Page 1120 – RTO Insider

March 26, 2020

CAISO Protecting Control Room Staff

By Hudson Sangree

CAISO is focused on keeping its control room running and isolating key employees from those who might be carrying the COVID-19 coronavirus, CEO Steve Berberich told the ISO’s Board of Governors Wednesday.

Some employees are working off site, Berberich said. Others have shifted to CAISO’s secondary control room at a 35,000-square-foot backup facility in Lincoln, Calif., about 20 miles north of the ISO’s Folsom headquarters near Sacramento.

“We’re doing our best to particularly make sure we protect our control room personnel and leveraging our backup site to make sure we have separation between them,” Berberich said. “Our focus though right now is to make sure we protect our staff but also ensure our primary missions of running the reliable grid and credible markets remains intact.”

Like other regions, CAISO has seen shifts in demand as a result of the coronavirus threat. The ISO has experienced a 3 to 5% load reduction, with Californians under a statewide stay-at-home order, he said. Mild weather and other factors may be disguising more pronounced effects on the state’s demand curve, he noted.

“We’re tracking that,” Berberich said. “I know [Vice President of Market Quality and California Regulatory Affairs] Mark Rothleder’s group is focused on making sure we take that into consideration as we make our forecasts.”

CAISO Wholesale Prices — CAISO’s control room in Folsom, Calif. | *CAISO*

CAISO has had a pandemic plan in place since 2015 as part of its business continuity plan and has put it into effect, the CEO said.

The ISO is continuing with business as usual in other ways too, he said.

CAISO is continuing to perform its role as reliability coordinator for much of the West and running the Western Energy Imbalance Market, so far without significant disruption, he said.

However, Berberich acknowledged that some of RC West’s “advanced tools continue to be challenged.” CAISO’s advanced computer applications run contingency analyses based on a system model that is changing, he said.

“We’re working through some of the issues getting that system model completely correct,” he said.

“We do expect to move forward on all our policy initiatives,” Berberich said. “The stakeholder processes will continue to go forward on a telephonic basis. We’ll continue to manage the interconnection queue, transmission planning and all the other efforts we have to support California, but also the region and its decarbonization goals.”

He said developers have asked not to postpone projects, so CAISO won’t meddle with interconnection timelines.

“We are mindful that there are a lot of strains out there on the system — local regulatory authorities, the permitting agencies, financing and all those things,” Berberich said. “We are in a position where we will do what’s right to try to make sure that people can move through the queue, [that] they can successfully bring in projects and they can add to California’s goals of decarbonizing the grid.

“To the extent that we need to work with FERC and the stakeholders to find ways through that, we will. We have explored changing the queue dates and the schedules. After consulting with the industry, we got resounding feedback that they would like to keep those dates and requirements as is, so that will be our plan.”

Berberich plans to retire this summer, and a nationwide search has commenced for his successor.

Board Chair David Olsen took time at the start of Wednesday’s meeting to tell stakeholders that the ISO’s policy goals, including the expansion of the Western Energy Imbalance Market across the West and to a day-ahead market, won’t change during the CEO transition.

“That will not change any of our current commitments and forward-looking policies,” Olsen said. “The board wanted to communicate that unambiguously.”

March 26, 2020

MISO Loads Down as Region Faces COVID-19 Threat

By Amanda Durish Cook

MISO’s weekday loads are looking more like weekends as social distancing measures to lessen COVID-19 cases take hold in more states in the footprint.

“We are starting to notice a few impacts,” Vice President of System Planning Jennifer Curran reported during the Markets Committee of the Board of Directors’ Tuesday meeting, conducted via WebEx and teleconference. (See Virus Fear Sends MISO Board Week to the Web.)

Director Tripp Doggett asked if MISO is experiencing more load shapes on par with weekend usage as more people stay home across the footprint.

“In general, it’s going in that direction; the peaks aren’t as prominent,” Executive Director of Market Operations Shawn McFarlane said.

MISO COVID-19 — MISO’s March 2019 Board of Directors meeting in New Orleans | © *RTO Insider*

For instance, McFarlane said, morning peaks are flattened absent the usual flurry of activity to get schoolchildren and workers out the door. In its place is a more dispersed demand over the morning hours, he said.

