Assessment indicated these resources likely would continue to grow under all scenarios studied,” Searcy said.

Michael Kuser and Rory D. Sweeney contributed to this report.

April 3, 2017

Trump Policies Likely Little Help to Coal; May Aid China

By Rich Heidorn Jr.

WASHINGTON — The executive order signed by President Trump on March 28 embraces the politically nuanced “all of the above” energy policy, declaring “it is … in the national interest to ensure that the nation’s electricity is affordable, reliable, safe, secure and clean, and that it can be produced from coal, natural gas, nuclear material, flowing water and other domestic sources, including renewable sources.”

But make no mistake. Trump — like Barack Obama before him — likes some fuels more than others.

In addition to seeking to undo the Clean Power Plan, the order also ends a moratorium on federal coal leasing and eliminates the requirement that federal officials consider the impact of climate change when making decisions.

Trump signed the order following remarks in the wood-paneled Map Room at EPA headquarters, surrounded by his top energy lieutenants and a group of coal miners and executives. “You know what this says?” Trump asked the miners, pen in hand. “You’re going back to work.”

Trump’s remarks followed those of Energy Secretary Rick Perry, Interior Secretary Ryan Zinke, EPA Administrator Scott Pruitt and Vice President Mike Pence, who also pledged to reverse the decline in coal mining jobs. “Those days are over,” Pence promised, “because the war on coal is over.”

Coal Jobs

While industry interest groups and coal-state lawmakers praised the action, most reaction to promises of a rebound in coal mining jobs ranged from skepticism to derision. Natural gas and renewable generation have become cheaper than coal-fired power in many regions, and the most productive mines are increasingly automated.

Trump coal energy efficiency renewable energy — Murray

Trump and Pence “cannot bring the coal industry back,” Robert E. Murray, CEO of Murray Energy, one of the nation’s largest coal mining companies, told Fox Business. “But they can stop the destruction.”

Trump’s order also requires EPA to review its emission standards for new generators, which effectively banned new coal plants without carbon sequestration. The levelized cost of a new coal generator with sequestration is about double the cost of new solar PV and wind, according to the Energy Information Administration.

But even current plants without sequestration are having difficulty competing against renewables and cheap natural gas.

EIA’s annual coal report last November found that U.S. coal production dropped 10.3% in 2015 to less than 900 million short tons, the lowest annual production level since 1986. Employment at U.S. coal mines dropped 12% in the year to less than 66,000, the lowest since the agency began collecting data in 1978.

More than 21 GW of coal generation retired in 2015 and 2016, largely as result of the Mercury and Air Toxics Standards, and EIA says another 14 GW is at risk of retirement by the end of 2028.

Energy economist Robert W. Godby, of the University of Wyoming, told The New York Times that Trump’s order could delay the closing of some endangered coal mines for as long as a decade. But because of increasing mechanization, “they’re not hiring people,” he said. “So even if we saw an increase in coal production, we could see a decrease in coal jobs.”

Economic Impact

At the signing ceremony, Trump’s cabinet members portrayed the Obama administration’s environmental policies as a drag on the economy, with Perry decrying “poorly designed government policies [and] distorted markets.”

“The executive order will begin the process to unravel the red tape that’s been keeping investment on the sidelines and innovation stymied,” Perry said.

“We’re no longer going to have regulatory assault on any given sector of our economy,” Pruitt said. “We’re not going to allow regulations here at the EPA to pick winners and losers.”

“Our nation can’t run on pixie dust and hope,” Zinke said.

EPA’s Regulatory Impact Analysis of the CPP, which predicts the rule would produce economic and health benefits far exceeding its costs, is not given credence by the agency’s critics.

But many others say Trump’s policies will hurt American leadership in clean energy technologies.

Trump’s budget would cut the $2 billion budget for the Department of Energy’s Office of Energy Efficiency and Renewable Energy by at least 25%. EERE’s research has been credited with helping produce the 74% drop in the cost of utility-scale solar since 2010.

Although it is the world’s largest coal consumer, China reached an agreement with the Obama administration in 2014 to cut both nations’ emissions, a pact that set the stage for the 2015 Paris Agreement.

