Page 1172 – RTO Insider

May 4, 2018

NYISO Study Identifies Key Areas of Tx Congestion

By Michael Kuser

Preliminary results from a biennial NYISO study show high congestion in three areas of the New York bulk power system, mainly in the eastern part of the state, ISO officials said Tuesday.

The 2017 Congestion Assessment and Resource Integration Study (CARIS) found congestion on the Central East interface, through the line eastward to Albany, and from the capital down the Hudson River Valley toward New York City.

“These are not necessarily surprising, being consistent with what we’ve seen in past studies,” said Timothy Duffy, the ISO’s manager of economic planning. “We also did find one interesting piece, which was a small line, referred to as Edic-Marcy, which we have found in the past year or so to have some significant contribution to congestion on the system.”

The Edic-Marcy line is located in the central part of the state.

System Resource Shift Transmission Congestion NYISO CARIS — Location of congested transmission | *NYISO*

The CARIS process requires planners to identify the top congestion elements on the system. “That’s obviously a key indicator of where developers ought to be thinking in terms of building additional transmission to provide value in terms of reduced congestion,” Duffy said.

The ISO’s Tariff calls for the CARIS to identify four solutions for each case study. Planners start with a generic solution such as transmission, demand response, energy efficiency and generation, then model those solutions and develop specific costs associated with them, calculating high-level cost-effectiveness tests and benefit-to-cost ratios.

The only benefit the CARIS process factors into its benefit-to-cost calculation is a reduction in statewide system production costs. While the study reports other benefits such as reductions in emissions, capacity market payments and consumer energy payments, it does not reflect them in the benefit-to-cost ratios.

“In terms of Phase I, there’s a whole host of data that’s presented,” Duffy said. “We look at historic, we look at its projected congestion on the system, we identify what the key drivers are, and we look at a number of different scenarios in terms of gas prices; for example, other load forecasts, other big macro changes on the system and how they affect system congestion.”

Six Studies

The ISO studied the three congested areas under six scenarios:

Study 1: Central East-Edic-Marcy
Study 2: Central East
Study 3: Central East- New Scotland- Pleasant Valley
Study 4: Study 3 with Edic- Marcy relaxed
Study 5: Study 3 under the System Resource Shift Case
Study 6: Study 5 with Edic-Marcy relaxed

Planners began with a “business as usual” (BAU) case consistent with past practices. In most such cases, the ISO is very constrained in terms of what it can model and assume, so the BAU results are of limited value, Duffy said.

A second set of results is more forward-looking, the product of the ISO “taking a step further, beyond the confines of the Tariff, in terms of the minimal amount of work required by the tariff,” Duffy said. “We created this system resource shift case, which essentially allowed us to use our judgment to identify a set of assumptions so that the results of the study would provide additional meaning.”

In including the system resource shift case, Studies 5 and 6 differed from the first four by modeling the Indian Point nuclear plant and all New York coal units as retired by 2020/21. In addition, the studies forecast that the state would meet its Clean Energy Standard 2030 goal of 50% renewable resources by 2026.

The study’s model included 4.6 GW of onshore wind, 10.8 GW of utility-scale solar and 250 MW of offshore wind in service by 2026, annually producing 28.5 TWh of renewable energy. ISO planners supplemented this with annual energy reductions of 10.5 TWh from energy efficiency.

Phase II of the CARIS process invites developers to propose specific transmission projects to address congestion on the system. The ISO will perform a benefit-to-cost analysis for each proposed transmission project to assess eligibility for regulated cost recovery.

While estimates of production cost savings will still dictate project eligibility, Phase 2 will examine zonal locational-based marginal pricing (LBMP) load savings to identify beneficiaries and determine cost allocation. The LBMP value used is net of transmission congestion contract (TCC) revenues and bilateral contracts.

To qualify for cost recovery under the ISO’s Tariff, a transmission project must have a capital cost of at least $25 million, benefits that outweigh costs over the first 10 years of operation and received approval to proceed from 80% or more of the actual votes cast by beneficiaries on a weighted basis.

Having met these conditions, the developer must also file with FERC for approval of the project costs and rate treatment.

Public Policy Tx

Switching gears from discussion about the CARIS process, Zach Smith, NYISO vice president for system and resource planning, said the ISO’s planning process has three core pieces: reliability, economic and public policy.

Among the steps taken so far on the public policy front, the ISO “last year selected the Western New York Public Policy Transmission project, and we’re currently going through stakeholder discussions on the AC transmission public policy, and we anticipate a selection of those projects in July this year,” Smith said. (See MC Approves Western New York Tx Proposal; NYISO Management Committee Briefs: Sept. 27, 2017.)