McFarlane said MISO hasn’t yet quantified how much load has declined across the footprint.

“Things have been evolving. Last week, it was only schools closed. Now we have shutdowns in the industrial sector. It’s very fluid at this time. It’s certainly greater than 5% — now it could be even 10%” year-over-year, he said.

Complicating matters, MISO’s load forecasting relies on historical information. “During this unprecedented time, we don’t have historical data,” Curran explained.

MISO Director Theresa Wise called the forecast challenges “completely understandable.”

Independent Market Monitor David Patton said MISO load in the first three weeks of March was about 8% lower than it was a year ago, reflecting the closure of schools and business. “We’ve noticed a significant impact,” he said.

“We expect that load effect to increase, and we’re talking to MISO about the impact. … We do think the learning of their models will improve the forecast,” Patton said, adding that in the meantime, RTO staff have manually adjusted short-term load forecasts.

MISO Director Baljit Dail asked if generators were scheduling maintenance outages to take advantage of the dip in demand as the economy slows.

“Actually, we’re seeing the opposite. We’re starting to see deferrals of planned outages,” Curran said. She said the root cause is likely that utilities are making do with fewer personnel.

Directors asked if MISO anticipates other impacts related to the pandemic.

“It’s early days yet, so we’ll be in constant communication with our members,” Curran said.

The RTO has convened incident response teams focusing on COVID-19 that meet daily and have escalation plans at the ready to protect grid operations, if necessary, Curran said.

“MISO’s top priority is to ensure the safety of its staff and stakeholders and reliability of the bulk electric system,” she said.

Although most MISO employees are working from home, Curran noted that the RTO has operations in four sites in three states: the headquarters and Central Region Operations Center in Carmel, Ind.; the North Region Operations Center in Eagan, Minn.; and the South Region Operations Center in Little Rock, Ark. “So, we have a built-in social distancing,” she said.

Curran said MISO is also working with law enforcement to make sure the RTO’s control room operators can get to and from work as more states order their residents to shelter in place. She also said control rooms are being disinfected more frequently, and MISO has limited access to control rooms to essential personnel only. MISO facilities continue to be closed to visitors through May 1.

“This situation seems to change daily so keep in mind these actions can change or be extended,” Curran said.

Patton also reported Potomac Economics staff are all working remotely.

“We’ve seen no real problems in the functioning of the IMM or the software. Our software is run from a third-party data center, so we didn’t anticipate any impacts there,” Patton said.

March 26, 2020

Appeals Court Sets Dates in Texas ROFR Challenge

By Tom Kleckner

The Texas Public Utility Commission has won extra time to respond to NextEra Energy’s efforts to void a Texas law giving incumbent transmission companies the right of first refusal to build new transmission lines.

The 5th U.S. Circuit Court of Appeals in New Orleans on Friday granted the PUC’s request for a 14-day extension to file response briefs, giving the commission until April 22. NextEra will have seven days to file a reply brief (20-50160).

NextEra Energy Capital Holdings and four other NextEra transmission owner/developer entities appealed to the 5th Circuit after the U.S. District Court for the Western District of Texas in February refused their motion to overturn Texas Senate Bill 1938. (See District Court Dismisses Texas ROFR Repeal.)

On March 13, the district court also rejected NextEra’s request for an injunction delaying the court’s decision, saying NextEra is unlikely to prevail on appeal (1:19-cv-00626).

The Texas law grants certificates of convenience and necessity to the owners of a new transmission line’s endpoints, essentially allowing only incumbent transmission companies to build new power lines in the state.

“The court concludes that plaintiffs have failed to make a sufficient showing to warrant an injunction pending appeal,” District Judge Lee Yeakel wrote.

The judge said an injunction would substantially harm the PUCT, the defendants in NextEra’s lawsuit, because it would be unable to “plan and facilitate” new transmission projects.

At issue is NextEra Energy Transmission (NEET) Midwest’s ability to build the $115 million Hartburg-Sabine Junction transmission project in MISO’s East Texas footprint. NEET Midwest won the project’s rights in 2018 through a competitive bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

NextEra has said it expects MISO to make a decision reassigning or canceling the project by March 31.

