Page 1221 – RTO Insider

November 22, 2019

FERC Adopts ROE Methodology in MISO Complaints

By Christen Smith

FERC adopted a new methodology for calculating return on equity rates for transmission owners and applied it to two MISO proceedings on Thursday (EL14-12, EL15-45).

The commission set the TOs’ ROE at 9.88%, a figure it determined via both the discounted cash flow (DCF) and capital asset pricing models (CAPM) — the two methods “investors most commonly use to estimate the cost of equity,” it said.

In the first docket, the commission granted the complaint, filed in November 2013, and ordered the TOs to implement the 9.88% ROE effective Sept. 28, 2016 — down from the previously approved 12.38% — and provide refunds for the period from the date of the complaint to Feb. 11, 2015.

FERC, however, dismissed the second complaint, filed by another group of transmission customers Feb. 12, 2015, reasoning that prospectively lowering the ROE in the first complaint rendered the second moot. This led to a partial dissent from Commissioner Richard Glick, who disagreed with the decision not to grant refunds in the second complaint.

The ruling comes two years after the D.C. Circuit Court of Appeals vacated and remanded FERC Opinion 531, finding that the commission’s DCF methodology used to revise rates for New England TOs — including “setting the replacement ROE at the midpoint of the upper half of the zone of reasonableness … rather than the midpoint of the overall zone of reasonableness” — was unjust and unreasonable.

FERC ROE MISO — FERC adopted a new methodology for ROE rates and applied it two proceeding in MISO on Nov. 21. | © *RTO Insider*

The decision pushed FERC to reconsider the metrics it used to calculate ROEs, a methodology that had been largely unchanged since the 1980s. The commission in a briefing order had previously considered giving equal weight to results from the DCF, CAPM, expected earnings and risk premium models before settling on the methodology used in Thursday’s ruling. (See FERC Changing ROE Rules; Higher Rates Likely.)

The new methodology adopts an equal weighting of the DCF and CAPM models to establish a “composite zone of reasonableness” but rejects use of the expected earnings or risk premium models.

“The commission will use that composite zone of reasonableness to evaluate whether an existing base ROE remains just and reasonable under the first prong of [Federal Power Act] Section 206 and to establish a new just and reasonable base ROE, under the second prong of FPA Section 206, when the existing base ROE has been shown to be unjust and unreasonable,” FERC wrote.

EL14-12 dates back to 2013, when industrial customers argued that the 12.38% ROE rate that TOs were collecting was too high. (See FERC Extends New ROE Policy to MISO; Seeks Comments.)

November 22, 2019

Parties near Agreement on El Paso Electric Purchase

By Tom Kleckner

The Texas Public Utility Commission’s scheduled hearing on a $4.3 billion private equity bid for El Paso Electric has been postponed until January to allow time for the parties to reach a unanimous settlement (49849).

EPE and its private equity suitors filed the continuance request on behalf of commission staff and the proceeding’s intervenors. They said the applicants, commission staff, and “most of the intervenors” had reached an agreement in principle on the major terms and hope to resolve all issues in the next few weeks.

“The remaining parties believe additional time for further discussions is merited rather than proceeding to a hearing at this time,” the applicants said.

El Paso Electric — Intervenors line up before the judge during a prehearing conference Nov. 20.

Administrative Law Judge Hunter Burkhalter granted the request Wednesday. He directed the parties to file a non-unanimous settlement by Dec. 17 and invited them to provide detailed status reports during the PUC’s Dec. 13 open meeting.

Burkhalter rescheduled the commission’s hearing for Jan. 7-8. It had originally been set for Nov. 20-22.

J.P. Morgan Investment Management’s Infrastructure Investments Fund US Holding 2 and Sun Jupiter Holdings, a limited liability company formed to enter into the merger agreement, announced their proposed purchase of EPE in June.

The parties have proposed a purchase price that is a 17% premium to EPE’s closing price before the merger’s announcement. The private equity firms have said the management team will remain in El Paso and no jobs will be transferred outside of Texas. They have sweetened the deal by offering a $21 million credit to current EPE customers and creating a $100 million community economic sustainability fund.

The deal has been opposed by the Texas Office of Public Utility Counsel, which says the proposal does not provide sufficient tangible, quantifiable benefits to EPE’s customers and does not adequately protect them from “the additional risks created by the post-closing corporate structure and governance.”

