WESTBOROUGH, Mass. — The Trump administration’s push to roll back environmental protections has prompted state leaders to recommit to achieving clean energy goals and inspired a surge in grassroots support for measures to tackle climate change, New England environmental and energy experts said last week.
The administration’s “radical agenda on environmental rules has galvanized public opposition,” as well as “created huge morale problems” within EPA, said Melissa Hoffer, chief of the Environmental and Energy Bureau for the Massachusetts attorney general’s office.
Hoffer made her remarks at the Northeast Energy and Commerce Association’s Environmental Conference on Thursday.
Even the Republican-led Congress did not go along with President Trump’s vision to slash EPA’s budget, instead increasing the agency’s funding this year by $760 million, said Normandeau Associates’ Bob Varney, a former EPA regional administrator for New England.
Following the U.S. decision last June to pull out of the Paris Agreement, environmentalists feared a “spiraling ripple effect” discouraging other nations from honoring the pledge to reduce emissions 20 to 26% below 2001 levels, “but that hasn’t happened,” said Ken Kimmell, president of the Union of Concerned Scientists.
The governors of several large states, including California and New York, joined together to commit to honoring the Paris Agreement, supported by mayors and corporate CEOs, which perhaps explains why other nations did not react too negatively to the U.S. pullout, Kimmell said.
Race to the Bottom
Varney noted what EPA calls “‘getting back to basics,’ with a focus on the agency’s core mission, restoring power to the states through cooperative federalism, and improving permitting and clean-up processes while adhering to the rule of law, according to the administrator in his comments.”
But Hoffer said EPA Administrator Scott Pruitt’s “notion of cooperative federalism is somewhat flexible and it invites a deregulatory race to the bottom. This is exactly what the primary federal environmental statutes were designed to avoid.”
Kimmell joked that after the 2016 election, “we changed our name to the Union of Freaking Out Scientists, known as UFO.”
He listed the agency’s big three regulatory rollbacks: the “evisceration” of the Clean Power Plan, the elimination of rules requiring oil and gas operators to trap methane and, “perhaps most distressing of all,” the reduction of the Obama-era fuel economy standards.
Hoffer said the administration’s “cavalier approach to the rollbacks that took place during the first 15 months is really not serving them well in the courts. They actually don’t have a good command of administrative law, and they don’t have a good command of federal environmental statutes, so that has caused some difficulty for them.”
She said, however, that the administration may be learning from its mistakes, as they’ve recruited some new experts. “I would expect that we’ll see their game upped tremendously over the course of the next couple of months,” Hoffer said.
Olivia Campbell Andersen, executive director of Renewable Energy Vermont, said state leadership has proven more significant for the growth of renewable energy than federal policy.
“If it weren’t for state provisions like net metering, if it weren’t for state renewable portfolio standards, we would not have seen the growth that we have had to this point,” she said.
“Climate change is already happening and we’re already seeing the impacts, including hotter days,” said Richard McGuinness, deputy director for waterfront planning at the Boston Planning and Development Agency.
The agency commissioned the Climate Ready Boston initiative focused on climate change, the first citywide plan for Boston in 60 years, he said.
“Heat island effect, extreme precipitation events and sea-level rise are the greatest risks to our coastal communities,” McGuinness said. “We are planning for a 36-inch sea-level rise and rounding it up to 40 inches to account for subsidence … we’re not planning on retreating.”
The worst-case scenario for coastal flooding in Boston would affect 85,000 people and damage 12,000 buildings worth about $85 billion, he said.
Grover Fugate, executive director of the Rhode Island Coastal Resources Management Council, said, “The brunt of climate change effects will fall on local communities, the ones with the least resources to deal with them.”
He complained that the Federal Emergency Management Agency makes planning assumptions that do not match Rhode Island conditions, resulting in post-storm dune profiles larger than the state’s dunes are before any storm. Fugate said his agency bases its sea-level estimates for the year 2100 on data from a 2017 report by the National Oceanic and Atmospheric Administration, which describes sea-level rise scenarios for the U.S.
For the Newport tide gauge, the figure is “essentially 9.6 feet by 2100 or essentially 10 feet,” Fugate said. “We also throw on a high-tide event, extreme high tide, which we see six to eight times a year, that will raise the tidal elevation 1.5 to 2 feet above normal tide, so we now have incorporated a 12-foot layer in our mapping system.”
The sleeper issue is groundwater rise compounded by sea-level rise, causing septic systems to fail and damaging local roads, he said.
“If you build today … potentially, within the 30-year mortgage period, that house will be below base-flood elevation.”
Thomas Murray, vice president for customers and communities at Vermont Gas Systems, said he learned that a large project can be incredibly more complex than a small one, and that it’s important to avoid “utility arrogance” and respect the views of project opponents.
“People see stopping our project [the 41-mile Addison Natural Gas Project] as a symbolic way to stop climate change,” Murray said.
“In fact, what may happen, the unintended consequence, is that they continue to burn dirtier fossil fuel, they continue to burn oil,” Murray said. “Vermont has the smallest natural gas footprint in the country, next to Hawaii, and we have the largest percentage of people that are burning heating oil.”
James Grasso, CEO of public relations firm Grasso Associates, noted that Brookline, Mass., residents voted 61% in favor of legalizing recreational marijuana, but they refused to have it sold in the town.
Emily Norton, chapter director of the Massachusetts Sierra Club, and a member of the Newton, Mass., City Council, said the council voted against solar parking canopies at the public library because the panels were too ugly.
“When people do get involved, they jump right into it, and they don’t understand how state or federal or local laws and regulations work,” said Heidi Ricci, assistant director of advocacy at Mass Audubon. “Most people don’t know where their water comes from when they turn on their tap. I think there’s a basic public education problem here as well as a civic engagement problem.