The proposed AC projects include the $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, which are intended to relieve downstate congestion by upgrading the AC transmission systems north and west of New York City. (See Downstate NY to Pay 90% of AC Tx Projects.)

Smith highlighted one change in the ISO’s planning process, noting that under FERC Order 1000, “an interregional transmission project can be proposed under any of our planning processes.”

An interregional project is one physically located in two regions, such as transmission that ties PJM to New York.

“That project could then get a joint cost allocation, where customers within the PJM system might bear some costs, and New York might bear some cost,” Smith said. “To date we have not had an interregional project, but there is that potential there.”

May 4, 2018

Report Highlights Fast-changing New York Grid

By Michael Kuser

New York faces increasing penetration of intermittent distributed energy resources, declining load, all-time low energy prices and the need to replace aging generation as the state moves toward achieving its Clean Energy Standard goal of producing 50% of its electricity from renewables by 2030, according to a NYISO report.

“Compared to other regions in the U.S., New York enjoys a fairly diverse fuel mix, but we’ve identified a real disparity between the upstate and downstate regions … with upstate [being] where just about all the hydro and renewable resources are located,” NYISO Executive Vice President Richard Dewey said Thursday while presenting Power Trends 2018, an annual report covering how technology, economics and public policy are influencing the state’s wholesale electricity markets.

NYISO DER natural gas prices intermittent energy — | *NYISO*

The state’s imbalance of renewable energy supplies means the downstate region (consisting of the Hudson River Valley and New York City area) will become increasingly reliant on natural gas-fired generation, the report said.

Low Capacity Factors

The operational challenge for the ISO is to keep the lights on 100% of the time when the capacity factors for onshore wind and solar are just 26% and 14%, respectively — compared to 89% for nuclear, Dewey said.

NYISO DER Distributed Energy Resources Offshore Wind — | *NYISO*

“We need to think about having the right type of generation capacity available so that we can meet the load requirement at the grid and provide the right kind of incentives so that generators are available,” he said.

Offshore wind differs from onshore in that it gives higher output during the daytime hours, which is more consistent with New York’s load profile. Offshore wind also operates at a higher capacity factor, sometimes in the 40% range or higher, Dewey said, adding that the ISO is modeling how that higher capacity factor might affect grid and market operations.

Offshore wind also has the added advantage of being located closer to demand centers in Long Island and New York City, he said.

According to data compiled from the Danish Energy Agency and Denmark’s state-owned utility, the Anholt 1 wind farm, which only opened in 2013, reached an average capacity factor of 53.7% for the full year 2017.

Asked whether New York could expect such higher capacity from its offshore installations, Dewey said, “A lot of that depends on the local environmental studies. I can’t comment on the wind currents off Long Island as opposed to what the Danish have experienced, but I will say that technology is continuing to work to our advantage where some of the newer turbines are both in terms of the height, turbine design and some of the technology around how they place and manage them. Increasingly, the industry is learning lessons from some of the existing installations.”

Low Market Prices

Dewey noted the impact that historically low wholesale electricity prices — largely correlated to falling natural gas costs — are having on the state’s generating fleet.

“When you talk about wholesale markets that really are at the all-time lows, this is great for consumers, from the standpoint of energy prices, but it creates some concerns when you start thinking about the viability of the generation fleet and the willingness of suppliers to make investments to some of those assets,” he said. “We really need to think about the revenue adequacy of some of those plants to the extent that natural gas prices are projected to be at or near these levels for the foreseeable future.”

Changing Demand

New York’s electricity demand experienced steady growth for many decades, but it has now flattened out and in many respects is starting to decline, Dewey said.

Energy usage is expected to decline over the next decade at a rate of 0.14% per year, and peak demand — a critical element to reliable system planning — is expected to fall by 0.13% per year through 2028, the report said.

“Increasingly our demand is impacted by the weather,” said Dewey. “We’re a summer peaking system that relies heavily on the load of air conditioning in the summer, and when we have a cool summer like we had last year, that has significant impacts on the overall consumption.”

The proliferation of rooftop solar and demand response is flattening that load, resulting in “substantive impacts on our planning and our markets,” he said.

“The impact solar has on energy demand is actually quite a bit different than the impact it has on the peak,” Dewey said.

Solar production fades just at 4 to 5 p.m., when the electric system is hitting its peak, “so what we end up getting is high ramp periods in the afternoon when we’ve got to get response from our suppliers to meet that high electric peak when the solar production is dropping off,” Dewey said.