Bloomberg New Energy Finance reported that China had $87.8 billion in clean energy investments in 2016, versus $58.6 billion in the U.S. And China recently announced it will invest $360 billion in renewable energy by 2020, which the government predicts will create 13 million new jobs.

China’s goal is to increase its use of non-fossil fuels to 20% of total energy consumption by 2030, with 200 GW of wind capacity and 100 GW of solar. The U.S. had 81.3 GW of wind capacity and 42.4 GW of solar PV as of the end of 2016.

Already, Chinese manufacturers lead the world in production of wind turbines, solar panels and batteries.

“The Trump administration is turning the nation’s back on the historic opportunity to build a clean energy future — a future that will modernize our energy system, offer consumers better value for their energy dollars and invest in state and local economies while taking the right steps to reduce climate pollution,” said Daniel Sosland, president of Acadia Center, which supports clean energy policies.

EIA predicts renewable electricity generation will grow 3.9% annually through 2030 without the CPP and 4.7% a year with it.

Regardless of what happens with the CPP, utilities, major corporations and many states are likely to continue their efforts at decarbonizing the generation mix.

New York Gov. Andrew Cuomo and California Gov. Jerry Brown issued a joint statement reaffirming their commitment to exceed the CPP’s targets.

“Climate change is real and will not be wished away by rhetoric or denial,” they said. “Together, California and New York represent approximately 60 million people — nearly one-in-five Americans — and 20% of the nation’s gross domestic product. With or without Washington, we will work with our partners throughout the world to aggressively fight climate change and protect our future.”

Reaction

Other reaction to Trump’s order was, unsurprisingly, mixed.

Environmentalists said the order could damage climate change efforts while producing no benefits for the coal industry. On Wednesday, a coalition of environmental groups filed suit over lifting the coal leasing moratorium, contending Trump’s action is illegal because it was done without an environmental impact study.

“The fact that major utilities in Ohio are planning to shut down a number of dirty coal-fired power plants throughout the state should be an indication that the market is moving on to less costly and cleaner resources,” said Shannon Fisk, managing attorney for the Earthjustice coal litigation program. “We will be advocating to maximize energy efficiency and renewable energy as the best options for replacing coal plants, and for providing a just economic transition for coal workers and communities.”

David Doniger, director of the Natural Resources Defense Council’s Climate and Clean Air Program, tweeted: “Coal country needs a path to the economy of the future, not false hopes Trump won’t deliver.”

Paul Bailey, CEO of The American Coalition for Clean Coal Electricity, called the CPP “the poster child for regulations that are unnecessarily expensive and have no meaningful environmental benefit.”

The American Public Power Association also supported the president’s action. “Public power has previously voiced its legal objection to the rule for requiring utilities to fundamentally alter the way they generate electricity. In some cases, utilities would have been forced to abandon functional power plants while continuing to pay them off,” the group said.

April 3, 2017

2016 NYISO Reliability Plan IDs No Needs

By Michael Kuser

RENSSELAER, N.Y. — NYISO’s Management Committee voted unanimously to recommend board approval of the grid operator’s 2016 Comprehensive Reliability Plan despite concerns about locational planning requirements and the shutdown of the Indian Point nuclear plant.

The CRP is prepared every two years. Laura Popa, manager of reliability planning, told the committee that under the conditions studied in the 2016 Reliability Needs Assessment, the grid’s bulk power transmission facilities meet all applicable reliability criteria from now through 2026.

Last October, officials identified two reliability needs: the Oakdale 345/115-kV substation in the NYSEG zone and the East Garden City-Valley Stream 138-kV line in PSEG-LIPA. In November, however, the transmission operators presented local transmission plans and operational procedures that eliminated the two needs.

Kevin Lang of law firm Couch White, representing New York City, said the grid operator should have considered in its CRP the closure of the Indian Point nuclear plant, whose two units are set to be shut down successively in 2020 and 2021. “I don’t think it’s appropriate to wait for a Notice to Retire, and it’s certainly important to New York City,” Lang said. He urged NYISO to go ahead with that analysis.

The grid operator contends, however, that it is pointless under the prevailing fast-changing market conditions to do a full reliability study before they receive a formal notice to retire the plant. (See NYISO, PSC: No Worries on Replacing Indian Point Capacity.)