Southwestern Public Service and East Texas Electric Cooperative have both appealed to the 5th Circuit to have their rejected intervention requests overturned. The district court denied both requests when it rejected NextEra’s motion in February.

March 25, 2020

Stakeholders Seek TO `Engagement’ on End-of-Life Tx

By Rich Heidorn Jr.

PJM stakeholders seeking to improve the transparency of transmission owners’ spending on end-of-life (EOL) projects urged the RTO Tuesday to swiftly conclude work on proposals that can be brought to a vote.

End-of-Life transmission — Ed Tatum, AMP | © *RTO Insider*

Over four special Markets and Reliability Committee meetings on transparency and end-of-life planning, American Municipal Power, Old Dominion Electric Cooperative and LS Power have proposed rule changes that would require TOs to share how they make EOL determinations, create a new category for EOLs within the Regional Transmission Expansion Plan (RTEP) and open them to competition.

“I just wanted to note I’ve only heard a solution from AMP, ODEC and LS Power. I’m aware that PJM is working on a solution. But … I’m not seeing a whole hell of a lot of engagement from others,” said Ed Tatum, AMP’s vice president for transmission, during Tuesday’s meeting, held via WebEx because of the coronavirus pandemic. “I appreciate that we’re in times that no one has ever lived through before. [But] there’s not a whole lot of new stuff coming here … . We are to a point in this process that we are very close to being able to finish it up.”

Proposals

The proposals would require TOs to have a transparent process for making EOL determinations based on industry averages, manufacturers’ recommendations and “good utility practice.” Once a TO has made a determination that a facility had reached the end of its life, that information would become part of the RTEP baseline planning process.

Currently, EOL projects developed under Tariff Attachment M-3 are designed based on assumptions and needs presented in local transmission planning meetings. For TOs that include EOL projects in FERC Form 715 planning criteria, the needs are presented in Transmission Expansion Advisory Committee and Subregional RTEP meetings.

The proposals would require all TOs to have a minimum 10-year look-ahead EOL program and to present their program’s criteria and guidelines to stakeholders at least annually.

TOs would have to present the methodology of their programs “in sufficient detail that stakeholders … can understand and, to the extent feasible, replicate the results for individual facilities determined to be EOL.”

Mark Ringhausen, vice president of engineering for ODEC, said this would apply to “bright line criteria” such as triggering new infrastructure based on the volume of outages. “I don’t think there’s going to be a lot of these, but we haven’t seen the TO criteria behind the scenes that are used for end-of-life determinations,” Ringhausen said.

EOL needs solutions developed by PJM would be subject to competitive bidding and would not be considered supplemental projects assigned to the incumbent TO.

PJM would conduct planning for all TO EOL replacements and retirements to ensure they don’t compromise reliability or create new critical facilities under FERC reliability standard CIP-014.

Timing Differences

The AMP/ODEC proposal would require TOs to notify PJM and stakeholders of any EOL conditions at least six years before the EOL date so that the project could be included in five-year planning models and opened to competitive bidding. The LS Power package would require six years’ notice for lower voltage facilities and at least eight years’ notice for facilities 230 kV and above.

Tatum and others have been attempting to gain more input on EOL spending since at least 2016. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)

Ringhausen said he believed the AMP-ODEC proposal complied with FERC precedent and existing rules and agreements.

But Exelon’s Robert Taylor said “we don’t share the same view that there’s no legal or contractual problems with” the proposal. “We want to see what PJM will say,” he added.

“These exact issues have recently been ruled on by FERC in the M-3 order, and some stakeholders want to go back to FERC and take it further,” Taylor said later via email. “We supported the changes in M-3 and are engaged in conversations to further improve transparency and address stakeholder needs, but to say we have been working on this for three years and done nothing is not accurate.” (See FERC Upholds PJM TOs’ Supplemental Project Rules.)

PJM Vice President of Planning Ken Seiler said RTO staff were “really looking hard at the three issues our board has asked us to work with the stakeholders on: … transparency, authority, as well as competition.”

And the authority to make the EOL determination, Seiler said, is with the TOs. “We’ve been very consistent about that message from day one: We are not in a position to make EOL decisions on transmission assets.”

