NERC and the regional entities are proposing almost $207 million in spending in 2020, a 3.8% increase. Assessments are projected to increase by 2.9%.
The Electric Reliability Organization Enterprise budgets include a 9.8% spending increase for the Midwest Reliability Organization, which is absorbing the former SPP Regional Entity’s compliance enforcement duties, and a 35.2% jump for SERC Reliability, which is expanding to peninsular Florida with the phase out of the Florida Reliability Coordinating Council. (See FERC OKs SERC’s Expansion into Florida.)
Including the elimination of about 21 jobs at FRCC, and the addition of 20 at SERC, total ERO Enterprise headcount is projected at about 698, an increase of about 18.
The preliminary budgets were presented to the Board of Trustees’ Finance and Audit Committee (FAC) meeting Thursday. Final draft budgets will be posted July 15 and discussed at a July 18 FAC webinar. The board is scheduled to approve the budgets on Aug. 15 and submit them for approval by FERC and Canadian authorities Aug. 26.
The Compliance Monitoring and Enforcement Program (49%) and Reliability Assessment and Performance Analysis (18%) account for two-thirds of the ERO Enterprise’s spending.
NERC’s proposed budget is almost $83 million, a 3.8% increase driven by a 13.3% boost in spending for the Electricity Information Sharing and Analysis Center (E-ISAC). Excluding the E-ISAC — which will account for 11% of the ERO Enterprise budget and 27% of NERC’s — the organization’s spending will decrease slightly. (See “E-ISAC Continues Growth,” NERC Technology & Security Committee Briefs: May 8, 2019.)
In presentations to the committee, the REs projected salary inflation of about 3 to 3.5%, and benefits increases ranging from about 5 to 6% for MRO and SERC to 14% for Texas Reliability Entity.
TRE is also projecting its rent and utilities costs will increase nearly 28% when it renews the lease on its Austin headquarters in late 2020.
ReliabilityFirst’s budget, which is increasing 4.4%, includes funding for “overlap” hires to prepare for the departure for retiring employees. About 11% of RF’s employees are at or over retirement age.
SERC is projecting a 35% increase in meeting and travel costs related to the addition of the FRCC entities and the expansion of its board Executive Committee to 15 from 12.
MISO’s effort to improve a key communication system will come too late to smooth summertime emergency procedures, stakeholders said last week.
In post-mortems of a January emergency event in which less than a quarter of load-modifying resources (LMRs) performed to the RTO’s criteria, multiple stakeholders complained the MISO Communications System (MCS) was difficult to understand and navigate.
The poor generator performance resulted in MISO last month issuing market participants nearly $2 million in penalties and disqualifying 21 LMRs for the remainder of the 2018/19 planning year. (See “MISO: $2 Million in Penalties for Jan. 30 LMR Underperformance,” MISO Reliability Subcommittee Briefs: May 2, 2019.)
During a Reliability Subcommittee (RSC) conference call Thursday, Chair Bill SeDoris said the low LMR success rate in January is evidence of “serious procedural issues on both sides of the house.”
Customized Energy Solutions’ Ted Kuhn criticized the RSC for scheduling MCS improvement discussions for the third quarter, saying MISO is likely to call multiple summertime emergencies using an inadequate system while market participants wait on improvements.
“The current MCS is not sufficient. … Some of these things need to get fixed,” Kuhn said. Other call participants repeated the plea for quicker improvements.
SeDoris said MISO’s nonpublic Reliable Operations Working Group (ROWG) has taken up short-term improvements, including clearer communication when the RTO terminates a maximum generation alert.
Ron Arness, MISO director of Central Region operations, said the ROWG had a “healthy” discussion on how to improve usability of the MCS on Wednesday.
“There are some changes coming; those changes aren’t going to occur overnight. … Be patient with us,” Arness said.
But stakeholders say a mid-May emergency in MISO South already illustrates that the MCS is ill-suited for emergency communications. WPPI Energy economist Valy Goepfrich said when MISO called the May 16 maximum generation alert, it wasn’t clear the alert only extended to the South region.
MISO South May Emergency
MISO said the five-hour May 16 emergency was atypical, the result of a higher-than-normal forced outage rate combined with above-average temperatures and the usual spring maintenance season.
“While unplanned outages are expected, the successive loss of [about] 4 GW of generation in a short period of time is outside normal expected operating conditions,” MISO said.
Outages and derates in MISO South reached 16.6 GW that day, and load obligations hit a peak of about 27 GW around 5 p.m. MISO said it was able to maintain reliability through two separate calls for LMRs with lead times of three hours or fewer. The RTO will provide LMR response data at a later date.
