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November 13, 2018

Analyses Show Flat Emissions Under NY Carbon Price

By Michael Kuser

RENSSELAER, N.Y. — New York electricity market stakeholders on Friday reviewed three separate studies to evaluate the implications of a carbon charge in NYISO’s energy markets.

The reports by the Brattle Group, Daymark Energy Advisors and Resources for the Future (RFF) find similar reductions in systemwide carbon emissions from a carbon charge: less than 1 million metric tons, according to the ISO’s synthesis of the studies

Michael DeSocio, the ISO’s senior manager for market design, told the Integrating Public Policy Task Force (IPPTF) Nov. 9 that “all the analyses were generally supportive of each other.”

All three studies isolate the effects of a carbon charge by modeling both a “base case” without carbon pricing and a “change case” with carbon pricing, but they each differ in the years evaluated. The Brattle study evaluates effects in 2020, 2025 and 2030, while Daymark’s analysis evaluates 2021-2025, 2030 and 2035. The RFF analysis focuses solely on 2025. (See NY Details Carbon Charge on Wholesale Suppliers.)

NYISO — Daymark Energy Advisors’ projected carbon emissions under a New York carbon pricing policy. | *Daymark*

Analytical Results

Daymark’s Marc Montalvo said that his group’s study found that “carbon emissions in New York are about flat. There’s not really a material change as a consequence of the introduction of the carbon charge.”

RFF’s Dan Shawhan said his group’s updated results show “a CO₂ emissions reduction of 0.2 million tons in the simulated year, which is 2025, and that’s about 0.65%, so about two-thirds of a percentage point reduction in New York emissions. And I don’t disagree with the characterization that you could describe that as not a big change in emissions.”

Brattle’s Sam Newell agreed and said “a lot of what’s happening here is we’re comparing to a base case that already has in place the Clean Energy Standard and other mechanisms to reduce emissions.”

But both the RFF and Brattle studies say that a carbon pricing policy can also be expected to reduce emissions in ways not captured in the modeling.

The carbon charge is another way of accomplishing decarbonization with more dollars put toward a market-oriented approach, and less money relying on targeted programs, Newell said.

“In both cases there’s decarbonization, so it’s not a surprise that there’s not some major change in carbon with the introduction of this policy,” Newell said. “Directionally it’s going to be an improvement because it finances some low-cost forms of carbon abatement, and there are probably some long-term investment effects.”

All studies find higher statewide locational-based marginal prices resulting from a carbon charge, with increases most significant downstate. The Brattle analysis finds LBMPs would rise by less than the Daymark and RFF studies.

Differences in LBMP changes can be at least partly explained by differences in each study’s modeling of the market heat rate, and also in part by assumptions regarding the net social cost of carbon in each study, the ISO’s summary said.

The studies assume similar carbon charges through 2025, but the Daymark study finds LBMP impacts would increase from 2025 to 2035. In contrast, Brattle finds lower carbon charges in 2030 than 2025 because of assumed increases in the Regional Greenhous Gas Initiative price, resulting in carbon charges of $45.40/ton in 2030, compared with $57/ton in 2030 assumed by Daymark.

Brattle and RFF both find collected carbon revenues on the order of $1.5 billion per year; Daymark finds declining carbon revenues, falling from $1.4 billion in 2021 to $1 billion in 2035.

Stakeholder Requests

DeSocio presented an update on NYISO’s progress in meeting stakeholder requests for further analysis on certain points.

Analysis is under way on augmenting the Brattle analysis with 2022 results and considering the effects of carbon pricing on repowering and retention, and should be ready for discussion at the Nov. 26 task force meeting, he said.

The ISO also said it does not recommend following a stakeholder suggestion to lower the 2030 RGGI price estimate because such a move is not supported by analysis based on results provided to date, DeSocio said. As RGGI is adjusted downward both with and without carbon pricing, the other parts of the analysis approximately scale. Because the overall impact is near zero, the scaled impact is near zero.

To consider the consequences of no carbon pricing, including estimates of the costs of various buyer-side mitigation scenarios, and the consequences of NYISO’s AC transmission project in western New York, the ISO is still considering how it might structure such analyses and will update the IPPTF at its next meeting, he said.

Regarding the effects of a carbon charge on existing renewable energy credit contracts and future REC contracts, DeSocio said, “In our analysis to date, we are not suggesting that REC contracts go away. Certainly the price of a REC contract may go down because the carbon price is being realized and therefore the delta payment that a renewable resource is getting is less, but in the analysis so far, we haven’t shown that to go to zero.” (See NY Carbon Task Force Looks at REC, EAS Impacts.)

The Daymark study does not evaluate changes in REC and zero-emission credit prices stemming from a carbon charge, but it finds the following gross profit margin (revenue minus fuel costs) average increases: upstate nuclear plants 70%; upstate solar 48%; upstate wind 46%; downstate offshore wind 47%; and downstate solar 51%, according to the ISO synthesis.

The RFF analysis finds the carbon charge would reduce REC prices from $43/MWh to $24/MWh and would reduce ZEC prices from $14/MWh to $0/MWh in 2025.