He said any package backed by PJM must be consistent with FERC precedent and “be supported from a process and staffing viewpoint.”

He noted the new rules could have impacts on the planning process, the interconnection queue and cost allocation. “Does the load pay or does the generation interconnection customer pay?” he asked. “We have to be very careful and very surgical.”

In a letter to members Oct. 4, Dean Oskvig, chair of the Board’s Reliability Committee, pledged the RTO would continue efforts to improve transparency.

“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced. Those decisions are the sole responsibility of the Transmission Owner,” Oskvig said. He added, however, that in developing the RTEP, “in some circumstances, PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility.”

No Rush?

Exelon’s Taylor also pushed back on Tatum’s urgency.

“It is not the time to rush. Let’s get this right,” he said. “There [are] so many interlocking pieces.”

“We’re still anxiously waiting to hear from your organization as to what [Exelon’s proposal] would look like,” responded Tatum. “And so far, we’ve heard nothing. Part of the stakeholder process is to engage and to try to be part of a consensus solution.”

Taylor said the pandemic was occupying the minds of “a lot of folks who make these decisions for us.”

The project’s work plan is to target a vote on proposed packages at the May 28 MRC meeting, following a first read on April 30.

The MRC is scheduled to return to the issue in a special meeting April 17, but PJM staff said it may seek an earlier meeting date.

March 25, 2020

FERC Upholds Ruling in PG&E Interconnection Case

By Hudson Sangree

FERC on March 20 rejected Pacific Gas & Electric’s request to rehear a case in which the commission ruled that interconnection customers could be harmed by changes occurring outside of their boundaries (EL15-55 –003).

The case began in 2015 when the Modesto Irrigation District and the Turlock Irrigation District claimed PG&E had denied the districts’ rights under interconnection agreements to the PG&E-owned section of the California-Oregon Transmission Project, a 340-mile, 500-KV line that runs from southern Oregon to Central California.

The districts, which supply power to large areas of California’s Central Valley, are members of the Transmission Agency of Northern California and hold shares in TANC’s entitlement to capacity on the project. They use those entitlements to transfer energy from the Pacific Northwest.

The districts’ interconnection agreements with PG&E provide that either party can request a joint study of any proposed “modification, new facility addition, or long-term change to operations that may reasonably be expected to result in an adverse impact.”

“If an adverse impact is identified through either study process [the interconnection agreements impose] the obligation on the primary party to avoid, fully mitigate or compensate the coordinating party for all costs incurred due to the adverse impact,” FERC said.

FERC PG&E rehearing — The Modesto Irrigation District (MID) supplies water and power to a section of California’s agricultural Central Valley. | *MID*

The California Department of Water Resources (DWR), which owns generation and pumping resources connected to the transmission project, had been part of a remedial action scheme to maintain reliable operations during disruptions. When DWR dropped out in March 2015, PG&E “reprogrammed” the scheme but didn’t notify the irrigation districts and then refused to conduct a study of the potential impacts.

The districts sought FERC intervention. The commission initially denied the districts’ complaint, finding that the relevant terms of the interconnection agreements did not apply to resources beyond their immediate control.

“The districts do not own or control any portion of the California-Oregon Transmission Project [and it cannot] be considered part of the districts’ systems as defined in the interconnection agreements,” FERC wrote.

The districts appealed to the 9th U.S. Circuit Court of Appeals, which decided in September 2018 that FERC had read the agreements too narrowly in “concluding that an adverse impact must be a direct, physical effect on a line or component inside the districts’ systems and did not include a physical effect on a line or component outside the districts’ systems that makes it more difficult for the districts to transfer power into their systems.”

On remand, FERC ruled in favor of the districts and ordered PG&E to conduct a study of potential adverse impacts.

PG&E sought a rehearing, claiming that it had not breached its interconnection agreements and that no adverse impact had occurred. It said the 9th Circuit and the commission misread the interconnection agreements.

FERC rejected all of PG&E’s arguments.

“Although PG&E asserts that the commission ignored the plain meaning of the interconnection agreements, PG&E essentially focuses on whether PG&E, in its own estimation, believed that it was not making a long-term change to operations on its system that may reasonably result in an adverse impact to the districts’ systems.

