Page 1087 – RTO Insider

December 17, 2018

PJM Market Implementation Committee Briefs: Dec. 12, 2018

By Rory D. Sweeney

Attendees discuss issues at last week’s meeting of PJM’s Market Implementation Committee. | © *RTO Insider*

Indemnification Conversation

VALLEY FORGE, Pa. — The PJM Market Implementation Committee will host a discussion on indemnification for financial transmission rights bilateral contracts at its Jan. 9 meeting.

The discussion, which was promised at the Dec. 5 meeting of the Markets and Reliability Committee, is intended to determine how PJM will respond to a deficiency letter FERC issued in response to one of the RTO’s proposed revisions to its FTR credit policies following the historic GreenHat Energy portfolio default.

PJM plans to request that FERC dismiss its filing, making the deficiency notice moot. But Shell Energy told the MRC on Dec. 5 that it wants to see the commission rule on the underlying indemnification issues that Shell pointed out in protesting the filing. (See “Bilateral FTR Retraction,” PJM MRC/MC Briefs: Dec. 6, 2018.)

FTR Collateral

PJM’s Bhavana Keshavamurthy and Diane Antonelli administrate a special session of the MIC last week on revising the RTO’s fuel-cost policy rules. The session was held as part of the regularly scheduled MIC meeting. | © *RTO Insider*

Stakeholders voted overwhelmingly in favor of PJM’s original proposal on revising its FTR credit requirements to include a “mark-to-auction” (MTA) provision. The proposal, known in the stakeholder process as G1, received 0.93 in favor in a contemporaneous vote with several alternatives and 0.93 in favor compared to maintaining the status quo.

The proposal has the potential to delay clearing of auctions and posting of results because of intra-auction collateral calls for undercollateralized portfolios. Delayed results have happened twice in the history of PJM’s FTR markets. Both times were in March 2017, caused by “super overlapping” clearings from multiple FTR auctions ending at the same time. PJM has since implemented rule changes to avoid that situation. (See “FTR Revisions Approved over Financial Dismay,” PJM MRC/MC Briefs: Jan. 25, 2018.)

An alternative proposal that only applied the collateral call for portfolios undercollateralized by at least $100,000 failed to receive stakeholder endorsement, with 0.14 in favor. Another that used the same analysis and requirements but removed bids from undercollateralized portfolios rather than making intra-auction collateral calls also failed with 0.3 in favor.

Suffolk Fund’s James Ramsey campaigned for two other alternatives that would have applied a credit requirement that is the higher of either the existing requirements or the MTA plus an adder. One included the $100,000 threshold while the other did not. He said the endorsed proposal would be “challenging to do” because it requires forecasting many variables and might require very small collateral calls that could exacerbate delays.

FTI Consulting’s Scott Harvey, retained by PJM to analyze the issue and compare the proposals, said all of the alternatives are sound, but that Ramsey’s proposals have “ad hoc parameters” that risk running down a portfolio’s initial credit margin at the wrong time because the margin declines as losses occur in the portfolio. His analysis found that two situations in the history of PJM’s FTR market wouldn’t have been covered by Ramsey’s proposals, but both were from the GreenHat default and would have been undercollateralized by more than $20 million.

“If they have a big loss when the margin’s reduced, you have the opportunity for a big default,” Harvey said.

Ramsey’s proposals failed to receive stakeholder endorsement, with votes of 0.23 and 0.08 in favor.

A third set of alternatives would have combined both to make the credit requirement the higher of the current credit requirement plus the MTA or the MTA and Ramsey’s MTA adders. That set differed on the option for the $100,000 threshold. However, they were removed from consideration before the vote.

PJM said it is targeting January to file the endorsed proposal with the intention of implementing it in April.

Fuel Cost Policy Special Session

Since the MIC’s agenda was short, staff decided to include a special session on considering tweaks to several parts of the fuel-cost policy (FCP) rules and cost-based offer procedures hashed out last year. The sessions started after the MIC approved a problem statement and issue charge in September. (See PJM Stakeholders Seek More Flexible Fuel Cost Rules.)

Joe Bowring, PJM’s Independent Market Monitor, questioned whether the process could be used to completely eliminate FCPs.

John Rohrbach of ACES, who initially proposed the re-evaluation, assured Bowring “our goal is not to vitiate” the FCP process.

“Or eviscerate? … Just checking that you don’t want to do either,” Bowring responded.

The session identified 14 factors to consider changing or adding.

December 17, 2018

Full PJM Study Makes Case for Fuel Security Payments

By Rory D. Sweeney

The full report on fuel security in PJM’s footprint that CEO Andy Ott teased during a D.C. press conference on Nov. 1 shows that the grid is reliable in all but extreme scenarios and will remain so — as long as resources are compensated for being fuel-secure.

On Nov. 1, PJM CEO Andy Ott announced the initial findings of the RTO’s fuel security study at the National Press Club in D.C. | © *RTO Insider*

“This analysis demonstrates that the PJM system is reliable today and will remain reliable in the future,” says the report, which was released Monday. “Key elements such as on-site fuel inventory, oil deliverability, availability of non-firm natural gas service, location of a pipeline disruption and pipeline configuration become increasingly important as the system comes under more stress. … While there is no imminent threat, fuel security is an important component of reliability and resilience — especially if multiple risks come to fruition. The findings underscore the importance of PJM exploring proactive measures to value fuel security attributes, and PJM believes this is best done through competitive wholesale markets.”

Ott went to D.C. last month to begin the drumbeat for compensating generators on their “fuel security,” outlining proposals including valuing it in the capacity market or developing a winter reserve product in the energy market. (See PJM Begins Campaign for ‘Fuel Security’ Payments.)

The study picks up where Ott left off, noting that the proposals have been submitted in the resilience docket FERC opened in January (AD18-7). (See Don’t Rush on Resilience, Commenters Urge.)