The Brattle analysis finds the carbon charge would reduce ZEC prices from $25/MWh to $12/MWh in 2025, while REC prices would fall from $22/MWh to $3/MWh in 2020, $25/MWh to $7/MWh in 2025 and $28/MWh to $12/MWh in 2030.

The task force next meets on Nov. 26. It plans to announce a proposal to incorporate carbon pricing into the state’s wholesale market next month.

November 13, 2018

OGE Beats Expectations with Q3 Earnings

By Tom Kleckner

OGE Energy beat expectations last week, reporting third-quarter earnings of $205 million ($1.02/share), up from a year ago, when it earned $183 million ($0.92/share).

A Zacks Investment Research survey of analysts had projected earnings of 96 cents/share.

“Good companies grow, and that is clearly what we are doing,” CEO Sean Trauschke said during a Nov. 8 conference call with analysts.

OGE’s regulated utility, Oklahoma Gas & Electric, contributed 92 cents/share during the quarter, thanks to new rates in Oklahoma, favorable weather and increased customer demand.

The Oklahoma City company also received earnings of 14 cents/share from Enable Midstream Partners, a gas-gathering and processing joint venture with Texas utility CenterPoint Energy.

Enable said Nov. 7 that it processed record amounts of natural gas during the third quarter. OGE holds a 25.7% limited-partnership interest and a 50% management interest in Enable, while CenterPoint owns a 54.1% share.

OGE increased and narrowed its year-end guidance to $1.59 to $1.61/share, up from $1.43 to 1.53/share.

OGE shares finished the week at $38.08/share, up almost 16% since the beginning of the year.

CenterPoint Earnings Drop 4 Cents

CenterPoint reported third-quarter earnings on Nov. 7 of $153 million ($0.35/share), a drop from a year earlier, when it earned $169 million ($0.39/share).

Revenues totaled $2.2 billion, up from $2.1 billion a year ago, thanks to increased rates and a growing customer base.

CenterPoint Energy EV | *CenterPoint Energy*

CEO Scott Prochazka told analysts during a conference call that the Houston-based company in October completed the equity and fixed rate debt components of the financing for its $6 billion acquisition of Indiana utility Vectren. Prochazka said the acquisition is still expected to close in the first quarter of 2019 and has targets in place “that are in line” with an $50 million to $100 million in pretax earnings by 2020.

CenterPoint’s share price lost 51 cents following the earnings announcement, finishing the week at $28.16.

November 13, 2018

New England Talks Energy Security, Public Policy

By Michael Kuser

MARLBOUROUGH, Mass. — Can New England balance reliability, economics and public policy in a fast-changing energy world? How will the region better prepare itself to handle winter cold snaps than in the past?

These and other questions arose at the Northeast Energy and Commerce Association’s 17th Power Markets Conference on Nov. 8. Here are highlights of what we heard.

NECA — The Northeast Energy and Commerce Association held its 17th annual Power Markets Conference on Nov. 8. | © *RTO Insider*

Internalize, Don’t Politicize

Ashley Brown, executive director of Harvard University’s Electricity Policy Group, said, “My fear today is that we’re moving back to a battle between various special interest groups and further politicizing the sector.”

Resource selection based on economics, reliability and social benefits has given way to state subsidies and mandates that often work against public policy environmental goals, with uneconomic resources chasing bailouts instead of focusing on how to become more efficient, he said.

“Part of the problem … is that we have simply failed to internalize social considerations in economics,” Brown said. “The lack of a carbon policy in the U.S. is not only intellectually bankrupt, but it does in fact penalize emissions-free resources.”

Energy Security Banking

Mark Karl, ISO-NE vice president for market development, said the region is moving into an era in which more resources have less fuel security. The grid operator is concerned the situation will get worse.

Fuel logistics become an issue in winter, whether because of natural gas pipeline constraints, limited dual-fuel storage or reduced ability to deliver oil by truck, he said. The significant retirement of large non-gas-fired generation is an important factor, as is the type of oil used.

“For example, some generators are burning No. 6 oil, which is basically almost asphalt, so in the wintertime, when that stuff gets cold, it gets pretty difficult to pump and move,” Karl said.

The retirement of two nuclear plants and the Brayton Point coal plant in recent years might be good for the environment, but collectively it presents a challenge for reliability, he said.

Karl said ISO-NE is looking to create a new reserve service referred to as “the energy inventory reserve constraint.”

“We’re proposing to incorporate into the real-time market an additional constraint that looks at the ability to provide energy storage or an energy bank,” he said. “I want to be careful here because it’s easy to think about this from the standpoint of conventional generator fuel, but this will apply to any sort of resource that has the ability to maintain essentially a reserve bank of energy that can be converted into electricity when needed.”

The idea is to optimize the use of limited energy over more extended periods compared with how markets are currently designed to optimize energy over the course of an operating day, he said.

Outside the marketplace, operators also worry about the next day and the days that follow, and sometimes order an oil-burning unit offline for a weekend anticipating the need to provide reserves come Monday, “so that’s an out-of-market action that does cause distortions in the marketplace,” Karl said.

