Page 1105 – RTO Insider

October 23, 2018December 12, 2023

SERC Taps ReliabilityFirst Exec as CEO

SERC Reliab i l i ty Corp. on Monday announced Jason Blake, vice president and general counsel of ReliabilityFirst, as its new CEO, effective Nov. 15.

He will replace Gary J. Taylor, who hasd served in the position since 2016.

“Our search encompassed a variety of industry segments including public power, investor owned utilities, and the electric reliability sector,” Tom Linquist, managing partner of Lyceum Leadership Consulting, SERC’s search firm, said in a statement.

“I have the utmost confidence that Jason will provide the superior level of leadership, management and vision required to take SERC to the next level in our mission of promoting effective and efficient administration of the bulk power system within our jurisdiction,” Chair Greg Ford said, citing Blake’s “extensive experience.”

Blake, who joined Cleveland-based ReliabilityFirst in 2010, led the organization’s legal and regulatory affairs, enforcement, and external communications departments. He also was corporate secretary and a member of the CEO’s executive team.

Before ReliabilityFirst, Blake gained business and regulatory experience in private practice in Pittsburgh and Cleveland. He is a graduate of The Ohio State University and the University of Pittsburgh School of Law.

ReliabilityFirst is the NERC-delegated regional entity (RE) for the Great Lakes and Mid-Atlantic regions of the United .States. Charlotte, N.C.-based SERC, is the RE for all or portions of 16 Central and Southeastern states.

“This is a great move, not just for SERC, but for the entire [Electric Reliability Organization] enterprise,” ReliabilityFirst CEO Tim Gallagher said in a statement. “Our pride in seeing him named CEO is matched only by our sadness in seeing such a great friend and valued colleague leave the RF family.”

RF has begun a search for Blake’s replacement. Megan Gambrel, managing legal and regulatory counsel, was appointed interim general counsel.

Taylor is departing SERC after a little more than two years as CEO. He joined SERC in 2015 and served as chief operating officer after retiring from Entergy, where he served as group president of Entergy’s utility operations, and CEO of its nuclear unit.

Blake and SERC officials did not immediately respond to requests for comment.

— Rich Heidorn Jr.

October 22, 2018

Climate Change Top of Mind at Vermont Conference

By Michael Kuser

BURLINGTON, Vt. — Climate change mingled with politics at last week’s Renewable Energy Vermont Conference and Expo, where state regulators and officials expressed frustration with federal and RTO policies.

Renewable Energy Vermont held its 2018 Conference and Expo in Burlington on Oct. 18-19. | © *RTO Insider*

While U.S. Rep. Peter Welch (D-Vt.) predicted a Democratic majority in the House of Representatives after the mid-term elections, some participants said planetary survival should come before party interests. Others focused on how to deliver cleaner electricity to consumers in New England.

Campbell Andersen Olivia | © *RTO Insider*

“It’s time to pick up the pace,” said Olivia Campbell Andersen, executive director of Renewable Energy Vermont. “Every week brings fresh evidence of the urgency of climate change. Close to home, here in Vermont, not a month goes by where our electric utilities aren’t issuing warnings about the impending extreme weather and power outages.”

With hydropower in Quebec, wind energy in northern New England and offshore wind all relatively far from load centers, transmission infrastructure must be built to move the electricity from producers to consumers, ISO-NE CEO Gordon van Welie said.

“If you love renewable energy, you have to love transmission,” van Welie said.

“The pipeline system built in the 1970s can’t meet the needs of today’s increased use of natural gas,” he said. “For a while I thought the answer was simply to put in more gas infrastructure — an engineer’s approach — but now we look to create a market solution. We propose to change the rules to maintain an energy buffer stock.”

The RTO’s thinking on the subject can be found in a recent report, “Winter Energy Security Improvements: Market-Based Approaches,” prepared for the Oct. 10 meeting of its Markets Committee.

“We want to use market-based incentives not only to supply the energy, but to reduce demand when needed and maintain a buffer stock of energy throughout the winter,” van Welie said. “We have no details yet; we’re in the process of designing this, and I’m bringing this to your attention so that if you’re interested, you can engage in the appropriate forum, which is the [New England Power Pool] stakeholder committees.”

The main idea is to move from the day-ahead market to a rolling, seven-day-ahead market, he said.

“We want to value energy that’s available today, that can be used today, but also seven days from now,” van Welie said. “And we want to purchase these commitments well ahead of the winter season so that we can stimulate investment in the right fuel arrangements, and ultimately the technologies that can actually deliver this type of service.”

Mission Disconnect

Vermont Public Utility Commissioner Margaret Cheney said ISO-NE is “inevitably a partner because our missions overlap somewhat,” but there’s been “a disconnect in getting the RTO to recognize our in-state distributed generation in their long-range planning forecasts.”

Rhode Island Public Utilities Commissioner Abigail Anthony said the RTO wants states in the region “to understand that their priority is reliability. I want ISO New England to understand that climate change is our state’s priority and to take that seriously.”

Lorraine Akiba, former Hawaii Public Utilities Commissioner, recounted sitting through the ISO-NE presentation and seeing “the lack of any planning for including more distributed energy resources into the ISO capacity portfolio, while others — California ISO in particular is a good example … they’re already into the market with energy storage and distributed generation from the utilities in that footprint, so it’s doable. You just have to conceptualize it. I think PJM has already started that as well.”

It’s also important to address Rhode Island’s concern about reliability versus climate change, Akiba said.

“Resiliency is the ultimate reliability, and because of climate change, resiliency is the key,” Akiba said. “We’ve heard repeatedly … resilience is what we need to do in the face of climate change. We’re going to try to stop the effect of climate change in the next 12 years, but we’ve been reminded that in the course of doing that, we also have to have adaptation strategies to deal with the extreme weather and the consequences of what we have failed to do up to now.”

Political Will

Vermont Gov. Phil Scott said, “Three of our electrical utilities are now 100% renewable, and our largest utility is 60% renewable and 90% carbon-free. We now expect to get at least 75% of our electric supply from renewable energy sources by 2032, and we’re putting in place a standard that … is the most ambitious in the U.S.”

Welch said that despite President Trump’s denial, in “every state and every region, people know just by what they’re seeing that climate change is real, and our failure to act is suicidal. … A confident country doesn’t deny the existence of a problem; a confident country assesses it, analyzes it and solve it. That’s what you do, and it’s in that effort that you then create wealth.”