MISO South May 16 emergency (megawatts) | MISO
Arness said MISO South frequently experienced tight capacity conditions over the last three weeks of May.
The RTO expects tight operating conditions in South through June due to hotter weather and continuing maintenance activity. Arness told stakeholders to be prepared for more emergency alerts in the region.
Goepfrich noted that MISO didn’t come close to hitting the North-South transfer limit during the event and asked that it ensure that transfer capability is used before it calls on LMRs.
Outage Exemption Talk Ongoing
MISO last week also said it will expand a penalty exemption to include resources that return early from a planned outage, part of new outage scheduling rules.
The RTO will exempt resources from accreditation penalties if the start and end date of their submitted outages remain within 10% of the originally scheduled outage window “and/or [the resource] reduces the capacity of the outage” to provide MISO with more available capacity.
MISO originally proposed that unit owners submit a new outage request for both extended and shortened outages to allow it to evaluate the request based on maintenance margin supply predictions, putting a resource’s penalty exemption at risk. Units earn penalty exemptions if they schedule an outage at least four months in advance. However, stakeholders questioned the potential for MISO to revoke the penalty exemption on even shortened outages. (See “MISO Taking Second Look at Outage Change Penalties,” MISO Reliability Subcommittee Briefs: May 2, 2019.)
Jeanna Furnish, MISO manager of outage coordination, said the RTO still seeks to discourage “bad behavior” when participants schedule planned outages. She said significant shortening of outages impacts MISO data and forecasting and affects other available megawatts.
“We want the best information we can get about your outage schedule. We want you to return early if you reliably can … but we want to acknowledge this isn’t a free pass to schedule the longest outage you can then reduce,” Furnish said.
Some stakeholders still weren’t satisfied with MISO’s compromise.
“You’re creating a huge disincentive for generation to shorten their outages,” CES’ David Sapper said.
Furnish said she rarely sees generation return significantly early from outages, adding that many generators actually lengthen planned outages.
MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO is seeking to “strike a balance” to prevent generators from scheduling longer-than-necessary outages simply for the wiggle room.
Furnish put the 10% proposal to a round of feedback and encouraged stakeholders to offer exemption alternatives.
RENSSELAER, N.Y. — NYISO stakeholders on Thursday debated the content of a draft study on the impact of public policy on the New York grid and learned about the ISO’s proposed changes to its carbon price calculation.
The draft “Reliability and Market Considerations for a Grid in Transition” study comes after New York Gov. Andrew Cuomo in January nearly quadrupled the state’s offshore wind energy goal to 9 GW by 2035, while his proposed Green New Deal would mandate 100% clean power by 2040, increase renewable energy requirements from 50% to 70% by 2030, and require other clean energy benchmarks. (See New York Boosts Zero-carbon, Renewable Goals.)
“What we try to do in the report is to describe the challenges and fill in the gaps,” Mike DeSocio, the ISO’s senior manager for market design, told the Installed Capacity/Market Issues Working Group.
NYISO first presented an outline of the new study, which analyzes the projected Bulk Power System in 2030 and 2040, at the group’s April 15 meeting. (See NYISO Studies Grid Transformation, Fuel Security.)
| NYISO
“The ISO would be better off looking at what the market will be like in five years and not spend too much time preparing for 15 or 20 years down the road,” said Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers.
DeSocio agreed but said some of the needed investments are long-term.
“I think looking at 2030 and 2040 is important, at least to provide reality checks on what people are planning,” said Mark Younger of Hudson Energy Economics. “NYISO needs to go out to 2040 and assume all-renewable generation, then do a multiday analysis of very little wind or solar, which would provide you a good snapshot of what you need for backup if you rely upon fossil generation compared to what you would need if you relied upon storage as backup.”
Noting that the state recognizes a carbon-reduction imperative that the market does not, David Clarke, director of wholesale market policy for Power Supply Long Island, suggested that NYISO’s study consider how to optimize various as-bid resources and other alternatives to achieve the state’s targets. He noted that whether carbon pricing is ratified or not, “sequestration might be a better way to achieve the goals cost-effectively rather than other approaches, including carbon pricing.”
Andrew Antinori, senior director of the New York Power Authority’s Market Issues Group, asked whether it would be more efficient for the ISO to see whether or not a carbon charge will be implemented before expending resources studying different possible futures.
Howard Fromer, director of market policy for PSEG Power New York, asked whether the ISO has looked at using external resources to provide reserves.
“It seems the movement of resources across borders is going to become more important,” Fromer said. “I know we don’t currently have any projects to look at that, but it seems important to look at the whole seam issue and see how to access those resources.” (See NY Carbon Task Force Discusses Seams, ‘Leakage’.)