The ISO expects the problem to grow as solar installations increase and extend throughout the state, he said. In addition, energy efficiency efforts continue to displace the amount of energy supplied by the grid, with the New York State Energy Research and Development Authority last month outlining plans to accelerate the state’s energy efficiency goal by 40%. (See NY Sets 40% Hike in EE Goal.)

“DERs hold tremendous value in that, if sited properly, they could address some of the resiliency issues at both the retail and the wholesale level, and provide a whole lot of options for both distribution companies and grid operators, but [they] do add a whole lot of complexity to the grid,” Dewey said.

As a wholesale market administrator, NYISO is working with the state and utilities to come up with market incentives to appropriately price the resilience attributes DERs bring to distribution companies and ensure those costs are incurred by the retail system. And to the extent that DERs provide value to the wholesale market, the ISO will make sure those revenues are appropriately allocated, he said.

The report notes that over the past year, the ISO has received proposals to connect more than 400 MW of battery storage to the grid.

May 4, 2018

SPP Seams Steering Committee Briefs: May 2, 2018

SPP’s Seams Steering Committee on Wednesday endorsed a staff-proposed Tariff change that would grant some transmission customers a four-hour exception from taking SPP transmission service in the case of an unplanned transmission outage that leaves them reliant on the RTO’s system.

The proposal encountered minor turbulence from members who wanted an exception exceeding four hours. It eventually passed by an 8-3 margin, with Kansas City Power & Light and Sunflower Electric Power abstaining.

Seams SPP Seams Steering Committee M2M Payments — | *ACES*

Staff drafted the proposal to address the committee’s concerns about the current requirement that transmission customers along the SPP seams obtain service from the RTO during an unplanned outage, even if the customer may not normally be required to take the service. Customers that do not prearrange for the service from SPP are charged for unreserved use, and the Tariff does not currently allow the RTO to waive those charges even when a customer unknowingly takes transmission service immediately after an outage.

The proposed change would allow SPP to waive the unreserved use charges during the first four hours of an unplanned outage. Staff said the revision will avoid burdening customers with having to arrange for transmission service during the initial moments of an unplanned outage, while still allowing transmission owners to be compensated.

Staff will now take the proposed change through SPP’s revision-request process. The Regional Tariff Working Group will be responsible for the measure’s progress.

MISO M2M Payments to SPP Exceed $50M

MISO’s market-to-market (M2M) payments to SPP surpassed $50 million in March when the Midwest RTO incurred $3.4 million in charges, increasing its total to $51.4 million since the two neighbors began the process in March 2015.

It was the eighth straight month and 16th of the last 18 that MISO has paid SPP.

SPP’s Nashua-Hawthorn and Riverton-Neosho-Blackberry flowgates — in Kansas and Missouri, respectively — were once again the main culprits, binding for a combined 267 hours and racking up $2.2 million in charges. The flowgates have accounted for more than $32 million in M2M payments to SPP, with the Riverton-Neosho-Blackberry flowgate responsible for $26.5 million.

A shadow-price override was put in place in early April to mitigate that flowgate’s power swings.

SPP, MISO Evaluating Feedback on Joint Studies

SPP and MISO staff are evaluating feedback gathered from their members on how best to improve their interregional planning process. Staff recommendations based on the feedback will be shared with members in May and June, before any tariff changes or joint operating agreement revisions are made.

The RTOs agreed in February to develop a new process for their coordinated system plan. SPP and MISO have conducted two joint studies, but have yet to approve any joint projects. (See MISO, SPP Look to Ease Interregional Project Criteria.)

— Tom Kleckner

May 3, 2018

Powelson: ‘Erosion of Confidence’ in Stakeholder Process

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — FERC Commissioner Robert Powelson on Wednesday reiterated his defense of organized markets but said he sees an “erosion of confidence” in RTO stakeholder processes.

Robert Powelson Stakeholder Process — Powelson | © *RTO Insider*

Powelson, who made the observation in a speech at a PJM issues workshop sponsored by the Great Plains Institute and Duke University’s Nicholas Institute for Environmental Policy Solutions, elaborated afterward in an interview with reporters.

He cited concerns over escalating transmission rates and PJM’s February “jump ball” filing of two competing proposals for insulating its capacity market from state-subsidized generation. (See PJM Board Punts Capacity Market Proposals to FERC.)

“You talk to certain state commissioners; you talk to consumer advocates; there’s a concern that voices are not being heard,” he said. “I think PJM — [CEO] Andy [Ott] has heard me say this — has to do a better job with their state outreach. … A lot of states right now are not happy.”

Illinois Commerce Commissioner John Rosales, and Pennsylvania Public Utility Commission Vice Chairman Andrew Place, who also spoke at the workshop, agreed with Powelson’s characterization. “PJM is swimming and drowning in capacity. … And capacity repricing only worsens that,” Place said.