He contended that a few people doing fine in the carbon-based economy, such as the Koch brothers, are going to fight any effort to transition to a clean energy economy, no matter the consequences to others, but that the upside is jobs created in facing the challenge.

Vermont Senate President pro tempore Tim Ashe said, “We suspect something different is happening … but still in Vermont, despite our ethic … there’s still a sense that this is really a problem mostly acutely experienced by others, not by us.”

Lt. Gov. David Zuckerman, who owns a farm just south of Burlington, said rain that used to fall steadily now comes in torrential downpours, if at all.

“This year it stopped raining in May, and we drained one pond, and then another, and there was no more water to put on the crops. So now this fall, we have 30,000 fewer pounds of food,” Zuckerman said.

He contrasted his situation this year with that of a friend who farms in Shaftsbury, 80 miles south, who said it wouldn’t stop raining, and that they had too much water.

Marc Pacheco, president pro tempore of the Massachusetts Senate, said that while his state has made itself a leader in clean energy and energy efficiency, climate change is becoming more urgent every day.

He recalled talking recently to a friend in Portugal, where Hurricane Leslie had hit last month.

“It’s the first time in 174 years we’ve seen hurricane activity in that part of the Atlantic, heading into the Iberian Peninsula,” Pacheco said. “It’s crazy that we as political leaders … why we have not put into law the concrete statutes that need to be there and need to be met in order to protect not just our climate, but human public health.”

Jared Duval of advocacy group Energy Action Network said, “From the evidence that we have reviewed, it appears that the states that have made the most progress are the ones that have renewable policies with teeth.”

Mackay Miller, formerly with the National Renewable Energy Laboratory and now National Grid’s director of U.S. strategy, said “One thing we are now realizing is that the prospects for a strong federal policy are dim … but at the state level, we can move markets if we move together.”

Dan Sosland of Acadia Center said, “We have the will; we need the political will.”

No Borders

Marie-Claude Francoeur | © *RTO Insider*

Marie-Claude Francoeur, Quebec’s delegate to New England, reminded the audience that “climate change knows no borders.”

Quebec didn’t join the Regional Greenhouse Gas Initiative “because 99% of our electricity comes from renewable energy, hydropower, so RGGI would not achieve our goals,” Francoeur said.

Transportation accounts for about 45% of carbon emissions in Quebec, which began taxing carbon at the distribution level in 2006 with a levy on fossil fuels. Now, with California, it participates in the Western Climate Initiative economy-wide carbon pricing scheme, “investing 100% of the proceeds into greenhouse gas pollution reduction,” she said.

October 22, 2018

MISO Stakeholders Rally to Save Interconnection Group

By Amanda Durish Cook

MISO’s Planning Advisory Committee will vote through Friday on whether to convert the longstanding Interconnection Process Task Force (IPTF) into a working group in an effort to save it from retirement.

The RTO last month proposed to end the task force and fold its discussions and duties into the Planning Subcommittee, a proposal that proved controversial for some stakeholders. (See “End of IPTF?” MISO Queues up Interconnection Options.)

MISO planners are still pulling for retirement, but many stakeholders continue to support converting the task force into a working group, as evidenced by discussion during an Oct. 17 PAC conference call where the Transmission-Dependent Utilities sector introduced a motion to vote on a makeover. The IPTF itself had already voted to convert itself into a working group. PAC voting results are considered advisory, not binding, for RTO staff.

“I think more folks agree that talk isn’t winding down around interconnection issues. If anything, it’s ramping up,” said Clean Grid Alliance’s Rhonda Peters, pointing out that MISO still has a great deal of interconnection work ahead of it based on the size of its 90-GW interconnection queue.

Peters asked the RTO to convert the task force into a more permanent working group so interconnection issues can continue to receive detailed discussions. She argued that the Planning Subcommittee doesn’t have the time to fully explore interconnection topics during its meetings.

“There is no doubt that years ago, the IPTF should have transitioned into a working group,” Independent Power Producers sector representative Mark Volpe said, noting that MISO’s storage participation model under Order 841 will raise policy issues involving the queue with which stakeholders will need to grapple. “There’s a lot of work left to be done,” he said.

“Squelching stakeholder voices on interconnection rule and policy matters is a bad idea based on the breadth of concern about the subject,” Apex Clean Energy’s Richard Seide said.

MISO planners at the meeting said they still recommend folding the IPTF into the Planning Subcommittee, although this time they styled the idea as a “consolidation” of the two by the end of 2018.

Resource Utilization Director Vikram Godbole said the RTO is now recommending a consolidated Transmission and Interconnection Planning Subcommittee (TIPSC), with a new charter and meetings held on an as-needed basis. The subcommittee would report to the PAC and “provide subject matter expertise to the MISO planning staff on technical matters related to the transmission and interconnection planning processes.”

Godbole pushed back on the stakeholder suggestion that the RTO is trying to exclude some stakeholder voices with its proposal.

“That’s not the intent at all,” he said, adding that it’s always MISO’s goal to have well-rounded proposals influenced by a wide range of stakeholders.

Madison Gas and Electric’s Megan Wisersky said she “couldn’t think of a group more ill-suited” to take on interconnection issues than the PAC. She said a power imbalance exists within the group.

“For one, the PAC is sector-focused and not stakeholder-focused. We need the ideas of the stakeholders” to inform interconnection issues, Wisersky said.

In response to stakeholder questions about how MISO and the PAC would resolve an impasse on the IPTF’s fate, Senior Director of Expansion Planning Jeff Webb said the results of a PAC vote and the RTO’s preferred approach will both be put before the Steering Committee for further discussion.

But some stakeholders support retirement of the decade-old IPTF. Great River Energy’s Mike Steckelberg said he and other utilities, including Entergy, Northern Indiana Public Service Co., Duke Energy and Vectren, agree with MISO’s proposal to dissolve the IPTF effective January 2019.

“The IPTF has delved into discussions which are the responsibility of the transmission planners,” Steckelberg said. “Transmission planners have the engineering expertise, judgment and responsibility to determine what reliability studies are needed to interconnect new generation, and this is best done in the [Planning Subcommittee] forum.”

October 22, 2018

MISO PAC Puts MTEP 18 to Vote, Removes 3 Projects

By Amanda Durish Cook

MISO’s Planning Advisory Committee will vote through Oct. 26 on whether to move most of the RTO’s $3.3 billion 2018 Transmission Expansion Plan forward, while holding off on considering approval for three projects because of stakeholder concerns.