DeSocio agreed that external resources do fit into the picture.
“We’re probably going to need additional transmission, but it’s got to be strategic, and we’re probably going to need additional capacity, but it’s got to be strategic,” DeSocio said. “We need to get the energy prices right … that’s what it’s about here. … My bias is not to spend a lot of time on expanding new capacity products; that’s a pretty blunt instrument.”
The ISO’s timeline is to get an updated report out by the end of summer and add some quantitative analysis ahead of the Board of Directors’ strategic planning session in September, DeSocio said. By the end of June, the Analysis Group will provide preliminary analyses from a different study examining the market impacts of pricing carbon and will complete its report by the end of July, he said. (See More Details Divulged on New NYISO Carbon Pricing Study.)
Carbon Pricing: Calculating the LBMPc
After considering stakeholder feedback, NYISO has revised its proposed calculation of the carbon component in locational-based marginal prices (LBMPc), now subtracting a variable operations and maintenance (VOM) cost from the LBMP. The resulting value will then be divided by the estimated marginal fuel cost ($/MMBtu) plus the cost of emissions ($/MMBtu).
“Adding the cost of emissions was suggested by a few stakeholders last time to arrive at a more realistic heat rate,” said Ethan Avallone, the ISO’s technical specialist in energy market design who presented the analysis.
As discussed in previous meetings, NYISO will set the LBMPc to zero when the calculated LBMPc is less than zero and set the implied heat rate to zero when the calculated implied heat rate is below the minimum implied heat rate. (See Carbon Pricing Impact on Waste-to-Energy Examined.)
“We will use the LBMPc to allocate the carbon credit to [load-serving entities] and to prevent leakage and distortion of regional flows by charging imports and crediting exports the LBMPc, and also to provide market transparency,” Avallone said.
LBMPc calculation – fuel indices by region | NYISO
Internal generators are charged based on their actual emissions — not the LBMPc.
The implied heat rate produced by the calculation should be limited by a minimum and maximum to maintain an appropriate LBMPc, Avallone said. Absent a maximum value, the impact of shortage pricing on the LBMP could result in an inappropriately high implied heat rate; without a minimum, the impact of renewable generation on the LBMP could result in an inappropriately low heat rate.
The implied heat rate should be set to zero when less than the minimum limit and set to the maximum when above the maximum limit, Avallone said. A low implied heat rate indicates that zero-emission energy, which does not bid opportunity cost, is likely marginal.
NYISO would post minimum and maximum heat rates on its website and is considering stakeholder feedback to describe potential future revisions to eligibility criteria, he said.
In addition, the ISO will post the effective social cost of carbon (SCC), as determined by the state’s Public Service Commission.
The net SCC would be the gross SCC, established by the commission, minus the Regional Greenhouse Gas Initiative price.
Avallone also presented a summary of proposed Tariff changes to accommodate a carbon pricing regime, with new sections to describe carbon charges, payments and residual allocation.
NYISO is considering stakeholder feedback to describe potential future revisions to eligibility criteria and plans to review the proposed Tariff changes again at the June 11 ICAP/MIWG meeting, Avallone said. (See “Tariff Terms, Penalties,” NYISO Commissions New Social Cost of Carbon Study.)
Illustrative change in revenues, 1×1 gas combined-cycle, assuming new entry is needed | NYISO
Enhanced Fast-start Pricing
In response to a FERC order, NYISO is revising fast-start pricing to apply to all resources that can start up and synchronize to the grid in 30 minutes or less, have a minimum run time of one hour or less, and submit economic offers for evaluation.
The commission on April 18 ordered the ISO to revise its pricing logic to reflect the start-up costs of fast-start resources and relax the economic minimum operating limits of all fast-start resources by up to 100% to allow them to set prices (ER18-33). (See FERC Orders Fast-start Rules for PJM, NYISO.)
Under the proposed changes, “we use special pricing logic to better reflect the true cost of energy,” said Whitney Lesnicki, an ISO manager for energy market design, who presented the enhancements.
The ISO must submit its compliance filing by Dec. 31 and implement the changes by Dec. 31, 2020.
PJM presented a first read of its annual Manual 6 cover-to-cover review regarding financial transmission rights.
Brian Chmielewski, manager of market simulation, said staff are continuing their look into rule changes around FTR mark-to-auction credit requirements detailed in Section 6.7, but they’re moving ahead with default settlement rule updates, realignments to the OASIS refresh and the hourly cost component change, pending FERC approval.
Manuals Endorsed
Manual 01: Control Center and Data Exchange Requirements as a part of the cover-to-cover review.