“People latch on to the one project that they’re concerned about that they oppose … but who’s looking at the big picture?” she said. “I’ve talked with the big gas pipeline opponents about, so, like what are we going to do? Will you work with us on getting some of these offshore wind projects going? It’s really hard to get people engaged in larger-picture planning.”
KANSAS CITY, Mo. — SPP officials were questioned at last week’s Markets and Operations Policy Committee meeting as to why the Holistic Integrated Tariff Team was created and approved behind closed doors in March.
The Board of Directors approved the team’s creation during the same executive session at Dallas/Fort Worth International Airport where it approved a set of policy recommendations to guide the Mountain West Transmission Group’s pending membership into SPP. (See SPP Begins Work of Integrating Mountain West.) Some stakeholders have taken to calling the team the “HITT squad.”
“Some of us didn’t hear the discussion about how the board thinks about this, or how it went about populating it and how the different entities were selected on it,” said The Wind Coalition’s Steve Gaw.
SPP Legal Counsel Paul Suskie, who is serving as the HITT’s staff secretary, said the team’s formation was presented to the board as a recommendation from staff, with the addition of “a couple of other people who could help out.”
“Honestly, it was a matter of getting it moving sooner rather than later,” Suskie said.
The team, comprising directors, regulators, staff and stakeholders, is charged with developing a set of high-level recommendations addressing the challenges facing SPP’s footprint. It is expected to complete its work with a written report by April 2019. (See SPP Team to Take ‘Holistic’ Look at Processes.)
“My point is, this did not need to be done in closed session,” Gaw said. “Stakeholders could have given some input to the board. This is a huge strategic undertaking.”
He said much of the HITT’s work will be dedicated to issues affecting renewable energy and noted that only one of the 16 team members is “related to those particular interests.”
“We would like to have had some degree of feedback to the board in open session,” Gaw said.
“All due respect, Steve, do you really believe we would have started down this road without stakeholder input?” responded SPP Director Julian Brix. “Someone had to make this decision. The board signed on to this because it said it would like a reasonable way to get answers to strategy questions we’ve had for some time. It will be an open process down the road. You’ve got to have a starting point, and this was it.”
SPP Vice President of Engineering Lanny Nickell reminded Gaw and the MOPC that the Strategic Planning Committee discussed creating such a group during a lengthy discussion in January. (See “Energy-only Resources Report Leads to Discussion, not Results,” SPP Strategic Planning Committee Briefs.)
“That’s really where we got started in identifying those interested in participating,” Nickell said.
SPP has proposed that most HITT meetings be held face to face, with stakeholders not on the team “encourage[d]” to participate by dialing in, unless they are presenting to the team in person. Those not on the team are also encouraged to ask questions and suggest future topics for the team to evaluate.
Staff has scheduled nine meetings for the HITT through Dec. 5. Two of those will follow the April and July board meetings, giving non-team members a chance to attend.
KANSAS CITY, Mo. — SPP’s Markets and Operations Policy Committee endorsed a rule change to address member concerns that the Integrated Transmission Planning (ITP) Manual doesn’t appropriately capture purchase power agreement (PPA) pricing in the adjusted production cost-benefit metric.
RR276 removes the PPA pricing from the variable operations and maintenance (VOM) methodology language in the ITP Manual and replaces it with a VOM cost of $0/MWh for all wind and solar units. The Economic Studies Working Group (ESWG) had proposed a VOM cost of $8/MWh but revised the number following stakeholder discussion.
The ESWG said RR276 better captures the “benefits of incremental transmission investment when reducing economic curtailment or congestion costs associated with transmission customer purchases from renewable generation resources under ‘take or pay’ power purchase agreements.”
The MMU said the zero VOM cost is a “much closer reflection” to the actual number based on its review of all mitigated offers resources have applied for in the SPP market.
“We were sort of surprised to see a number that high,” Collins said referencing the $8/MWh proposal. “It does not in any away affect the bottom prices we have on file. Zero is more reflective of the true number.”
The Nebraska Public Power District’s Tim Owens, the ESWG’s vice chair, said the revision request is necessary as the 2019 planning cycle begins. He said it is an interim solution to objections over proxy PPA pricing, and the group will continue to work with staff on improving the economic studies process.
“We are trying to address this one particular input,” Owens said. “We fully understand that this is not the end-all assumption. Setting it to zero or eight won’t in and of itself address all of these other issues. We’re just focusing on what we’re going to do for the 2019 ITP assessment.”
“I see the benefits of a zero VOM, but my major concern is fixing the process,” said Southwestern Public Service’s Bill Grant.
The measure cleared the two-thirds approval threshold at 68.3% in a roll-call vote. Transmission-using members (TUs) voted 36-7 in favor of the revision, overcoming a 9-8 split by transmission owners.
Members Hash out Charter Revisions by Working Groups
Members revised and endorsed a Transmission Working Group (TWG) charter revision to increase its membership, proposing that the group include all TOs and an equal number of TUs.
The TWG had proposed increasing its membership from 24 members to 26, with no more than 14 TOs or TUs at any one time. Several members expressed concerns about the group handling compliance issues without representation of all 17 TOs.
“It’s very important that the votes presented to MOPC are reflective of the full membership, and that MOPC has that guidance when they vote,” Grant said. “You don’t want the unintended consequences because of what that one person could come up with.”
Sunflower Electric Power Cooperative’s Al Tamimi pointed out his company is one of the TOs currently excluded from the TWG. “If I don’t get a seat, I don’t want this group handling compliance matters,” he said.
Other members pushed back against the membership expansion.
“If we’re going to do this for the TWG, what other groups now can be expanding their membership?” asked Oklahoma Gas & Electric’s Greg McAuley. “With the Mountain West coming with another potential 10 TOs, this group is going to be enormous. I don’t know what you’re going to get done.”