David Patton, head of NYISO’s Market Monitoring Unit, said the MMU had concerns about locational planning requirements under the current rules. Some wind farms, for example, might be located in places that aggravate transmission constraints. “In particular, we find that market incentives for investment in resources in certain areas of the 115-kV system in upstate New York are inadequate partly because these lower voltage constraints are not reflected in the NYISO’s energy and ancillary services markets,” he said. “This has contributed to the need for cost-of-service contracts to keep older capacity in service.”

indian point NYISO reliability plan — | *NYISO*

Patton recommended the ISO consider managing upstate 115-kV constraints in the day-ahead and real-time markets that currently require supplemental commitments, out-of-merit dispatch and other expensive operator actions.

Howard Fromer, director of market policy at PSEG Power New York, said that the CRP failed to mention any adjustments “to accommodate vast new changes in our intermittent energy supply. We don’t yet have a good answer to the question of ‘Will we have a reliable system?’”

Lang questioned the validity of the Monitor’s approach. “Some of these resources are coal plants that are 50 years old or older, or nuclear plants,” he said. “These resources are also being pushed out for policy reasons, not just market reasons. Low natural gas prices are competitive forces. … I don’t see any real analysis in your comments. Where’s your cost-benefit analysis?”

April 3, 2017

Trump Order Begins Perilous Attempt to Undo Clean Power Plan

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — President Trump signed an executive order Tuesday directing EPA to begin the lengthy process of undoing its Clean Power Plan, a centerpiece of American efforts to battle climate change.

Years of Litigation to Come?

The long-promised order, which directs EPA Administrator Scott Pruitt to immediately review and begin steps to rescind the CPP, is but the first step in a process that could take years. And it’s unclear if the effort will ultimately succeed.

The Supreme Court stayed the CPP in February 2016 pending a legal challenge by more than two dozen states that contended the rule overstepped EPA’s regulatory authority. The D.C. Circuit Court of Appeals heard arguments in the case in September. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

Shortly after Trump signed the order, the Justice Department filed a motion with the D.C. Circuit to hold the state challenge in abeyance while EPA reconsiders the plan. “The Clean Power Plan is under close scrutiny by the EPA, and the prior positions taken by the agency with respect to the rule do not necessarily reflect its ultimate conclusions,” the department said.

trump epa clean power plan — President Trump speaks before signing an executive order seeking to undo the Clean Power Plan as Vice President Mike Pence, EPA Administrator Scott Pruitt, Interior Secretary Ryan Zinke and coal miners watch. | *WhiteHouse.gov*

On Thursday, Pruitt sent a letter to state governors, telling them, “It is the policy of the Environmental Protection Agency that states have no obligation to spend resources to comply with a rule that has been stayed by the Supreme Court of the United States. To the extent any deadlines become relevant in the future, case law and past practice of the EPA supports the application of day-to-day tolling.”

Legal experts differ on whether the D.C. Circuit will dismiss the states’ challenge based on the Trump administration’s withdrawal of support. Environmental groups immediately promised to fight the reversal of the plan.

The challenge for the Trump administration is to kill the CPP without providing some alternative for controlling greenhouse gases. Under the 1946 Administrative Procedure Act, the federal rulemaking process cannot be “arbitrary and capricious.”

Thus, Trump’s order will put EPA officials in the odd position of having to contradict the findings the agency cited when it issued the final rule in August 2015, which incorporated feedback from 4.3 million comments and months of meetings with state regulators, utilities and RTO officials. (See Revised Clean Power Plan Allows More Time, Sets Higher Targets.)

The administration also will have to overcome the Supreme Court’s 2007 ruling in Massachusetts v. EPA that carbon dioxide is a pollutant that EPA must regulate under the Clean Air Act and the agency’s 2009 finding that greenhouse gases endanger public health.

According to a report in Politico, Pruitt successfully argued against attempting to reverse the agency’s endangerment finding, citing concerns it would be difficult to defend in a court challenge.

