Page 1179 – RTO Insider

April 17, 2018

SPP Markets and Operations Policy Committee Briefs: April 17, 2018

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.

SPP’s Markets and Operations Policy Committee (MOPC) met on April 10th and 11th | © *RTO Insider*

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.

SPP’s Lanny Nickell, NTEC’s Jason Atwood and KCP&L’s Denise Buffington lead the April MOPC meeting. | © *RTO Insider*

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.

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.

Midwest Energy’s Bill Dowling makes a point. | © *RTO Insider*

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.

— Tom Kleckner

April 17, 2018

Vote to Make Variable Resources Dispatchable Falls Short at MOPC

By Tom Kleckner

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.

Non-Dispatchable Variable Energy Resources NDVERs SPP MOPRC — AEP’s Richard Ross explains Tariff revisions. | © *RTO Insider*

“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.

April 17, 2018

Most of West Signs up for CAISO RC Services

By Jason Fordney

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.

CAISO discussed its new RC services proposal at a Thursday meeting | © *RTO Insider*

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.

CAISO REV load forecasting Western RTO — Pettingill | © *RTO Insider*

“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.

April 17, 2018

CPUC to Vote on $98M PG&E Settlement

By Jason Fordney

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.

CPUC ex parte communications PG&E — The CPUC is due to vote on the settlement on April 26 | © *RTO Insider*

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.

April 15, 2018

PJM Markets and Reliability Committee Preview: April 19, 2018

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

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:40)

Members will be asked to endorse the following proposed manual changes:

A. Manual 14A: New Services Request Process. The revisions clarify language to match existing procedures and add language to describe in detail system impact study and interconnection feasibility study analyses. In January, a FERC administrative law judge issued an initial decision finding that PJM’s process is unjust and unreasonable because of a lack of transparency (EL15-79). On Feb. 20, PJM filed a brief on exceptions challenging the ruling.
(See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)

B. Manual 14B: Regional Transmission Planning Process. The revisions are the result of a periodic review that identified several administrative changes, including a revision to the generator deliverability procedure and adding the Ohio Valley Electric Corp. to the Western region study area definition.

C. Manual 28: Operating Agreement Accounting. The revisions address changes to comply with FERC Order 825 implementing five-minute settlements. Also makes a technical correction for the revenue data used to calculate settlements for generation resources. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)

D. Manual 11: Energy & Ancillary Services Market Operations. Removes offer cap revisions for price-based offers that were approved at the October 2017 MRC to comply with FERC Order 831. PJM discovered the revisions restrict market-based offers to $1,000/MWh, contradicting language in the Operating Agreement. The manual is being revised to say that market-based incremental energy offers may not exceed $1,000/MWh unless the cost-based incremental energy offer is more than that amount. In that case, the market-based incremental energy offer is capped at the lesser of the cost-based incremental energy offer or $2,000/MWh.

3. PJM External Capacity Filing (9:40-9:55)

Members will be asked to endorse proposed revisions to Manual 12: Balancing Operations to incorporate rules approved by FERC in November regarding reviews required for approval of pseudo-tied generators. (See “External Capacity,” PJM PC/TEAC Briefs: March 8, 2018.)

4. Balancing Ratio Issue Charge (9:55-10:10)

Members will be asked to endorse proposed revisions to the deliverables in the balancing ratio issue charge that the Market Implementation Committee is currently addressing. The revisions highlight the potential for changes to, and the underlying logic for, the market seller offer cap. (See “Stopgap Balancing Ratio OK’d Despite Questions,” PJM MRC/MC Briefs 10-26-17.)

5. Operating Committee Charter Update (10:10-10:20)

Members will be asked to approve proposed revisions to the Operating Committee charter to replace the term “spinning reserve” with “synchronized reserves.” The revisions will match the language of other PJM manuals.

— Rory D. Sweeney

April 15, 2018

Court Questions FERC Change on ISO-NE Renewable Exemption

By Michael Brooks

A three-judge panel of the D.C. Circuit Court of Appeals on Friday questioned whether FERC had changed its position without adequate explanation in its approval of ISO-NE’s renewable technology resource (RTR) exemption from its minimum offer price rule (17-1110).