The PAC agreed to consider 439 of 442 projects in its email ballot, reserving three for additional stakeholder comment next week. The committee’s vote will take place via email until 4 p.m. EDT on Oct. 26. The committee was originally slated to take a position on MTEP 18 during its Oct. 17 conference call, but it delayed the vote to address stakeholder concerns with projects.

miso mtep Transmission Expansion Plan — MTEP 18 breakdown | *MISO*

The portfolio, which was updated late last week with more projects, now contains 81 baseline reliability projects, 16 generator interconnection projects, two transmission deliverability service projects and two targeted market efficiency projects with PJM. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)

Most projects fall under MISO’s “other” designation: those chosen by transmission owners and reviewed by the RTO that are not eligible for cost allocation and represent replacement of aging infrastructure, construction because of local reliability needs or modifications made for environmental purposes. The portfolio will be considered for approval at MISO’s year-end Board of Directors meeting in December. An earlier version contained 434 transmission projects valued at $3 billion. (See MISO Recommending $3B MTEP 18 Draft Plan.)

Three Projects

The three problematic projects that won’t make the PAC vote include an $11 million rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota, which was identified in this year’s market congestion planning study. MISO claims that the project will yield a 6.8:1 benefit-cost ratio, but stakeholders are skeptical of that estimate.

The Wabaco-Rochester line already experiences congestion, with increased traffic expected from wind generation coming online. Some stakeholders have said the project should be delayed in favor of a future larger project.

Others suggested that the amount of future wind generation driving the project’s benefits might not ultimately be able to connect.

“We do not support the results on this project,” Xcel Energy’s Drew Siebenaler said. “A lot of our reasoning is coming from study results that are CEII [critical energy/electric infrastructure information], so I can’t disclose them in public comments.”

MISO staff said the RTO continues to believe Wabaco-Rochester is a beneficial project and that it studied higher voltage alternatives before drawing that conclusion.

Dairyland Power Cooperative’s Terry Torgerson said the cooperative’s lawyer would be reaching out to MISO with its concerns over the project. “We’ve had discussions with MISO many, many times, and we feel we’re getting nowhere,” Torgerson said.

Entergy’s Yarrow Etheredge asked for more discussion and a possible email vote to find out if stakeholders support the project. MISO ultimately opened a longer stakeholder comment period on it.

Straits Project

Kavita Maini, economist for Midwest Industrial Customers, said the MTEP18 report seems incomplete because MISO is still considering alternatives to American Transmission Co.’s Straits of Mackinaw project.

MISO executives in September said they were still weighing alternatives to ATC’s proposal to replace a 138-kV circuit connecting Michigan’s Upper and Lower peninsulas after two submarine cables were damaged in April, most likely by a passing vessel. ATC said one of the cables was rendered permanently inoperable. (See ATC Restores Tx Link Between Michigan Peninsulas.)

“You’re right, that’s a project whose final recommendation is still in progress with MISO,” said Jeff Webb, the RTO’s senior director of expansion planning.

Webb said the RTO will continue to work with the parties involved on the project and will deliver an update at the Nov. 13 meeting of the System Planning Committee of the Board of Directors. For now, the project has encountered “complicated siting issues at the straits,” though MISO still expects to recommend a replacement of the underwater cables, he said.

Stakeholders have submitted alternatives to the straits project that include battery storage, relocating generators from Michigan’s Lower Peninsula to the Upper Peninsula, tunneling the cables in bedrock below the lake, connecting to Ontario’s grid and constructing a new gas-fired plant near Mackinac.

“We still have hopes of having this resolved before the December recommendation to the Board of Directors, but there is a possibility that it could linger beyond that,” Webb said.

“It doesn’t seem right to vote on this today when the projects aren’t fully vetted,” Maini said.

WPPI Energy’s Steve Leovy said ITC Midwest’s $11 million line and transformer project at the Walters 161/69-kV substation in southern Minnesota was also under evaluation against alternatives, with MISO choosing one such alternative instead of the originally proposed project.

Webb agreed that MISO should update the MTEP report to reflect the change, and the original project was removed from PAC voting consideration.

October 22, 2018January 18, 2024

SPP MOPC Briefs: Oct. 16-17, 2018

LITTLE ROCK, Ark. — SPP’s Market and Operations Policy Committee last week unanimously approved staff recommendations to revise the SPP-MISO Coordinated System Plan by eliminating the RTOs’ joint transmission model and the $5 million minimum cost threshold on interregional projects, while adding adjusted production cost and avoided-cost benefit metrics.

The RTOs have told their stakeholders they will use only their individual regional planning models to evaluate interregional projects. Members on both sides of the seam have complained that a “triple hurdle” has contributed to the lack of interregional projects. (See MISO, SPP Loosen Interregional Project Requirements.)

“We have concerns … about getting rid of the joint model, because it is clear up front that the joint model will determine the way costs are allocated,” The Wind Alliance’s Steve Gaw said. “We lose that stability in the new process, and it remains to be seen if efficiency gains in the new process will outweigh this risk.”

MOPC Endorses Battery Storage as Market Participant

The committee endorsed several market design changes for SPP’s compliance filing with FERC Order 841.

RR323 defines batteries as electric storage resources (ESRs), capable of being dispatched and participating in price formation. Excluded as ESRs are those resources that are either contractually barred or physically incapable of injecting energy back onto the grid because of their design or configuration.

The Tariff change also creates a new registration type, “market storage resource,” to be used only by ESRs. The resources are not required to use the MSR model but must specify ancillary services offered — e.g., energy, regulation up, regulation down, spinning reserves and/or supplemental reserves — and provide at least a tenth of a megawatt to be eligible for any market product.

“The resource can be committed as a charging resource or as a non-charging resource. It’s no different than a regular resource,” SPP’s Yasser Bahbaz said. He pointed out that pumped hydro, a non-charging resource, already qualifies as an ESR.

Renewable interests were hoping to see more on capacity accreditation but were satisfied to learn that the Supply Adequacy Working Group is considering a four-hour accreditation for ESRs. Existing governing language allows ESRs to qualify for capacity credits if the resource meets the planning criteria’s testing requirements.

The measure passed with 10 abstentions.

“Our impression is this has gone little bit beyond what we need to do to comply with the FERC order,” American Electric Power’s Richard Ross said, explaining his company’s abstention. “[SPP] already [has] a storage resource, and it seems to have found a way to operate under the current guidelines.”

The MOPC also approved tweaks to the Market Working Group’s RR266, which modeled joint-owned units as single resources and the committee had approved in July. “Ownership” was changed to “interest,” recognizing that the former term doesn’t capture stakeholder intent that power purchase agreements and other non-ownership interests be included.