The utility’s industrial customers have also raised concerns over the utility’s governance and financial risks. Other intervenors include PUC staff and the city of El Paso, who both say most of the regulatory commitments don’t impact customer rates or promise any benefits beyond the status quo.

November 22, 2019

MISO Committee Revisits ‘Other’ Sector Spin-off

By Amanda Durish Cook

Environmental advocates are stepping up calls for MISO to split up its Environmental and Other Stakeholder Groups sector to provide them with a more singular voice — and the idea may be getting some traction.

Sector members continue to press MISO’s Steering Committee to expand the number of sectors in the Advisory Committee, affording dedicated space for green advocates in RTO activities.

“In the long run, if you don’t offer a new way for folks to join MISO … there are always going to be problems,” John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project, said during a Steering Committee conference call Thursday.

Advisory Committee members in September indicated they weren’t yet ready to embrace the idea of creating an 11th sector to accommodate hard-to-pin-down members. At the time, the Power Marketers and Brokers sector offered to take on the “Other” contingent temporarily to see if it was a harmonious fit. (See Scant Support for 11th MISO Sector.)

But the Steering Committee is now suggesting that the Advisory Committee re-examine the issue.

Moore this week sent an email urging Steering Committee members and MISO staff to revive the issue. He wrote that “regardless of the intentions for creating this sector at the inception of MISO, a sector composed of entities in addition to ‘environmental’ is problematic at best and creates governance challenges within our sector.”

“For that reason, we encourage MISO to develop a solution that allows members to participate in the stakeholder process and governance in ways that do not render our sector dysfunctional,” Moore wrote citing two instances of entities joining the sector that were not “aligned” with its mission.

“In one instance, it was several gas pipeline development companies, and in another case, it was several competitive transmission developers,” he wrote.

Moore said those two instances “substantially disrupted our ability to operate as a cohesive sector.” He also wrote that he fears that prospective MISO member the Lignite Energy Council (LEC) may end up in the sector because the organization “does not fit neatly into any sector because it is so diverse in its membership.”

“MISO needs a durable solution that can allow for meaningful participation in the stakeholder process for entities like the LEC, who wish to become members, without forcing them into sectors with fundamentally different interests,” Moore wrote.

During the conference call, Moore suggested MISO at least create a “holding” space for new members that may have a difficult time deciding where they fit in.

“We don’t want our sector to become a repository for just anyone that doesn’t have a home,” Moore said.

“I’m very sensitive to the concerns of the Environmental sector, but where do we draw the line on creating new sectors? … I’m struggling myself on coming up with an answer to that,” WEC Energy Group’s Chris Plante said.

Plante said his Municipals, Cooperatives and Transmission Dependent Utilities sector also contains groups that don’t always agree with each other.

But some Steering Committee members said MISO cannot expect to persist with the same 10 sectors given the increasingly mercurial nature of the energy industry.

“The world is changing, and the industry is changing,” Manitoba Hydro’s Audrey Penner said, citing Bill Gates’ secretive Heliogen solar startup that has created solar arrays capable of generating heat above 1,000 degrees Celsius with the help of artificial intelligence. She said it was an example of the “new players entering our industry.”

“To the extent that we need to create new sectors, that’s going to be pressed upon us whether we like it or not. We’re not in a static industry,” Penner reminded fellow members.

Penner argued that MISO could create as many as three new sectors, for example, and said members “could still feel comfortable and make their voices heard.”

Steering Committee Chair Tia Elliott said the topic would be passed to the Advisory Committee in time for its Dec. 11 meeting as part of MISO Board Week in Indianapolis.

Remove Affiliation Obligation?

Steering Committee leaders on the same call also discussed eliminating the requirement that entities must join a sector in order to become MISO members.

Current rules dictate that organizations seeking MISO membership must declare affiliation to one of the 10 sectors in order to gain entry. Sectors are used for member voting purposes in the Planning Advisory Committee and Advisory Committee.

The Steering Committee ultimately agreed to hold off on making draft changes to MISO’s Stakeholder Governance Guide until further discussion. Any revisions to the governance guide must go before the Advisory Committee before they are adopted.