Manual 03: Transmission Operations as a part of a cover-to-cover review.
Manual 07: PJM Protection Standards to update applicability references and an Institute of Electrical and Electronics Engineers standard reference.
Manual 11: Energy & Ancillary Services Market Operations and Manual 13: Emergency Operations to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
Manual 13: Emergency Operations as part of a cover-to-cover review.
Manual 36: System Restoration as a part of a cover-to-cover review.
CAISO is postponing stakeholder initiatives on day-ahead market enhancements and storage-as-transmission assets (SATA), while adding four new initiatives as part of its 2019 annual plan.
The day-ahead market enhancements initiative has been postponed in response to stakeholder requests for more time to implement required changes, CAISO said in an update posted Wednesday. The effort aims to replace the day-ahead market’s current one-hour scheduling with a 15-minute granularity to improve handling of net load variability in real time. (See CAISO Says Changes Will Better Match Forecasting, Demand.)
“Grid infrastructure has advanced, the resource fleet has changed and the policies regulating operation of the grid have evolved (i.e., FERC mandated 15-minute scheduling in real-time energy markets). As a result, hourly scheduling granularity is no longer the most efficient way to schedule resources,” the ISO said in its straw proposal for the initiative.
CAISO’s control room in Folsom, Calif. | CAISO
As a byproduct of the initiative, CAISO is proposing to alter the Western Energy Imbalance Market to require participants to submit base schedules with a 15-minute granularity instead of the current one-hour.
“The use of hourly base schedules was originally chosen to align with the CAISO’s hourly day-ahead schedules, which were the reference point for imbalance energy,” the ISO said.
While EIM participants are generally supportive of the change, they’ve also cautioned CAISO that they need more time to comply with it.
In its April 1 comments on the ISO’s third straw proposal, for example, EIM member Arizona Public Service wrote that “while APS is supportive of moving to 15-minute scheduling and bidding granularity, these changes will require significant software and system changes, and will likely require modifications to EIM entities’ internal business processes. Sufficient time must be included in the implementation schedule for these system upgrades.”
NV Energy noted that the scheduling changes will require EIM members to revise their open access transmission tariffs (OATTs).
“NV Energy requests that the EIM entity OATT amendments be coordinated with the CAISO Tariff amendment for this market enhancement. It will be necessary for the CAISO Tariff to be approved with ample time for the EIM entities to file OATT amendment changes with FERC,” the utility said. It and founding EIM member PacifiCorp also urged CAISO to provide market participants 60 days to test the 15-minute functionality before implementation.
Northern California Power Agency (NCPA) also expressed concerns about the speed of the effort, contending the ISO “has exhibited a tendency to release major market changes that contain material deficiencies that have to be corrected over time.” Such an approach can have “financial consequences” for market participants, it warned.
“As such, NCPA believes the implementation timeline being considered will need to be adjusted to include very robust structured and unstructured market simulations, based on a clearly defined set of measurable and verifiable milestones, managed in close coordination and collaboration with stakeholders prior to releasing the changes into the production environments,” it said.
SATA Deferred
The storage initiative is being deferred until 2020 to provide time for the resolution of storage-dispatch policy in CAISO’s energy storage and distributed energy resources initiative phase 4 (ESDER 4). Phase 4 “will explore refinements to the distributed energy resource and storage participation models, as well as lower integration barriers for demand response resources,” the ISO said. (See CAISO Updates ESDER Phase 3 Proposal.)
“The scope of this initiative is to enable storage providing cost-based transmission services to also participate in ISO markets and receive market revenues to provide additional ratepayer benefits and provide greater flexibility to the grid,” CAISO wrote in its second revised straw proposal in October 2018.
New Additions
Meanwhile, CAISO said it’s adding four new measures to its 2019 roadmap:
Its new hybrid resources initiative will address issues related to solar-plus-storage in “forecasting, operations, resource adequacy and market design to provide for storage dispatch resolution in ESDER 4.”
A second initiative will address an “inefficiency” in the allocation of the real-time market neutrality settlement charge, which is currently calculated based on the sum of instructed and uninstructed imbalance energy, unaccounted for energy and greenhouse gas awards. The charge is allocated to settlements based on an offset calculated for each LMP component. The initiative proposes to eliminate the transfer of the real-time imbalance energy offset between EIM balancing authority areas, remove the GHG awards from the real-time market neutrality and create a GHG-specific neutrality allocation.
An intertie bid cost verification initiative will seek to align “intertie resource requirements with internal resources under FERC Order 831,” which directs ISOs and RTOs to cap resources’ incremental energy offers at the higher of $1,000/MWh or the resource’s verified cost-based incremental energy offer. FERC issued the order in November 2016 after wholesale power prices spiked during the winter storms of 2013/14 and generators said they could not recover their costs. (See CAISO Developing New Bidding Rules.)