“However, the commission in the remand order found that PG&E breached the interconnection agreements by failing to undertake a study … which considers the perspective of the coordinating party, here, the districts.”

“Equally unavailing,” FERC said, “is PG&E’s assertion that the term ‘adverse impact’ under the interconnection agreements was not intended to cover changes occurring outside the districts’ systems. As an initial matter, the Ninth Circuit already ruled that adverse impacts should not be so narrowly construed. From a technical perspective, the districts’ ability to transfer power into their systems may be affected by changes occurring outside of their boundaries, and this specific scenario could result from PG&E’s re-programming of its remedial action scheme … PG&E must participate in a study to assess the potential adverse impacts to the districts’ systems.”

March 24, 2020March 12, 2025

Gas, Renewables Pushed Power Prices Down in 2019

By Rich Heidorn Jr.

Lower natural gas prices and increased renewable penetration pushed wholesale power prices down sharply in most of the country last year, FERC reported last week.

The commission’s 2019 State of the Markets report noted that prices dropped 20% to 30% in MISO, PJM, NYISO and ISO-NE compared with 2018. Prices in northern CAISO were down 10%, and those in southern CAISO down 20%.

SPP’s prices were the lowest of the organized markets, averaging $30.43/MWh, unchanged from a year before, according to the report by the Office of Energy Policy and Innovation’s Division of Energy Market Assessments (DEMA).

Only ERCOT saw an increase, as record-high demand in summer pushed prices for the year to $49.65/MWh, up 20%.

Natural Gas

Although natural gas demand hit new highs, record-high production and relatively mild weather resulted in price declines of 35% to 41% at hubs in the Mid-Atlantic, New England and New York City. The biggest drops were in the Southwest, where hubs traded at negative prices at times because of pipeline takeaway capacity constraints.

U.S. natural gas production rose to 92.2 billion cubic feet per day (Bcfd) in 2019, up 8.4 Bcfd, the second-largest increase since the advent of shale exploration. Net gas exports averaged 5.1 Bcfd through November 2019, up from 1.9 Bcfd in 2018.

U.S. natural gas pipeline in-service capacity additions by region (Bcfd) | FERC Office of Energy Projects

Natural gas shippers added nearly 5 Bcfd (17 miles) of commission-jurisdictional pipeline capacity in 2019, down from the 13 Bcfd added in 2018.

Overall natural gas demand increased 2.6 Bcfd to 84.9 Bcfd in 2019, a 3% jump. Demand for electric generation averaged 30.9 Bcfd, up 7%, with a 12% increase in the Midwest.

Fuel Mix

Natural gas was responsible for 42% of generation nationwide between January and November 2019, according to the Energy Information Administration (EIA), with 26% from coal, 22% from nuclear, 4% from wind and 1% from solar.

MISO and SPP were most dependent on coal, which accounted for 43% of the regions’ generation. Solar and wind were big contributors in CAISO and SPP, respectively.

As in recent years, most new generation was natural gas or renewables and most retirements were coal plants.

Generation by fuel type | ABB Velocity Suite

The biggest retirements were the 670-MW Pilgrim Nuclear Power plant in ISO-NE (May 2019) and the 980-MW Three Mile Island nuclear power plant in PJM (September 2019).

PJM added 356 MW of natural gas-fired capacity, mostly combined cycle units. MISO saw a net decrease of 852 MW as it lost 2.9 GW of coal-fired capacity and gained 969 MW of natural gas and 997 MW of wind capacity.

SPP added 1.8 GW of wind capacity and had no retirements in 2019.

CAISO’s capacity dropped by 21 MW, losing 600 MW of natural gas capacity and adding 561 MW of solar.

Storage, DERs

Battery storage capacity increased by 174 MW in 2019, down from a 202-MW boost in 2018. But EIA forecasts about 400 MW of new battery storage will be added in 2020 and 1,816 MW in 2021.

“While it is unlikely all planned facilities will be operational by the end of 2021, the large increase represents a sea change in the role that battery storage plays in the bulk power system,” FERC said.

Battery storage capacity additions in recent years | EIA Form 860M

Battery storage additions have been clustered in a few states, led by California with 38% percent of planned capacity through 2023.