Moore said dropping the requirement might be a positive step, freeing elusive and prospective members from trying to narrow down their purpose.

“I think it’s definitely a sticking point,” he said.

November 22, 2019

IMM Cites Smooth Summer, Outage Issues in MISO South

MISO’s Independent Market Monitor found no major concerns with performance in MISO South over the summer and early fall, but it still wants the RTO to get a handle on short-notice and unreported generation outages in the region.

Potomac Economics’ Robert Sinclair delivered a MISO South operations report at the Entergy Regional State Committee’s annual meeting Wednesday. The report showed South prices for late summer and fall were significantly lower than in 2017 and 2018, holding to about $25/MWh, while natural gas prices hovered around $2.50/MMBtu.

“During the year, you see prices have been declining, and that’s the result of declining natural gas prices,” Sinclair said. Monitor staff also reported higher prices in the MISO portions of Texas in recent months because of transmission outages.

But Sinclair said the Monitor is keeping tabs on short-notice outages and extensions of planned generation outages, along with unreported outages and derates, which continue to be prevalent in South.

“A significant portion of resources continue to be unreported and short-notice,” Sinclair said.

MISO Director of Operations and External Affairs Liaison Tag Short said the RTO called a maximum generation warning in South in early June because of both high load and forced generation outages.

Short said South’s 32.2-GW summer peak occurring Aug. 12 came in lower than the 32.7-GW all-time peak on Aug. 10, 2015.

Sinclair also told Entergy executives that the regional dispatch transfer limit continues to provide South members with cost savings and the benefit of integration. He said the transfer limit bound much more frequently in the South-to-Midwest region August through October. MISO’s agreement to use SPP transmission to facilitate transfers stipulates a 2,500-MW South-to-Midwest limit and a 3,000-MW Midwest-to-South limit.

— Amanda Durish Cook

November 22, 2019

CAISO Tx Planners Look at Reliability, Capacity Reqs

By Hudson Sangree

FOLSOM, Calif. — During a daylong planning session Monday, CAISO engineers examined options for transmission upgrades to resolve reliability concerns and reduce natural gas generation’s role in meeting local capacity requirements.

The ISO is in the second of its three-phase 2019/20 transmission planning process (TPP). On Monday, it held the third of four stakeholder meetings to go over its findings and proposals. The goal is to provide the Board of Governors with a transmission plan to approve by March.

The annual TPP looks ahead 10 years, assess ing CAISO’s grid based on economic, policy and reliability considerations.

“In addition to those, we’re also doing this sidebar where we’re looking at potential [opportunities] for reducing reliance on gas-fired generation in local capacity areas,” said Neil Millar, CAISO’s executive director of infrastructure development. Reducing dependence on gas can create a need for economically beneficial transmission projects, he said.

California has a legal mandate to dramatically reduce its greenhouse gas emissions and increase its reliance on renewable energy sources by 2030. The 2019/20 TPP’s planning horizon extends through 2029.

Over the course of several hours, engineers presented the results of their detailed examination of the state to identify areas and subareas where transmission upgrades could cut local capacity requirements (LCRs) and eliminate or reduce the need for gas-fired generation. The long-term LCR assessment began in 2018.

In Southern California, billions of dollars in proposed projects could potentially reduce thousands of megawatts of LCRs, though planners questioned the cost-benefit ratio of many large projects and the potential adverse impacts on the sprawling, interconnected grid in Los Angeles and San Diego counties.

In Northern California, spending $30 million on the Tesla-Delta switchyard 230-kV line reconductor in the Contra Costa subarea would reduce the need for gas to meet local capacity needs from 1,207 MW to 299 MW, CAISO planners found.

In the Tesla-Bellota subarea of Stockton, reconductoring about 200 miles of overloaded 115-kV lines, at a cost of $143 million, could completely eliminate the need for 365 MW of gas generation to meet local demand.

Both those projects, and many others on the list, were submitted by CAISO.

Reliability Projects

Planners also presented proposals for reliability projects costing less than $50 million each that require only the approval of CAISO executives. Projects that cost more than $50 million require board approval and will be included in the draft transmission planning report due Jan 31.

The proposals are intended to meet NERC standards, Western Electricity Coordinating Council criteria or ISO planning standards, which can be stricter than NERC or WECC requirements.