TWG Chair Travis Hyde, of OG&E, said the group’s proposal was a compromise as it tried to seat all 17 of the TOs listed under SPP’s bylaws. He said the TWG has tried to maintain a balance between TOs and TUs but has realized its attempt was becoming unwieldy.
“If we did, we’d get to [34],” Hyde said. “That’s too big for a technical group like we are.”
SPP COO Carl Monroe said the RTO’s bylaws require all stakeholder groups to be balanced, “unless your charters are accepted with some other requirement.” He said the organization uses TOs and TUs as “shortcuts,” in the absence of member-type definitions in the bylaws, but recommended the groups change their governing documents if they disagree with the shortcuts.
“You can change the charter, but all these changes have to go through the Corporate Governance Committee,” he said. “If we had half this many people in a room trying to make the decision, we wouldn’t have the issues we do as the MOPC together.”
Kansas City Power & Light’s Denise Buffington, a member of the CGC, clarified Monroe’s comments. “The bylaws don’t explicitly say stakeholder groups should be balanced. That’s just the way it’s always been interpreted,” she said.
The MOPC also endorsed a change to the charter of the Regional Tariff Working Group that gives all TOs representation, with an “up to” equal number of TUs. The RTWG said it has a longstanding policy that all TOs be represented, as their facilities are under SPP’s functional control “for the provision of transmission service, planning, interconnections and recovery of revenue requirements.”
Members did strike a provision that would have limited members with affiliated relationships to a single vote on the RTWG.
“I am opposed to putting affiliate restrictions in any charter. They’re not in any other charter,” Buffington said. “What I fear is you put the restriction in one charter, then everyone is going to come here and ask for similar language.”
Monroe suggested it would be worth the governance committee’s time to discuss affiliate restrictions and the number of working group members.
“It’s not the number of people, it’s the chair getting organized and ensuring people express their opinions,” he said.
The MOPC also approved modifications to the Model Development Working Group’s (MDWG) charter. The stakeholder group said the changes reflect current practices and adds references to assignments from the TWG, MOPC and Board of Directors and the development of models for reliability standard TPL-007-1 (Transmission System Planned Performance During Geomagnetic Disturbances).
The MDWG reports to the TWG and is responsible for the coordination, development and maintenance of SPP’s transmission system planning models.
OG&E Raises Concerns over Third-party Tx Line Upgrade
Members voted to table a sponsored upgrade of an OG&E transmission line in northern Oklahoma, accepting the utility’s request to give it more time to work out legal issues.
The work would be sponsored by EDF Renewable Energy, which wants to upgrade terminal equipment and rebuild an 11-mile, 138-kV line near Ponca City and its 154-MW Rock Falls wind farm, which became operational in December. EDF has said it will seek cost recovery through SPP’s Attachment Z2 revenue crediting or incremental long-term congestion rights.
EDF presented the project to the TWG under SPP’s new transmission planning process. The TWG approved the project in March after determining there wasn’t a reliability impact. SPP Vice President of Engineering Lanny Nickell told members he was unsure whether the upgrade has ever been studied as an economic project in previous RTO planning studies.
OG&E pushed back against the project, saying it has engaged outside legal counsel to understand the consequences of having a third party pay to rebuild a line. McAuley noted his company is already recovering costs on the line through an annual transmission revenue requirement, but it is unclear what will happen to its depreciation or how to expense additional maintenance costs following the rebuild.
“At first blush, someone comes in and says they want to rebuild a line, you say, ‘Fine. What’s the big deal?’ That’s probably what the TWG said,” McAuley said. “We have an existing line with an ATRR that’s recovering revenue. What happens to that? This has opened up a broader set of legal questions we don’t have answers to yet.”
EDF did not have a representative in the room to participate in the lengthy discussion, but the company’s transmission strategy director, Omar Martino, was eventually patched in to answer questions. He said EDF understood the region is facing congestion issues, but that no one had committed to the upgrade.
“To the extent we can alleviate congestion and protect ourselves from congestion pricing, the upgrade would provide sufficient relief for the wind farm,” Martino said. EDF hopes to see the upgrade in place by June 2019.
“Bottom line, we have a whole lot of questions and not many answers,” McAuley said, suggesting a revision request be drafted if SPP’s Tariff doesn’t supply enough guidance. “I think it is precedent setting, and we might want to take a little bit longer look at it.”
SPP determined that while the vote was to determine MOPC’s endorsement, RTO staff still have the responsibility to bring the proposal to the Board of Directors for its approval. In the meantime, OG&E’s counsel will meet with SPP’s legal staff to resolve its questions.
Six members voted against tabling the proposal and two abstained.
Members did endorse a second sponsored upgrade, the addition by City Utilities of Springfield of a second 161/69-kV transformer at its James River Power Station. The upgrade has a June in-service date.
Members Approve Three-Stage Process for GI Requests
Members easily approved a task force’s white paper that overhauls SPP’s process for handling generator interconnection requests. BP Wind Energy North America abstained from the vote.
The Generator Interconnection Improvement Task Force’s (GIITF) paper outlines a three-stage process comprising a thermal and voltage analysis, dynamic stability and short-circuit analysis, and a facilities study.
| SPP
An increasing security deposit is required before each step, beginning at $2,000/MW and escalating to 10% and 20% of allocated upgrade costs, respectively. A decision period follows each stage, allowing transmission customers to determine whether to proceed to the next step following receipt of study reports.
The GIITF’s work replaces the current convoluted process, which involves feasibility, interconnection and system impact, and facilities studies, bidirectional work flows, and mandatory and optional steps.
Tamimi, the task force’s chair, said the simplified process will be easier for SPP to administer and for customers to understand and navigate. He said most upgrades will be identified in the first stage, allowing customers to make informed decisions before committing to a lengthy and expensive stability analysis.