It says the results will be used to define and value “fuel security attributes” and describes the “key variables” to maintaining reliability during extreme events as:

Availability of non-firm gas transportation service;
Ability of the fuel oil delivery system to replenish oil supplies during an extended period of extreme cold weather;
Physical breaks at key locations on the pipeline system;
Customer demand;
Generator retirements, replacements and the resulting installed reserve margin (IRM);
Use of operating procedures to conserve fuel during peak-winter conditions; and
Pipeline configuration.

Study Details

The study focuses on natural gas- and oil-fired units that make up 84,823 MW of PJM’s capacity — about half of the total — but maintain less than five days of fuel on-site. It encompasses 324 “different scenarios that could occur during an extended period of cold weather” during the 2023/24 winter, including variables such as customer demand, fuel availability, oil refueling frequency, generator forced outage rates, retirements announced as of Oct. 1, new generation planned to be operational by 2023, level of reserves and natural gas pipeline disruptions.

Duration of pipeline disruptions | *PJM*

The report provides extensive discussion to validate its assumptions, which it says are based on more than 45 years of weather data, previous studies, surveys of PJM generation owners and meetings with regulators, operators and stakeholders throughout the supply chain.

“Even in a scenario such as extreme winter load combined with a pipeline disruption at a critical location on the pipeline system from which a significant number of generators are served, PJM’s system would remain reliable and fuel-secure. While there could be reserve shortages in the extreme winter load scenarios, the grid continues to deliver electricity reliably under these extreme conditions,” the report says.

However, when combined with “escalated” assumptions that generation reserves are reduced to the 15.8% IRM, “the system may be at risk for emergency procedures and operator-directed load shed.” The retirements announced so far would create a 25.8% IRM.

Non-firm Gas

The analysis found that 16,000 MW of gas units in PJM haven’t contracted for firm service that is only interruptible by force majeure, such as a pipeline disruption. The analysis determined that a typical winter day would have 10,000 MW, or 62.5%, of those units available while an extreme winter day of high gas demand would have 0% availability from those units.

The study’s assumptions for pipeline disruptions account for up to five days of 100% reduction and at most 20% reduction for the ensuing nine days. PJM has experienced interstate pipeline outages, or “line hits,” over the past two years as the result of both pipeline corrosion and accidental third-party damage. Outages with easily identifiable sources are “typically” back in service within five days. However, non-point source issues may “require a longer outage and potential derating of the pipeline capacity.”

The scenarios studied only consider individual pipeline disruptions and don’t contemplate multiple simultaneous disruptions.

Results

Without escalated retirements, even an extreme weather event with 0% availability from non-firm units and a single high-impact pipeline disruption with limited refueling availability results in no worse than reserve shortages, according to the study.

However, of the 144 scenarios in which extreme winter load is combined with escalated retirements, 73 scenarios, or 51%, required manual load shed, which would mostly be localized to one of three areas in PJM: East, West or South. The worst scenario would result in 83 hours and 204 GWh of load shed.

December 17, 2018

PJM Moving Quickly to Make Board’s Price Formation Deadline

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM staff moved briskly through a dense agenda during Friday’s meeting of the Energy Price Formation Senior Task Force (EPFSTF) in hopes of wrapping up the wide-ranging, yearlong initiative by a Jan. 31 deadline set last week by the Board of Managers.

Energy Price Formation Senior Task Force | © *RTO Insider*

The dramatic debates that often attend PJM stakeholder meetings were largely kept in check, although several stakeholders shared their reactions to the deadline at the meeting, the task force’s first since the board published a letter issuing it.

The board said it saw need for six revisions to how the RTO sets prices in its energy market and that if stakeholders haven’t endorsed plans to address the six needs by Jan. 31, it will direct PJM staff to unilaterally file a plan for FERC approval. (See PJM Board Demands Action on Energy Price Formation.)

Susan Bruce, who represents the PJM Industrial Customer Coalition, said the board appeared to feel stakeholders weren’t making progress on the issues, even though the RTO had recently made large-scale revisions to its proposal and stakeholders made it clear a vote was coming soon.

“I was left with the impression [from the letter] that stakeholders couldn’t get their act together to get a vote,” she said. “I’m concerned about the perception of the board about what was happening, which has been good work at the EPFSTF. … I think it doesn’t fully appreciate the work that been done.”

PJM’s Dave Anders assured attendees that the board was apprised of all of the task force’s activity.

Other stakeholders expressed skepticism that the task force can comprehensively address the six revisions demanded, particularly because two of them have yet to receive any discussion.

Carl Johnson, who represents the PJM Public Power Coalition, said aligning market-based reserve products in day-ahead and real-time energy markets was “the one thing I said at the beginning that I wanted to come out of this process … so that’s great.”

But a “piecemeal” approach of endorsing solutions for any of the six that stakeholders can agree on — which the board indicated it would accept — “doesn’t work,” he added. “I do not see how we can pull all of this together. I think the time frame is pretty unrealistic.”

However, staff were confident that the timing is achievable. PJM’s Adam Keech said the other as-yet-unaddressed revision — increasing operating reserve demand curve (ORDC) penalty factors to ensure utilization of all supply prior to a reserve shortage — is a relatively “straightforward” extension of what’s already been discussed.

Catherine Tyler with PJM’s Independent Market Monitor questioned whether there is evidence for what the grid needs to respond to stress events like the polar vortex and bomb cyclone cold snaps.

Keech pointed to reports staff produced on the RTO’s performance during both of those events.

“I don’t agree with the statement that there’s been no analysis on stressed system events,” he said, adding that the board saw all the documentation it needed to see “to come to the conclusion they’ve come to.”

Anders added that he’s “absolutely sure” the board has reviewed those documents.