Pacific Gas and Electric, for example, has proposed installing a 230/115-kV transformer bank in the San Francisco Bay Area, at an estimated cost of $3 million to $6 million to prevent overloads and meet NERC reliability requirements.

PG&E has also proposed reconductoring 9 circuit miles of the overloaded 115-kV Wilson Oro Loma line in the Fresno area to meet NERC reliability standards, with a price tag of $11.3 million to $22.7 million.

Written stakeholder comments on the presentations in Monday’s meeting are due Dec. 2.

November 22, 2019

RF Enforcement: ‘Getting Harder to Process Violations’

By Rich Heidorn Jr.

WASHINGTON — Processing NERC violations is getting more difficult — at least in ReliabilityFirst, says the regional entity’s enforcement chief.

ReliabilityFirst enforcement of NERC violations — Kristen Senk, ReliabilityFirst | © *ERO Insider*

RF Managing Enforcement Counsel Kristen Senk made the observation during a Compliance Committee presentation on 2019 enforcement activities at RF’s annual meeting Wednesday.

“I’m really proud of the team that’s here for the work that they’ve done. It’s getting harder to process violations,” Senk said. “I think entities probably realize this too. The violations themselves are getting more complicated. On the CIP [critical infrastructure protection] side, there’s some new technologies out there. Our [subject matter experts] are spending a lot of time trying to learn those technologies and working with the entities that understand [them].

“On the [operations] side, we’ve seen some really complicated … facility ratings issues. And also, the further we get into compliance, the more compliance history an entity has,” she continued. “So, for every new violation we process, we look at all the prior violations that were similar for that entity. So that list is just growing longer each year.”

2019 Statistics

RF had received 360 violations as of mid-November, so it may end the year with a slightly lower total than in 2018, Senk said. About 78% of this year’s violations were self-reports (vs. 76% for the ERO overall), with 22% resulting from audit findings.

“That’s good news,” Senk said. “We want to see mostly self-reports.”

ReliabilityFirst enforcement — RF and WECC receive and identify more potential violations than other NERC regions. | *ReliabilityFirst*

Senk noted that audit findings in 2019 more than doubled from the number in 2018. “That might sound alarming, but we’re actually not too concerned. … We did have a few more audits in 2019. … We also had some late audits in 2018 that kind of rolled over and we didn’t get the violations until 2019. And then we had a few entities that had multiple registrations, so when we audit them, the number would tend to go up.”

Three-quarters of the violations were for CIP, up from 72% last year. Like the ERO, about half the violations were in CIP-007 (patching) and CIP-010 (change management and baselining).

Senk said RF also is seeing an increase in CIP-004 violations. “Those really started increasing with the changeover to CIP version 5. CIP-004 violations are access management: So, some entities are revoking access too late. There’s a pretty strict timeline around those [requirements]. Also, not having the proper authorizations before granting access,” she said. “A lot of entities have kind of manual processes around this access management and they’re learning that those just aren’t sustainable for version 5.”

November 22, 2019

FERC Refocusing Cybersecurity Efforts

By Rich Heidorn Jr.

FERC announced Thursday it was rethinking its cybersecurity strategy by reorganizing two departments and directing its efforts at five “focus areas.”

FERC Cybersecurity — FERC is directing its cybersecurity efforts at five “focus areas.” | *FERC*

The changes resulted from Chairman Neil Chatterjee’s directive that the Office of Electric Reliability (OER), the Office of Energy Infrastructure Security (OEIS) and the Office of Energy Projects (OEP) identify ways they can combine their cybersecurity efforts.

As a result of that review, OEP is creating a unit within the Division of Dam Safety and Inspections staffed by physical and cybersecurity specialists.

In addition, OER will reorganize based on functions effective Sunday, with the Division of Reliability Standards and Security and the Division of Compliance realigned into the Division of Operations and Planning Standards and the Division of Cybersecurity.