PJM spokeswoman Susan Buehler said Powelson’s “concern about our stakeholder process … is valid and has been recently discussed with members.”

Regarding complaints about the “jump ball” filing, Buehler said: “PJM believes this is a policy question and that FERC should make policy calls. Based on the recent New England ruling, it appears evident that commissioners are divided.” (See Split FERC Approves ISO-NE CASPR Plan.)

‘Awkward Position’

Powelson said PJM’s decision to file both the two-tier capacity repricing proposal RTO staff prefer and the Independent Market Monitor’s proposal to extend the minimum offer price rule (MOPR) to all units indefinitely “puts us in an awkward position.”

The former Pennsylvania regulator contrasted the filing with the RTO’s Capacity Performance proposal, which was supported by his state as a response to the 22% generator forced outage rate during the 2014 polar vortex. “I want to see more of that synchronization as these constructs come down [to FERC]. It makes the commission’s job a lot easier if there’s those kind of alignments.

“It’s hard to build consensus, and that’s a concern too,” he added. “I don’t know how to change that, but I’d like to see us at least look at it more.”

Adam Keech, PJM executive director of market operations, who spoke after Powelson, also addressed his comments.

“I think the stakeholder process is a great process for getting feedback and vetting proposals and understanding the interests,” Keech said. But he acknowledged the RTO has difficulty advancing “big ticket items” and navigating some “larger issues.”

“And so, are there are ways we can make the process more efficient? I’m sure there are, but there’s value to the process nonetheless. … We need to not throw the baby out with the bath water,” he said.

The challenge of reaching stakeholder consensus was highlighted in a May 2017 paper on PJM’s governance by Christina Simeone, director of policy and external affairs at the University of Pennsylvania’s Kleinman Center for Energy Policy.

“For these high controversy issues, it seems the stakeholder process is falling short at exactly the time when stakeholder collaboration and joint problem solving is critical to informing profound questions about market design and the future of competitive markets,” Simeone wrote.

`Very Disappointing’

Rosales, who is president of the Organization of PJM States Inc. (OPSI), said he agreed that state regulators don’t feel PJM is sufficiently responsive. “Absolutely. 100%. Unqualified yes,” said Rosales, who called PJM’s jump ball filing “very disappointing.”

“We were very clear,” he told RTO Insider in a brief interview. “We thought that the status quo was better than these two really poor options that they put to be filed at FERC.”

Rosales elaborated in a panel of state regulators. PJM is “trying to resolve an issue that hasn’t become an issue yet. It’s a solution to a problem that we don’t have.”

OPSI sent the PJM Board of Managers a letter in February urging it to take no action on any repricing proposal, saying that if the RTO thought rule changes are necessary, “it should reinitiate a more holistic stakeholder process.” The organization said it was not convinced that state policies undermine the RTO’s markets and that PJM’s proposal does not respect state jurisdiction and may raise capacity prices.

But Rosales said OPSI’s concerns have gone unheeded and that PJM has recently adopted a practice of effectively covering its ears and saying, “We hear you.”

“It becomes very frustrating for us because they’ll say they listen, they’ll tell us about the stakeholder process, they’ll tell us everything that they’ve done … and then they’ll just throw it out the door and say, ‘We’re going to go with this anyway.’”

OPSI is not a PJM member, so it has no means of trying to change the stakeholder process at FERC. “We as a group have decided not to be stakeholders,” Rosales said. “We try to have a relationship with PJM … [and] play nice in the sandbox. … But for the most part they’ve not had an open dialogue. … They listen, but the changes aren’t there.”

Monitor Contract

Rosales also cited the renewal of PJM’s contract with its Monitor, Monitoring Analytics. The IMM’s current contract expires in December 2019. “We have problems with getting the Market Monitor contract — again. They seem to be going not the right way,” he told RTO Insider. He did not elaborate on his concerns, which he repeated on the panel.

Monitoring Analytics President Joe Bowring, a Ph.D. economist, has served as PJM’s Monitor since 1999. In 2013, the PJM board came under fire over its proposed request for proposals for monitoring services, which OPSI and other critics said contained language that would undermine the independence and quality of the monitoring function. The board dropped the proposal and signed a contract renewal with Monitoring Analytics later that year. (See Board, OPSI Bury the Hatchet over Monitor Contract.)

OPSI Executive Director Gregory Carmean did not respond to a request for comment Wednesday on the current contract negotiations. Bowring declined to comment in detail but said he was confident in reaching agreement with the RTO.