New England generating companies — including NextEra Energy Resources, NRG Power Marketing and PSEG Energy Resources & Trade — sued the commission last year over the exemption, which allows 200 MW of renewables annually (up to a 600-MW maximum) to clear ISO-NE’s capacity market without regard to the MOPR. The companies charged that FERC reversed its position from previous orders finding that out-of-market entry into the market can suppress prices and that it never justified the 200-MW cap.

FERC ISO-NE Renewable Exemption MOPR — Meade and Prettyman Courthouse | *DC Circuit*

The companies previously sued over the issue in 2015, but the court allowed the case to be remanded back to FERC at the commission’s request. FERC affirmed its approval in April 2016 (ER14-1639-004) and denied the generators’ request for rehearing in February 2017 (ER14-1639-005). (See Bay Blasts MOPR on Way Out the Door.)

“The narrowly tailored renewables exemption, in combination with ISO-NE’s sloped demand curves, balances our responsibility to promote economically efficient prices, while accommodating states’ ability to pursue legitimate policy objectives,” FERC said in its order on remand.

As FERC attorney Carol Banta attempted to explain Friday how the RTO’s implementation of a systemwide sloped demand curve — approved along with the RTR exemption — has lessened the price effects of the exemption, Judge David B. Sentelle interrupted her, saying he wanted to focus on “the more mundane aspects of administrative law.” He asked that she defend the charge that FERC had unreasonably changed its position.

He cited FERC saying “the orders cited by [the plaintiffs] and the first two orders in this proceeding demonstrate that the commission’s view on the question of a broad (i.e., not resource-by-resource) exemption for renewable resources has evolved.”

“That’s a lot like saying it ‘changed,’” Sentelle said. “Now we certainly have a lot of precedent that says that an agency can change, but we say that in order to avoid being arbitrary and capricious they have to explain why they changed.” He asked Banta to show where FERC explained its reasoning.

Banta cited a passage in the commission’s last order denying rehearing, in which it said, “Moreover, not only has the commission’s view of the relationship between state-sponsored renewable resources and the capacity market evolved over time, but in the five years since the commission accepted the minimum offer price rule to mitigate buyer-side market power, New England states have continued to intensify their renewable resource development. The commission does not regulate in a vacuum. We recognize that, as ISO-NE stated in its original filing, it is seeking to balance its need to retain and attract capacity with its obligation to meet customers’ needs in an economically efficient manner.”

The commission is “balancing its responsibility to promote economically efficient prices,” Banta said. If the increased entry of state-sponsored renewable resources is not accounted for, “the price signal is actually false if it’s signaling the need for new entry [and] ignoring the new entry that’s there.”

“Wouldn’t any prudent company take that into account before making a multimillion-dollar investment in a new generating facility?” Judge A. Raymond Randolph asked. “They wouldn’t take into account just the so-called ‘false signal.’ They would take into account the fact that there are all these renewables out there.”

“This is about making sure the capacity market is a just and reasonable mechanism,” Banta responded, “and that includes, is it sending accurate price signals? Is it incentivizing new entry that the system needs? And is it ensuring fair prices for consumers? And these all go into the mix.”

CASPR Rehearing Requests

NextEra and NRG cited the RTR exemption case as a reason why FERC’s reasoning was flawed in its approval of ISO-NE’s Competitive Auctions with Sponsored Policy Resources capacity market construct (ER18-619). (See Split FERC Approves ISO-NE CASPR Plan.)

As part of CASPR, the RTO plans to phase out the exemption by allowing accrued exempt megawatts to be used through Forward Capacity Auction 15. The companies cited Commissioner Richard Glick’s dissent on the order, in which he said FERC’s pursuit of “investor confidence” would cause over-procurement of capacity.

“While we agree with Commissioner Glick that respecting settled market expectations are important, the RTR exemption is not based on settled law, as the matter is pending before the D.C. Circuit,” the companies said in their request for rehearing last week. “Prior to the RTR remand order, the justness and reasonableness of the FCA had continuously been based on the principle that ‘over the long run, the average price for capacity should reflect [cost of new entry], in order to attract new entry needed for reliability.’ In the RTR remand order, without any explanation, the commission for the first time stated that ‘the renewable exemption fulfills the commission’s statutory mandate by protecting consumers from paying for redundant capacity.’”

The Eastern New England Consumer-Owned Systems also requested rehearing, criticizing the commission’s accepted definition of sponsored-policy resources, which limits participation in the second auction under CASPR to renewable resources procured by distribution utilities as part of state mandates.