FERC also identified five subject areas that will guide FERC staff efforts:

Supply Chain/Insider Threat/Third-Party Authorized Access: Ways an attacker can bypass perimeter security controls.
Industry access to timely information on threats and vulnerabilities: A recognition that many entities have limited threat intelligence capabilities and access to information on threats.
Cloud/Managed Security Service Providers: A recognition that delegating trusted third parties to perform common services can have security benefits while also calling for more research to determine if the most critical systems, such as those used for real-time operations, could be moved to the cloud.
Adequacy of security controls: Although low-impact bulk electric system cyber systems (BCS) make up the majority of BES cyber assets, they are generally not subject to mandatory security controls. The simultaneous loss or degradation of a large number of these systems could have a significant impact. Many commission jurisdictional hydroelectric facilities and natural gas pipelines are not subject to mandatory cybersecurity controls.
Internal network monitoring and detection: Internal monitoring of protected networks is not required by NERC critical infrastructure protection (CIP) standards; a failure to conduct monitoring can allow attackers to move laterally within “trust zones.”

Staff identified the focus areas based on a review of public and nonpublic threat reports, significant cybersecurity events impacting industrial infrastructure and CIP standards.

“Staff will continue to monitor entities’ supply chain security implementation and use of trusted connections,” staffers said in a presentation at the commission’s open meeting Thursday. “Additionally, staff will monitor entities’ adoption of new technologies and services to address cyber infrastructure implementation [including] virtualization of systems and use of cloud-computing services. Staff will continue to gather information and work with regulated entities on these issues as well as potential modifications to the CIP standards, such as the security controls for low-impact BES cyber systems.”

Staff noted that OEIS offers voluntary network architecture assessments of electric, hydroelectric, natural gas and LNG facilities, working with other federal agencies such as the Department of Homeland Security, the Transportation Security Administration and the Coast Guard.

Hydro Security, Internal Monitoring

FERC said the additional security capabilities for OEP will build on the Security Program for Hydropower Projects, created in response to the Sept. 11, 2001, terrorist attacks and revised three times since.

“The program’s been enhanced over the years,” David Capka, director of the dam safety division, explained in response to a question from the chairman after the presentation. “However, when cybersecurity became part of the program, within OEP we had to rely heavily on experts outside our office. So, we relied on OEIS and OER to help us. And it quickly became clear that we needed in-house … expertise.”

Capka said the changes will have two benefits. “I think we’re going to have a much more robust security program with the expertise we’ve been able to bring on board. [And] we’re allowing our dam safety engineers to focus on dam safety now.”

OER’s Barry Kuehnle responded to a question from Commissioner Bernard McNamee about the need for internal network monitoring to prevent hackers from being able to make undetected lateral movement within a “trust zone.”

“If someone were to gain access [within a safety perimeter] — suppose they come in with a supply chain attack where you purchase a piece of equipment with a back door in it — you put that into the network, now it’s an authenticated piece of equipment … that potentially may end up … communicating with other equipment within that network,” Kuehnle said. “If you’re … looking for anomalies … you can catch that quicker and you’re able to address any type of security concerns.”

November 22, 2019

NERC Standards Committee Briefs: Nov. 20, 2019

The standards drafting team revising the requirements for determining and communicating system operating limits (SOLs) told the Standards Committee on Wednesday it may have broken an impasse that has slowed progress and expects to post the standard for industry comment by February 2020 (Project 2015-09: FAC-010, FAC-011, FAC-014).

SDT Chair Vic Howell said most sticking points have been resolved, but the team is still considering how to deal with the burden placed on industry by the logging and communication requirements relating to SOL exceedance. The team has been working with FERC and industry operators over the last nine months to revise the relevant language and reach consensus with the affected stakeholders.

“We’ve come up with something this morning that we think will address the FERC concerns, as well as those commenters who have been very concerned about the logging and communications administrative burden,” Howell said, without elaborating on the proposed solution.

In response to questions about the collection of industry data to support the SDT’s work, Howell acknowledged that the entities surveyed have been reluctant to share relevant information. As a result, the team created measures to ensure anonymity for the industry participants. In addition, the organizations used a variety of methods to collect and store data, which created challenges with synthesizing information in a useful format.

Some committee members questioned whether the team should make sure it has enough data from all industry players before it posts the proposals for comment next year. However, others noted that this could result in even more delays.

“People would have to put things in place today to start collecting winter [data], and then you’d have to wait for summer, and then you’d have to select a couple of off-peak scenarios. So that really would drag out the process another year,” said Howard Gugel, NERC director of engineering and standards. “Hopefully the drafting team has come up with a solution that … addresses the problem, without having to burden industry with a tremendous amount of data collection and data reporting.”