Gabel Associates’ Mike Borgatti and Erik Heinle with the D.C. Office of the People’s Counsel struck more upbeat tones with their comments. Heinle was optimistic that the differing sides were not too far apart. Borgatti called the deadline “a healthy step in the process” as the sides may never get to agreement.

Any FERC filing would come after the board’s next meeting, scheduled for Feb. 11.

PJM Proposal

Keech and PJM’s Lisa Morelli described staff’s proposal for the six revisions. Though stakeholders indicated concerns, staff continued to move through a presentation in an attempt to fully describe the plan, which was published on Dec. 11, six days after the board’s letter and three days before the task force meeting.

PJM’s Anthony Giacomoni also presented the results of an analysis that stakeholders requested at the task force’s previous meeting. The study simulated energy, reserve and uplift impacts of including the regulation requirement in the ORDC, first using the current two-step curve and then the proposed reserve-market revisions. The study, which covered June 1, 2017, through May 31, 2018, found that, at its most extreme, net costs would be reduced by $350 million, with a $1.92 billion increase in energy and reserve market revenues offset by a $1.5 billion cut in capacity market revenue and a $770 million drop in retail rate costs to load.

December 17, 2018

PJM MRC Preview: Dec. 20, 2018

By Rory D. Sweeney

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See our December 26 newsletter for a full report. (NOTE: The meeting will be held at PJM’s Conference and Training Center instead of the Chase Center.)

Markets and Reliability Committee

Informational Update (9:10-9:25)

PJM Board of Managers member Susan Riley will provide an update via phone on the progress of the Special Board Committee investigating PJM’s handling of the GreenHat Energy financial transmission rights portfolio default.

1. PJM Manuals (9:25-9:40)

Members will be asked to endorse the following manual changes:

A. Manual 14D: Generator Operational Requirements. Revisions developed to revise information input deadlines for the Resource Tracker application. (See “Resource Tracker,” PJM Operating Committee Briefs: Nov. 6, 2018.)

B. Manual 14E: Upgrade and Transmission Interconnection Requests. Revisions developed as part of a triennial cover-to-cover review. The revisions include changing the manual name to align it with the structure of Manuals 14A and 14G and explaining how to apply to the interconnection queue via Queue Point.

2. FTR Mark-to-auction Credit Requirements (9:40-10:05)

Members will be asked to approve a proposal endorsed by the Market Implementation Committee to increase FTR credit requirements with the addition of a “mark-to-auction” provision. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)

3. Must-offer Exception Process (10:05-10:30)

Members will be asked to endorse a proposal endorsed by the Market Implementation Committee to revise the capacity market must-offer exception process. The changes would allow participants to specify multiple auctions when making exception requests. Resources that cannot be made Capacity Performance-capable by the start of the delivery year will be permitted to seek an exception. (See “Must-offer Exception Changes,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

4. FTR Forfeiture Rule (10:30-10:55)

Members will be asked to endorse a proposal endorsed by the MIC to revise the FTR forfeiture rule. It would specify that a binding constraint shall be considered if the difference between the shift factors at the FTR delivery and receipt buses across the constraint exceeds 10% and is in the direction that increases the value of the FTR. (See “FTR Forfeiture Proposal Endorsed,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

5. Primary Frequency Response Senior Task Force (10:55-11:15)

Members will be asked to consider putting the task force on hiatus for one year to gather data and subsequently determine whether to reconvene. (See PJM SHs Seek End to Frequency Response Debate.)

6. Distributed Energy Resources (11:15-11:40)

Members will be asked to endorse proposed clarifications of market participation rules for distributed energy resources. Among the changes are a consistent definition of on-site generators.

December 17, 2018

State Regulators Still Frustrated with PJM

By Michael Brooks

WASHINGTON — The tension between PJM and certain states has not loosened, judging by comments made at a forum held by the Great Plains Institute and Duke University’s Nicholas Institute on Environmental Policy Solutions last week.

From left to right: Panel moderator Jennifer Chen, Nicholas Institute; M. Beth Trombold, Ohio PUC commissioner; Brien Sheahan, Illinois Commerce Commission chairman; Mary-Anna Holden, New Jersey BPU commissioner; and Norman Bay, Willkie Farr & Gallagher. | © *RTO Insider*

During a panel on PJM and state authority over resource adequacy, Illinois Commerce Commission Chairman Brien Sheahan and New Jersey Board of Public Utilities Commissioner Mary-Anna Holden took the RTO to task over several issues, including its latest proposal to revise the capacity market to factor in their states’ subsidies for zero-emission resources.

Holden said that while she thinks the relationship between her state and PJM has improved, she was incensed by a recent letter from the RTO’s Board of Managers giving stakeholders a Jan. 31 deadline to reach consensus on several energy price formation issues. (See PJM Board Demands Action on Energy Price Formation.)

“We’d like to have representation in the stakeholder process,” Holden said. “Yes, a stakeholder process takes place, but we’d like to have respect in the stakeholder process. And that when we’re moving towards an answer, not to come out with a letter of decree from PJM saying, ‘Well, you didn’t work fast enough, so we’re just moving ahead,’” she continued, holding a copy of the letter aloft. “That’s not good governance, and that’s not communicating or collaborating.”

“I would second all of that,” Sheahan said. “I think the letter certainly has rubbed people the wrong way.”

Sheahan expressed appreciation for PJM’s position. “They have a very, very difficult job. … There is enormous tension between the job they have and the policies that states express.”

But, he added later, “I really don’t know how that tension gets resolved.” He noted that he has advocated for Commonwealth Edison, whose Chicago service territory is in PJM, to join MISO, which encompasses the rest of Illinois. But he said the solution may be for the state to not participate in PJM’s capacity market. “I think PJM may just have to decide, ‘Look this is the best we can do, and if it doesn’t fit for your state, we have some other alternatives.’”