Stakeholders approved the change with one abstention.

MOPC Approves 2 Revised Futures in 2020 Study

The committee agreed with the Economic Studies Working Group’s recommendation to study only two futures in its 2020 Integrated Transmission Planning assessment: a reference case and an emerging technologies scenario.

It also agreed with the ESWG that there is no need to study a third future that assumes a carbon adder or carbon-emissions reduction and accelerated emerging technologies. The third future would have increased the 2020 ITP’s study costs, adding about 6,600 consulting hours.

ESWG Chair Alan Myers, with ITC Holdings, said many of the third future’s assumptions will be included in SPP’s first 20-year assessment, which will begin in 2022. “That might be a good vehicle for studying these types of things,” he said.

Staff will use the 2019 ITP’s two futures as a starting point, adding fossil fuel retirements, ESRs and an increase in utility-scale solar and wind additions to the original assumptions. Both futures will assume coal plants retire at 56 years old, a decrease of four years over previous assumptions.

“We think the shift from 60 to 56 [years] … is definitely a movement in the right direction,” said Keith Collins, executive director of SPP’s Market Monitoring Unit, which has joined the ESWG’s discussions. “But [based on] what we’re seeing in other markets, it’s not [reducing] it enough.”

Collins favored including the third future, saying SPP’s market indicates that uneconomic resources are likely operating, as evidenced by the self-commitment of generation and negative prices.

“The economics Keith talks about are driven by the inability of a coal plant to recover its fixed costs,” Board of Directors Chairman Larry Altenbaumer said. “To a large extent, that fixed cost is subject to the regulatory environment that exists. I’m not at all convinced Future 3 is the right way to [address] that.”

SPP Updates Members on Western RC Effort

Peak Reliability’s decision to cease operations may slow SPP’s pursuit of the Mountain West Transmission Group, but it is also giving the RTO some business with the group.

Operations Vice President Bruce Rew told stakeholders the 16 entities who have signed up for SPP’s reliability coordinator services include all original Mountain West members: Black Hills Energy (Black Hills Power, Black Hills Colorado Electric Utility Co. and Cheyenne Light Fuel & Power); Colorado Springs Utilities; Platte River Power Authority; Tri-State Generation and Transmission Association; the Western Area Power Administration (Rocky Mountain Region and Desert Southwest Region); and Xcel Energy’s Public Service Company of Colorado.

Xcel’s surprise April announcement that it was leaving the Mountain West shelved SPP’s integration of the group. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

That news was followed up by Peak’s decision in June to wind down its RC operations by the end of 2019. (See Peak Reliability to Wind Down Operations.)

The other entities who have signed up with SPP are: Arizona Electric Power Cooperative; the city of Farmington, N.M.; El Paso Electric; Intermountain Rural Electric Association, in Colorado; Tucson Electric Power; Arlington Valley, in Arizona; and Griffith Energy, also in Arizona.

SPP will continue strengthen its toehold in the West with its RC services, expanding its footprint to 16 states with the addition of Arizona and Utah.

SPP’s Western RC will serve approximately 20% of the non-CAISO load in the Western U.S., accounting for 100 TWh of net energy for load, Rew said. A Western Reliability Executive Committee and a Western Reliability Working Group will provide governance. Three task forces have already been formed: Congestion Management and Seams, RC Readiness and West Modeling.

Rew said the groups are currently populating the transmission models, with the hopes of exchanging real-time data with transmission owners, balancing authorities and neighboring RCs by May 1, 2019. The Western RC is scheduled to begin shadow operations with Peak by Oct. 1, with the cutover set for Dec. 1, 2019.

Rew also briefed the MOPC on the major operations events with MISO in January and September, calling the latter a “success story” because of the improved coordination between the RTOs.

Unseasonably warm conditions in mid-September led to higher loads than forecast in SPP’s southern region and in MISO South. When several units tripped, MISO was forced to call a maximum generation alert and a Level 2 Energy Emergency Alert on Sept. 15. SPP sent 300 MW of emergency assistance for three hours to help resolve the situation. (See MISO: Sept. Emergency Response Improved by Jan. Event.)

“With our operational preparations, we were able to make it through,” Rew said.

HITT Group Continues its Education Sessions

The Holistic Integrated Tariff Team has moved into a second phase of education, listening to and discussing presentations by various stakeholders as it eyes an April 2019 deadline for delivering a report on the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services.

The team, which reports to the board, was only formed in April. (See SPP’s Tariff Team Begins Carving up the Elephant.)

“I won’t disagree that it’s an ambitious schedule,” said SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary.

The HITT expects to begin its third phase in December, when it will begin drafting its recommendations to the board and Members Committee.

The team meets next Oct. 23 and has scheduled meetings through April 2019.

The meetings continue to be limited to team members, with those stakeholders not delivering presentations “encouraged” to call in to listen.

Suskie acknowledged the lack of face-to-face interaction and stakeholders’ complaints about technological problems during conference calls. “We tried to line the meetings up with board meetings as best we could, but we haven’t been able to do that,” he said.

Competitive Transmission Group Kept on Standby

The committee agreed to keep the Competitive Transmission Process Task Force on “hot standby” rather than disband it, should a future Order 1000 issue deserve its attention.

Several committee members agreed with the group’s recommendation that it disband, saying its work has been completed. But task force Chair Bill Grant, of Southwestern Public Service, argued the group’s expertise should be leveraged by keeping it on standby, rather than disbanding it.

“We had a pretty balanced group of people who had transmission experience and know how projects are put together. We also had financial people who could look at and analyze bidding forms,” he said. “If MOPC wants to disband and bring it back up if needed, I would caution you that we have the right people at the table.”

Formed in 2015, the CTPTF picked up where a previous task force left off to revise SPP’s Tariff to comply with FERC’s 2011 order introducing competition to transmission development. The group has worked to improve the competitive process following the first two solicitations, neither of which resulted in an approved project.

Admin Cost Recovery Looks at Demand, Energy Charges

Evergy’s John Olsen, chair of the Schedule 1A Task Force, told the MOPC his group will propose revisions to SPP’s administrative fee recovery mechanism at the committee’s January meeting. Olsen said that timeline would give members a year to work with their regulators before final revisions are filed with FERC in 2020.

Olsen said the group favors a mix of demand and energy charges, with market costs recovered through energy charges and planning costs recovered through demand charges. Contested issues include scheduling and dispatch costs and what “determinants” should be included in cost allocation calculations, he said.