Myron Ebell of the Competitive Enterprise Institute and the former head of Trump’s EPA transition team, told Politico that leaving the endangerment finding in place would require EPA to come up with an alternative to the CPP for regulating power plant emissions. “Before you know it, you end up having to do a Trump Clean Power Plan,” he said.

Paris Agreement Threatened

Although the order does not indicate whether the U.S. will withdraw from the 2015 Paris Agreement on climate change, eliminating the CPP would make it far more difficult for the nation to meet its obligations to cut its carbon emissions to 26% below 2005 levels by 2025. The CPP requires a 32% reduction in power plant CO₂ emissions from 2005 levels by 2030.

Economic consultancy company Rhodium Group estimates the U.S. would reduce carbon emissions by 21% below 2005 levels in 2025 under the CPP but that the reduction would flatten at 14% under Trump’s rollback.

The Paris Agreement is intended to prevent the planet’s temperature from increasing by more than 3.6 degrees Fahrenheit, which many experts say would lead to an irreversible future of rising oceans and extreme weather, leading to drought, flooding, and food and water shortages.

Social Cost of Carbon

Trump’s order requires federal agencies to use “the best available science and economics” in their cost-benefit analyses of regulations. But it also disbands the Interagency Working Group on Social Cost of Greenhouse Gases, created by the Council of Economic Advisers and the Office of Management and Budget in 2009, and dismisses the group’s work products as “no longer representative of governmental policy.”

Instead, it orders that “when monetizing the value of changes in greenhouse gas emissions resulting from regulations,” agencies rely on a 2003 Bush-era finding by OMB.

“In sum, to make a calculation based on ‘the best available science,’ they’re reverting to 2003 data,” wrote astrophysicist turned science writer Ramin Skibba in Slate.

The working group’s current SCC price of $36/ton has been widely criticized as too low, with some scientists contending it should be as high as $220/ton.

The OMB circular that Trump’s executive order cites suggests using a 7% discount rate for valuing future impacts of carbon emissions, more than twice the Obama administration’s rate of 3%. The higher discount rate is likely to reduce the SCC further.

Trump’s “plan would return the calculation to its 2003 level — a time when regulators could get away with ignoring climate costs and the benefits to avoiding them because of how uncertain they were,” Skibba said. “The main effect will be on proposed policies; for example, the next time [Department of Transportation] or EPA officials evaluate the fuel economy standards of cars and trucks, they wouldn’t have to set such strict limits. Eventually there will be more heavily polluting vehicles on the road, less efficient appliances in the marketplace, etc.”

March 31, 2017

CAISO to Create New TAC Area for Water District

By Robert Mullin

CAISO is seeking to create a new transmission access charge (TAC) area for a California load-serving entity that does not intend to become a participating transmission owner in the ISO.

The “one-off” proposal with the Metropolitan Water District of Southern California (MWD) would create an unorthodox relationship between the CAISO and an important transmission provider that seeks to retain rights over its own network, while also protecting the ISO’s access to key delivery points along the California-Nevada border.

transmission access charge area caiso — CAISO’s proposed new TAC area would cover the transmission system the Metropolitan Water District uses to feed pump stations used to move water from the Colorado River Aqueduct into Southern California. | *CAISO*

MWD delivers water to 26 member agencies serving 19 million consumers in six Southern California counties. It owns about 300 miles of 230-kV transmission lines that feed five pumping plants moving water from the Colorado River Aqueduct and State Water Project into Southern California. At full power, the pumps consume 300 MW of load, which is served by the agency’s share of output from the Hoover and Parker dams.

Edison Agreement Ending

Southern California Edison has been operating MWD’s transmission under a decades-long agreement that predates the existence of the ISO. SoCalEd has declined to renew the agreement when it expires Sept. 30 because of the utility’s reduced allocations from the Hoover Dam.

As a result, MWD is seeking a similar arrangement with CAISO allowing it to preserve its transmission operating rights (TORs) while continuing to offload responsibility for operating its grid. The ISO late last year agreed to act as the water agency’s transmission planning coordinator in matters related to meeting NERC reliability requirements.