Capacity from distributed energy resources using net metering rose 4 GW to a record 23 GW in 2019, most of it in California, New Jersey, Massachusetts, Arizona and New York. The five states represent 70% of the net-metered capacity in the country, including California’s 40% share.

All but 6% of net metered capacity is solar PV. Solar PV’s price dropped 37% between 2013 and 2017, FERC said.

Transmission

Order 1000 transmission planning regions had 309 transmission projects go into service during the year, led by MISO (104) and PJM (101). In 2019, PJM, ISO-NE and NYISO each announced, or awarded to developers, new transmission projects using the competitive bidding processes in Order 1000.

Transmission additions by transmission planning region | C Three Group

March 24, 2020

FERC Sides With PJM on Pseudo-tie Challenges

By Michael Yoder

FERC on Friday rejected rehearing requests by American Municipal Power and Illinois Municipal Electric Agency over the commission’s November 2017 order approving PJM’s tougher requirements for pseudo-tied generators. The commission also approved PJM’s December 2017 compliance filing required by the order (ER17-1138).

“The commission found that PJM’s new pseudo-tie requirements would help ensure that external resources bidding into the PJM capacity auctions are comparable to internal resources in assuring that they will be deliverable to PJM’s system when needed,” FERC said last week. “With this principle in mind, we continue to find that PJM’s proposed treatment of pseudo-tied resources is just and reasonable.”

AMP’s Challenge

AMP’s rehearing request alleged five errors by the commission, including a challenge to PJM’s decision to set the electrical distance requirement at 0.065 per-unit impedance. AMP said the commission “failed to weigh and substantiate the impact of the proposed electrical distance requirement with the level of reliability assurance” and “failed to address the relationship between the value selected as the electrical distance requirement and the impact on PJM’s state estimator.”

PJM said the 0.065 threshold was based on a distribution factor analysis (DFAX) to identify the external facilities that would be impacted by PJM’s dispatch of external resources. PJM said the distance requirement made at least 130 GW of existing external resources in the Eastern and Midwestern U.S. eligible for pseudo-ties. The commission accepted PJM’s threshold, saying it was the “result of significant analysis and requiring PJM to rely on an external resource with a higher impedance value would increase the risk to PJM’s state estimator.”

The commission reiterated its previous finding that the electrical distance requirement was just and reasonable “because establishing a bright-line test for external participation strikes an appropriate balance between allowing external resources to participate in PJM’s capacity auctions, while providing PJM with a level of reliability assurances.”

IMEA’s Arguments

IMEA questioned FERC’s interpretation of Section 217(b) of the Federal Power Act and whether the commission’s decision “violated the sanctity of contracts.”

The agency argued that the commission’s determination that Section 217(b) of the FPA only applies to the energy markets and not capacity markets “effectively destroys the self-supply rights of load serving entities (LSEs).”

It said that if Section 217(b) does not apply to capacity markets, then PJM and other RTOs could make filings through Section 205 of the FPA to eliminate all “self-supply options” based on a finding that having control of all resources and planning would ensure better reliability.

FERC was unmoved. “Unlike energy markets, RTOs implement capacity markets to ensure long-term reliability and resource adequacy and, therefore, different requirements for using generation may be applied to capacity and energy markets,” the commission said.

March 24, 2020

SPP FERC Briefs: Week of March 16, 2020

FERC last week accepted Tri-State Generation and Transmission Association’s petition for a declaratory order that recognizes the cooperative as jurisdictional to the commission when it added its first non-utility member last year (EL20-16).

The commission agreed with Tri-State’s contention that the admission last September of Mieco, a wholesale energy services company that provides natural gas to Tri-State and other purchasers, made the cooperative a non-exempt jurisdictional public utility for purposes under the Federal Power Act (FPA).

FERC found that since Sept. 3, Mieco has “continuously been earning patronage capital through its sales of natural gas below index prices” and that Mieco and Tri-State have engaged in transactions that generated patronage capital — or the difference between a cooperative’s yearly operating income and expenses. It said Mieco has a vote in Tri-State’s operations “tailored to its status as a non-utility member,” noting that although the natural gas marketer holds voting rights different from those held by utility members, the commission has not found that the FPA “requires that owners have equal levels of control to demonstrate ownership.”