Sheahan’s opinion echoed that of Independent Market Monitor Joe Bowring, who gave a presentation on several PJM market issues prior to the panel, including his firm’s own proposal for the capacity market. “If units don’t clear, then as far as we’re concerned, they’re not capacity resources,” Bowring said. “If states want to maintain them, they’re free to do that, but they do not get capacity market revenues. So the capacity market does not change; we don’t need some hugely complicated, impossible-to-understand set of rules to make sure they really clear and force out competitive units. If they’re not competitive, they’re not competitive; they should not clear. …

“If you want to maintain cost-of-service regulation in the state, that’s fine, but rather than acting as if you were a market competitor, you should simply offer in as” a fixed resource requirement.

The RTO’s energy market is working well and also does not need a complete overhaul, Bowring argued. On that point, Norman Bay, a former FERC chairman who is now a partner at Willkie Farr & Gallagher, agreed. Throughout the panel, it often fell to Bay to act as a calming presence as a counter to Sheahan’s and Holden’s frustrations.

“We should acknowledge that the energy market in PJM works well, and it’s producing competitive outcomes from which consumers have benefited,” Bay said. “PJM deserves a lot of credit with respect to the energy market. It’s the capacity market that seems to have engendered the greatest amount of controversy.”

Bay suggested asking FERC to hold a technical conference on stakeholder processes in RTOs and ISOs. He cited the D.C. Circuit Court of Appeals ruling last year that FERC had overstepped its bounds in suggesting to PJM what revisions to the RTO’s minimum offer price rule it would accept. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

The ruling, written by now Supreme Court Justice Brett Kavanaugh, said the commission could only suggest minor, technical or administrative changes, not “modifications that result in an entirely different rate design than the utility’s original proposal or the utility’s prior rate scheme.”

“Thus, the RTO/ISO stakeholder process is more important than ever,” Bay said. “Which means that, given the importance of the process, I think it is critical that stakeholders have a seat and voice at the table.” He said many stakeholders — not just state regulators in PJM — have concerns about the processes.

FERC Commissioner Richard Glick, who gave a keynote luncheon speech at the event, noted that as well. He said he attended a recent Edison Electric Institute conference, and “I was amazed at how many people came up to me to complain about RTO governance in general. … People from all sides of various issues.”

He said it would be worthwhile for FERC to look at the issue, though he did not have any specific suggestions. Both he and Bay noted that it had been a long time since the commission examined RTO governance. In 2008, FERC Order 719 required that each grid operator “increase its responsiveness to customers and other stakeholders.”

Sheahan’s and Holden’s sentiments have been shared by other regulators on their commissions this year. (See NJ Regulator Threatens to Exit PJM Amid States’ Complaints.)

For his part, Bowring said he believes that PJM stakeholder process, “as difficult as it is, has been working just fine. … The stakeholder process is messy … it could be made more efficient. But real issues are debated, real interests are debated and, from my perspective, it has worked very well. The fact that it doesn’t do what one party or another wants, as quickly as they want, is not a sign that it’s not working; it’s a sign that it is working.”

Stu Bresler, PJM senior vice president of markets and operations, defended the RTO’s capacity market filing in a presentation prior to the panel. PJM’s proposal was “really, despite what you may read out there in the press, aimed at accommodating these state policy decisions.”

“There are no easy answers. There are very tough questions with which we are all wrestling,” Bresler said. “From PJM’s standpoint, what we want to do is make sure that we continue to engage with our federal regulator, our state commissions and all our stakeholders, to work our way through these issues.”

“PJM is a member organization,” spokesman Jeff Shields said in an email. “The decision to remain as a member resides with those PJM members.

“We respect the rights of states to determine the mix of generators within their borders, and we have worked with FERC and our stakeholders on recently filed proposals that seek to maintain the integrity of the market while respecting state policy initiatives.”

Looking Ahead

True to the event’s name — “Looking Ahead: Big Challenges in 2019” — many attendees asked speakers and panelists how they thought FERC might rule on the capacity market proceeding.

The abridged version of everyone’s answers: No idea.

But whatever FERC issues, many speakers hoped for a solution that lasts. “It would just be nice to have some consistency,” Holden said. The capacity market “has changed 30 times in 10 years,” she said.

“I don’t know where the commission will end up on this, but I do think that whatever design the commission considers, that it should be sustainable and durable,” Bay said. “I think that it is very hard for stakeholders to deal with significant changes to market design every few years.”

“Good market design is self-sustaining,” Bowring said in closing his presentation.

December 17, 2018

New England Talks Solar, Storage and Public Policy

By Michael Kuser

BOSTON — Growing solar generation will be able to meet a third of peak load in Massachusetts in a few years, but as the grid is reaching the saturation point in certain areas, policymakers are looking to energy storage to help address some of the challenges.

“The grid was not initially designed for this much distributed energy … and we never envisioned 90,000 power plants out there,” Commissioner Judith Judson of the Massachusetts Department of Energy Resources said Friday at the 160th New England Electricity Restructuring Roundtable run by Raab Associates.

The 160th New England Electricity Restructuring Roundtable drew a standing-room-only crowd in Boston on Dec. 14. | © *RTO Insider*

Judson said the state now has more than 89,000 installed solar projects totaling more than 2,300 MW in each of its 351 cities and towns.

On Nov. 26, it launched the Solar Massachusetts Renewable Target (SMART) program, which provides incentives for projects on brownfields, landfills, parking lots and rooftops. “SMART provides a fixed revenue stream to reduce the cost of the program, and we are the first state in the nation to have a solar-plus-storage incentive,” Judson said.