While MWD’s generating assets sit outside CAISO’s balancing authority area, its agreement with SoCalEd has firmly integrated the agency’s transmission network into the ISO’s operations. It has allowed the utility to take advantage of MWD’s regulation, ramping capability and capacity reserves. The utility has, in turn, used its own baseload resources to serve MWD’s 24/7 pump loads at a flat rate.

The agreement also requires MWD to turn over its excess transmission capacity to SoCalEd — and now CAISO — for market use. That last point is especially important, because MWD’s transmission broadens the ISO’s access to the key Mead wheeling point out of Nevada and provides the ISO market its only access to the Parker delivery point.

“The ISO has been working with MWD on an operations agreement, which is what we typically do with entities inside the ISO [balancing authority area] that are nonparticipating TOs, but still have a substantial system within the ISO,” Deb Le Vine, CAISO director of infrastructure contracts and management, said during a March 28 call to discuss the issue.

Self Sufficient

As Le Vine explained, MWD is positioned to interact with the ISO as a nonparticipating TO because of its self-sufficiency: The agency can completely serve its load with its own generation and transmission.

“MWD does not lean on the CAISO system at all,” Le Vine said. “They have sufficient generation to meet the [California Energy Commission’s] resource adequacy requirements.”

And the ISO will derive a key benefit from continued integration with MWD. “They are going to still let us use their excess transmission,” Le Vine said.

MWD does have an alternative to being required to join CAISO as a full member. It could instead turn control of its assets over to the Western Area Power Administration’s Lower Colorado balancing area, which would narrow the reach of the ISO’s market.

“We’d stay at Mead, but only with Southern California Edison’s transmission,” Le Vine said. “We would no longer have access to Parker. We’d no longer have MWD’s parallel transmission line [out of Nevada] and the ability to use their transmission.”

Resource Adequacy Requirements

The need to create a new TAC area for MWD is based on an “unfortunate” technicality rooted in the link between California’s resource adequacy (RA) requirements and the ISO’s TAC areas, according to Le Vine. In adopting the state’s RA framework, the ISO chose to use TAC areas as the basis for allocating requirements among LSEs.

“We just need to create this TAC area to account for [MWD’s] load-serving entity obligations separately from how they’ve been accounted for in the past, which was all part of the Edison arrangement under the existing contract,” said John Anders, CAISO assistant general counsel.

Creation of the area will allow MWD to cover the resource adequacy requirements for powering its pumps along the Colorado River Aqueduct system.

“Are they going to pay the same TAC that load everywhere else pays?” asked Susan Schneider of Phoenix Consulting.

“No, MWD has TORs,” replied Le Vine. “They own their own transmission system, so they have never paid the TAC since 1998,” when the ISO began operations.

Eric Little, manager of wholesale market and greenhouse gas market design with SoCalEd, asked if the ISO expected MWD to serve a “significant portion” of its RA requirement with its own pumping load, which can provide system RA in a demand response capacity. Little noted that CAISO’s Tariff exempts participating load from ISO penalties meant to guarantee the availability of resources. Entities that enter a participating load agreement with the ISO are entitled to self-supply to meet their requirements.

“Which means that if they were to use a significant portion of their pumping load to serve as their RA, they would meet RA without having a similar obligation as others because they wouldn’t be penalized if they didn’t meet the obligation,” Little said.

“Well, that’s a decision for MWD to make, and they’d need to be consistent with what’s in the ISO Tariff,” Le Vine said.

“I don’t think there is any other load-serving entity out there that is in that same boat,” Little said. “I think everybody else, if they’ve got participating load, [pumping load] is a very small proportion of their load.”

Le Vine disagreed.

“There’s a very large entity that has a significant amount of participating load that is pumping load that uses that as RA,” she countered, referring to the California Department of Water Resources.

“It’s concerning, but I guess that ship has already sailed,” Little responded.

CAISO wants stakeholders to submit comments on the proposal to create the MWD TAC area by April 11, and expects to seek Board of Governors approval on the measure in May.

March 31, 2017

Texas PUC Puts Brakes on NextEra’s Oncor Acquisition

By Tom Kleckner

The Public Utility Commission of Texas unanimously agreed Thursday that NextEra Energy’s proposed $18.7 billion acquisition of Texas utility Oncor is not “at this point” in the public interest.