It said because no party provided evidence countering Tri-State’s claim that Mieco is not an exempt entity under the FPA, Tri-State “has demonstrated that Mieco’s rights are sufficient … to establish that Tri-State has not been wholly owned by entities exempt under [the FPA] since Sept. 3.

“Tri-State is grateful to FERC for its actions today and looks forward to working with FERC in a constructive manner for the benefit of Tri-State’s members,” Tri-State CEO Duane Highley said in a statem e nt.

SPP Tri-State — Tri-State G&T’s service territory spans much of the Rockies. | *Tri-State*

The company noted that it advances member flexibility for more self-supply and local renewable energy development. As part of Tri-State’s Responsible E nergy Plan, members have additional flexibility for the self-supply of power and more local renewable energy development.

Partial requirements contracts address the concerns of some members that desire self-supply above the 5% provisions in their current contracts.

Tri-State also requested relief to terminate controversy and remove uncertainty due to pending complaints filed in November before the Colorado Public Utilities Commission by members La Plata Electric Association and United Power. The cooperative said the utilities asked the PUC to “establish an exit charge [for the Member to be relieved of its obligations under its Wholesale Service Contract and exit Tri-State] that is just, reasonable, and nondiscriminatory.”

FERC said that while it had jurisdiction over Tri-State’s exit charges, it declined to rule that the jurisdiction is exclusive, recognizing that no federal court has found the commission has exclusive jurisdiction over “rules or practices that directly affect a jurisdictional rate.

“We find that the Colorado PUC’s jurisdiction over complaints before it regarding Tri-State’s exit charges is not currently preempted,” FERC wrote. “A ruling by the Colorado PUC on those complaints would not be preempted unless and until such ruling conflicts with a commission-approved Tariff or agreement that establishes how Tri-State’s exit charges will be calculated.”

Tri-State is a generation and transmission cooperative that provides wholesale electricity to 43 member electric distribution cooperatives and public power districts in Colorado, Nebraska, New Mexico and Wyoming.

Other Tri-State Requests Accepted

The commission also issued four other orders related to Tri-State’s request for FERC jurisdiction that the cooperative said ensure “consistent wholesale rate regulation” for its member distribution utilities. Those orders:

Granted Tri-State’s and Thermo Cogeneration Partnership’s request for market-based rate authorization. FERC denied Tri-State’s request for certain waivers and blanket authorization and granted Thermo Cogen’s request for waivers commonly granted to market-based rate sellers (ER20-6 81).
Found that Tri-State and Thermo Cogen had rebutted the presumption of market power in the Western Area Power Administration’s Colorado-Missouri balancing authority area and that they met the criteria for Category 2 sellers in the Northwest, Southwest and SPP regions and Category 1 sellers in the Southeast, Northeast and Central regions.
Denied Tri-State’s request for regulatory waivers and blanket authorizations, saying it does not typically grant waivers where the seller makes sales at cost-based rates.
Accepted Tri-State’s stated rate Tariff and wholesale electric service contracts and instituted a Section 206 proceeding under the FPA to determine whether the cooperative’s Tariff and electric service contracts are just and reasonable. The order establishes a refund effective date, as well as hearing and settlement judge procedures (20 –676).
Found that Tri-State’s filings raised issues of material fact that could not be resolved based on the record before it, saying they would be more appropriately addressed through hearings. It accepted the cooperative’s state rate Tariff and wholesale contracts to be effective Feb. 22 and Feb. 25.
Accepted Tri-State’s Tariff and instituted a Section 206 proceeding and hearing and settlement judge proceedings (E R 20-686).

FERC’s 206 investigation will determine whether Tri-State’s proposed formula rate, base return on equity (ROE), formula rate implementation protocols, reactive supply and voltage control service rates and real power loss factor are just and reasonable.

The commission also accepted Tri-State’s proposed service agreements and a notice of cancellation for filing. It held two contested cancellation notices in abeyance. It rejected without prejudice a board policy that describes members’ option to use self-owned or -controlled distributed or renewable generation resources to serve up to 5% of that members’ requirement (ER20 –689).