It took the state a long time to launch the program because “we have a regulatory process in DOER and in the Department of Public Utilities, plus heavy stakeholder engagement,” Judson said. “But we’ve had over 2,850 applications for 650 MW in capacity submitted so far and $4.7 billion in cost savings to ratepayers compared to earlier solar programs, so I think it’s made for a better program.”

On Dec. 12, the state issued its Comprehensive Energy Plan (CEP), including a provision for the state’s utilities to procure a combined 200 MWh of energy storage by 2020. (See Massachusetts Deploys Utility-Scale Energy Storage.)

Transition in Connecticut

“The grid modernization proceeding [Case 17-2-03] in Connecticut is a really promising opportunity,” said Mary Sotos, deputy commissioner of the state’s Department of Energy and Environmental Protection.

“I think it’s the first time utilities have laid out for the public … how they’re doing manual, back-end system work for stuff they want automated at scale,” Sotos said. “It’s not just the cost of the meters for them; the concern is managing the data … putting it in the right format, which is all part of this broader shift in information availability.” (See Connecticut Explores its Energy Future at CPES Event.)

Sotos highlighted “opportunities to align policy objectives, customer objectives and developer objectives.”

Connecticut’s solar programs are all in transition, including ones that limit virtual net metering for state, municipal and aggregation customers by capping the amount that could be reflected into rates, she said.

Connecticut last spring passed a bill that doubles the amount of renewable energy utilities must use to serve load — 40% by 2030 — while also revoking net metering guarantees that ensured rooftop solar owners earn retail prices for their excess electricity. (See Connecticut Energy Bill Draws Mixed Reviews.)

“Net metering was available to all these customers in the past on the energy side to compensate solar energy … and each of those solar programs had a statutory spending cap, but we found that municipalities were reaching that cap very quickly,” Sotos said. “For each of these groups we also had a separate program to help facilitate the deployment of behind-the-meter solar by focusing on the RECs [renewable energy credits].”

The state’s Green Bank ran “an incredibly successful” residential solar investment program to focus on the RECs from installations with storage, she said.

“However, under the current monthly net metering model, there isn’t an obvious incentive for customers to do storage, because any energy that is excess or used in real time, it’s all valued at the same level,” Sotos said. “From our perspective, to really value storage for dynamic peak reduction or other benefits … there needs to be an additional financial signal, whether that’s a time-of-use rate or some other type of adder.”

Field Experience

Jonathan Raab of Raab Associates, who has been convening the roundtables since 1995, said he was lucky in his selection of two of last week’s panelists: Evan Dube, senior director of policy at SunRun, represented the most megawatts bid in the under-25-kW category in the SMART program, while Ilan Gutherz, senior director of strategy and policy at Borrego Solar, represented the most megawatts bid in the over-25-kW category.

“Having a robust [distributed energy resources] market, both behind-the-meter and in front, is going to be critical for sustaining the grid in the future,” Dube said. “We hear an awful lot about how rate design must be sustainable … but in so doing, we have to keep in mind the benefits that building out these resources will have in the long term, and how that’s going to make us more sustainable in the future.”

More granular rate design such as time-of-use rates is preferable because it is fairer to customers, but that rate structure is contingent on penetration levels and their location, which affect the price of electricity, Dube said. The availability of metering infrastructure and data also influence how exact electric power billing can get.

The future of compensation for zero-marginal-cost resources like wind and solar depends on getting regulators to “think about how PV and batteries can avoid the need for long-term transmission investment,” Gutherz said.

New York’s Value of DER tariff that large-scale solar and other resources are now on has been testing value-based compensation as opposed to cost-based compensation alone, he said.

“New York’s an interesting experiment; in our opinion, they went a little bit too fast, so if you watch the recent filings from the commission there, you’ll see there’s been a lot of back-pedaling on certain aspects of that tariff,” Gutherz said.

“Solar plus storage is a game-changer,” said Juliana Mandell, director of market development and policy at ENGIE Storage. “You’re transforming solar into a dispatchable, reliable renewable energy resource that’s no longer time-constrained, and that fundamentally shifts the conversation.”

Energy storage can flatten load and generation, be used to reduce peak demand, or to shift generation and load depending on grid system needs and economic signals, she said.

“And you can use storage to mitigate locational constraints and congestion [and] improve capacity supply, and storage can participate at a high level in the wholesale market,” Mandell said. “You can see that coming out of the recent FERC orders if you’re looking [at] how do we pay fairly for resources that provide a different level of performance.”

“The questions is not why solar, but why distributed solar?” said Jesse Jenkins, postdoctoral fellow at Harvard’s Kennedy School and one of the contributors to the MIT Utility of the Future study. “Solar and storage are technologies and means that deliver value, so what we need to focus on is the ends that we have in mind and the value that we want to capture. … Solar and storage are not the only ways to deliver any of the values we’re talking about.”

Mark LeBel, an attorney with Acadia Center, said that solar, peaking in summer, has to be balanced with winter-peaking wind, but that balance is also needed to value societal concerns.

Rooftops almost certainly have to be part of the answer for solar, because there are little or no siting issues, he said.

“Where are we going to put 20 GW of solar?” LeBel said. “Does New England want to pave over paradise?”

December 17, 2018

Soapbox: Large Buyers – Don’t Stop Our Renewable Purchases

By Jeff Dennis and Caitlin Marquis

In response to FERC’s directive to address the impacts of state policies on capacity prices, PJM has proposed a sweeping approach that could put at risk a broad set of transactions for renewable energy that have nothing to do with any state policy or mandate. On behalf of the Advanced Energy Buyers Group, a collection of large companies ranging from technology to retail to manufacturing, we urge FERC to avoid disrupting the voluntary market for renewable energy by rejecting PJM’s approach.