Tying financial security to upgrade cost allocation will encourage customers to weigh the risks of proceeding at an earlier stage, reducing the number of requests that are withdrawn late in the process, Tamimi said.
The task force was created early last year to address SPP’s overloaded interconnection queue and requirements that could emerge from a rulemaking FERC opened in December 2016 to consider changes to its pro forma large generator interconnection procedures (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)
The commission has not approved any changes in the rulemaking. Earlier this month, however, FERC staff conducted a two-day technical conference to examine how SPP, PJM and MISO coordinate interconnection studies on projects near their seams, after the commission said their practices may not be just and reasonable. (See Developers, Tx Providers Seek Direction on ‘Affected Systems’.)
The MOPC in 2017 granted the task force a one-year extension to develop a replacement for SPP’s current interconnection process.
Ciesiel Delivers Final SPP RE Report
Members gave Regional Entity President Ron Ciesiel a round of applause following what may have been his last update to the MOPC.
SPP’s RE has been dissolved and is in the process of transitioning its data and responsibilities to the Midwest Reliability Organization and SERC Reliability, where its 122 registered entities have been reassigned. (See NERC Board Approves Dissolving SPP Regional Entity.)
Ciesiel said he hopes to complete the work by July. He said 10 of the 17 remaining RE employees have found jobs within the RTO or elsewhere, noting cybersecurity personnel are “in great demand.” Two others have decided to retire.
McAuley complimented Ciesiel and his staff on their work, saying, “While we didn’t always agree with the audits, they were done well.”
Tx Planning Improvement Task Force Delivers Final Work
The Transmission Planning Improvement Task Force wrapped up three years of work by winning the MOPC’s unanimous endorsement of its 20-Year Assessment Manual, which now goes to the board for its final approval.
The assessment is intended to develop an extra high voltage (300 kV and above) transmission road map for the SPP region, with candidate projects helping inform shorter-term planning assessments. According to the manual, “The assessment will result in the identification of projects that economically deliver energy within the SPP region while addressing a reasonable range of future industry uncertainty.”
The manual lays out roles and responsibilities within the 20-year assessment, study process and data inputs. The manual has been approved by the task force, the TWG and the Economic Studies Working Group.
Unanimous Consent Agenda Includes 9 RRs
Members unanimously approved the consent agenda, which included the re-baselining of a Nebraska Public Power District 69- and 161-kV project, from $37.8 million to $27.5 million; removing OG&E remedial action schemes at the Centennial and Crossroads wind farms; and nine revision requests:
GIITF RR267: Eliminates the “standalone scenario,” which considers each interconnection request by itself, from the definitive interconnection system impact study process. This will free SPP resources to focus on the binding cluster study results, permitting results to be available earlier than they currently are. Staff will provide the standalone equivalent study models through existing confidentiality provisions to customers seeking to conduct a stand-alone scenario of their own.
MWG RR252: Assigns an out-of-merit energy (OOME) cap and/or floor, allowing staff to economically dispatch the resource down or up within the ranges.
MWG RR259: Modifies the market settlement posting and dispute timelines being implemented with the new settlement system, reducing the number of resettlement postings and manual processes resulting from revisions to meter and bilateral settlement schedules.
MWG RR273: Automates several the market settlement system’s charge types that are not yet part of revenue neutrality uplift processing, resulting in rounding/residual amounts that must be manually processed and distributed through miscellaneous charges. The new system is scheduled to go live in May 2019.
MWG RR280: Clarifies the settlement system’s reserve sharing group (RSG) processing by modifying the RtImpExp5minQty field with an attribute indicating whether the import/export quantity was because of an RSG event.
ORWG RR268: Clarifies or removes outdated language from the operating criteria, improving SPP’s ability to perform reliability coordinator, balancing authority, transmission service provider and reserve sharing group functions.
ORWG RR269: Clarifies language and removes antiquated and redundant language in SPP’s operating criteria and describes the existence of multiple standalone documents.
ORWG RR270: Converts the operating criteria Appendix OP-2 to a standalone document, clarifies language and adds formatting improvements.
PCWG RR255: Revises business practice 7060 by adding triggers to stop the annual escalation of undefined baseline costs when a designated TO provides 1) SPP a letter of commercial operation, 2) notification that an upgrade is in-service, and 3) notification that an upgrade is complete.
KANSAS CITY, Mo. — SPP’s Markets and Operations Policy Committee last week failed to endorse a revision request that would have required non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.
The Market Working Group’s (MWG) recommended revision request (RR272) will likely be appealed to the Board of Directors for its April 24 meeting.
A roll-call vote resulted in 62.3% of members favoring the measure, short of the necessary two-thirds majority. Transmission-owning members Western Farmers Electric Cooperative and Westar Energy, last in alphabetical order, cast the final two votes opposing the change to seal its fate, at least temporarily.
“I’m not saying I’m going to submit one, but I have a feeling there will be [an appeal],” said American Electric Power’s Richard Ross, who chairs the MWG.
NDVERs converting to DVERs would need to ensure they have the proper communication systems in place and the technical capabilities to reduce their output.
Ross said the Tariff change will increase market efficiency through the reduction of manual out-of-merit energy orders to mitigate constraints. The addition of dispatchable resources will only increase reliability, he said.
“Any time you’re taking actions out of market, you are creating inefficiencies,” said SPP’s David Kelley.
The Market Monitoring Unit expressed strong support for the Tariff change, saying it would help reverse the recent growth of negative real-time pricing. The Monitor’s recent quarterly report noted the frequency of intervals experiencing negative prices increased from 2.6% in 2015 to 7% through November 2017. (See SPP Market Monitor: Negative Prices May Require Rule Changes.)
“Negative pricing is a significant issue in our market,” MMU Executive Director Keith Collins reminded members. “Something that increases flexibility is at a premium, which we will highlight in our next report. Having non-dispatchable resources becoming dispatchable is an important piece of that recommendation.”