Market Reaction

Brett Kruse, vice president of market design at Calpine, said ISO-NE could use a six- or seven-day-ahead market to effectively manage storage in a way that avoids having to take out-of-the-market actions.

The proposal could help the RTO manage how it deploys plants day to day and provide an insurance policy to keep a certain amount of storage in the system, he said.

“There are a lot of questions about that and how it would be priced, but it’s conceptually a pretty good idea,” Kruse said.

But he also had some reservations about the plan. “Looking at the way they’re presenting it now, where it’s a voluntary forward market, and won’t have any mitigation, which is a key aspect to go with that, we think it has some potential, although it’s hard to see how a lot of load will come into that,” he said.

David Cavanaugh, vice president of regulatory and market affairs for Energy New England, an energy services firm, said the RTO’s thinking at first glance seems robust, as its design extends beyond the winter period into a period where the bulk power system has more renewables and, perhaps, storage resources.

“I’m not sure the sophistication of this model gets us there … but we can be informed by other interim efforts such as the opportunity cost model set for use this winter,” Cavanaugh said. “I think the design is well thought out … just have some concerns when I look at the multi-day-ahead market, its voluntary participation,” in terms of maintaining adequate fuel stocks.

Abigail Krich, president of Boreas Renewables, said she sees a market design that, “even though it was triggered by fossil fuel issues, could work with that transition to a clean energy system that relies on intermittent generation. It looks like something that makes sure we have a dispatchable store of available energy in reserve.”

“I question whether we need all of these pieces in the proposal or whether we might just use some of them,” Krich said.

Public Policies

Discussing the race for renewables at the state level, Peter Fuller of Autumn Lane Energy Consulting said the tension in these markets is understandable. While consumers have benefited greatly from the markets, and investors and market participants have an expectation that everyone in the market will play by the same set of rules, states pursuing policy objectives don’t necessarily feel bound by those rules. In addition, the states have not been able, individually or collectively, to identify exactly what they want in a way that an RTO can create a market for it, he said.

Rather, states want to maintain control of resource decisions as policy objectives continue to evolve over time. “As much as anything they want to control that,” Fuller said. “If I’m a governor or legislator thinking how I want to transform the energy system in my state, my first instinct is not to send somebody to [the New England Power Pool] or to PJM to offer proposals, to come up with a matrix or a set of market rules and see how that plays out.” States are more likely to take direct action that then can cause dislocations in the markets.

Day Pitney attorney Sebastian Lombardi, who serves as counsel to NEPOOL, said that overlaying all the fuel security and grid resilience efforts is the need for regions to continue to engage in efforts to help bridge the divide between evolving state and federal policies and the market.

“From a state policy perspective, the competitive markets are not always achieving what they’d like the markets to achieve,” Lombardi said.

Darlene Phillips, senior director for strategic policy and external affairs at PJM, explained the RTO’s proposed revamp of its capacity market.

The Extended Resource Carve-out proposal would allow specific, state-subsidized resources to opt out of the capacity market and PJM to adjust market clearing prices as if the resources were still in it. (See related story, PJM Stakeholders Hold Their Lines in Capacity Battle.)

“If you don’t want your subsidized resources to get a minimum offer for price and go into the market, we will allow you to take those resources out of the market,” she said. “One of the things that FERC did not like about our original approach is that we actually paid those resources a payment.”

When it comes to existing renewable resources, PJM’s minimum offer price rule would have very little impact because the price would be zero, she said. The RTO applies a 20-MW threshold to renewables for the MOPR, which most of them don’t meet, though that situation might change with large-scale offshore wind coming along.

November 13, 2018

NERC to Try Again on Inverter Rules

By Rich Heidorn Jr.

ATLANTA — NERC stakeholders are expected to consider a new standard authorization request (SAR) to address inverter-based resources after the Standards Committee rejected two SARs proposed by CAISO in September, officials said last week.

CAISO submitted the SARs in May, saying it had recorded at least 14 occasions since August 2016 when inverter-based solar generation incorrectly tripped or ceased to operate during the routine high-speed clearing of short circuits on bulk electric system (BES) transmission. NERC has issued several reports and alerts following the two most serious incidents: the August 2016 Blue Cut wildfire, when 1,200 MW of solar disconnected; and the October 2017 Canyon 2 fire, which resulted in the loss of more than 900 MW. (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)

Most solar PV generation (top map) is below the 75-MW threshold requiring registration with NERC (bottom map). | *NERC*

The ISO proposed incorporating performance requirements for inverter-based resources connected to the BES in a revised NERC standard PRC-024, or developing a new standard for such resources and clarifying that PRC-024 applies only to synchronous generation.

At its Sept. 13 meeting, however, the Standards Committee rejected both SARs by a 12-5 vote on a motion by Dominion Energy’s Sean Bodkin, who noted the Institute of Electrical and Electronics Engineers (IEEE) is addressing the issues in Standard 1547-2018.