Companies involved in the Advanced Energy Buyers Group are committed to increasing their use of advanced energy, with many entering into contracts to develop renewable energy projects to meet their own business needs, completely independent of state mandates or incentives. We are concerned that PJM’s proposal, if adopted by FERC, would unfairly apply to some of these voluntary transactions the same measures intended to “correct” a market distortion supposedly caused by so-called “material subsidies” provided by states. This could threaten the continued growth of the quickly expanding voluntary market for renewable energy in the PJM footprint, and the jobs and other economic benefits that growth brings to states and communities in the region even as it gives companies the clean energy they seek.

According to FERC, generating resources that receive revenue as a result of state renewable portfolio standards or zero-emissions credit (ZEC) programs are able to submit offers in PJM’s capacity auctions at a lower price than they would otherwise. FERC claims that these offers result in “artificially” lower prices, harming other suppliers that do not receive such revenue. To address this alleged price suppression, FERC ordered PJM to expand its minimum offer price rule (MOPR) — which requires capacity suppliers to make offers at or above a predetermined minimum value — to apply to any capacity resource receiving revenues from state policy programs.

To its credit, PJM correctly acknowledged that voluntary renewable energy purchases should be exempted from the expanded MOPR because any revenue received from such purchases aren’t the result of any state mandate or policy. PJM goes on, however, to state that any renewable energy certificates (RECs) purchased through brokers or intermediaries will be assumed to be serving state policy needs rather than meeting voluntary market demand. This means that only those RECs that are purchased by voluntary buyers through direct, bilateral transactions would be exempt from MOPR requirements. Other renewable energy transactions that use different structures would face the possibility that they could be subject to the MOPR. That matters because application of the MOPR could force certain renewable energy projects out of the capacity market, depriving them of legitimate revenue.

Applying the MOPR in such a broad fashion would fail to satisfy FERC’s legal obligation to narrowly tailor such mitigation to the market harm it identified, i.e., the supposed price-suppressive impacts of state-directed revenues. Equally important, it would fail to account for how the voluntary market actually works, especially the variety of transaction structures and market actors, including REC brokers and intermediaries, that support voluntary renewable energy purchases.

Direct REC purchases from renewable energy projects are an important segment of the voluntary market, to be sure. But so too are “unbundled” RECs purchased through brokers or intermediaries. Renewable energy buyers range from residential consumers to small businesses to large international corporations. Many of these buyers rely on unbundled RECs to some degree, and in 2017 unbundled REC sales accounted for nearly half (46%) of all voluntary market sales of renewable energy. The voluntary purchase of these unbundled RECs by buyers who (unlike utilities and other electricity suppliers) have no state-imposed obligation to purchase renewable energy does not contribute to the state’s RPS or other policy mandate. These RECs are effectively retired, rather than used for compliance with state requirements — which is why they can be counted toward corporate sustainability goals.

Even for large companies that pursue direct contracts with renewable energy projects, unbundled RECs purchased from brokers or other intermediaries can play an important part in an overall renewable energy strategy. Unbundled RECs allow companies to purchase renewable energy without a long-term, large-scale commitment to a single project, as part of a diversified renewable energy portfolio. Unbundled RECs also allow companies to meet renewable energy goals while they pursue direct renewable energy contracts, which takes time.

Many companies and other renewable energy buyers rely heavily on RECs purchased through brokers or intermediaries — to the tune of 51 million MWh across the country last year. These RECs have contributed to a rapid expansion of voluntary corporate renewable energy deals in the PJM region in just the past few years. One voluntary REC getting swept up in mitigation that is, by the terms of FERC’s directive, supposed to be narrowly focused on material subsidies provided by states is one too many, and PJM’s approach could sweep up nearly half the market.

Accordingly, we urge the commission to ensure that any changes to PJM’s capacity market do not, even inadvertently, unfairly cripple the voluntary market for renewable energy.

Caitlin Marquis is manager of federal and state policy for the Advanced Energy Buyers Group, a business-led coalition of large energy users engaging on policies to expand opportunities to procure advanced energy to meet their operational needs.

Jeff Dennis is general counsel, regulatory affairs, for Advanced Energy Economy, a national association of businesses making the energy we use secure, clean, and affordable. AEE facilitates and supports the work of the Advanced Energy Buyers Group.

December 17, 2018

Mass. Offshore Lease Auction Nets Record $405 Million

By Michael Kuser

Offshore wind in the U.S. hit a new milestone Friday when the eighth federal lease auction brought in $405 million for three sites — about six times the revenue from all previous auctions combined.

Eleven companies participated in 32 rounds of bidding. The winners were Equinor, a Norwegian state-controlled company formerly known as Statoil; Mayflower Wind Energy, a joint venture of Shell and EDP Renewables; and Vineyard Wind, a joint venture by Iberdrola and Copenhagen Infrastructure Partners.

A BOEM simulation of what the offshore wind turbines might look like from Wasque Point on Martha’s Vineyard. | *BOEM*

The three lease areas are located 19.8 nautical miles from Martha’s Vineyard and 16.7 nautical miles from Nantucket. The areas total 388,569 acres and, if fully developed, could support 4.1 GW of wind generation, or enough electricity to power about 1.5 million homes.

“Wow … we are truly blown away by this result,” Walter Cruickshank, acting director of the Bureau of Ocean Energy Management, which conducted the auction, said on a press call.

“The intense competition we’ve seen in this offshore wind lease auction is completely unprecedented,” said Nancy Sopko, director of offshore wind for the American Wind Energy Association.

“To anyone who doubted that our ambitious vision for energy dominance would not include renewables, today we put that rumor to rest,” Interior Secretary Ryan Zinke said.

To illustrate the pace of the bidding, a BOEM webpage shows the winning bids — each $135 million — at more than 500 times the size of the opening bids, which started at less than $260,000.