Chairman Donna Nelson and Commissioner Ken Anderson both read prepared statements into the record during a PUC open meeting. They cited the need for strong ring-fencing provisions that would include an independent board of directors for Oncor — a requirement NextEra has called a “deal-killer.”

“The tangible benefits to this transaction are few,” Nelson said. “In order to find this in the public interest, I would need to keep those ring-fencing provisions in place.”

“Bottom line, I do not find the tangible and quantifiable benefits are an improvement over the status quo to justify approval” of the deal, Anderson said, reading from a memo he later filed (Docket 46238). “To be honest, it has to do with their deal-killers.”

Commissioner Brandy Marty Marquez agreed with Anderson, saying she took NextEra “at its word” and complimented the company on its candor in the proceeding.

“I don’t believe they were posturing,” she said. “They were telling us quite clearly what they could and could not live with. I’m not happy to say that those were, unfortunately, the things I feel like we should not bend on.”

PUC staff will now draft a preliminary order that the commissioners can adopt during their April 13 open meeting.

Next Step Unclear

Whether this ends NextEra’s bid to acquire Oncor — which the Florida-based company has eyed for several years — remains to be seen. NextEra and Oncor representatives were not given an opportunity to appear before the PUC on Thursday, and both companies declined to comment on the commissioners’ remarks or next steps.

A previous attempt to acquire Oncor, by Dallas-based Hunt Consolidated, ended last May when Hunt withdrew its yearlong application over PUC requirements it found too onerous. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)

Hunt officials would not say Thursday whether they hope to make another bid.

“We have a long-standing policy of not commenting on other parties’ regulatory proceedings,” said Hunt spokesperson Jeanne Phillips in a written statement. “We are watching these events with interest and will wait for the commission’s final vote.”

Oncor has long been considered the crown jewel of Energy Future Holdings’ assets. EFH — previously TXU Corp. before being acquired by private-equity firms in a leveraged buyout — declared Chapter 11 bankruptcy in 2014 and has since spun off its generation and retail electric service providers as part of Vistra Energy.

Board Independence Issue

The utility has been ring-fenced since the 2007 buyout. That helped insulate Oncor from much of the $45 billion in debt EFH had incurred when it declared bankruptcy.

“The lack of a truly independent disinterested board and the lack of independent board control over the dividends are what worry me the most,” Nelson said. “And unfortunately, those are the issues on which it seems NextEra Energy is not willing to budge.”

During a public hearing in February, NextEra told the PUC it needs to maintain control over Oncor’s board to ensure its ability to appoint or remove the utility’s directors. The company said that is a fair trade-off for lending its A- credit rating and $59.2 billion market capitalization to help Oncor eliminate debt left by EFH. (See Hearings Over, PUCT, NextEra Ponder Oncor ‘Deal-Killers’.)

In its most recent filing, NextEra said its proposed ring fence retains virtually all of the 2007 conditions, while adding additional protections “that would not impede consolidation of NextEra Energy’s and Oncor’s credit profiles.”

The company noted it is proposing “a comprehensive suite of 73 regulatory commitments,” some in response to staff and intervenor concerns.

“These regulatory commitments offer substantial protections and benefits for Oncor and its customers and are more than sufficient to protect Oncor and its customers from any perceived risks associated with NextEra Energy’s ownership of Oncor,” NextEra said.

Nelson also referenced a July 2016 ratings report from Moody’s Investor Service. She quoted the report as saying “the acquisition-related debt without a material amount of deleveraging would exhaust NextEra Energy’s debt capacity at its current rating” and “makes the company more vulnerable to unforeseen events or margin shortfalls.”

NextEra told the PUC in February it has $12.2 billion reserved for funding the transaction — $9.8 billion for an 80% interest in Oncor and $2.4 billion for a 20% interest in various holding companies. It would assume the remaining $6.5 billion in debt, in line with its 60/40 debt-to-equity ratio.

“I worry about removing the ring-fence protections in this situation, where the debt above Oncor isn’t being extinguished, but is instead being refinanced with new debt at NextEra Capital Holdings,” Nelson said. “The parent company will remain substantially leveraged in order to make the purchase happen.”