NERC is working with IEEE on the standards for inverter settings and developing instructions on compliance monitoring and enforcement activities related to the issue, James Merlo, NERC vice president of reliability risk management, told the Member Representatives Committee (MRC) at its quarterly meeting Nov. 6.

FERC Commissioner Cheryl LaFleur, who attended the MRC and Board of Trustees meetings, said she was concerned about the rejection of the SARs, saying “nothing clarifies the mind like an enforceable standard.” She said it was better for NERC and its stakeholders to design standards rather than respond to directives from FERC.

NERC CEO Jim Robb said he was disappointed that the two SARs “met with such headwinds at the Standards Committee.”

“I think we need to get over the notion that any standard creates peril and get to the point where standards create certainty,” he said. “And I think, particularly, in the case of these inverter resources, that’s a very, very important thing for us to do. … These resources are not going away. They’re already at scale in the West, and they will [soon] be at scale … in many parts of the country.”

Merlo said the Operating and Planning committees and the Inverter-Based Resource Performance Task Force will seek a new SAR to modify PRC-024 that will build on a white paper to be released in about two weeks identifying gaps between current standards and what’s needed by grid operators. “The expectation is the Standards Committee would take that up in December,” Merlo said.

“I’m optimistic that that will accomplish much of what we wanted to accomplish through the original two SARs,” Robb said.

The work may not stop with revisions to PRC-024, said Howard Gugel, NERC senior director of engineering and standards. “Then that task force is also going to go forward to say, ‘given that this is a brave new world and we have these resources, is there another standard that we should write that says how they should actually operate?’” he said in an interview. “And it’s not just limited to solar. … [idle EVs injecting energy into the grid are] an inverter resource also.”

NERC has already asked solar generators to modify their inverter settings to ensure voltage excursions don’t result in momentary cessation (MC) — when they stop injecting current into the grid. For inverters that cannot use another ride-through mode, NERC asked that MC settings be reduced to the lowest voltage value possible and that the recovery delay be reduced to one to three electrical cycles.

In arguing for the SARs, CAISO’s Keith E. Casey, vice president of market and infrastructure development, noted that NERC guidelines are not enforceable.

“Due to a lack of any standard addressing the minimum performance of inverter-based generation connected to the BES, original equipment manufacturers often apply standards for resources connected to the distribution system to BES resources,” Casey wrote.

NERC reported that most of the lost solar generation in the Blue Cut fire resulted when inverters incorrectly perceived a low frequency condition and tripped, not returning to service for five minutes or longer. “Five minutes may make sense on a rooftop, but five minutes is an eternity on the bulk electric system,” Merlo said.

NERC, which originally surveyed 13,543 MW of solar PV as potentially using momentary cessation, now believes all but about 1,952 MW do not use it or can overcome it with modified settings. (The survey covered only utility-scale solar generators at or above 75 MW, the threshold for generators that must register with NERC.)

“We understand a lot more than we did when we first saw the event just 18 months” ago, Merlo said.

November 13, 2018

MISO Quick Capacity Reserves Wait Until 2021

By Amanda Durish Cook

MISO is working to create market rules for capacity reserves that can be supplied within 30 minutes, though the RTO won’t have a sophisticated enough technology platform to support the new product for more than two years.

RTO staff told the Market Subcommittee on Nov. 8 that the earliest the new product could be rolled out is the first half of 2021 because it will require the new market platform.

MISO Director of Market Design Kevin Vannoy said the short-term reserve product will address issues that are “more severe” than can be solved by either the ramp product and regulation reserve, which is supplied within seconds, or issues that are “less severe” than the Disturbance Control Standard events requiring the RTO’s 10-minute contingency reserves.

“The idea is to get the 30-minute reserves reflecting actual needs [of the system] rather than trying to have the 10-minute reserves covering it,” Vannoy said.

“We have needs that we make out-of-market commitments for, but they’re not modeled in the market,” said Bill Peters of MISO’s market design team.

The short-term reserves would be furnished by either online generators dispatched according to opportunity costs or offline generators, which would be dispatched based on an offer price.

Peters said short-term reserves would help manage flows on SPP transmission between MISO Midwest and MISO South and aid areas hemmed in by transmission constraints or short on nimble reserves. They also will help meet load and avoid volatility as the RTO adds more intermittent resources.

MISO’s final ranking of Market Roadmap improvements placed the creation of short-term reserves at the highest priority, beating out projects to better model combined cycle generators, and respond to shifting resource availability and need.

Peters said the reserves could have market-wide, regional and local response requirements. He said MISO would dynamically schedule the reserves to a load pocket or region, assessing the state of the system, capacity needs, amount of cleared energy and amount of cleared short-term reserves before dispatch. He also said the RTO is considering applying a demand curve to pricing. Peters said the generators that sign up to provide the service will be tested to demonstrate they’re able to provide capacity within 30 minutes.

MISO has scheduled a Jan. 15 workshop to further discuss the conceptual design of a short-term reserve product.

November 12, 2018

UPDATED: Destructive Fire Drives Down PG&E Stock

By Hudson Sangree

Updated Nov. 16.