The new industry has gained momentum on the East Coast this year. Massachusetts and Rhode Island in May awarded 1,200 MW of offshore wind energy contracts. Vineyard Wind will supply Massachusetts with 800 MW, while Deepwater Wind won the contract to supply Rhode Island with 400 MW, which Connecticut expanded soon after with a 200-MW award. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

New Jersey committed in May to build 3,500 MW, and New York in July authorized procurement of at least 800 MW or more in offshore wind energy, the first part of a two-phase plan to develop 2,400 MW by 2030.

The U.S. Department of Energy in June awarded an $18.5 million grant to the New York State Energy Research and Development Authority to lead a nationwide research and development consortium for the offshore wind industry, with the state to match the federal funds. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)

Massachusetts officials hope to develop supply chains for the nascent industry in the Port of New Bedford, where they have funded a terminal, but are also working to avoid interfering with fishing operations there, the No. 1 fishing port in the U.S. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)

BOEM said it now has 15 active wind leases for nearly 2 million acres in federal waters.

BOEM map shows the leases won Dec. 14 by three developers: Equinor Wind US in pink; Mayflower Wind Energy in purple; and Vineyard Wind in green. | *BOEM*

Before the Dec. 14 lease sale, the highest price for an offshore wind lease was slightly more than $42 million paid by Statoil two years ago for an area in the New York Bight. New York is expected to issue its first offshore request for proposals this month.

The U.S. Department of Justice and Federal Trade Commission will conduct a competitiveness review of the auction, and the provisional winner will be required to pay the winning bid and provide financial assurance to BOEM.

Upon BOEM approval of a site assessment plan in a lease’s first year, the developer then has four and a half years to submit a construction and operations plan (COP).

After the bureau receives a COP, it will conduct an environmental review, with public input, and if BOEM approves the plan, the developer will then have 33 years to build and operate its project.

December 16, 2018

PG&E Grapples with Line Safety After Camp Fire

By Hudson Sangree

PG&E last week reported additional problems with its transmission lines prior to the deadly Camp Fire, vowed to enhance its grid safety and asked state regulators to approve a more than $1 billion rate hike, largely to help it harden its grid against wildfires.

“We are acting decisively now to address these real and growing threats, and we are committed to working together with our regulators, state leaders and customers to consider what additional wildfire safety efforts we can all take to make our communities safer,” company CEO Geisha Williams said in a news release.

PG&E filed a supplemental report Dec. 11 with the California Public Utilities Commission, detailing problems with its lines near the Camp Fire on the morning the fire started. It also released the report to the public.

The Camp Fire killed 85 people and leveled the town of Paradise, Calif., making it by far the deadliest wildfire in state history. It started at 6:33 a.m. on Nov. 8 near Tower :27/222 on PG&E’s Caribou-Palermo 115 kV transmission line, the California Department of Forestry and Fire Protection (CAL FIRE) and PG&E reported.

NASA mapped damage to Paradise, Calif., from the Camp Fire, the deadliest wildfire in state history. | *NASA/JPL-Caltech*

For the first time publicly, PG&E in its report provided detailed information about the problems it experienced on that line and in other areas of rural Butte County preceding the Camp Fire.

“On Nov. 8, 2018, at approximately 6:15 a.m., the PG&E Caribou-Palermo 115-kV transmission line relayed and de-energized,” the company told the PUC. “At approximately 6:30 a.m., a PG&E employee observed fire in the vicinity of Tower :27/222, and this observation was reported to 911 by PG&E employees.

“In the afternoon of Nov. 8, PG&E observed damage on the line at Tower :27/222, located near Camp Creek and Pulga Roads, near the town of Pulga. Specifically, an aerial patrol identified that on Tower :27/222, a suspension insulator supporting a transposition jumper had separated from an arm on the tower. The suspension insulator and the transposition jumper remained suspended above the ground.”

State fire investigators denied PG&E access to the site for a week but eventually requested the company’s help collecting evidence from Tower :27/222 and the adjacent Tower :27/221, with PUC staff observing, the utility said.

“At the time of the collection at Tower :27/222, PG&E observed a broken C-hook attached to the separated suspension insulator that had connected the suspension insulator to a tower arm, along with wear at the connection point,” PG&E wrote. “In addition, PG&E observed a flash mark on Tower :27/222 near where the transposition jumper was suspended and damage to the transposition jumper and suspension insulator.

“At Tower :27/221, there was an insulator hold-down anchor that had become disconnected. The insulator hold-down anchor is not an energized piece of equipment. After the evidence collection, CAL FIRE released the site. PG&E has not yet made repairs at either tower or restored service.”

Another incident occurred nearby on Nov. 8 at 6:45 a.m., when “the PG&E Big Bend 1101 12-kV circuit experienced an outage. Four customers on Flea Mountain were affected by the distribution outage,” the company said. The next day, a PG&E employee “observed that the pole and other equipment was on the ground with bullets and bullet holes at the break point of the pole and on the equipment.”

After the Camp Fire tore through Paradise in a single day, there was speculation that the Flea Mountain site or another site may have been a second ignition point for the Camp Fire, but so far those reports remain unverified.

PG&E said it’s continuing to investigate the Pulga Road and Flea Mountain incidents and two other reported problems with its equipment in the week following the Camp Fire.

“The cause of these incidents has not been determined and may not be fully understood until additional information becomes available, including information that can only be obtained through examination and testing of the equipment retained by CAL FIRE,” the utility said. “PG&E is cooperating with CAL FIRE.”

PG&E outlined its efforts to deal with wildfire threats in a report to the CPUC. | *PG&E*

In the meantime, PG&E said it would implement additional safety measures to decrease fire risks to threatened communities. The measures include inspections of more than 5,550 miles of transmission lines and 50,000 transmission poles and towers in risk-prone areas, increased vegetation management along its lines and more real-time monitoring of fire conditions.