“The debate has been whether generators or loads pay for all cost,” Olsen said.

He shared a picture of Grant and Tenaska’s John Varnell, wearing seemingly identical plaid shirts and body language during a task force meeting.

“That’s what five hours of talking about denominator billing determinants will do to a person,” Olsen said, drawing laughs.

The task force has been asked to simplify the rate structure and include energy transactions into the design. The RTO’s administrative fee of 42.9 cents/MWh is budgeted to recover $164 million in the current budget year. The administrative fee is collected on contracts between transmission providers and customers. Point-to-point contracts are billed against reserved transmission capacity, and network service is billed against the prior year’s average monthly zonal peak. (See SPP Stakeholders to Study Admin Fee Changes.)

MOPC Approves Order 845 Compliance Language

The MOPC easily endorsed the Regional Tariff Work Group’s revisions to the pro forma large generator interconnection procedures and large generator interconnection agreement to comply with FERC Order 845. The commission’s order is designed to address delays in interconnection queues, a common complaint among SPP’s membership.

RTWG Chair David Kays, with Oklahoma Gas and Electric, said Revision Request 325 will not be filed until a pending rehearing request before the commission is resolved, which would likely add another 90 days to the timeline.

The vote was unanimous, with only ITC abstaining.

Consent Agenda

The MOPC rejected a change to the ITP’s operational model development, agreeing that ESWG/TWG RR317 would be undoing the Transmission Planning Improvement Task Force’s work.

The change would have removed the day-ahead reliability unit commitment to evaluate economic flowgates in planning models. It was removed from the consent agenda, with two members abstaining from the vote.

The committee unanimously approved the rest of the agenda, which included 10 revision requests, updates to the 2019 ITP assessment’s scope, removal of references to the SPP Regional Entity from the MOPC’s scope, the MWG’s annual violation relaxation limits analysis, and charter changes for the Operating Reliability, Operations Training Project Cost and Regional Compliance Working Groups. (RR318 was discussed separately but also passed unanimously.):

BPWG RR319: Standardizes market import service (MIS) over all SPP ties by adding MIS to the Miles City DC tie in Montana, which is partially owned by the Western Area Power Administration.
ESWG/TWG RR321: Cleans up several items, grammatical errors and small improvements in the ITP manual that were discovered since its approval.
MWG RR288: Allows non-dispatchable variable energy resources converting to dispatchable to use control statuses not originally available to them. SPP’s control statuses are: offline (the resource is not operating); non-regulating (online and capable of following a dispatch instruction or contingency reserve deployment but not eligible to clear regulation service); regulating (online and capable of following dispatch or contingency reserve instruction, and regulation deployment); and manual (online but not able to follow dispatch; e.g., start-up, shutdown, testing, etc.).
MWG RR316: Updates the multi-configuration (combined cycle) resource market design by adding two additional commitment parameters: group minimum down time and plant minimum down time. Also removes sync-to-min and min-to-off times from the submitted minimum down time or group minimum down time when the resource transitions between operational configurations. The current design only allows individual registered configurations to submit a minimum down time.
MWG RR328: Allows the automation of out-of-merit energy and RUC make-whole payment calculations when a contingency reserve deployment test is issued.
MWG RR332: Corrects protocol calculations from designs implemented in RR200 (design change for bilateral settlement schedules and over-collected losses (OCL) distribution) and RR235 (correction to RR200) necessary to ensure bilateral settlement schedules are receiving their correct OCL. The change — which also must be approved by the Regional Tariff Working Group — ensures corrected resettlements back to the original May 1, 2018, release date. The RTWG next meets Oct. 25.
MWG RR333: Modifies four charge types necessary to implement RR229 (FERC Order 831 compliance) and discovered by staff during a recent settlements system replacement project. It also must go before the RTWG for approval.
ORWG RR318: Changes the contingency reserve requirement calculation to allow the use of the “most severe single contingency” as the basis of the minimum contingency reserve requirement on an hourly basis. SPP said the revision allows it to more accurately and reliably set the reserve requirement.
RTWG RR305: Updates Tariff language following modifications to the aggregate facilities study process by removing the requirement to file a service agreement before modeling new transmission service in the ITP models. Also removes the requirement that SPP issue notifications to construct (NTC) and notifications to construct with conditions (NTC-C) before filing a service agreement. Adds a financial commitment date of four years to the issuance of an NTC or NTC-C.
RTWG RR322: Changes the Tariff and other documents to reflect that the RTO is no longer using U.S. Energy Information Administration data in monthly load forecasts. SPP said the data in the EIA report are not granular enough because they are at the balancing authority level, rather than the local balancing authority level required. In January, the RTO began using forecast data that are available through the NERC system data exchange (SDX) and historical data where forecasts are not available.

— Tom Kleckner

October 22, 2018

SPP Strategic Planning Committee Briefs: Oct. 18, 2018

LITTLE ROCK, Ark. — SPP Board of Directors Chair Larry Altenbaumer last week unveiled a proposal to reduce the number of face-to-face meetings and add more executive sessions, saying it would improve the board’s focus on its strategic plan.

SPP Chair Larry Altenbaumer shares his thoughts on changes to the Board meetings. | © *RTO Insider*

While no final decisions have been made, Altenbaumer told the Strategic Planning Committee he is proposing adding two executive time slots to the board and Members Committee’s quarterly meetings and eliminating the two non-quarterly face-to-face board sessions. The executive time would be used for discussions with the state regulators’ Regional State Committee and the Members Committee.

Altenbaumer called the changes part of the board’s “broader evolution,” but that he was sensitive to concerns about taking discussions behind closed doors. He said the executive sessions are not intended to be decision-making meetings but will improve the quality of the discussions.

“Does this reduce the transparency of the organization? We want to be very much on guard that does not happen,” Altenbaumer said. “We want to ensure that in the forums where decisions are made that all stakeholders have the opportunity to participate. I think [meeting with] an outside resource in a smaller setting provides a greater quality of interaction.”

The new chairman, who took his position at the head of the table following April’s board meeting, said he was driven by the outcome of efforts to integrate the Mountain West Transmission Group. SPP received pushback late in the process from the RSC and members, who felt cut out of some of the earlier discussions.

The work to integrate Mountain West is officially ongoing, but most Western entities are now focused on securing reliability coordination services from SPP and CAISO with the pending shutdown of Peak Reliability. (See Peak Reliability to Wind Down Operations.)