Pacific Gas and Electric’s stock price rose dramatically Friday after state California Public Utilities Commission President Michael Picker made a series of surprising public statements about the company’s future as it faces potentially billions of dollars in wildfire liability for the current Camp Fire, the deadliest in state history, and a series of devastating blazes in 2017.

On Thursday, Picker took part in a call with Wall Street analysts in which he said allowing PG&E to go bankrupt wouldn’t be good policy, Bloomberg News and other media outlets reported. He reiterated those comments in at least two newspaper interviews, and discussed the possibility of legislative action to relieve PG&E’s financial burden.

But Picker also said he was concerned about the utility’s lack of accountability. He told the Wall Street Journal that breaking up the company might be an option for regulators to consider. In a news release, the PUC president said he intended to expand an ongoing investigation into PG&E’s “safety culture” that the commission opened after the San Bruno gas line explosion in 2010.

“In the existing PG&E Safety Culture investigation proceeding,” Picker said in the statement, “I will open a new phase examining the corporate governance, structure, and operation of PG&E, including in light of the recent wildfires, to determine the best path forward for Northern Californians to receive safe electrical and gas service in the future.”

PG&E’s stock rose back to around $24 per share Friday after it plunged this week as the toll of death and destruction from the Camp Fire, the worst in modern California history, increased. The company fell under suspicion for starting the wildfire after one of the utility’s transmission lines was reported downed at the time and location of the fire’s ignition.

NASA’s Earth Observatory photographed the Camp Fire as it exploded late last week. | *NASA*

The news sent PG&E Corp.’s stock tumbling from roughly $48 per share on Nov. 8, when the fire started, to less than $18 per share on Thursday – a 62.5% drop in one week.

Similarly, Southern California Edison’s stock fell sharply as the Woolsey Fire raged in Los Angeles and Ventura counties, killing two and destroying more than 500 structures so far. Edison told state regulators it experienced an outage at a substation near where the fire started, the Los Angeles Times reported.

On Nov. 8, PG&E filed a report with the California Public Utilities Commission, saying it had experienced an outage on a 115-kV line near where the Camp Fire started and shortly before it was first reported. The company later wrote in a news release that the “information provided in this report is preliminary, and PG&E will fully cooperate with any investigations. There has been no determination on the causes of the Camp Fire.”

Early Thursday morning, firefighters responded to reports of a vegetation fire under transmission lines near Poe Dam, part of PG&E’s Feather River Canyon Power Project in rural Butte County. The California Department of Forestry and Fire Protection (Cal Fire) has identified the area as the approximate location where the fire started. A property owner in the area has told media outlets that she received an email from PG&E saying the company planned to do work on her land because its power lines were causing sparks.

Fanned by 35-mph winds, the fire quickly grew and destroyed most of the town of Paradise (population 27,000). As of Friday, it had killed 63 civilians, destroyed approximately 9,844 homes and hundreds of other structures and burned 142,000 acres, Cal Fire reported.

Previously the deadliest fire in state history was the Griffith Park Fire in Los Angeles in 1933, which killed 29 people, according to Cal Fire. The most damaging in terms of homes and other structures destroyed previously was the Tubbs Fire in Napa and Sonoma counties in October 2017, the cause of which is still under investigation.

The largest wildfire in modern state history, the Mendocino Complex of fires, occurred this summer, burning 459,000 acres in the rugged mountains north of San Francisco from July to September 2018.

The Camp Fire decimated the town of Paradise in the Sierra Nevada foothills. | *Cal Fire*

The Camp Fire has revived talk of PG&E’s possible bankruptcy, which became the subject of concern following a series of devastating wildfires in 2017. State fire investigators have said PG&E was responsible for 17 of the 21 blazes. The 2017 fires could subject the company to billions of dollars in liability under California’s unique system of holding utilities strictly liable for damage caused by power lines and equipment, regardless of negligence.

Earlier this year Gov. Jerry Brown proposed doing away with that system, known as inverse condemnation, arguing it threatened electric reliability and the state’s efforts to completely exclude carbon emissions from its power grid by the middle of the century.

Lawmakers tasked with formulating a major wildfire bill, SB 901, ultimately left inverse condemnation intact while creating a method by which utilities could issue long-term bonds to pay for some fire damage. (See California Wildfire Bill Goes to Governor.) Critics called the bill a bailout for the utilities, but Brown signed the legislation in September.

PG&E executives recently said in an earnings call that the new law was insufficient, and they intend to seek an end to inverse condemnation through the courts and legislature. (See PG&E Outlines Fire Strategy in Earnings Call.)

Company CEO Geisha Williams also discussed the company’s new practice of proactively shutting down sections of its grid during conditions that made wildfires especially dangerous. The company warned last week that it might have to shut down power to areas, including Butte County, but then decided conditions there did not warrant it.

In its recent third-quarter earnings call, SCE said its equipment was likely a partial cause of the hugely destructive and deadly Thomas Fire last year. That fire was the largest in state history until this year’s Mendocino Complex far surpassed it. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)

SCE’s stock price fell from more than $25 a share before the Woolsey fire began, also on Nov. 8, to around $21 per share in trading Thursday.