Consultants Removed from SDT Nominee List

Following a proposal to nominate 10 members to the PRC-005-6 SAR drafting team, Dominion Resources Services’ Sean Bodkin asked that two of the nominees — who, like the others, were not identified by name during the discussion — be removed on the grounds that they were consultants.

“When I go back and look at the policy from last year for including consultants on drafting teams, they’re supposed to add some particular technical expertise or something that the team is lacking,” Bodkin said. “In this case I don’t see … any specific technical expertise that they are adding that the other members of the team do not have.”

NERC Manager of Standards Development Soo Jin Kim said that the nominating team had considered this objection but concluded the two candidates’ backgrounds in generation would provide the team with valuable insights. In addition, one had previous drafting team experience.

Kim said that if the full slate of nominees was not approved, another round of solicitation would likely be needed to fill the two gaps on the team. Committee members saw this as an acceptable way to fulfill the requirements regarding drafting team membership.

“If NERC thinks it can achieve its needs by having an additional solicitation for nominees, that would definitely be my preferred option, rather than adding the two consultants,” said Sean Cavote of Public Service Enterprise Group.

Bodkin’s motion passed unanimously, and all nominees except the two consultants, including the chair and vice chair, were approved.

Impact of New NERC Committee

Gugel updated the committee on the expected results of the NERC Board of Trustees’ decision to merge the Operating, Planning and Critical Infrastructure Protection Committees (See Board O K s Committees Merger.) The merger would create a new body, tentatively called the Reliability and Security Technical Committee (RSTC).

Nominations for the new committee are currently being solicited. The RSTC will have 34 voting members: two each from sectors 1-10 and 12, 10 at-large members, and a chair and vice chair. The existing committees will conduct their scheduled meetings in December and March, with the new body taking over their functions by June.

“Probably the largest impact that has for us is that … the Standards Committee would be going to the RSTC for legal and technical support for SARs, as opposed to … the OC, PC or CIPC [as in the past],” Gugel said. “The standards [creation] process will [also] probably need to be revised to incorporate whatever methods the RSTC would like to set up.”

— Holden Mann

November 21, 2019

MISO, SPP Regulators Nibble Away at Seams Issues

By Tom Kleckner

SAN ANTONIO — State regulators working to improve MISO–SPP interregional planning processes and seams issues drew more than three dozen interested onlookers to their latest committee meeting on Sunday.

Continuing a trend for much of the last year, the SPP RSC/Organization of MISO States Liaison Committee held its meeting in conjunction with a conference of the National Association of Regulatory Utility Commissioners (NARUC). But that may soon be changing.

During a discussion on timelines, North Dakota Commissioner Julie Fedorchak echoed the frustration of several members when she said, “We don’t move quickly enough.”

Kansas Corporation Commissioner Shari Feist Albrecht, who leads the SPP side of the committee, agreed the group’s progress is slow, hampered in part by insufficient face-to-face time between the RSC and OMS members.

“It’s moving too slow,” she said. “I’m hoping we can develop a regular schedule of meetings going forward.”

MISO SPP — Commissioners Ted Thomas, Arkansas, and Shari Feist Albrecht, Kansas, lead the discussion. | © *RTO Insider*

The committee intends to rectify that situation by scheduling at least one meeting in early 2020, albeit possibly through the web, for an education session on SPP’s and MISO’s planning processes before NARUC’s next meeting.

FERC Commissioner Richard Glick was among those who sat in on the Nov. 17 meeting, being granted a seat at the table while others lined the walls. He declined to offer comments during the discussion but did address the session two days later during NARUC’s annual meeting.

“I appreciated being invited. It was a very interesting discussion,” Glick said during a Q&A session with outgoing NARUC President Nick Wagner. “It’s pretty apparent that we’re not necessarily building the transmission system that might be needed for the grid of the future. We’re not going to resolve those issues today. If we can do a better job of planning between regions, that would really be helpful.”

Three separate coordinated studies between the ISOs have failed to yield a joint project. Stakeholders have laid much of the blame on differences in modeling and criteria between the grid operators, which has led to market inefficiencies. (See MISO, SPP to Ease Interregional Project Criter i a.)