PJM’s Buehler acknowledged PJM has received questions from OPSI about the contract negotiations. “PJM believes the discussions are productive and ongoing and we are frankly confused by any other characterization,” she said.

Not Just PJM

Powelson said his concerns over the stakeholder process are not limited to PJM, saying all RTO/ISO boards should operate under term limits and ensure diversity among their members. “I’m looking at this … from general business practices as a regulator overseeing those boards and what these RTOs do; making sure they’re synchronizing with what’s going on in the corporate world.

“In my view, you can’t have enough transparency in this [stakeholder] process,” he continued. “We’re making all these changes. People should have the ability to see it, understand it and feel comfortable with the final outcome.”

Powelson also commented on PJM’s initiative, announced Monday, to seek a market-based response to potential fuel security concerns. (See PJM Seeks to Have Market Value Fuel Security.)

Based on “the briefing I received from Andy Ott and his team, I think [PJM] is exactly where we need to be,” he said.

Powelson said “people should not read into” PJM’s announcement that it will end up paying coal and nuclear operators to provide backup for gas-fired generators subject to fuel delivery interruptions. “I think what PJM is saying is ‘we’re going to look at it and we’re going to do it in a market-based approach.’ There might be other technologies out there that have the same [fuel security] characteristics. It could be an oxidized fuel cell. It could be storage. It’s going to be a level playing field discussion. … It’s going to be done in a fuel-neutral, technology-neutral way.”

Powelson said it would be a mistake for the Trump administration to use the 68-year-old Defense Production Act to keep financially struggling coal and nuclear power plants operating, as is being considered, according to published reports. The act was used by President Harry Truman to control steel prices during the Korean War.

“I think it would lead to the unwinding of competitive markets in this country,” Powelson said. “It would be the wrong direction for us to venture down.”

May 3, 2018January 3, 2024

WEC Delivers Strong Q1 Despite Leadership Uncertainties

By Amanda Durish Cook

Cold weather and a stronger regional economy helped boost WEC Energy Group’s first-quarter earnings above expectations, the company reported Tuesday.

The company also addressed uncertainty in its executive suite and described its near-term plans for more renewable investment.

WEC’s profits totaled $390.1 million ($1.23/share) during the quarter, compared with $356.6 million ($1.12/share) for the same period last year.

CEO Gale Klappa said the “solid results” were driven by a stronger-than-expected demand for electricity and natural gas. “Colder winter temperatures, a strengthening economy and efficiency gains across our system were all positive factors that lifted our earnings above year-ago levels,” Klappa said.

The company’s operating revenue for the quarter slipped from $2.3 billion to $2.29 billion this year.

During a May 1 earnings conference call, Klappa praised the company’s performance and said it has a plan readied in the event that company President Allen Leverett does not return to his post as CEO after being placed on medical leave in October 2017 when he suffered a stroke. Klappa said Leverett is currently undergoing intensive speech therapy and is in “good physical condition.” Should Leverett choose not to resume the role of CEO, WEC will employ a succession plan that would “involve a number of internal promotions,” Klappa said.

“I can assure you that we have a solid Plan B in place if Allen does not assume his previous role. … We would have great continuity going forward, and the board and I are very comfortable with [that],” Klappa said, adding that he and WEC’s board of directors will continue to monitor the situation.

Klappa also said WEC is making multiple renewable energy investments throughout 2018. The company on April 30 signed a $280 million agreement to acquire an 80% ownership interest in the 200-MW Upstream Wind Energy Center, currently being built by Invenergy in Antelope County, Neb. Klappa said he expects the wind farm deal to close in early 2019, pending FERC approval — just as Upstream begins commercial operation.

Early last month, WEC closed on its $80 million partial purchase of the 129-MW Forward Wind Energy Center near Brownsville, Wis. Klappa said WEC now owns 44.6% of the wind farm, which is expected to generate savings for customers.

WEC also plans to file construction requests with Wisconsin regulators by the end of the second quarter to build its first solar farm, Klappa said.

“Over the past few years … utility-scale solar has increased in efficiency, and prices have dropped by nearly 70%, making it a cost-effective option for our customers, an option that also fits very well with our summer peak demand curve and with our plan to significantly reduce carbon dioxide emissions,” Klappa said.

He also said WEC is developing plans to provide natural gas and electric infrastructure to “Wisconn Valley,” the moniker for the future site of electronics manufacturer Foxconn’s $10 billion plant. In February, MISO Fast-Tracks ATC Foxconn Project Review.)