November 12, 2018

NERC to Try Again on Inverter Rules

By Rich Heidorn Jr.

NERC CEO Jim Robb said he was disappointed that the two SARs “met with such headwinds at the Standards Committee.”

“I’m optimistic that that will accomplish much of what we wanted to accomplish through the original two SARs,” Robb said.

In arguing for the SARs, CAISO’s Keith E. Casey, vice president of market and infrastructure development, noted that NERC guidelines are not enforceable.

“We understand a lot more than we did when we first saw the event just 18 months” ago, Merlo said.

November 11, 2018

MISO, SPP to Ease Interregional Project Criteria

By Amanda Durish Cook

MISO and SPP last week agreed to file changes to their joint operating agreement that they say will smooth the approval of interregional projects.

The changes, to be filed at FERC early next year, will eliminate the $5 million cost threshold for the projects, add avoided costs and adjusted production cost benefits to project evaluation, and remove the joint modeling requirement in favor of individual RTO regional analyses. The RTOs will also increase the regularity with which they produce a coordinated system plan (CSP), the joint study used to identify interregional transmission needs. (See MISO, SPP Loosen Interregional Project Requirements.)

The JOA revisions will not lower a 345-kV voltage requirement mandated by MISO, though the RTOs last month said they might create a category of smaller interregional transmission projects without voltage requirements. (See MISO, SPP Mulling Small Interregional Project Type.)

The RTOs earlier this year said the criteria currently spelled out in JOA might be preventing beneficial interregional projects from gaining approval.

“I think SPP and MISO are on the same page on these JOA changes,” SPP Interregional Coordinator Adam Bell said during a Nov. 9 Interregional Stakeholder Planning Advisory Committee conference call.

However, Bell said the revisions won’t be considered final until they’re reviewed by both RTO legal teams. He said the RTOs hope to file the changes in February and will likely hold another conference call with stakeholders before then.

But Entergy’s Jennifer Amerkhail said the JOA revisions lack the FERC Order 1000 safeguards requiring transmission developers to first propose projects to RTOs jointly before they are evaluated in each individual regional process. She said it was important for interested parties to review projects, especially because relaxed cost requirements will result in a higher number of proposed interregional projects. Amerkhail promised to provide SPP and MISO with proposed redlines so that a joint review is clearly stated as a first step before projects are put to regional review.

RTO staff said the regional analysis design will be a more efficient process than building a joint model, and other stakeholders pointed out that MISO and SPP have never approved an interregional transmission project.

“It’s not like the world is running amuck and there’s thousands of interregional projects getting proposed,” LS Power’s Pat Hayes said.

The revisions also prescribe that the CSP will take place annually automatically unless staff from either RTO vote to skip a year. The new rules require the CSP be developed no less than once every three years. The JOA currently stipulates that CSPs are produced only when either MISO or SPP staff raise the issue and then both agree to a plan.

“It moves the default from not doing a study to doing a study,” Bell said.

SPP and MISO still have at least one JOA revision to iron out: whether to include negative adjusted production costs (APC) in the evaluation of reliability interregional projects as well as economic projects.

The JOA currently requires that negative APC not be considered in the cost allocation of interregional reliability projects. Each RTO calculates APC using its own regional models.

MISO Planning Adviser Davey Lopez said MISO believes the most equitable cost allocation would include the impacts of negative APC. SPP, however, only commits to supporting “continued stakeholder discussion on whether or not negative APC values should be considered.” Bell said by including negative APC, the RTOs might find themselves in a situation where the JOA won’t allow them to pursue an otherwise beneficial reliability project for both regions.

Bell asked stakeholders to submit their opinions on negative APC to SPP. Some stakeholders at the meeting said excluding negative APC from an interregional reliability project assessment results in a biased and less transparent project evaluation.

M2M Payments Again in MISO’s Favor

MISO recorded its third straight month of market-to-market (M2M) payments from SPP in September, with the latter sending the former slightly more than $165,000.

The total, less than a quarter of what SPP sent MISO the month before, reduced the amount of M2M payments SPP has accumulated to $51.2 million since the two RTOs began the M2M process in March 2015.

Temporary flowgates were binding for 519 hours in September, resulting in $1.2 million in M2M payments to MISO. That was almost entirely negated by $1.1 million for permanent flowgates binding for 110 hours in SPP’s favor.

Tom Kleckner contributed to this report.

November 11, 2018

PJM Stakeholders Hold Their Lines in Capacity Battle

By Michael Brooks

PJM stakeholders last week dug in further on the RTO’s proposed revamp to its capacity market, reiterating comments made last month in FERC’s paper hearing on the proposal (EL16-49, ER18-1314, EL18-178).

In reply comments Nov. 6, PJM rebutted “anticipated” criticisms of its Extended Resource Carve-out (RCO) proposal, which would allow specific, state-subsidized resources to opt out of the capacity market and the RTO to adjust market clearing prices as if the resources were still in.