A capacity procurement mechanism (CPM) initiative is meant to update the soft offer cap and consider 12-month pricing for CPM designations.
The five members of the California Public Utilities Commission on Thursday unanimously approved wildfire mitigation plans filed by the state’s three large investor-owned utilities in response to last year’s Senate Bill 901.
But they warned that hardening the grid against fires and climate change could be an immense and extremely expensive undertaking.
CPUC President Michael Picker cited Pacific Gas and Electric’s plans to spend $237 million to expand its use of covered conductors along 150 miles of its overhead lines in 2019.
“Assuming that the 7,100 miles of PG&E’s system located in Tier 3 high-fire-threat areas is eventually covered, the magnitude of future general rate case costs could be enormous,” Picker said.
California’s investor-owned utilities have plans to de-energize transmission and distribution lines during high winds in areas of extreme (red) and elevated (yellow) fire risk. | CPUC
PG&E also intends to clear 305,000 hazardous trees near its lines at an estimated cost of $1.3 billion, he said.
The CPUC announced a series of public hearings Tuesday to consider PG&E’s request for a $2 billion rate hike over the next three years to cover wildfire prevention measures.
On Wednesday, a panel convened by Gov. Gavin Newsom — the Commission on Catastrophic Wildfire Cost and Recovery — issued a draft report and scheduled a June 7 hearing in Sacramento. Its recommendations include replacing the state’s strict liability standard for utilities when electrical equipment starts wildfires — called “inverse condemnation” — with a negligence standard. (See Calif. Must Limit Wildfire Liability, Governor Says.)
PG&E filed for bankruptcy in January, saying it faced at least $30 billion in liability for fires in 2017 and 2018, including the Camp Fire, the deadliest in state history. Southern California Edison also faces massive liability for its equipment’s role in starting the fatal Thomas Fire in 2017. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
On Thursday, the CPUC approved a proposed decision providing guidance on wildfire plans submitted under SB 901 along with individual decisions on each of the 2019 plans submitted.
In its plan, SCE said it will inspect 450,000 pieces of equipment by the height of the 2019 fire season, Picker said.
“It’s unclear how Southern California Edison can perform detailed inspections of this volume of equipment in so short a time,” he said. “But without better data and a stronger record, we’re not prepared to stop SCE from carrying out its new inspection program. It is required under SB 901 to prove the effectiveness of its inspection program.”
Picker said the commissioners want to make sure that SCE isn’t just doing drive-by inspections or duplicating routine inspections.
Both PG&E and SCE, the state’s first- and second-largest utilities, are playing catchup with smaller San Diego Gas & Electric, which has been hardening its grid and installing cameras and weather stations for a decade in response to catastrophic fires in 2003 and 2007.
While often cited as a model, SDG&E has far less territory to cover than PG&E or SCE, whose systems cover 70,000 and 50,000 square miles respectively. SDG&E’s service territory is 4,100 square miles. (See California Utilities Prepare, as Fire Season Looms.)
“In congratulating SDG&E, I don’t want to underestimate how long it’s going to take for the other utilities to get to that scale,” Commissioner Liane Randolph said. “I just want to make sure that we’re mindful of the heavy lift in terms of expense and time that it’s going to take to implement these plans, and as they get updated in the coming years.”
The CPUC also approved the wildfire mitigation plans of several smaller utilities in California: PacifiCorp, Liberty Utilities and Bear Valley Electric Service. The utilities’ lines run through high-fire-risk areas, commissioners said.
“It’s critical that these utilities have robust and effective mitigation plans as well,” Commissioner Clifford Rechtschaffen said.
Transmission owners NextEra Energy and Trans Bay Cable also had to file wildfire mitigation plans, which the commission approved.
Trans Bay operates a cable that runs under San Francisco Bay and said its cable was “fire-hardened by virtue of being located underwater,” Picker said.
In a separate item on utilities’ plans to de-energize lines in hazardous weather conditions, commissioners insisted that the tool be used only as last resort and not to avoid liability.
De-energization “presents its own safety and health risks,” especially to those who rely on electricity for medical equipment, Rechtschaffen said.
With about six months left before it seeks approval, MISO is polishing a draft 2019 Transmission Expansion Plan (MTEP) that could end up being one of the RTO’s most expensive buildout packages.
The draft so far contains 518 new projects at $4.3 billion to be recommended for approval. Included are 65 new projects valued at $771 million up for consideration in MISO South, stakeholders learned Wednesday at a subregional planning meeting.