Collins said an SPP operations study revealed that “the more flexibility you have, you end up increasing [energy market] pricing” by reducing the magnitude of negative prices.
“All resources will benefit from that change, which will allow the integration of more and more variable resources in the system,” he said.
But Westar said the change would hurt SPP’s “market reputation.”
“NDVERs were a condition of several [market participants] agreeing to transition from [the Energy Imbalance Service to the Integrated Marketplace],” the company said in written comments. “If we go back on our word, will other [market participants] lose confidence in the stability of SPP tariff grandfathering and agreements made to prospective balancing authorities, asset owners and market participants considering the benefits of [joining] SPP as a stable settlement and market platform?”
Members accepted a friendly amendment to the revision, extending the registration deadline to January 2021.
The revision request exempts about 2,000 MW of resources without direct interconnection agreements with SPP or registered as qualifying facilities under the Public Utility Regulatory Policies Act. That drew concerns from members over whether Mountain West Transmission Group entities would be able to acquire similar exceptions.
“If the current language excludes those, it does appear to leave questions about those who joined SPP with a previous interconnection agreement, but not one with SPP,” said The Wind Coalition’s Steve Gaw. “Will they have to comply with this [requirement], or does the language exempt them, including the generators in the Mountain West region?”
“That’s exactly right,” said Oklahoma Gas & Electric’s David Kays. “When you’re being prospective about anyone coming in afterwards … I think it creates a hole in the Tariff, and I’m not sure that’s something we should be doing intentionally.”
Ross said there is no specific provision to carve out the Mountain West entities. “They’ll have to be prepared to comply with these requirements when they’re integrated into the SPP system,” he said. The MWG fashioned the change so that “anyone who wants an exception can make a [Federal Power Act Section] 200-whatever filing from that [requirement] at FERC,” he added.
Kelley pointed out that ISO-NE and CAISO have gone through similar conversions. He said the revision would help a grid that has “grown exponentially in size” with new wind resources and continues to hit new wind-penetration peaks.
“I go back to the overall problems we’re trying to address, which is overall market efficiency and reliability,” Kelley said. “When you hit those [constrained] situations, it’s imperative that the operators and markets have the tools to make the most efficient decisions on a systematic basis, rather than take out-of-market actions.”
The vote followed one of several vigorous discussions that livened up what staff and members had expected to be a perfunctory MOPC meeting.
“If you’re not careful, you’ll have an MWG meeting break out,” Ross joked.
FOLSOM, Calif. — At its first public meeting with potential customers of its reliability coordinator (RC) services Thursday, CAISO divulged that most of the load in the West has signed letters of intent for the new program.
In response to a question, CAISO Regional Integration Director Phil Pettingill said he could not say publicly who has signed letters of intent and nondisclosure agreements to receive RC services.
“What I feel like I can say is, most of the load that is in the Western Interconnection has signed those agreements with us,” Pettingill said. “We are really talking to almost everybody.”
He added that the letters of intent are not binding and can be withdrawn. The notifications that have been sent to Peak Reliability from customers planning to depart its RC program are also nonbinding.
NERC’s reliability standards require balancing authorities and transmission operators to procure RC services, which include outage coordination, real-time situation awareness, and system restoration coordination and training.
CAISO on April 5 issued its initial proposal for RC services, which it hopes to have running by May 2019. The ISO and Peak are also developing competing proposals for new energy markets that could develop into a full RTO. (See Multiple Entities, Markets Now Beckon in West.)
CAISO is now developing prices for its supplemental, non-core RC services, such as hosting advanced applications and addressing certain critical infrastructure protection services, Pettingill said in a presentation.
The ISO says its RC services will be much cheaper than Peak’s, but Peak countered that the comparison is not straightforward because Peak has more RC experience and offers certain customer services such as the WECC Interchange Tool, the Enhanced Curtailment Calculator and the Peak Synchrophasor Project. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)
In developing the RC services, the ISO will issue straw proposals and gather feedback to revise the initiatives. The final proposal will be subject to approval by the Board of Governors and FERC.
CAISO hopes for the commission’s approval in October.
The goal is for potential RC customers to export their network models by August and begin data integration and system verification in January 2019. RC service agreements would be executed in November with much of the integration and testing occurring next year, Pettingill said.
CAISO will use its “activity-based costing system,” which has been used for all rate design initiatives since 2011, to determine the costs of RC services.
About 6% of CAISO’s annual costs would be allocated to RC services in the revenue requirement for 2019 and 2020 rates, CAISO CFO and Treasurer Ryan Seghesio said Thursday.
“The ISO is committed to a really level, stable revenue requirement,” Seghesio said. CAISO’s revenue requirement of $190 million to $200 million has been stable for about 11 years. There is a FERC-approved $202 million cap on the revenue requirement, he said, to prevent surprises for market participants.
The California Public Utilities Commission will vote later this month on a $98 million settlement agreement regarding its own improper communications with Pacific Gas and Electric related to the fatal 2010 San Bruno gas pipeline explosion and other matters.
The commission will vote April 26 on the proposed decision of Administrative Law Judge Robert Mason regarding ex parte communications with PG&E after the company’s San Bruno pipeline exploded and killed eight people, as well as seven other proceedings.
The five CPUC members that will vote on the agreement April 26 were not involved with the improper communications several years ago. The parties listed on the settlement include PG&E, the city of San Bruno, The Utility Reform Network (TURN), city of San Carlos, and the CPUC’s Office of Ratepayer Advocates and Safety and Enforcement Division.
But the agreement does not close the San Bruno ex parte matter, instead kicking off a new proceeding to explore additional archived emails that PG&E provided to the CPUC in September 2017 that rocked the yearslong settlement process. (See Probe Reveals More CPUC-PG&E Contacts on Pipeline Blast.)