State renewable portfolio standards and impact on PJM (2009-2033) | *PJM*

PJM’s proposal is a response to the Fixed Resource Requirement (FRR) Alternative FERC recommended when it found the RTO’s minimum offer price rule (MOPR) unjust in June. PJM’s current FRR only allows utilities to opt out of the market if they can serve all of their load through other means, such as bilateral contracts.

“Despite the hundreds of pages of initial comments, barely a handful provided the commission with detailed proposals supported by pro forma tariff changes,” PJM said. “Of those that did, only PJM’s proposal meets both key objectives, i.e., preserving competitive markets while accommodating state policies.” (See Little Common Ground in PJM Capacity Revamp Filings.)

Critics generally fell into two camps. One argued for a rejection of any carve-out, calling instead for a “clean,” MOPR-only construct that extended to all resources. The other generally supported the concept of the FRR Alternative but argued that because of the repricing mechanism, Extended RCO would lead to inflated capacity prices.

Exelon said the FRR Alternative “strikes a just and reasonable balance among equally important policy goals. It makes room for states to pursue energy policy initiatives favoring particular types of generation resources, by allowing states to provide for the procurement of their capacity outside the PJM auction market — but credits load for that capacity, thus avoiding unnecessary costs for customers.”

Exelon said “the Extended RCO results in … massively inflated customer costs because of a fatal design flaw: PJM proposes to set the stage 2 price — which cleared resources would be paid — by removing RCO resources from the supply curve entirely. In other words, rather than resetting the bids of RCO resources to ‘competitive’ levels at stage 2, as the MOPR purports to do, the Extended RCO simply acts as though the RCO resources do not exist. That makes no sense.”

The Maryland Public Service Commission, which also argued that Extended RCO would lead to inflated clearing prices, proposed a separate auction for state-subsidized resources.

“Resources that do not clear the auction but serve to set a higher clearing price would be paid what PJM terms as ‘infra-marginal rent payments,’” the PSC said. “These potentially perpetual payments, in the form of uplift, are characterized as rents those resources would have ‘earned’ had they cleared the auction at the elevated artificial clearing price.”

FirstEnergy Solutions called Extended RCO “a reasonable means of accomplishing the objectives articulated by the commission.” But it also criticized PJM’s proposal to continue applying the MOPR to previously subsidized resources seeking to re-enter the capacity market. “The commission should consider the reality of this proposal: Most resources that elect the [resource-specific FRR] for some period of time would effectively be precluded from ever re-entering” the capacity market, FES said.

Exelon also joined in a reply brief in support of the FRR Alternative filed by a diverse group of stakeholders: the Nuclear Energy Institute, the Illinois Citizens Utility Board, the Natural Resources Defense Council, Talen Energy, the Sierra Club, PSEG Energy Resources & Trade and the D.C. Office of the People’s Counsel.

Noting that they frequently disagree on other issues, the groups said, “We are unified, however, in our belief that the commission and PJM must reasonably accommodate states taking actions to achieve their clean energy policies. …

“The only parties arguing against the concept of balancing an expanded MOPR with adoption of a resource-specific FRR mechanism are the companies that have brought — and lost — legal challenges to the states’ authority to implement clean energy programs.”

Clean MOPR

The Electric Power Supply Association, the PJM Power Providers Group and NRG Power Marketing continued to insist on a clean MOPR, in which all resources, with limited exceptions, are subject to the rule. They also criticized FERC’s FRR Alternative proposal.

“As acknowledged by PJM and others advocating such an approach, the FRR Alternative will negate the remedial benefits of an expanded MOPR and thus perpetuate the price suppression problem that the commission properly found to be unjust and unreasonable in the June 29 order,” EPSA said. “Adopting such a replacement rate would be irrational and unacceptable as a policy matter and unlawful as a statutory and constitutional matter.”

“Let’s call FRR-A what it is: a proposal to reregulate a substantial portion of the competitive wholesale market,” NRG said. “Adopting FRR-A would signal a retreat from the competitive markets that the commission has espoused since its landmark Order No. 888. Like all massive government interventions in the market, FRR-A would stifle the efficient allocation of private capital, shift costs and risks to consumers, and replace private, at-risk investment with ratepayer-backed investment.”

EPSA criticized Exelon, whose nuclear plants in Illinois are the beneficiaries of zero-emission credits, for calling for a blanket waiver of FERC’s affiliate transaction rules in espousing the right of states to choose how they procure energy. In its initial brief, Exelon had said, “At the very least, the commission should treat state involvement in the procurement of capacity by a load-serving entity from an affiliated generation company as strong evidence pointing against any affiliate abuse.”

“Leaving aside the fact that it is a bit rich for Exelon to imply that the Illinois legislature spontaneously decided to award Exelon billions of dollars in subsidies, there is simply no basis for the contention that the commission’s concerns about rates negotiated between affiliates are a function of the level of ‘state involvement,’” EPSA replied. “The commission has a statutory duty to ensure that rates for wholesale sales are just and reasonable and … that duty may not be delegated to the states.”