“I see as much downside as upside to linking Oncor’s credit rating to NextEra Energy,” Anderson said. “I would require staff’s version of the condition de-linking the respective credit ratings … but given that they are all also NextEra Energy deal-killers, it seems to me that we would be wasting time and resources to proceed further down the road of appearing to approve the transactions with such conditions.”

March 31, 2017

PJM Stakeholders Explore Price Formation, Seek Transparency

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM should explain its daily operating decisions in more detail so market participants can better understand how markets are formed, stakeholders told staff at Tuesday’s special session of the Market Implementation Committee.

PJM price formation security constrained economic dispatch — Greiner | © *RTO Insider*

Bruce Bleiweis of DC Energy went so far as to request that PJM produce “an actual document” that enunciates all of its processes.

“If there are things that PJM doesn’t publicly want to post, doing it under the [Critical Energy Infrastructure Information] protocol should be sufficient,” he said.

Chantal Hendrzak, who chairs the MIC, said that her staff at PJM will “take that back and see what we can come up with.”

Part of the concern for stakeholders is that PJM gives its system operators discretion to analyze data and make decisions on the fly. While this keeps the system flexible, stakeholders said it also makes understanding the RTO’s thought processes more opaque.

“I think the first order of priority ought to be [finding out] what information [PJM can share] to understand what’s going on on the system,” one stakeholder said. He clarified that part of his interest was looking back to determine what caused uplift on the system.

PJM’s Keyur Patel, who gave a presentation on the RTO’s day-ahead market clearing process, pointed out that PJM will dispatch between 1,200 and 1,500 generation units on a typical day, and only 10 to 15 units will change throughout the day.

“There are times where we do want to make some commitment changes, but we run out of time and at those times, it’s better to post results on time than to change one unit,” he said.

Additionally, some decisions are made by the mathematic calculations of PJM’s security constrained economic dispatch (SCED) system without human intervention, said PJM’s Joe Ciabattoni, who gave a presentation on the RTO’s dispatch process.

There are times when “the engine cannot solve the problem in the time parameters it’s given. [It will] sacrifice one constraint to get power balance and retain control for the rest of the system,” he said. “We need a solution every three to five minutes to maintain system control.”

In that case, the system relaxes its constraints to allow the system to solve.

Ciabattoni explained it as his “but-for logic,” in that certain units wouldn’t have been committed but for a specific constraint.

“To unravel every one of those little variables … would need a team to determine them all,” he said. “But we could use: ‘but for that constraint, we wouldn’t have committed these [theoretical] 500 MW.’”

PJM’s perfect dispatch analysis evaluates all commitments, but only after the fact when the RTO knows what flow actually transpired, he said.

Ciabattoni said PJM doesn’t have any ramping issues for wind or solar “like other RTOs do,” except on extremely cold mornings.

An issue to consider, he said, is that once a unit is brought on, the constraint may go away because that unit overwhelms the constraint, but it may return if the unit is turned off.

“When SCED is looking at a solution … it may be getting fractional megawatts from a bunch of units,” Ciabattoni said, or a unit’s economic minimum output may be so close to its economic maximum output that it can’t cycle up or down efficiently. If such a unit is left running, there will be hours where it sets price and hours where it does not. When It doesn’t, it will create uplift, he said.

Joel Luna of Monitoring Analytics, the firm that serves as PJM’s Independent Market Monitor, said uplift comes down to three factors: megawatt-hours, LMP and the unit’s offer price.

The session resulted from a problem statement approved by stakeholders in January. (See “Work on Uplift Moves Forward Despite NOPR,” PJM Markets and Reliability and Members Committees Briefs.)

By the end of the meeting, the special session’s facilitator, PJM’s Rami Dirani, determined that stakeholders needed more education before a useful list of interests for the group could be determined. He decided to cancel the group’s next meeting on April 5 and proceed with more education at its following meeting on April 25.

March 31, 2017

PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will

By Rory D. Sweeney

PJM can maintain adequate reliability with a generation fleet almost entirely composed of natural gas units, but a capacity mix of more than 20% of solar would unacceptably increase the risk of loss-of-load events, according to a study the RTO released Thursday.