May 3, 2018

CAISO, PacifiCorp Gain Most EIM Q1 Benefits

By Robert Mullin

CAISO and PacifiCorp reaped the majority of the Western Energy Imbalance Market’s (EIM) $42.1 million in gross benefits during the first quarter, according to a report released by market operator CAISO.

The ISO earned $14.85 million in EIM benefits over the quarter, followed by PacifiCorp at $10.5 million. Trailing those two market players were Arizona Public Service ($5.9 million), NV Energy ($4.2 million), Portland General Electric ($3.6 million) and Puget Sound Energy ($3 million).

Total quarterly benefits were up nearly 26% from the fourth quarter of 2017 and 31% from the same period a year ago — before Portland General Electric began transacting in the EIM last October. The market has yielded $330.5 million in benefits since it was launched with PacifiCorp in November 2014, the ISO estimates.

EIM CAISO PacifiCorp Western RTO — | *CAISO*

The report again illustrated an established pattern with the arrival of spring: that CAISO becomes a net exporter of energy as increasing output from solar resources coincides with modest electricity demand during mild weather in California. (See CAISO EIM Exports Rise with Spring, Report Shows.)

The ISO’s EIM exports surged from 94,769 MWh in January to 325,664 MWh in March, with imports falling from 299,586 MWh to 185,008 MWh, the report showed. First-quarter exports totaled 608,416 MWh, compared with 362,774 MWh the previous quarter.

CAISO said the energy transfers facilitated by the EIM allowed it to avoid curtailment of 65,680 MWh of renewable output during the quarter, up 24% from the same period last year. That was still down sharply from the nearly 113,000 MWh of avoided curtailments in the second quarter of 2016, which the ISO attributed to improved hydroelectric conditions and advancements in how EIM participants are deploying their resources.

The avoided renewable curtailments translated into the displacement of 28,188 metric tons of carbon dioxide, based on an assumed default emissions rate of 0.428 metric tons CO₂/MWh from other sources of generation. By avoiding curtailments, the EIM has helped to displace 250,845 metrics tons of CO₂ since 2014, the ISO said.

The report also showed that APS and NV Energy functioned heavily as “wheel through” areas during the first quarter, meaning their transmission networks facilitated many transactions for which the utilities received no financial benefits because they were neither source nor sink. (See graph). During February and March, energy volumes wheeled through APS’ territory exceeded the utility’s combined EIM net imports and exports, as significant amounts of energy flowed between the CAISO and PacifiCorp-East balancing authority areas during what is typically a period of low demand in Arizona.

The ISO has “committed to monitoring the wheel-through volumes to assess whether, after the addition of new EIM entities, there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits,” the report said.

A CAISO proposal to provide transmission revenue to EIM participants that wheel energy through their BAAs last summer drew stiff opposition from current and future stakeholders concerned about the impact of new charges on the economic dispatch of generating resources. (See EIM Member Wary of Need for Wheeling Charge.)

May 3, 2018

Edison Hopeful for State Action on Wildfire Liability

By Jason Fordney

Edison International CEO Pedro Pizarro said the company is hopeful that several bills working their way through the California State Legislature will ease the financial pressure stemming from hundreds of millions of dollars in wildfire costs.

The company’s main subsidiary, Southern California Edison, is the target of civil lawsuits stemming from the Thomas Fire that began in December 2017 in Ventura County, Calif., burning about 440 square miles and causing two deaths. While the California Department of Forestry and Fire Protection, the Ventura County Fire Department and the California Public Utilities Commission’s Safety and Enforcement Division look into the causes of the fire, the utility is conducting it own investigation, Pizarro said.

During an earnings call Tuesday, Pizarro called for the state to implement wildfire mitigation operating standards to help determine whether a utility properly ran its transmission system prior to a fire.

“An updated standard of liability that considers degree of fault rather than the current standard of strict liability would ensure that there is a fair sharing of the increasing risk of climate change impacts across society,” Pizarro said. He said he was “heartened” by Gov. Jerry Brown’s comments in March about updating utility liability rules for wildfires. Three related bills have been introduced into the legislature: SB 819, SB 901 and SB 1088.

Edison International California Wildfire costs — Edison International reported its first quarter earnings this week

The third bill, set for a May 7 hearing at the Senate Committee on Appropriations, would allow utilities to recover wildfire costs if they conform to state-regulated safety plans, but it faces heavy opposition from critics who say it lets utilities off the hook for their contribution to wildfires. (See Calif. Legislation Shields Utilities from Wildfire Costs.)