While meeting irregularly since last year’s creation, the liaison committee has gathered stakeholder feedback and commissioned the RTOs’ market monitors to analyze the seams issues. (See RSC, OMS Approve Moni t ors’ Seams Study.)

SPP’s Market Monitoring Unit finished a draft report on rate pancaking and unreserved transmission use in time for the meeting.

MISO’s Independent Market Monitor is scheduled to wrap a study on joint dispatch before year’s end. The IMM is also working on suggested changes to the market-to-market framework with the SPP-MISO joint operating agreement. The latter report may not be finalized until spring 2020.

The MMU’s analysis indicated removing duplicate transmission charges (rate pancaking) has a very limited effect on import and export volumes. The SPP Monitor said most transactions are “inelastic” to the market-clearing price and the majority of these transactions are already taking advantage of market import service in the SPP footprint and a comparable service in MISO.

Its study of SPP unreserved use charges since 2016 revealed they are unaffected by the SPP-MISO seam. The MMU said it could not quantify an impact of these charges on interchange volumes and “abstained” from providing an opinion on the current processes.

The work that lies ahead prompted Dana Murphy, chair of the Oklahoma Corporation Commission, to ask for clarification on just who various studies’ stakeholders are?

“My concern in general is who is asking the RTOs to do this background work?” Murphy said. “We have to be thoughtful in our communicating and what we are communicating.”

November 21, 2019

New Jersey Doubles OSW Target

By Christen Smith

New Jersey doubled its offshore wind goal on Tuesday, committing the Garden State to develop 7,500 MW of generation by 2035 in hopes of becoming the “nexus of the global offshore wind industry.”

Gov. Phil Murphy, flanked by First Lady Tammy Murphy and former Vice President Al Gore, signed the executive order at the Liberty Science Center in Jersey City — the latest development in the state’s march toward 100% clean energy by 2050.

“There is no other renewable energy resource that provides us with either the electric-generation or economic-growth potential of offshore wind,” Murphy said. “When we reach our goal of 7,500 megawatts, New Jersey’s offshore wind infrastructure will generate electricity to power more than 3.2 million homes and meet 50% of our state’s electric power need.”

New Jersey offshore wind — Offshore wind | *Avangrid*

In June, the New Jersey Board of Public Utilities selected Ørsted to develop the first 1,100 MW of offshore wind planned for the state. (See Orsted Wins Record OSW Bid in NJ.) Regulators will solicit bids for two more 1,200-MW projects in 2020 and 2022.

“As our federal government abdicates its responsibility to confront the climate crisis, our transition to a clean energy future is being led by states like New Jersey,” Gore said. “Today’s announcement couldn’t be more timely and more needed, as climate-related extreme weather events continue to wreak havoc on our communities. With this executive order, Governor Murphy is unleashing the unprecedented economic and job creating opportunities of clean, wind energy.”

The projects represent just a fraction of the potential researchers say offshore wind development holds along the Mid-Atlantic coast. University of Delaware Professor Willett Kempton said in April his analysis concludes a hypothetical buildout from New Jersey to North Carolina could add as much as 80 GW to the grid. (See Big Prospects for Offsh o re Wind in PJM.)

Companies, however, struggle with the logistics of building offshore wind generation in PJM. Anbaric Development Partners asked FERC on Monday to order the RTO to allow developers of offshore transmission “platforms” to obtain injection rights, saying PJM’s Tariff violates the commission’s open access requirements and is discriminatory. (See Anbaric Seeks FE R C Help on OSW Tx.)

The transmission developer said it was forced to file its complaint after a stakeholder initiative to consider changing PJM’s rules stalled in September. (See “PJM Recommends Sunsetting Offshore Wind Special Sessions” in PJM PC/TEAC Briefs : Sept. 12, 2019.)

Liz Burdock, CEO of the Business Network for Offshore Wind, said up to 8,240 MW of offshore wind projects are currently under development on the East Coast, with “steel in the water” promised by 2026. New Jersey’s latest commitment will further encourage investment in the industry’s component manufacturing inside the U.S. — a major boon for the national economy.

“This additional 3,500 MW will accelerate the development of the state’s offshore wind industry and supply chain, and will translate into more economic opportunities, and more jobs, up and down the New Jersey coastline,” she said.