FERC’s “adoption of the discriminatory ‘sponsored-policy resource’ definition results in the exclusion of conventional generating resources developed by New England’s consumer-owned utilities from the eligibility to participate in the Substitution Auction without identifying any rational basis for its conclusion that public power conventional resources are not ‘similarly situated’ to state-mandated renewables purchases by investor-owned distribution utilities,” the municipal utilities said.

Several clean energy advocate groups, including the Natural Resources Defense Council and Sierra Club, reiterated their complaint that the RTO had not justified eliminating the RTR exemption.

“CASPR replaces a proven mechanism for reconciling state policies with competitive capacity markets with a totally unproven construct that offers little likelihood of integrating renewable resources,” the groups said.

Like NextEra and NRG, consumer advocacy group Public Citizen cited Glick, agreeing with his criticism of the commission’s focus on investor confidence in its justification.

“The commission never bothers to define ‘investor confidence’ for the purposes of this order,” wrote Tyson Slocum, the group’s energy program director. “There are many owners of power plants that talk incessantly about the dangers of the ‘erosion of investor confidence’ if power prices aren’t high enough to provide the generous financial returns the owners promised to shareholders. Because hey, we all feel a lot more confident when we get paid more money.”

April 15, 2018

Lovins: We’re Only Scratching the Surface on Energy Efficiency

By Rich Heidorn Jr.

NEW YORK — Amory Lovins knows the conventional wisdom on energy efficiency. And he doesn’t buy it.

Lovins ERCOT energy efficiency — Lovins | © *RTO Insider*

Economic theory says you stop investing in EE when the heat savings from insulation, for example, no longer outweighs the costs. But “integrative design” — optimizing buildings, vehicles and factories as whole systems rather than individual parts — changes the equation, he says.

Lovins, the visionary founder of the Rocky Mountain Institute, ascribes to Dwight Eisenhower’s advice: “If a problem cannot be solved, enlarge it.” Expanding the boundaries of the problem uncovers new options and synergies, he says.

Thus, he told the Bloomberg New Energy Finance’s Future of Energy Summit last week that electric intensity — which he said dropped a record 4.4% in 2017 — could fall even more dramatically in the future.

“If you keep investing well beyond that supposed cost-effectiveness limit, suddenly your marginal cost goes back down because now your house loses so little heat that it no longer needs a furnace, ducts, fans, pipes, pumps, wires, controls [and] fuel-supply arrangements,” Lovins said.

Lovins displayed a photo of him with his latest harvest of bananas, grown in his 35-year-old passive solar home near Aspen, Colo. “Integrative design saved 99% of its heating energy and $1,100 of construction cost because the super insulation, super windows and so on cost less than the heating system they displaced,” he said. “Now over 160,000 European buildings do this.”

Fat, Short and Straight

Lovins cited the 2011 retrofits to the Empire State Building. Replacing 6,000 leaky windows with ones that pass light but block heat, plus improved lighting and office equipment, cut the skyscraper’s energy costs by 38% and the peak cooling load by a third. “Then renovating smaller chillers instead of adding bigger ones saved over $17 million in capital cost, paying for most of those savings and cutting the payback to three years — the same payback as saving a sixth as much energy with standard disintegrative design.”

Three years later, Lovins said, the retrofit of an office building in Denver reduced energy costs by 70%, “making this half-century old federal office more efficient than what was then the best new U.S. office, which in turn is less than half as efficient as [RMI’s] own net positive, no mechanicals office. And now there’s a German building using three-fifths less energy than ours.”

The results were not from new technology, he said, but from design improvements. Making pipes and ducts “fat, short and straight rather than skinny, long and crooked as in normal practice,” he said, eliminates at least 80% of the friction and energy consumption. “If that were done worldwide, it could save about half the world’s coal-fired electricity. The payback is typically less than a year in retrofit and zero in new build. But this is hardly noticed because it’s not a technology, it’s a design method.”

He also cited the engineers on the Tesla Model S, who realized batteries work better if prewarmed. “Many other components also needed heat added or removed at various times, so rather than separately heating or cooling each, they were all choreographed so that in each stage of driving, thermally linked coolant loops shuttle heat around from where it’s not wanted to where it is. That means longer [battery] range, lower weight, lower cost. And not needing the radiator for first 50 km — which is longer than most trips — keeps it shuttered until needed, further improving aerodynamics.”