“Despite a lot of effort and a ton of meetings [with Mountain West], I think we failed at effectively communicating with both the RSC and our members,” Altenbaumer said. “I had a lot of one-on-one interactions with members to address an issue. On many strategic issues, there is a variety of opinions on how those items need to be addressed. If we can facilitate a discussion with all members on the Members Committee, we’ll get a more robust discussion and up-front direction for all our stakeholder groups to address those issues.”

Altenbaumer said the organizational strategy should be determined by the board and Members Committee, but he remarked, “I don’t think we’ve always acted as owners of that strategy.” He said he prefers setting aside time to “discuss matters of strategic importance” in place of quarterly reports.

The chairman reassured the SPC that it is still the committee responsible for developing SPP’s strategic plan.

“This is where the technical expertise resides,” he said. “I hope there will be dialogue back and forth to ensure we’re discussing issues of strategic matters.”

Altenbaumer wants to eliminate the board’s June education session and the December meeting in which the board approves the budget. The December meeting would become a conference call.

He is also proposing the board delegate to the Markets and Operations Policy Committee decisions “that need not be brought to the board.”

SPC Takes No Action on Clean Energy Rule

The committee decided not to have SPP provide comments on EPA’s proposed Affordable Clean Energy (ACE) rule, determining there is little to be gained, but much to lose.

In explaining the ACE rule to the SPC, Vice President of Engineering Lanny Nickell said the rule is “less onerous” than the Obama administration’s Clean Power Plan, which required a 32% cut in emissions below 2005 levels by 2030.

SPP’s Lanny Nickell (r) discusses the proposed Affordable Clean Energy rule as Director Mark Crisson takes notes. | © *RTO Insider*

The ACE rule applies only to existing coal-fired plants and does not set a federal carbon-emission rate, requiring states to set unit-specific standards, Nickell said.

“From a reliability perspective, it’s a lot more flexible and easier to anticipate than output limitations,” he said.

Nickell conducted several CPP studies after its 2014 release. The final analysis indicated that a state-by-state compliance approach could result in nearly 40% higher costs than a regional approach.

Nickell said there is no reason for SPP to study the ACE rule’s “rate-based approach” or to issue a statement. “I don’t have any personal concerns about its reliability implications,” he said. EPA has issued an Oct. 31 deadline for public comments.

SPP Director Phyllis Bernard in discussion with Evergy’s Denise Buffington. | © *RTO Insider*

“We haven’t made a quantitative analysis” of the new rule, he pointed out. “It would be an opinion we are offering, what we think the implication of ACE would be. We would be making an opinion without a quantitative analysis.”

“I love you guys, but you’re thinking like electrical engineers rather than politicians,” said Director Phyllis Bernard, who has a strong background in administrative law. “Your opinion, while qualitative, is far superior from the opinion of someone out there who is putting out spin. You can make a difference. If you say nothing, the default position may go back to something you don’t want to hear. If you think something in the proposed rule is positive, you should say that.”

Several members urged SPP to rely on the facts — no reliability impact; the market is producing emission-reductions through the dispatch of cleaner fuels — and provide comments.

“If you don’t say anything, someone will go on the record and dictate the final rule,” said Basin Electric Power Cooperative’s Mike Risan.

“Once we say something, it invites questions,” Altenbaumer countered. “One of the first questions I would ask is, ‘How can you make that assertion if you haven’t done any studies?’ I don’t know why you go down that path if there are no benefits, other than a feel-good.”

Mike Ross, SPP’s senior vice president of government affairs and public relations and a six-term member of the U.S. House of Representatives for Arkansas, cautioned against going public with comments on the rule.

“If we’re not careful, we’re going to be labeled pro-environment or anti-environment, pro-coal or anti-coal, pro-Trump or anti-Trump. That’s not our job,” Ross said.

“Our job is to be fuel agnostic and let the markets choose the fuel source and to focus on reliability. The proposed rule by this administration is going to be adopted, whether we comment or not, and since it won’t impact reliability, I don’t think we should comment. It’ll be tied up in the courts for years. When we are trying to make decisions on 40- and 50-year assets, our country needs a national energy policy that transcends administrations and political parties.”

Asked whether the ISO/RTO Council has weighed in on the ACE, CEO Nick Brown noted that the industry group was silent on the CPP.

“It’s certainly not going to step up as a group and comment on this, as it doesn’t appear to have any impact on the bulk power system,” Brown said.

— Tom Kleckner

October 22, 2018

SPP Stakeholders Stop Work on Unreserved Tx Waiver

By Tom Kleckner

LITTLE ROCK, Ark. — SPP stakeholders last week directed the Seams Steering Committee to stop work on proposed Tariff changes that would have granted a waiver from charges for unreserved transmission use across the seams.

The Market and Operations Policy Committee’s action during its Oct. 16-17 meeting means SPP’s current practices for unreserved use will continue. They have resulted in about $23,000 in service charges since 2016, but only when that unreserved use is reported to the RTO.

The revision request (RR308) would have granted transmission customers a four-hour grace period for unreserved service during an unplanned transmission outage. SPP’s Tariff and its business practices do not allow exemptions for transmission customers using the RTO’s system to take transmission service because of outages, whether planned or unplanned.

The SSC was unable to reach a consensus during its monthslong discussions, with some members saying temporary use of interconnected systems should be a benefit and others calling for transmission owners to be compensated. The four-hour grace period was a compromise position.

“Several members thought the four-hour grace period was at least some justification to take this to FERC and stakeholders,” American Electric Power’s Jim Jacoby, chair of the SSC, told the MOPC. “It seemed to have at least some backing. From an AEP perspective, that’s a benefit of interconnected systems. We ought to give customers some time [to arrange service during an unplanned outage].”

SPP attorney Mike Riley | © *RTO Insider*

RR308 received little support from SPP’s legal department. Associate General Counsel Mike Riley pointed to excerpts from FERC Orders 890 and 890-A, which address situations where a customer is unaware of changing conditions that result in additional service requirements. Riley said FERC’s language does not exempt “any class of transmission customer from the potential assessment of unreserved use penalties” and refers to entities “serving native load in multiple control areas.”

“Not being a FERC commissioner, it’s hard to say what the [language] is intended to cover, but when I read words like ‘multiple control areas,’ that seems applicable to us,” said SPP’s David Kelley, director of seams and market design.

“If SPP and the stakeholders have a basis for filing and justifying this four-hour window, or grace period, we’ll absolutely file it,” Riley said. “But based on 890’s provisions, where FERC appears not to make a distinction between reserved use and unreserved use, we’ve got an uphill battle.”