MTEP 19 is so far clocking in at $1 billion more than the $3.3 billion, 442-project MTEP 18. (See MISO Board OKs Full MTEP 18 over Stakeholder Complaints.) MTEP 11, which contained the Multi-Value Project portfolio, holds the record for the most expensive proposal at $6.5 billion.
The highest-cost MTEP transmission projects in recent years have been in MISO South, which held five of the top 10 most expensive projects in MTEP 16 and MTEP 18, and eight of the top 10 costliest in MTEP 17.
MISO South Replacement Project
One of the priciest MISO South projects recommended in MTEP 19 will negate the need for two costlier projects approved for southern Louisiana the two previous years.
Cleco and Entergy’s proposed $81.5 million joint project near Lafayette can replace the North and East Acadiana Load Pocket (ALP) transmission projects that were set to cost a combined $213.1 million.
MISO engineer Patrick Jehring said the replacement Sellers LeBlanc project is poised to save customers $131.6 million, and the cost difference is the only “differentiating factor” between the projects. He said MISO supports the withdrawal of the ALP projects.
He praised Cleco and Entergy for working together on a lower-cost solution.
“This is really a good story to tell, and really only happened because of … significant collaboration between entities,” Jehring said. “The only way we got here is through engagement with Cleco, Entergy and the Lafayette Utilities System.”
The Sellers LeBlanc project involves a new 19-mile 138-kV line and a series reactor on an existing nearby 138-kV line for $66.7 million from Entergy. Cleco will take on the remaining $14.8 million by tying the new line into an existing 138-kV line and constructing a new autotransformer.
The project will resolve the overloading risk of multiple 138-kV lines around Lafayette. Additionally, MISO said there is approximately 300 MW of load in the Abbeville, La., area served by just one 230-kV line.
“It’s pretty obvious that we want to go with the cheaper project,” Jehring said. “We’ve truly identified the least-cost solution here.”
Jehring encouraged stakeholders to provide written feedback on the proposed project.
Issues in the Lafayette, La., area | MISO
Shortlist from MCPS
Meanwhile, MISO’s 2019 Market Congestion Planning Study (MCPS) has identified a short list of potential projects, with seven project candidates proposing to solve three separate issues making the first round of screening.
Three 345-kV projects ranging from $32 million to $85 million propose to solve congestion issues on the Helena-to-Scott County 345-kV line in southern Minnesota. MISO Economic Studies Engineer Karthik Munukutla said all three solutions are potentially eligible for market efficiency project categorization and cost sharing.
Two projects — a $58 million, 161-kV line rebuild and a $20 million new substation — are proposed to solve congestion on a 161-kV flowgate on the Iowa-Nebraska border. Finally, two new 115-kV lines at either $35 million or $37 million are competing to solve congestion on a 115-kV flowgate in southwest Arkansas. Munukutla said the four projects deal with MISO-SPP seams issues and will be added to the RTOs’ ongoing coordinated system plan study to see whether they’d make beneficial interregional projects.
Munukutla said he wanted to share preliminary MCPS results so stakeholders get an idea of which projects stand to provide the most value after initial transmission analyses. He said MISO expects to have more certainty in July about what projects may be selected from the study.
HOUSTON — It wasn’t too long ago that Michael Skelly was at the forefront of an effort to develop long-haul transmission lines to ship power from remote wind farms in SPP to urban centers to the east.
Skelly’s Clean Line Energy Partners, which he founded and led, was developing five projects capable of carrying 16.5 GW of energy. The future seemed bright.
He’s now on the outside looking in. Clean Line has sold off its projects, its employee count is down to zero, and Skelly has taken a senior adviser role for Lazard Asset Management.
Asked how he is doing during a panel discussion at the American Wind Energy Association’s WINDPOWER 2019 conference this month, Skelly responded, “I’m very happy.”
But Skelly exhibited new regrets over his failure to complete a long-haul, high-voltage project. He’s said Clean Line wasn’t able to “win the World Cup of transmission,” but that’s not to say someone else won’t.
“Hopefully, the second mouse gets the cheese in the transmission world,” he said, using the proposed $2.6 billion, 1.5-GW Cape Wind offshore site off Massachusetts as an example. Cape Wind was abandoned in 2017, but developers expect the nation’s 30 GW of offshore capacity to exceed 2 GW by 2030. Another 25 GW sits in the development pipeline.
“Transmission is super hard. We’re not really in the mood right now to do these giant projects in the United States,” Skelly said. “These things change. We’ll look back in 100 years. There’ll be times we didn’t do a lot of infrastructure; there are times we did a lot of infrastructure. Hopefully, the country will be in a better mood and ready to do these big-bone transmission projects.”