“This proceeding shall remain open to consider whether PG&E’s newly disclosed email communications violate the commission’s ex parte rules and should result in the imposition of additional fines,” the settlement says.
PG&E said the new batch of emails it submitted to the CPUC last September in the ex parte proceeding were “a recent development” from an unrelated government agency inquiry. The utility said that while the emails dating from 2013 and 2014 were new, “their general nature is not new.”
The “unrelated government agency inquiry” that PG&E referred to appears to be a concurrent investigation into former CPUC Commissioner Susan P. Kennedy that directed her to provide the California Fair Political Practices Commission with communications from 2012 to 2017. The investigation sought communications between the PUC and Kennedy and others at her company, Caliber Strategies, that mention PG&E and legal, legislative or regulatory actions regarding the San Bruno explosion, as well as other matters.
PG&E will pay these penalties under the current terms of the settlement | CPUC
That CFPPC investigation led to a $32,000 fine against Kennedy in February for unreported lobbying for ride-sharing company Lyft and San Gabriel Valley Water Co., an investor-owned public water utility, but the CFPPC decision did not mention any communications with PG&E. (See Former CPUC Member Fined for Lobbying Violations.)
Kennedy was chief of staff for former Gov. Arnold Schwarzenegger, deputy chief of staff and cabinet secretary for former Gov. Gray Davis and previously communications director for U.S. Sen. Dianne Feinstein. She is also founder of Advanced Microgrid Solutions (AMS), a prominent California energy storage company whose investors include Schwarzenegger.
TURN was successful in pressuring the CPUC to consider the emails submitted by PG&E in September separately from the agreement to be voted on this month, rather than lumping them together with the previous violations. But TURN spokeswoman Mindy Spatt told RTO Insider last week that the provisions could still be changed in PG&E’s favor before April 26. Still, she said the settlement “looks pretty good from our perspective.”
The CPUC said the settlement agreement “has, to a great extent, put an end to years of disputes … that has spanned at least nine separate proceedings following the San Bruno tragedy.”
Settlement Mentions Ferron, Florio, Peevey
The new settlement document describes some of the ex parte communications at issue, including an email from PG&E consultant Jerry Hallisey to then-PG&E Vice President Brian Cherry in September 2011. The email described a meeting with then-CPUC Commissioner Mark Ferron to discuss support for a gas pipeline project and cost-splitting between shareholders and ratepayers. Ferron served on the CPUC from 2011 to 2014 and is now a member of the CAISO Board of Governors.
Also listed is a November 2011 email from Hallisey to Cherry and others that described meetings with former CPUC Commissioner Mike Florio, now a private consultant, regarding cost recovery and pipelines.
It also lists an email from Kennedy to Cherry that summarized a meeting with former CPUC Chair Michael Peevey and Kennedy regarding “an independent forensics analysis.” A Jan. 1, 2013, email from Cherry to PG&E Senior Vice President Thomas Bottorff described Cherry’s meeting with Peevey regarding gas settlement mediation and return on equity changes, among other exchanges.
In a separate matter, Peevey’s unreported ex parte communications with Southern California Edison during negotiations of the San Onofre nuclear plant closure led to a reworking of the $4.7 billion deal. (See CPUC Orders Renegotiation of San Onofre Settlement.) Peevey resigned from the CPUC at the end of 2014.
FERC last week approved MISO’s proposal to shorten the window of time it allows generation owners to alter estimated capacity volumes for projects in the interconnection queue.
The commission’s decision clears MISO to require interconnection customers to finalize their requested network resource interconnection service (NRIS) megawatt values during “Decision Point II” — roughly 200 days into the queue (ER18-835). The revision became effective April 11.
FERC said requiring a final figure earlier in the process should help MISO achieve its goal of reducing unscheduled queue restudies in order to cut down on the number of months projects spend in the queue.
“MISO’s current proposal is a modification to further streamline its interconnection process and to prevent unscheduled, ad hoc restudies late in the interconnection process. We agree with MISO that unscheduled restudies will be less likely under the timeline established by MISO’s proposal,” FERC said.
The RTO’s previous process allowed interconnection customers to revise their requested level of NRIS up until after the final system impact study of the definitive planning phase of the queue.
MidAmerican Energy protested the change, saying that MISO and neighboring balancing authorities often do not complete affected-system studies on each other’s territories in time for Decision Point II, making an informed decision on NRIS levels impossible. But FERC ruled MidAmerican’s argument was underdeveloped and that “the benefits of reducing the potential for restudies and keeping the queue process on schedule outweigh MidAmerican’s concerns about potentially having less information at the earlier decision point.”
NEW YORK — Hundreds of investors, utility executives and others gathered last week for Bloomberg New Energy Finance’s Future of Energy Summit, where electric vehicles, energy storage and renewables dominated discussions. Here’s some highlights.
Robert Murray has been trying for more than a year to persuade President Trump and Energy Secretary Rick Perry to provide subsidies for the utilities that buy Murray Energy’s coal. (See Photos Show Murray’s Role in Perry Coal NOPR.)
Last week, he took his message — that the grid cannot be resilient without coal generation — to a skeptical audience at the BNEF conference.
“I’m probably the only coal guy in the room. I’m also an American,” he said, pausing to gather his composure after tearing up. “The recent polar vortex shows our grid is not as reliable as grid operators would like you to believe.”
Murray criticized FERC for rejecting Perry’s proposal to subsidize coal and nuclear plants with onsite fuel and said Perry should approve FirstEnergy’s request for an emergency declaration to protect coal plants. (See Perry Hints DOE Won’t Grant FES ‘Emergency’ Request.)