Riley agreed with the concept of a grace period before assessing penalties, saying it should be a business practice in the Tariff.

“We just haven’t seen or found a justification that would get us over the 890/890-A hurdle, but it’s up to FERC,” he said.

Several members suggested SPP could conform its practices with those of MISO — which Southwestern Public Service’s Bill Grant said MISO does not apply unreserved charges in similar situations — through their joint operating agreement. But Kelley pointed out, “Even if we address this issue through the JOA, we’ll still have to make a filing at the commission. We still have to get around the hurdles of what we’re arguing.”

“This is not being applied consistently,” Grant said. “Only when SPP knows about it.”

“What we’re trying to do is address the unfortunate bystander that doesn’t know what’s going on, and only finds out about it when they get a bill,” AEP’s Richard Ross said.

On the sidelines, some members referred to the TOs who reported unreserved use as “tattletales.”

The MOPC’s motion passed over 10 opposing votes and five abstentions.

October 22, 2018

SPP Generator Interconnection Group Wraps up Work

By Tom Kleckner

LITTLE ROCK, Ark. — SPP members last week approved one of two Generator Interconnection Improvement Task Force recommendations but took no action on the second and agreed to disband the group.

The task force was formed last year to identify improvements in the RTO’s transmission study process, which is backlogged with more than 62 GW of interconnection requests. Its work will be carried on by various working groups.

The Market and Operations Policy Committee approved the GIITF’s suggestion to address generator interconnection studies in regions where the amounts of new generation being requested exceed load during spring and other light load periods.

SPP currently divides its footprint into cluster groups for individual study. In the high variable energy resource case, all VERs inside the cluster are set to 100% of capacity while external VERs are set to 20% to simulate counterflow to the internal generation.

With the increase in VERs, the amount of counterflow contained in the Integrated Transmission Planning models is high enough that the simulation is no longer needed, and the 20% setting has resulted in situations with insufficient load to absorb all the generation being requested. Under the new rules, the external VERs remain at the base reliability dispatch setting used in the ITP process.

“The changes here allow the energy to flow a further distance to a neighboring zone, which should identify [needed] transmission upgrades,” said Tradewind Energy’s Derek Sunderman.

Task force Chair Al Tamimi, of Sunflower Electric Power, said the change “might help us move forward with [definitive system impact studies].” Staff is working on study requests that date back to 2015.

OG&E’s Greg McAuley (right) states his position as AEP’s Richard Ross listens. | © *RTO Insider*

“That should tell us something,” Oklahoma Gas & Electric’s Greg McAuley said. “We’re dancing around the problem. We have too much generation coming in, and we have no place to put it.”

McAuley pointed out that the Holistic Integrated Tariff Team is also working on the problem. “We don’t know where they’re going to land,” he said.

The measure passed with six opposing votes, mostly from transmission owners, and 14 abstentions.

Members declined to take a vote on the GIITF’s recommendation to change the criteria for allocating network upgrade costs to interconnection customers by adding a new energy resource interconnection service (ERIS) criterion.

Under the proposal, SPP would have first allocated cost responsibility to requests with 20% or more of the generator’s output flowing across a constrained element, as under current practice.

After applying the 20% transfer distribution factor (TDF) test, the proposal would have added a second screening to determine which requests have at least a 5% TDF. If the number of such requests resulted in a cumulative TDF of 20% or more, a mitigation would be assigned to the cluster, with the cost allocated to those requests with at least a 5% TDF.

SPP said the change would have resulted in the identification of four additional constraints in the DISIS-2016-001 study.

But several members said the recommendation didn’t go far enough in identifying constraints caused by interconnection requests. Staff agreed the current process doesn’t catch enough constraints.

The committee also accepted a storage white paper for incorporation into SPP’s generator interconnection processes. The document describes proposed rules for processing and evaluating storage interconnection requests. Two members opposed the motion and three abstained.

October 22, 2018

Overheard at Storage East 2018

WASHINGTON — Infocast’s inaugural Storage East summit drew policymakers, grid operators, utilities and companies looking to break into energy storage to the Washington Plaza Hotel last week. Panelists discussed the optimism surrounding the industry, as well as strategies for locating resources and optimizing their services for maximizing returns.

Infocast’s inaugural Storage East summit was held at the Washington Plaza Hotel in D.C. on Oct. 16-17, 2018. | © *RTO Insider*

Here’s some of what we heard.

Chatterjee Touts FERC Orders

FERC Commissioner Neil Chatterjee delivers the keynote address of the conference. | © *RTO Insider*

FERC Commissioner Neil Chatterjee kicked things off by recalling actions the commission has taken on storage since he joined in August 2017. The highlight of these was the February issuance of Order 841, which directed RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets. (See FERC Rules to Boost Storage Role in Markets.)

When Chatterjee joined FERC as chairman, he restored the commission’s quorum, which it had been without for six months. He said he had expected to be able to vote on a final version of the commission’s November 2016 Notice of Proposed Rulemaking as soon as he walked in, but he found that staff were still working on “a number of complex, legal and technical issues.”

“Understanding the importance of what was at stake, during my tenure as chairman, I worked closely with staff to push that final rule forward,” he said proudly. “I believe in the potential for storage to be a transformative technology for our grid. Storage is a game-changer. I’ll admit it’s a bit cliche, but there’s truth to it.”

He also noted the importance of Order 845, which revised the commission’s pro forma large generator interconnection procedures and interconnection agreement. One of the 11 changes the commission approved was to include storage in the definition of “generating facility.” (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

Another change allows generators to sell their surplus interconnection capacity to other resources. Storage owners can purchase surplus capacity for their resources so they can interconnect without having to go through the full queue, Chatterjee said.

“While this change in policy sounds very wonky — and it is — I think it’s a subtle but important action we’ve taken to improve opportunities for storage development.”

Chatterjee also noted the challenges storage still faces. RTOs and ISOs face a Dec. 3 deadline for their Order 841 compliance filings. FERC is “likely to take several months” to review them, and any deficiencies it finds will delay implementation further, Chatterjee said.

He also said grid operators have been slow to develop new products to compensate storage resources for their different services.

“With the exception of PJM’s RegD product, there’s been little momentum toward expanding the traditional set of ancillary services in the past few years,” Chatterjee said. “The increasing penetration of renewables might provide additional momentum for such products, but in any event, whether and how these products come to fruition could have a significant effect on the opportunities for storage.”