An All-Renewables ERCOT

Lovins said ERCOT could address its steep late-afternoon ramp rate — the so-called “dead armadillo curve” — by moving to 100% distributed renewables, with 86% wind and solar PV, and the remaining 14% supplied by dispatchable renewables, including burning animal manure in existing gas turbines.

ERCOT energy efficiency lovins — Amory Lovins presented this graph to demonstrate how ERCOT could run on 100% distributed renewables in the summer of 2050. | *Rocky Mountain Institute*

“Then match the load by putting the surplus electricity into two kinds of distributed storage worth buying anyway, namely ice storage air conditioning and smart charging of [electric vehicles]. And then recovering that energy when needed and filling the last gaps with unobtrusively flexible demand yields 100% renewable energy every hour of the year,” he said. “Five percent annual spill, very low prices using no bulk storage but eight cheaper kinds of grid flexibility resources.

“Efficiency is not a dwindling, rising-cost resource like copper,” he concluded. “Energy efficiency resources are ubiquitous and infinitely expandable assemblages of ideas depleting nothing but stupidity — a very abundant resource. So, to all you smart designers, I give you this charge: Blessed be your negawatts. Go forth and be fruitful and subtract.”

April 15, 2018

Solar Industry Looks for Bright Spots on Tariffs

By Rich Heidorn Jr.

NEW YORK — Solar industry officials last week expressed confidence that the sector will continue to grow despite the Trump administration’s tariffs on imported solar cells and modules. But they told Bloomberg New Energy Finance’s Future of Energy Summit that the levies have hurt in the short term.

Trump tariffs solar industry — BNEF’s Hugh Bromley (far left) interviewed (left to right) Vikram Aggarwal, EnergySage; Abigail Hopper, SEIA; Nam Nguyen, SunPower; and Scott Wiater, Standard Solar | © *RTO Insider*

“They were more of a punch to the gut than a complete decapitation, which is what we feared,” said Abigail Hopper, CEO of the Solar Energy Industries Association. “And so, while they will certainly have a dampening effect on the industry — and I think we’ll see that for years — I feel fairly confident that it will continue to grow.”

“It certainly slowed things down. We were seeing a slowing of project flow,” said Scott Wiater, CEO of Standard Solar, which provides financing and management of utility-scale solar projects. “But recently we’ve seen it start to pick up tremendously. I think a lot of developers have been sitting on projects, waiting for the tariff decision and tax [legislation] to settle down. [There was also] some seasonality thrown in there. And now we’re really starting to see it ramp back up.

“I do think in some states where it’s a difficult environment [to operate] it may have iced the markets. But in states that are solar-friendly, I think we’re going to hit the ground running.”

Vikram Aggarwal, CEO of EnergySage, which provides a portal for homeowners researching pre-screened rooftop PV installers, agreed that the impact has varied by geography. Aggarwal said a survey of his company’s installers indicated two-thirds planned to absorb all or most of the cost increases, with one-third saying they would pass most of the increases to consumers.

“It actually seems like it’s playing out that way. … We’re seeing prices roughly 1% down on a national basis compared to last year. In certain markets like California, the prices are actually down quite a bit. In markets that are less developed, less mature, prices are trending up. It’s a tale of two cities.”

Aggarwal said consumers have not been scared away by the tariffs. “The consumer interest is actually very strong this quarter. We’re running about 150 to 200% above year-over-year.”

Wiater said he has no fear of higher prices squelching consumer interest. “I think we may have an oversupply situation coming very quickly and prices could come down below what … analysts are expecting very quickly.”

Hopper said the tariff debate brought it new conservative allies in D.C., with the American Legislative Exchange Council (ALEC), the Heritage Foundation and R Street Group joining SEIA in opposing the levies.

Portrayals of the solar industry as split over the tariff debate were inaccurate, she said. “It really was two companies [who filed the complaint that prompted the tariffs] against 1,000 others.” She said about 20 solar companies have reported the loss of jobs or investments. “It is serious and harmful,” she said. (See Tariff to Pinch US Solar Growth; Factory Surge Unlikely.)

The solar industry lost 10,000 jobs (3.8%) last year, dropping to 250,271, according to the Solar Foundation’s National Solar Jobs Census. It was the first year-over-year drop in employment, said Hugh Bromley, head of U.S. solar for BNEF, who moderated the discussion.