Coincidentally, Pattern Energy CEO Michael Garland sat at the other end of the panel. Pattern last year bought Clean Line’s interests in the Mesa Canyons Wind Farm and Western Spirit Clean Line projects in New Mexico. It has already reached a $285 million agreement with PNM Resources to sell Western Spirit once it’s completed in 2021.
“They’ve pushed forward with development,” Skelly said of Pattern. “Clearly it’s a new model, and that’s exciting.”
Clean Line sold another of its projects, the Grain Belt Express in the Upper Midwest, to Invenergy, contingent upon approval from Missouri regulators. The Public Service Commission has already approved the line after several earlier failed attempts and is now deliberating the sale.
Clean Line Energy Partners’ projects | Clean Line Energy Partners
The state’s most recent legislative session ended without eminent domain legislation, another positive for the $2.3 billion, 780-mile project that would connect Kansas’ bountiful wind energy with population centers on the other side of the Mississippi River.
“It’s survived several attempts to kill it,” Skelly said.
NextEra Energy Resources has acquired Clean Line’s Plains & Eastern Clean Line assets in Oklahoma. The Rock Island Clean Line was killed by Iowa legislation that made above-ground HVDC transmission projects illegal, Skelly has said.
Still, he remains optimistic about the wind energy business, pointing to decreasing costs and increased hunger for renewable energy.
“There’s a huge supply chain of service folks that really know how to do these things, and that will help us to be more flexible,” Skelly said. “There’s a bunch of states now that want 100% renewable energy. I think we’re on a great path, and for the younger folks just getting started in the industry, it’s going to be interesting.”
NERC is looking for a new CFO and general counsel, allowing CEO Jim Robb to reshape the organization’s senior management as he enters his second year on the job.
The Electric Reliability Organization announced on Tuesday that Scott Jones — its CFO, chief administrative officer and treasurer — had resigned and that General Counsel Charles “Charlie” Berardesco would be retiring in August.
There was no indication that Jones was on his way out earlier this month, when he gave several presentations at the quarterly meetings of the Board of Trustees and Member Representatives Committee in St. Louis. Berardesco also made no public mention of his retirement plans at the meetings. (See NERC MRC, Trustees Meeting Briefs: May 8-9, 2019.)
“I heard Scott was being forced out and they’re giving Charlie a retirement party,” one former senior NERC official who is still in contact with former colleagues said in an interview. “When you see two senior guys leaving at the same time, it’s clear somebody’s cleaning house.”
Berardesco, who joined NERC in 2012 from Constellation Energy, will retire on Aug. 31, NERC said. He served as acting CEO for about five months after the November 2017 resignation of former CEO Gerry Cauley following his arrest on domestic abuse charges in an incident involving his then-wife.
Robb joined NERC from the Western Electricity Coordinating Council in April 2018.
The former official said that Robb was selected by the board as “an independent guy who could come in and do what was necessary to take NERC into the future” after Cauley’s departure. “I’m sure he’s taken this last year to learn and evaluate any dysfunctions within the company.”
But Jean Cauley, Gerry Cauley’s ex-wife, said she suspects the moves may have been orchestrated by the board after Ken McIntyre, NERC’s vice president of standards and compliance, left the organization in March after less than three years.
Jean Cauley and the former NERC official said McIntyre was well regarded and was being groomed by Gerry Cauley as his successor.
“The board would have done a follow-up. They wanted to know why [McIntyre left]. If he told them, they would have started things rolling,” Jean Cauley said. McIntyre did not respond to a request for comment.
Jean Cauley said Berardesco and Jones had attempted to prevent her and staff from talking to board members about management problems at NERC after Gerry Cauley’s arrest for assaulting her.
She told police that her husband pushed her into a wall and a bathtub after she discovered him having cybersex with a “young female employee of his.” She suffered a broken spine in the assault and now needs a walker. Gerry Cauley resigned about a week after the incident. (See Cauley Resigns; NERC Launches Search for Replacement.)
“Scott was telling everybody I was unbalanced and a nut case and not to be believed,” Jean Cauley said in an interview.
“The board finally wised up and started seeing some of the deceit that’s been going on at NERC for years,” Jean Cauley said.
Cauley and several former NERC employees have described Berardesco as an abusive manager.
“Charlie is flat-out mean. He yells. Throws things,” she said.
“He was pretty rough on people,” the former executive said. “One of Charlie’s favorite things to say was, ‘I have more money than God.’ … If he liked you, you were fine. lf he didn’t like you, it was hell on wheels.”