Siting and Co-location

Multiple panelists discussed the best strategies for deciding where to develop storage resources.

energy storage east neil chatterjee — Michael Harrington, Utility of the Future department manager for Consolidated Edison | © *RTO Insider*

Storage can receive the federal investment tax credit when added to existing qualifying resources, mainly solar facilities. But Michael Harrington, of Consolidated Edison’s Utility of the Future department, pointed out that the New York State Energy Storage Roadmap, issued in June, predicted that more than half of the 1,500 MW of storage the state aims to procure by 2025 would be downstate, close to New York City’s load.

“We do think there’s opportunity with upstate renewables, but certainly we recognize that storage is going to follow where the economics are the best,” he said.

Ascend Analytics CEO Gary Dorris | © *RTO Insider*

Ascend Analytics CEO Gary Dorris explained why being near the city is so attractive for storage. The best way to determine where to site storage resources, he said, is finding where prices are most volatile: where congestion on the grid is most persistent.

Price spikes occur very infrequently on a typical New York node — only 1.5% of a 24-hour day — but they represent 22% of the average real-time energy price, according to Dorris. “So storage can be a wonderful physical hedge against price spikes, and that’s a real opportunity to mitigate uncertainty in supply by having that physical hedge in attacking those price spikes.”

“Co-located storage with renewables certainly has benefits, but is co-locating renewables with storage going to become standard practice?” Chatterjee posited. “The answer to that question could have major implications for storage. We have evidence that the cost-benefit ratio of co-located storage is tipping in favor of adding storage.”

He pointed to a 2017 resource solicitation by Xcel Energy’s Public Service Company of Colorado. While individual wind and solar resources received median offers of $18/MWh and $29 MWh, respectively (“amazing numbers in their own right”), wind and solar resources co-located with storage received a $3 and $7 premium.

“When you consider market incentives like … capacity constructs in PJM and ISO-NE, co-location could be extremely beneficial in allowing renewables to avoid performance penalties and take advantage of high prices,” he said.

Wish List from States, RTOs

Several speakers said grid operators and states could be doing more to value storage’s services.

In introducing a panel on innovative business models for storage, Dorris suggested that states should lower their property taxes for storage. Taxes are particularly high in the Northeast, where storage is most in demand. “That’s probably not being talked about as much as perhaps it could be given the nature of these projects,” he said.

The panelists focused on the lack of a “T&D benefit” in RTOs and ISOs, saying storage should be compensated for its congestion-reducing benefits as energy efficiency programs are. Such programs are valued in part for reducing the voltage levels on transmission and distribution lines, allowing transmission owners and utilities to defer costly upgrades.

“Just level the playing field between how you treat conservation and how you treat storage,” Dorris urged.

From left, Thomas Leyden, EDF Renewables; Adam Rousselle, Renewable Energy Aggregators; and Stephen Wemple, Consolidated Edison. | © *RTO Insider*

“As a developer, we need to have certainty, and we need to have predictability going forward,” said Thomas Leyden of EDF Renewables. “That’s not easy in a market-based system, but there are things that can be done to help our investors become more comfortable.”

Adam Rousselle, CEO of Renewable Energy Aggregators, went further. He noted that transmission owners get paid fixed rates of returns based on the value of their assets. “If we can not align the development of storage with the transmission owner, we won’t be building storage any time soon in PJM,” he said. “And if your solution delays their transmission investment, they’re competing with you, make no mistake about it.”

— Michael Brooks

October 22, 2018

Methane Tax Suggested to Reduce Emissions

By Rory D. Sweeney

PHILADELPHIA — Fugitive methane emissions might be reduced throughout the natural gas supply chain by making accidental leaks and routine venting part of the carbon markets being considered for the power industry, panelists told attendees Wednesday at a policy forum hosted by The Kleinman Center for Energy Policy at the University of Pennsylvania.

The key would be developing a market that taxes emitters but also pays those who capture emissions, as the technologies would also be useful for reducing methane emitted by nature — either as part of natural processes or negative feedback loops exacerbated by global climate change.

“If you can price greenhouse gas emissions and you put in that financial incentive for capturing it, and then whatever brilliant technology gets developed, it faces the right incentives and it has a financial ability to move forward,” said Catherine Hausman, an assistant professor of public policy at the University of Michigan. “The carbon tax, the flip of that is the subsidy or whatever for what gets captured.”

She suggested a policy, which she acknowledged has legal concerns, where every potential source of methane in a region would be responsible for a share of the area’s emissions unless it can prove it wasn’t the source. That would incentivize gas producers and pipelines to monitor their operations to prove themselves innocent.

The panelists weren’t afraid to promote increased governmental regulation.

“Tax the emission if you can. Absent a tax … you need regulations on the way they run. … I am totally happy with regulatory measures that are not market-based in situations where you can’t develop market-based solutions,” Hausman said. “I always teach that zero pollution is not the right answer because it stops all economic activity. Now, very aggressive action is certainly needed.”

“I would love to get to the place where methane emissions from the oil and gas industry are appropriately taxed. … Our view is we’re not there yet,” the Environmental Defense Fund’s Ben Ratner said. “Where we really want to get to over time is prevention. … There’s just no way around government action.”

Kleinman Center for Energy Policy methane tax carbon markets — From left, Environmental Defense Fund’s Ben Ratner, Catherine Hausman, assistant professor of public policy at the University of Michigan, and moderator Karen Goldberg, a chemistry professor at the University of Pennsylvania and the director of the Vagelos Institute for Energy Science and Technology. | *(c) RTO Insider*

Another challenge for developing a carbon market will be defining what values are used to determine payments. As hard as it is to nail down a valuation of carbon — the panelists noted suggestions from $40 to $400/ton — so too is calculating the amounts emitted. And while researchers can estimate global emissions, “knowing the precise location [of the source] is what’s hard,” Hausman said.

“You have to solve the measurement problem,” she said.

“There’s still so much uncertainty about global emissions … that we don’t know yet what [each source’s emissions limit] should be,” Ratner said.

Hausman suggested the key might be locating “super-emitters.”

The panelists also criticized the Trump administration for attempting to reverse regulations on methane emissions in the oil and gas industry. The Clean Air Act’s procedural rules barred the Obama administration from expanding its more stringent regulations for new and modified facilities to existing facilities, Ratner said.

The hope was for the next administration to make that expansion, he said. But “not only is this new administration not doing that, it seems to be intent to roll back” the Obama revisions, he said.