Wildfire costs and the financial health of the state’s investor-owned utilities have sparked concerns in the capitol about the impact on utility stock prices and the potential for bankruptcies — shades of the electricity crisis of the early 2000s. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)

Edison reported first-quarter net income from continuing operations of $242 million, compared with $392 million in the same quarter last year. Operating revenue was $2.5 billion in the first quarter, and total operating expenses were $2.2 billion. SCE is a waiting for a CPUC decision on its 2018 retail general rate case.

SCE on April 3 filed an application at the CPUC for a Wildfire Expense Memorandum Account to track incremental wildfire costs. The company is in the process of renewing its wildfire insurance for 2018 and 2019 and said the cost of additional insurance may substantially exceed the amount authorized in rates or in the pending 2018 rate case. The utility has proposed a schedule that would see a decision on the account issued by August.

The state’s three utilities have banded together on the wildfire issue after the CPUC last year denied San Diego Gas & Electric’s request to recover $379 million in wildfire-related costs. (See Besieged CPUC Denies SDG&E Wildfire Recovery.)

May 2, 2018

FERC Accepts Southeast Transmission Import Limits

By Amanda Durish Cook

FERC on Tuesday approved simultaneous transmission import limits for several balancing authority areas in the Southeast, stretching from Kentucky to Florida.

The 16 simultaneous import limits (SILs) were submitted with non-public market power analyses by several transmission-owning companies, including eight subsidiaries each of Southern Co. and Duke Energy; seven NextEra Energy affiliates (including Florida Power & Light); PPL affiliates Louisville Gas & Electric and Kentucky Utilities; Tampa Electric Co.; and South Carolina Electric & Gas. (ER10-1325 –008, et al.).

FERC SILS — South Carolina Electric & Gas Co. linemen at work | *SCE&G*

FERC will use the SIL values to evaluate market power analyses submitted by the region’s transmission owners (TOs) and non-transmission-owning sellers.

The limits range from a 10.7-GW import capability during winter in the Tennessee Valley Authority balancing area down to a zero-megawatt year-round import limit in the Florida Power & Light balancing area. The limits were created based on a study period extending from December 2014 to November 2015.

While FERC accepted most of the transmission owners’ own SILs, it said it selected Tampa Electric’s calculated values for a few Florida balancing areas where various TO SIL values conflicted with one another.

The commission commended the TOs for coordinating to create the SIL values but said in the future SIL calculations must follow a commission-ordered procedure.

“The southeast transmission owners generally performed their SIL studies correctly. However, the review of these filings, as well as the review of filings for other regions, leads the commission to conclude that it is appropriate to remind sellers of its expectations, and provide clarification, with respect to the calculation of SIL values,” FERC said.

FERC said TOs should abide by the tariff-approved methodologies to calculate SIL capability and should take into account voltage and stability limits, capacity benefit margins and transmission reserve margins.

“The commission emphasizes here that each transmission owner’s SIL values must reflect [transmission reserve margins] and [capacity benefit margins] in the same manner as utilized to calculate and post [available transfer capability] and to evaluate requests for firm transmission service,” FERC said.

May 2, 2018

FERC Approves CAISO-Calpine RMR Settlements

By Jason Fordney

FERC on Monday approved settlement agreements among CAISO, Pacific Gas and Electric and Calpine covering reliability-must-run (RMR) contracts for three Northern California gas-fired plants, reducing the revenue they will receive and making them subject to a must-offer requirement.

FERC’s orders covered two proceedings, one for Calpine’s Metcalf plant (ER18-2 40) and another for the company’s Feather River and Yuba City plants (ER18-2 30). A FERC Administrative Law Judge last month recommended the commission approve the agreements. (See FERC ALJ Certifies Calpine R M R Settlements; PG&E, CAISO Protest Calpine RMR Terms.)

RMR CAISO PG&E Calpine reliability-must-run — Calpine’s Yuba City Energy Center in Northern California | © *RTO Insider*

While the commission said the agreements resolved all issues in dispute in the proceedings and appeared to be “fair and reasonable and in the public interest,” the out-of-market RMR payments are not popular with many CAISO stakeholders and were opposed by the California Public Utilities Commission (CPUC) after the ISO’s Board of Governors reluctantly approved them in November. (See Board Decisions Highlight CAISO Market P roblems.) The CPUC in January voted to require PG&E to hold solicitations to replace the agreements with energy storage. (See CPUC Retires Di a blo Canyon , Replaces Calpine RMRs.)

The Metcalf settlement reduces the plant’s annual fixed revenue requirement from about $72 million to $43 million through 2020 if it retains its RMR status and makes the plant operator responsible for routine repairs and capital expenses. Under the agreement, the plant will recover $8 million in 2018 capital items in 12 installments of $675,000 beginning on Jan. 1, 2018. If the RMR agreement is extended, capital recovery would remain at about $8 million per year. The settlement also grants the plant $8 million in 2019 and 2020 if the revised agreement is not renewed and the unit shuts down.