The study, titled “PJM’s Evolving Resource Mix and System Reliability,” identified essential reliability and adequacy criteria and used them to compare a wide range of potential future fuel diversity scenarios. PJM focused on generator “reliability attributes” of frequency response, voltage control, ramping ability, fuel assurance and flexibility.

PJM created a “composite reliability index” to assess the operational reliability of various resources under four conditions: normal peak conditions, light load, extremely hot weather and extremely cold weather. Resources were grouped into 11 categories: coal, natural gas steam, natural gas combustion turbine, oil steam, oil combustion turbine, nuclear, solar, wind, hydro, battery/storage and demand response.

The RTO said the report is in response to stakeholder concerns that the system is losing too many traditional baseload resources as coal plants retire and nuclear assets struggle to remain profitable.

In 2016, PJM’s installed capacity was 33% coal, 33% natural gas, 18% nuclear and 6% renewables, which include hydro. By comparison, coal and nuclear resources accounted for 91% of its generation fleet in 2005.

“This analysis underscores our responsibility to continue to operate the system reliably, and explore the role of resilience, the ability to tolerate unforeseen shocks and continue to deliver electricity,” PJM CEO Andy Ott said in a statement. “Different resources provide different reliability attributes, though new technology or regulations have the ability to improve those capabilities.”

No Upper Bound on Gas

Of particular interest, given the rise in gas-fired units interconnecting to PJM’s system, was the revelation that the there was no upper bound for the percentage of gas-fired units in the fleet before reliability is harmed.

The scenarios showed natural gas’ share of the fuel mix could rise to as high as 86% without reliability problems. Mike Bryson, PJM’s ‎vice president of system operations, who spoke during a press briefing on the report, said staff stopped at 86% to account for demand response, hydropower and biomass currently on the system. “We figured it was a safe assumption to say they won’t go away.”

The report acknowledged, however, that it didn’t assess the gas-deliverability issues that pinched supply during January 2014 or the continued sluggishness of gas pipeline development. PJM’s previous natural gas studies generally concluded that the existing and planned pipeline infrastructure would be adequate for current and future anticipated electric system needs.

“We did not look at ability for infrastructure to support that, but we think it’s probably worthy of following up with the natural gas industry,” Bryson said. “There’s a lot of work left to do.”

The report also didn’t address the economics of resource types, factors that might impact a fuel’s deliverability or public policy issues such as environmental impacts or the use of subsidies. Bryson suggested coordination with the gas industry to begin addressing “more complicated issues” that cross over from the electricity sector, including data coordination.

That said, the report found that PJM’s current and near-term fuel mixes were near the top of the study’s reliability analyses. Less coal and nuclear generation would decrease frequency response, reactive capability and fuel assurance, but increase flexibility and ramping capabilities.

Renewables Limits

Portfolios with solar representing 20% or more of unforced capacity (UCAP) failed because they resulted in loss-of-load-expectation (LOLE) violations at night. UCAP is calculated by multiplying nameplate capacity by the resource’s capacity factor (38% for solar).

Bryson said increases in batteries and other storage would likely change the conclusions.

He added that certain fuel types were given credit for their abilities, if not their current usages. “We gave wind kind of high marks on flexibility, even though that’s not how they operate today,” he said. “The capability’s clearly there, but they don’t operate in that way.”

Fuel Diversity ≠ Reliability

The study also found that a more diverse fuel portfolio isn’t necessarily more reliable. Certain resource blends that fall between the least and most diverse offer the greatest number of key generator reliability attributes.

“Having a certain amount of diversity — not too much, not too little — gives you optimal reliability,” said PJM’s Chantal Hendrzak, who also spoke at the briefing.

However, high reliance on one type, such as gas, would create concerns that the paper didn’t attempt to analyze. PJM said it would continue to investigate ways to minimize its exposure to “low-probability, high-impact” events that could pose serious threats to the system.

“Our markets are designed to provide the incentives that the [13] states [within PJM’s footprint] need to implement their policies. We think there is an opportunity for PJM to work with the states” to determine how to harmonize well-functioning markets and public-policy initiatives, Bryson said.

The topic of reliability will be the focus of PJM’s upcoming Grid 20/20 conference scheduled for April 19.