By 2022, the company said, it will add 1,300 new weather stations, with one every 20 miles in high-risk areas, and install 600 high-definition cameras. The proposed steps align with measures already undertaken by San Diego Gas & Electric to prevent fires and avoid pre-emptive shutoffs of transmission lines in its service area. PUC President Michael Picker praised SDG&E’s long-term efforts Thursday and touted them as a model for the state’s other investor-owned utilities ahead of a commission vote to examine the practice of de-energizing lines in fire-prone conditions. (See Calif. Regulators to Scrutinize Line De-energization.)

PG&E is facing a snowballing number of lawsuits for the Camp Fire, billions of dollars in financial exposure for its role in 2017’s devastating wine country fires and talk of the state stepping in and breaking up the IOU and makings its pieces public. (See Camp Fire Prompts Talk of PG&E Bailout or Breakup.) It watched its stock price plummet in November before recovering some ground. (See Destructive Fire Drives Down PG&E Stock.)

The PUC said recently it would expand its probe into PG&E’s safety practices following the Camp Fire. That investigation started after the fatal explosion of a PG&E gas line in San Bruno, Calif., in 2010. (See CPUC Expands Probe into PG&E Practices After Deadly Fire.)

On Thursday, the company asked the PUC to approve a $1.1 billion rate hike to help pay for those additions and other upgrades as part of its 2020 General Rate Case before the commission.

“PG&E is asking for a $1.1 billion increase over currently adopted revenues for 2019” ($8.506 billion), the company said on its website. “More than half of PG&E’s proposed increase would be directly related to wildfire prevention, risk reduction and additional safety enhancements.”

Part of its Community Wildfire Safety Plan, the changes would include installing stronger poles and covered power lines across 2,000 miles of high-risk fire areas.

“As noted, this rate case calls for $1.1 billion in 2020, $454 million in 2021 and $486 million in 2022, respectively, to capture inflation and other cost escalation,” PG&E wrote. “If approved by the CPUC, this proposal would increase a typical residential customer bill by 6.4% or $10.57/month ($8.73 for electric service and $1.84 for gas service).”

The proposal doesn’t cover potential liability for the wine country fires or the Camp Fire, PG&E said.

December 16, 2018

MISO Prepping for Growth in Dynamic Line Ratings

By Amanda Durish Cook

MISO staff are considering how to respond to transmission owners’ adoption of dynamic line ratings, acknowledging that changes in systems and operations would likely be necessary with widespread use.

Acting on a recommendation from the RTO’s Independent Market Monitor, staff broached the topic with a presentation during a Dec. 13 conference call of the Market Subcommittee.

Operations engineering manager Jay Dondeti said MISO already allows TOs to submit dynamic line ratings, though most don’t. Dynamic line rating technology provides real-time data on environmental conditions near transmission lines, including ambient temperature, solar radiation and wind speed, allowing lines more capacity in cooler conditions.

Currently, TOs can provide line ratings to MISO through one of four ways: a seasonal ratings table with ratings for up to four seasons; a ratings lookup table based on temperatures; supplying specific ratings through the Inter-Control Center Communications Protocol; and submitting hourly and current day ratings through direct data files.

MISO staff and systems would not be able to process dynamic line ratings if every TO in its network decided to use them, and it’s unclear how much dynamic data the RTO can handle.

Widespread use is a long way off. Dondeti said about 93% of MISO TOs currently use seasonal ratings, with the “vast majority” of them providing ratings for two seasons, not four. He said less than 1% of line segments in the Midwest use some form of temperature-based ratings. In MISO South, however — where Entergy has adopted some temperature-based ratings using the filing approach — the percentage goes up to 5%.

Some stakeholders are echoing the Monitor’s calls to adopt dynamic line ratings. (See “Dynamic Line Ratings,” MISO Market Subcommittee Briefs: Oct. 11, 2018.)

“We see the transmission system as underutilized in the day-ahead and real-time markets because of static line ratings,” WEC Energy Group’s Chris Plante said.

Kevin Murray, representing the Coalition of MISO Transmission Customers, said dynamic line ratings might have helped the RTO mitigate some of its recent maximum generation events by transporting additional capacity stranded by static line ratings.

Entergy’s Mark McCulla said his company provides temperature-adjusted line ratings using historical and forecasted weather conditions near a facility to help increase the carrying capability of static line ratings. The company does not factor wind speeds into its more detailed ratings, instead using a 2-feet/second estimate. Entergy provides dynamic ratings to MISO on an hourly, daily and two-day-ahead basis.

“There can be a large swing in ambient temperatures in the Entergy region regardless of season. As a result, Entergy does not use seasonal ratings but instead uses the more granular temperature-adjusted ratings,” McCulla said.

Of Entergy’s more than 2,300 69-kV and above transmission facilities, 978 are in Entergy’s temperature-adjusted ratings database and 140 have short-term emergency ratings.

Entergy said it has experienced a 11% average increase over base facilities ratings when using temperature-adjusted ratings and a further 13% rating increase when coupled with short-term emergency ratings.

Plante asked if Entergy has experienced reliability risks since using the ratings. Entergy representatives said they have yet to experience an overload.

IMM staffer Michael Wander said the Monitor supports using temperature-adjusted ratings, saying MISO’s static line ratings are often conservative.

Wander agreed to appear at future MSC meetings to discuss the economic benefits of dynamic line ratings. He said the Monitor is not advocating a “one-size-fits-all” approach to ratings, but an RTO review process.

Dondeti said MISO will likely have to assess how it would handle the volume of ratings adjustments if dynamic line ratings become routine among TOs. He said it would need to figure out how often line ratings would be changed and how many staffers would need to process them.

RTO officials said they would report on the benefits and potential cost of processing dynamic line ratings in the first half of 2019. MSC Chair Megan Wisersky told stakeholders to expect discussion on the topic at upcoming subcommittee meetings.