‘Moral Obligation’

Calpine, which had led a challenge to PJM’s MOPR in 2016, argued that Extended RCO was FERC’s best option, and that it had a duty to it and other generating companies to implement the proposal.

“The commission cannot turn its back on existing generators,” Calpine said. “Not only does the commission have a statutory obligation to ensure that capacity market prices are just and reasonable, the commission also has a moral obligation to implement rules that allow competitive generators the opportunity to recover their investments in the market. …

“Competitive generators have flocked to the PJM market, investing tens of billions of dollars of private money with the understanding that they will have a fair opportunity to recover their investment. There was no guarantee that their investment would be recovered, but there was a regulatory compact that PJM and the commission would protect and defend competitive markets, so investors have the opportunity to compete on a level playing field. … If the commission fails to take the necessary action in this proceeding to shore up the structure of PJM’s capacity market, then the commission must be prepared to develop mechanisms to provide stranded cost recovery for these investors who were otherwise tricked into investing capital in a market with no meaningful opportunity to recover that capital, and a fair return with it.”

Calpine’s claim was rebutted by the Harvard Electricity Law Initiative in the opening lines of its comments. “As the commission considers how to avoid raising wholesale capacity rates, it should discount generators’ warnings that they may demand ‘stranded cost’ recovery if the commission does not approve their preferred approach to the PJM Tariff,” it said.

“Generators’ actual expectations about market rules and prices are premised on a mistaken view of the commission’s ratemaking authority and have no equitable force,” Harvard said. “Generators assert that the commission must approve a ‘clean’ market, untouched by direct and certain indirect government interventions, to ensure that the PJM capacity auction is ‘competitive.’” The judiciary has held that the “just and reasonable” standard in the Federal Power Act does not necessarily mean “structurally competitive,” Harvard noted.

Ari Peskoe of the Harvard Electricity Law Initiative created this wheel to illustrate the range of opinions on PJM’s capacity market. “How will FERC decide? Lots of options. Here’s a handy tool FERC can use to pick the design of the next PJM capacity auction,” he tweeted.

Consumer Responses

A group of industrial customers said the Extended RCO should be rejected because it is essentially identical to the capacity repricing proposal the commission rejected in June as an unjust cost shift. “In addition to discriminating against customers that are captive to states that are subsidizing resources, the Extended RCO is likely to produce pricing outcomes that cannot be defended as being just and reasonable.”

State consumer advocates for Illinois, West Virginia, Delaware, Maryland and D.C. said there is no evidence that state resources are suppressing capacity prices, noting that “PJM has two-thirds more capacity than necessary to meet its reliability requirement, the largest excess of any RTO in North America.”

They also said PJM’s proposed resource-specific criteria for the carve-out are too restrictive. “States should be allowed to count carved-out resources toward resource adequacy requirements according to actual grid needs, which are portfolio-wide and seasonal,” they said.

PJM’s Independent Market Monitor lobbied for its proposed “Sustainable Market Rule,” which would allow all nonmarket resources to participate in the energy market but use the capacity market as a “balancing mechanism” to provide incentives for entry and exit.

“If resources offer at competitive levels and clear the capacity market, the resources are paid the market clearing price. If resources do not clear the capacity market, the resources are not paid for capacity,” the Monitor said. “Any nonmarket revenues required to meet the public policy goals associated with these resources would be provided outside the market in whatever manner the supporters of those resources choose.”

Rich Heidorn Jr. contributed to this report.

November 11, 2018

OMS Executive Director to Exit

By Amanda Durish Cook

Tanya Paslawski at the OMS Annual Meeting in October | © *RTO Insider*

The Organization of MISO States said Friday that Executive Director Tanya Paslawski will depart the organization at the end of the year.

Paslawski has accepted a position as president of the Michigan Gas and Electric Association starting Jan. 1, 2019, and will resign her OMS post effective Dec. 31.

Paslawski joined OMS in 2014 as the organization’s deputy executive director, becoming executive director in 2015. Prior to OMS, she worked for ITC Holdings and was a staffer at the Michigan Public Service Commission.

OMS leaders said Paslawski navigated the organization through a transitional stage as the electric industry itself experiences change.

“Tanya has brought leadership, knowledge of the industry and an ability to forge consensus among regulators in the MISO footprint. She has served with distinction, and I wish her well in her new position,” OMS President Ted Thomas, chairman of the Arkansas Public Service Commission, said in a statement.

“Tanya did an incredible job as OMS executive director, providing astute legal and policy analysis on complex and critical issues … and her ability to facilitate consensus on those issues will be deeply missed,” OMS Vice President and Missouri Public Service Commissioner Daniel Hall said.

Paslawski had lauded the organization’s perseverance and collaborative nature during the OMS Annual Meeting and 15-year anniversary celebration last month. (See Overheard at OMS 2018 Annual Meeting.)

OMS’ executive committee will open a search to select a new executive director, who will be subject to confirmation by the organization’s board of directors. Staff said the search for a replacement will be opened next week, with any next steps, including the potential need for an interim director, determined thereafter.