NERC’s announcements gave no indication of any dissatisfaction with either Jones or Berardesco, neither of whom responded to RTO Insider’s requests for comment.
“Charlie has done an outstanding job during his tenure at NERC,” Board Chair Roy Thilly said in a statement. “He was instrumental in leading NERC as interim CEO during our time of transition.”
Jones, who joined NERC in December 2014 as senior director of finance, was promoted to vice president of finance in May 2016 and CFO in August 2017.
“During his tenure, Scott elevated the caliber of our financial processes and procedures and brought a high level of expertise to our accounting and budgeting processes that will benefit NERC and our many stakeholders well into the future,” Robb said in a statement.
NERC said Controller Andy Sharp will serve as interim CFO, responsible for oversight of business plans and budgets and day-to-day financial administration, while the organization searches for Jones’ successor.
With the latest moves, NERC will have replaced three of its top officials since Cauley’s departure. Senior Vice President and Chief Security Officer Marcus Sachs, then one of seven direct reports to CEO, was forced out in November 2017 and replaced by Bill Lawrence. (See NERC Parts Ways with Chief Security Officer.)
NERC’s proposed 2020 business plan also reduces Robb’s direct reports to five from eight. Two direct reports were reduced to one with Lawrence’s appointment. Michael Walker, a direct report as SVP/chief enterprise risk and strategic development officer, now is chief of staff for the E-ISAC. Also eliminated as a direct report was Tina Buzzard, the associate director to the office of the CEO, Cauley’s former administrative aide.
At its meeting in May, the board announced the appointment of two new vice presidents: Howard Gugel, director of engineering and standards, and Mechelle Thomas, chief compliance officer.
The key players in the Western reliability coordinator transition said Wednesday they’re largely on track to take over from Peak Reliability on a staggered timeline from July to December.
“Overall, our project is on schedule, and we’re making changes needed to be ready in August,” Bruce Rew, SPP’s vice president of operations, told the Western Electricity Coordinating Council’s RC Forum in a web-only meeting.
SPP and CAISO will be the main RCs for the Western states, while BC Hydro will assume responsibility for most of British Columbia. Gridforce will serve several small balancing areas in Arizona, Oregon and Washington. Alberta Electric Service Operator will continue performing the RC function in its province, rounding out the Western Interconnection.
Each entity provided an update on its progress Wednesday, and Peak described its gradual wind down as it exits the RC business this year.
CAISO and SPP are taking over RC responsibilties in most of the West this year. | CAISO
CAISO’s RC West will start the handoff when it takes over RC services for its California territory July 1. The ISO is awaiting final certification from NERC, which it expects to receive “any day now,” Tim Beach, RC West’s director of operations told the forum. (See RC West Moving Smoothly Toward July Handover.)
RC West staff members are in the second phase of shadowing Peak employees and have already been involved in problem situations, including a high-voltage event last weekend in California that required switching a transmission line out of service to mitigate the problem, Beach said.
After July 1, RC West will be preparing for Nov. 1, when it assumes the RC role for most of the West; 39 entities have contracted for its services from the Canadian border to northern Baja California and from the Pacific Ocean to the Rocky Mountains.
SPP has agreements with 13 customers, 11 of which have completed connecting with SPP, Rew said. The utility will start its certification process with WECC and NERC in August in anticipation of going live Dec. 3. (See SPP on Track for WECC RC Certification.)
Gridforce President C.J. Ingersoll said that as a relative newcomer, the company is in “catchup mode” but with its small footprint, things should work out fine.
“Our target go-live date is Dec. 3, and we feel like we’re on track there,” Ingersoll said.
Asher Steed, BC Hydro’s manager of provincial reliability coordination operations, said the company’s employees will start shadow operations with Peak on July 8 as it ramps up for its Sept. 2 start date.
Peak said all is going as planned on its end. Losing key staff members was a major concern earlier this year, but the company’s retention policies, including severance packages, appear to have worked, Chief Administrative Officer Rachel Sherrard said.
“We’ve had some unplanned attrition. Not a lot.” The company has shrunk from more than 160 employees in May 2018 to 119 today, she said.
Peak will start decertifying Dec. 4, vacate its offices in Vancouver, Wash., and Loveland, Colo., and cease to be a company by May 2020.
Eric Whitley, a grid expert from Folsom, Calif., who serves on WECC’s RC Transition Coordination Group, said “Peak will not be operational after the last transition on Dec. 3. There’s no going backwards,” he warned. Peak has posted a banner on its website showing the countdown to when it ceases operations.
The forums will continue every two or three months, as needed, Whitley said.
“It’s going to be a very active rest of the year,” he said.