The Feather River and Yuba City settlements would reduce each plant’s 2018 revenue to about $3.5 million from the previous $4.4 million, with a 2% hike for 2019 and 2020, if the RMRs are renewed.

The settlements would also take all three plants from Condition 2 (eligible for full cost-of-service payments) to Condition 1 (eligible for only a portion of their revenue requirement) status and impose a must-offer requirement, which the ISO’s Department of Market Monitoring has recommended for all RMR units. CAISO is working to revise its RMR program to establish a must-offer requirement for resources. (See CAISO, Stakeholders Debate RMR Re v isions.)

CAISO Tariff Waivers

In a separate order, FERC also granted CAISO a limited Tariff waiver to permit nine scheduling coordinators (SCs) to submit out-of-time requests to recertify 18 resources for the 2018 resource adequacy compliance year (ER18-85 7). CAISO said the SCs had failed to renew an exemption related to its Resource Adequacy Availability Incentive Mechanism (RAAIM) program by the Nov. 15, 2017, deadline because of confusion about the recertification process for acquired resources within the program.

FERC said the waiver grants certainty to those resources that they their RAAIM exemption will not be unwound. CAISO replaced its Standard Capacity Product with RAAIM in November 2016. SCs must present an affidavit for each resource adequacy year testifying that each resource meets eligibility for exemption from certain performance incentives.

Energy Crisis Settlement

The Commission also approved an uncontested settlement filed Feb. 6 among CAISO, Wayzata Opportunities, PG&E, Southern California Edison and San Diego Gas and Electric related to the 2000/01 California energy crisis (EL02 –18). The agreement ensures the payment of interest to the resource owners who had received delayed compensation for certain power supply contracts because of the default of the California Power Exchange. The filing parties said approval of the settlement would avoid further litigation, eliminate regulatory uncertainty and enhance financial certainty.

May 2, 2018

ERCOT Gains Additional Capacity to Meet Summer Demand

By Tom Kleckner

ERCOT will have more breathing room as it prepares for record demand this summer after an additional 525 MW of generation recently came online in Texas.

The ISO said Monday it now has 78.2 GW of capacity available to meet an expected peak demand of 72.8 GW, which would break the 2016 record of 71.1 GW. The additional capacity has boosted ERCOT’s planning reserve margin from 9.3% to 11% since the previous seasonal assessment of resource adequacy (SARA) report.

“That definitely improves the situation,” said Pete Warnken, ERCOT’s manager of resource adequacy, during a media call Monday.

The additional generation comes from the 225-MW, gas-fired Denton Energy Center that recently went into service in North Texas and the return of the mothballed 300-MW gas unit at Barney Davis in Corpus Christi.

ERCOT summer peak demand planning reserve margin — South Texas Nuclear Generating Station

Warnken said rotating outages are still possible under extreme scenarios, “but that risk has been reduced a little bit with those resources.”

ERCOT has approximately 2.3 GW of capacity available through load-control measures with transmission or distribution service providers. Tight reserves could also trigger the need for the ISO to deploy ancillary services and contracted emergency response service capacity to maintain sufficient operating reserves.

Staff also expects industrial facilities to make voluntary load reductions and increase the power they sell into the market during peak demand.

“We expect the market to respond to scarcity conditions,” Warnken said. “It’s a good bet to expect they’ll be looking at summer conditions and making decisions appropriately before they bring their resources on.”

ERCOT summer peak — ERCOT’s Dan Woodfin | © *RTO Insider*

Dan Woodfin, the ISO’s senior director of system operations, said the grid will also benefit with the completion of the Houston Import Project, a $590 million effort that will allow more power to be imported from the north.

“All the pieces are in service at this point,” Woodfin said. “That will help reduce congestion into the Houston area because it improves the transfer capability.”

ERCOT also released its latest Capacity, Demand and Reserves (CDR) report, which includes planning reserve margins for the next five years. The reserve margin peaks at 12.3% in 2020, before dropping to 8.9% in 2023.

The CDR report adjusts the 2019 summer demand forecast down to 74.2 GW, reflecting a delay in a new industrial facility on the Texas coast. Staff expects the load forecast to eclipse 77 GW in 2023. That number includes the planned integration of Lubbock Power & Light’s customers, which is scheduled to take place in 2021.

The ISO’s target planning reserve margin is 13.75%. Warnken said staff is studying an economically optimal reserve margin, which would balance the amount of generation needed to maintain reliability with its cost.

The next CDR report will be released in early December.