Even so, 29 states added solar jobs. The prospects of job growth has helped open doors for the industry, Hopper said.

“In terms of electricity generation, solar creates more jobs than all fossil fuels combined, which is an incredible statistic that now more people in Washington know,” she said. “One of the great outcomes [of the tariff case] was we did so much education among all these brand new policymakers in Washington. And when we talk about the amount of jobs, and the jobs in relation to other industries and other fuel sources, that was always a point on which I felt like we’re getting traction. Because we’re now talking about jobs in lots and lots of red states.”

April 15, 2018

FERC Rejects CAISO CPM Proposal

By Jason Fordney

FERC last week rejected a major CAISO proposal to expand its backstop procurement process to prevent the early retirement of generation needed to maintain near-term reliability, saying the grid operator needs to “propose a more comprehensive package of reforms.”

In its April 12 order (ER18-641), FERC sided with parties that had protested CAISO’s Capacity Procurement Mechanism Risk-of-Retirement (CPM ROR) program, including the California Public Utilities Commission (CPUC), six California cities, the state’s three investor-owned utilities and the ISO’s Department of Market Monitoring.

CAISO CPM ROR FERC resource adequacy — Calpine’s Yuba City plant is one that is under a reliability-must-run contract

“We find that CAISO has not adequately demonstrated that its proposal addresses the front-running concerns raised by protesters and that the proposal will avoid potentially deleterious effects on the competitiveness of capacity procurement under CPUC’s resource adequacy program,” FERC said.

CAISO spokesman Steven Greenlee said Friday that the ISO is reviewing the order “and will be considering our next steps as part of the ongoing stakeholder process.” In recent meetings, ISO officials have been telling market participants they expected FERC to approve the rule changes.

But stakeholders had been critical of the program throughout the development process. (See CAISO, Stakeholders Debate RMR Revisions.)

CAISO has two major backstop procurement programs, CPM and its mandatory reliability-must-run program that is also raising stakeholder objections for providing out-of-market payments to keep gas-fired generators online. The ISO is considering merging the two programs.

The rejected CPM ROR program would have expanded the existing CPM process to include procurement of at-risk capacity needed for the next resource adequacy compliance year. The process would have included two request windows for generators to seek a CPM designation, one in April and other in November of each year. FERC said that in practice, CAISO currently makes the designation in mid-December at the earliest for the following year, which generation owners complained occurs too late in the year for their planning decisions.

CAISO CPM ROR resource adequacy — CAISO’s proposed two windows for units to pursue CPM designations | *CAISO*

But the CPUC argued that the spring application window would allow resources to “front-run” its resource adequacy process and could lead to other gaming by resources because CPM revenues might exceed market revenues. IOUs raised concerns that a more holistic approach is needed and that CAISO did not consider the interplay with RMR, which is a mandatory contract unlike the voluntary CPM.

The CPUC has also battled with CAISO over RMR designations for gas units, and in February it hastily crafted and passed an order mandating that CAISO-approved RMRs be replaced with energy storage by 2019. (See CPUC Targets CAISO’s Calpine RMRs.)

Stakeholders also complained that the CPM proposal’s cost-based compensation provides for full cost recovery while also allowing resources to retain revenues earned in the ISO’s market. The Monitor had argued the units should not receive compensation beyond their cost of service, and that the changes could affect the bilateral resource adequacy market.

CAISO had contended that “front-running” of the RA process would not occur, but FERC said “the potential for the spring request window to distort prices or otherwise interfere with the bilateral resource adequacy process have merit and are significant enough to render CAISO’s proposal unjust and unreasonable.”

FERC also said that CAISO’s development of the current package of RMR/CPM changes indicate a need to more closely align the two programs. The commission said there is a “need to evaluate the fundamental reliability and market factors associated with resource adequacy as a whole.”

The commission said CAISO should revisit the issues of RMR/CPM compensation, evaluate whether both need to be retained and examine how the CPM designations could affect procurement. CAISO will make quarterly filings beginning June 1 to give updates on the stakeholder process and any changes that occur as it progresses. FERC said it would not move or act on the filings.

April 15, 2018

FERC OKs MISO Queue Deadline Change

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.

MISO Decision Point II — | © *RTO Insider*

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.”

FERC held a technical conference earlier this month to gather ideas on how RTOs can better align their affected-system studies. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.)

— Amanda Durish Cook