The declaration “has to be [made] or we’re going to have a disaster. … Will we have to have a system collapse before recognizing that something has to be done about the security, resiliency and reliability of the power grid?” he asked. “Barely one-half of [remaining coal] plants generate enough revenue to cover their expenses. There has to be a capacity payment there.”
Lynn Doan, head of power and renewables for Bloomberg News, asked Murray about reports by NERC and others that some coal plants were unable to run during recent cold spells because of frozen coal piles. “Did not happen ma’am,” he insisted.
“The poorest 25 million families in this country are putting out 31% of their income for energy — gasoline, oil and electricity,” he continued. “We have an energy poverty problem in this country. We don’t have a global warming problem.
“All of you are building your businesses around climate change. The best thing that could happen is overturning the [EPA’s CO2] endangerment finding — that artificial thing that has put political correctness ahead of getting the lowest-cost electricity for the people on fixed income, for that single mom, for that manufacturer.”
Power Markets Under Stress
Although most of the conference focused on advances in renewable technologies, there was some discussion of the impact of those resources on organized power markets.
“We know that clean, zero-marginal cost energy does fundamentally change the way the power markets work,” said Albert Cheung, BNEF’s head of global analysis. He cited BNEF modeling on the impact of adding 5 GW of solar in Texas. “It creates $300 million going toward solar. But you also destroy about $2 billion worth of revenue for other generators, whether it’s gas or coal or wind or nuclear. In California we already see this happening,” he said, with even solar “cannibalizing itself already.”
“Be wary of capacity mechanisms which bake in solutions of the past,” he added.
Former FERC Commissioner Nora Mead Brownell said she is confident organized competitive power markets will survive state and federal interventions to protect favored generation resources.
“I think it’s easy to sit in a vertically integrated market where you have elected regulators who pretty much approve what [utilities] wish and say this life is perfect. What we’ve seen in organized markets is a decrease in price, an increase in innovation and an increase in reliability and investment.”
FERC, she said, is acting properly in considering market redesigns to respond to decreased prices resulting from renewables and cheap shale gas. “They’re doing it in a methodical way based on a fact pattern, unlike kind of throwing subsidies at old solutions. They want to keep the market open for this continuing innovation that you will only see if you let the market drive decisions. You don’t see big huge mistakes in organized markets with big huge ratepayer-funded R&D projects. You don’t see that at all. There’s financial discipline, there’s transparency and there is encouragement of new solutions. It’s not happening fast enough … but I think it’s moving forward now. So, we need to step back and make economic decisions and not political decisions.”
Storage vs. Gas?
David Nason, CEO of GE Financial Services, was asked whether he sees storage as a threat to investments in gas-fired generation.
“I don’t know if storage is a complete competitor to gas yet,” he said. “It’s just one of the variables that we [consider in projecting] a long-term return for these investments. The difficulty with investing in gas without a structured market or without [power purchase agreements] is that these are 30-year, very capital-intensive investments. So, if I can’t get some level of confidence that I’m going to get an adequate return on my cost of capital, I’m just never going to put the money to work there.”
Reza Shaybani, co-founder and interim CEO of The EV Network, said the EV industry must not be paralyzed by concerns over which charging technologies and business models will survive. “This is going to evolve. This is going to change. What we see today is not necessarily going to be the future business model,” he said. “But it has to start from somewhere.”
Shaybani’s company, which is developing the charging infrastructure in the U.K., conducted a survey of EV buyers in the country and found that 90% were “middle-age men, well educated, very affluent and living in the Southeast and they have at least two or three other cars in their household. That’s … not going to take this revolution forward.”
The revolution will need cheaper vehicles and many more charging stations so that the drive from London to Manchester takes only three hours. “That should not take 18 hours if you are going to stop every 150 miles to charge,” he said.
Bryan Urban, executive vice president of Leclanche North America, said there is already a compelling business case for EVs and fast-charging infrastructure for mass transit and fleet vehicles. His company is conducting a pilot project in India for its plan to separate city buses from the batteries to make the capital expenditure model similar to that for diesel vehicles.
The company’s plan — which he dubbed, “taking the sun and putting it on the run” — replaces buses’ depleted batteries for charged ones three or four times daily, a swap which he says takes about three minutes each.
Mary Nichols, chair of the California Air Resources Board, said EVs need more marketing. “Even in California, where we pride ourselves that half of all EVs have been sold in the U.S., we … have done polls that show most people who are in the market for a new car aren’t even aware that there might be an electric car that could serve their needs,” she said. “So, we have a long way to go to really penetrate the thinking of customers.”
Nichols talked of Nissan’s hope to lease the batteries for its Leaf when it launched the first widely available all-electric car in Los Angeles. The plan was to include a mileage guarantee on the batteries, like the miles-per-gallon ratings for gasoline vehicles. “The only way they could do that at a level price was if they could negotiate with the electric utilities a product that would cut across state lines and local lines,” she said. “And after a period of time, they gave up on that idea. There was no practical way to do it.”
“And that’s in a relatively vertically integrated market, as most of the Western U.S. is,” added Colin McKerracher, the head of BNEF’s advanced transportation coverage. “It’s … even harder if you were to be in an unbundled market.”
Utilities are “unfortunately a very fragmented industry in the United States,” acknowledged Pedro Pizzaro, CEO of Edison International. “I think as an industry, we realize that and we’re trying to come to terms with that to help solve that issue. … We get your point, that from an automaker perspective or from a charger manufacturer perspective, they’re looking for as cohesive a national market as possible.”
LNG: No Glut Worries
Speakers at a panel on U.S. LNG exports expressed little concern over a potential glut in supply.
Meg Gentle, CEO of LNG exporter Tellurian, said she expects strong demand from China, which is converting coal furnaces to gas and adding natural gas-powered autos. Gas only represents 6% of total primary energy in the country, she said. Boosting that share to 10% would represent a nearly 70% increase in Chinese demand for the fuel.
She predicted Henry Hub benchmark prices will stay at $3/MMBtu or less for the foreseeable future, noting that it can now be produced for less than $1.
Greg Vesey, CEO of LNG Limited, which provides liquefaction for LNG export terminals, said he expects demand for gas to continue despite the growth of energy storage.
“Obviously the trend toward renewables and the need for storage with those is something to keep watching. … But in all cases, natural gas is going to provide that backup,” he said. “It’s been called the bridge fuel. I think we’re going to see that for a long time.”
Even if EVs supplant internal combustion vehicles, BP Chief Financial Officer Brian Gilvary said, oil will remain a “baseload” fuel.
“When I first joined the industry 32 years ago, people talked about peak oil supply. We now talk about peak oil demand,” he said. BP projects that peak to hit between 2035 and 2040.
“But we don’t think of it as a peak; we think of it as a plateau,” he added. Even under a scenario in which all internal combustion engines are banned by 2040, “we can see oil demand plateauing at round about 100 million barrels, which is what it is today.”
Corporate Purchasing of Renewables
Rob Threlkeld, global manager for renewable energy General Motors, said he’s been encouraged by the increasing number of utilities offering “green” tariffs to corporate buyers who want to purchase renewables. “I want price stability. I want to be able to understand what my costs are today and tomorrow. That allows me to be able to then [make] long-term commitments.”
“For a while, there was this huge tension between the renewable energy market and the regulated utilities. There was a significant pushback for years and years,” said Conor McKenna, managing director at investment bank CohnReznick Capital. “It was like when you were going into the regulated markets, you just had to put your mouthpiece in because it would be a battle. Now it feels like a lot of the guys that are coming to us [to deploy renewables] are regulated utilities [asking], ‘How can we incorporate a greater allocation of these resources into our portfolio?’”
MISO last week said it has concluded that a short-term capacity reserve product would be cost-effective and beneficial to reliability.
An evaluation paper released last month said the product would “strengthen MISO’s vision for reliable and economically efficient markets.”
MISO Market Design Advisor Bill Peters told an April 12 Market Subcommittee meeting that the RTO plans to design a market product that can provide capacity within 30 minutes on the recommendation of the Independent Market Monitor, who last year said a local reserve product could provide voltage support, local reliability and subregional capacity. (See MISO Board Hears State of the Market Recommendations.)
Last year the RTO incurred about $35 million in revenue sufficiency guarantee payments to cover load pocket needs and regional dispatch transfers over its contract path on SPP transmission from MISO Midwest to MISO South. The annual amount was “much more in some previous years,” MISO said.
Make whole payments MISO has incurred to manage the MISO-SPP contract path between MISO Midwest and MISO South | MISO
The RTO currently makes “inefficient, out-of-market commitments to address operational needs” in both load pockets and regional areas, Peters said.
Staff have said that a short-term capacity reserve would be especially helpful in South, which has less than 500 MW of offline capacity available within 30 minutes. West of the Atchafalaya Basin (WOTAB) has 100 MW of 30-minute reserves, while Amite South has none. (See MISO Researching 30-Minute Reserves, Multiday Commitments.)
Peters said MISO envisions the short-term capacity reserves as an ancillary service to be deployed in late 2019. The RTO will now move into a conceptual design phase.
Minnesota Public Utilities Commission staff member Hwikwon Ham asked how MISO arrived at the requirement that the reserve product must be delivered within 30 minutes rather than another length of time.
“Some of the needs, particularly the [regional dispatch transfer] constraint, are 30 minutes,” Peters replied.
Northern Indiana Public Service Co.’s Bill SeDoris asked if the cost of maintaining a reserve product would be shared footprint-wide.
Peters said MISO is considering employing a “nesting” approach for the product in which load needs are determined by specific demands on load pockets.
“I’m just concerned that the entire footprint could be responsible for what are very localized problems,” SeDoris said.
Peters said MISO must still iron out numerous details of a new reserve product, including determining how the service would interact with other existing ancillary services, creating scarcity pricing and demand curves for the new reserves, and identifying how commitment would be justified in settlements.
MISO Manages Chilly February
MISO reported a 76-GW average load during February, down from the average 83 GW in January as winter wound down across the footprint.
Average prices likewise decreased month over month from $41.75/MWh to $25.05/MWh in the day-ahead market and $39.68/MWh to $25.36/MWh in the real-time. Systemwide energy prices in February were “kept flat” with the help of natural gas prices below $3/MMBtu. Average Henry Hub gas prices were $2.64/MMBtu.
Past February Market Comparison | MISO
Load peaked for the month at 94.6 GW on Feb. 8, 7.5 GW above the previous February’s peak load of 87.1 GW. MISO said average monthly temperatures were lower than the prior two years but higher than in February 2015.
PJM’s Board of Managers announced in a letter to members last week that the Nominating Committee is recommending former InterGen CEO Neil H. Smith to replace Chairman Howard Schneider, who will retire from the board at the RTO’s Annual Meeting next month.
Smith
The committee also recommended re-electing current board members Neel Foster and Sarah Rogers. The Members Committee will vote on the candidates at the Annual Meeting.
Smith was selected following a national search, assisted by the Heidrick & Struggles search firm, that included candidates suggested by current board members. He retired from InterGen in 2016 after 25 years with the company, working his way up from development director.
InterGen operates 11 power plants with a generation capacity of 7,686 MW, three compression facilities and a 40-mile gas pipeline. The facilities are located in the U.K., Netherlands, Mexico and Australia. The company is jointly owned by the Ontario Teachers’ Pension Plan and China Huaneng Group/Guangdong Yudean Group.
Smith also served as a non-executive director and board member of The Wood Group, a worldwide service provider for the oil-and-gas and power generation industries. He was on the board for nine years, between 2004 and 2013, according to his LinkedIn profile.