FERC also found the cooperative’s board policy and generation contracts are deficient without another board policy on file that comprises specific rate mechanisms, terms and conditions that significantly affect the rates utility members must pay if they produce energy in excess of the 5% allowance. It directed Tri-State to refile the rate schedules. The commission did accept the cooperative’s bylaws and other rate schedules for filing.

Commission Partially Accepts GridLiance Filing

The commission found that GridLiance High Plains’ amendments to FERC’s pro forma large generator interconnection agreement (LGIA) and pro forma large generator interconnection procedures partially comply with requirements of orders 845 and 845-A, requiring a further compliance filing within 120 days (ER19 –196 1).

The commissioners said GridLiance’s proposed revisions regarding the option to build transmission partially comply with the orders’ requirements because they incorporate most of their language without modification. However, FERC found that GridLiance had not justified its proposal to retain language of its pro forma LGIA that the commission removed from FERC’s pro forma LGIA in the revisions set forth in the orders.

The language at issue provides that the “interconnection customer shall so notify transmission provider within 30 calendar days” as required by orders 845 and 845-A.

FERC issued orders 8 4 5 and 84 5 -A in 2018 and 2019, respectively, to increase the transparency and speed of generator interconnection processes. (See FERC Order Seeks to Redu c e Time, Uncertainty on Interconnections and ‘Borin g Good’ Rulemaking Seeks to Clean up Order 845.)

— Tom Kleckner

March 24, 2020

MISO TO Cost Recovery Provision Approved

By Amanda Durish Cook

FERC on Thursday approved a new MISO Tariff provision that allows transmission owners to recover interconnection facility operations and maintenance costs from interconnection customers.

The decision allows MISO to include a new rate schedule — Schedule 50 — to allow TOs to recoup costs from interconnection customers for “reasonable expenses, including overheads, associated with operation and maintenance, and repair” of TO-owned interconnection facilities (ER20-170).

MISO TOs filed in October for the new rate schedule.

“While relevant provisions of a MISO generator interconnection agreement … already explicitly provide that interconnection customers ‘shall be responsible’ for all reasonable [operations and maintenance] expenses, there is presently no mechanism in the Tariff to enable the calculation and recovery of such expenses from interconnection customers,” the TOs explained to FERC.

MISO joined the filing as administrator of its Tariff but took no stance on the proposed revisions.

The TOs plan to allocate O&M annual charges based on a calculation involving the interconnection facilities’ installed costs as a share of a total annual transmission gross plant. When installed costs aren’t available for calculation, TOs will have to submit filings so FERC can review the alternate calculations.

In accepting the new schedule, FERC disagreed with renewable energy proponents that the Schedule 50 approach would “unduly” shift costs to interconnection customers. Some had argued that a process including transmission facilities didn’t translate well for interconnection facilities because they’re newer and less prone to maintenance charges. But the commission said the average useful life or O&M costs of an interconnection facility aren’t much different than the average useful life or O&M costs “of other similar transmission facilities.”

Other clean energy advocates said O&M costs should be assigned directly to interconnection customers instead of using a calculation. FERC again disagreed.

” … [E]ven in the instances where transmission owners utilize direct billing, not all costs are able to be directly assigned, some are assigned based on various allocators, and some costs are not even recovered,” the commission explained.

March 24, 2020

FERC OKs NETOs, Emera Maine Order 845 Filings

By Michael Kuser

FERC on Thursday accepted changes to the New England Transmission Owners’ (NETOs) interconnection study deadlines and the scope of their feasibility studies (ER19-1952).

However, the commission only partially accepted a separate Order 845/845-A compliance filing by ISO-NE and NETOs to reflect the orders’ changes to the commission’s pro forma large generator interconnection agreement (LGIA) and large generator interconnection procedures (LGIP), ordering a further compliance filing within 120 days (ER19-1951).

Renewable developers EDF Renewables, E.ON Climate & Renewables N.A. and Enel Green Power N.A. had argued that the revised deadlines — extending the feasibility study from 45 to 90 days and the system impact study (SIS) from 90 to 270 days — are unreasonably ambitious. They noted ISO-NE’s severe backlog, with feasibility studies averaging 229 days and SIS averaging 443 days.

But the commission said it expects “that the average study lengths will drop due to the reduced scope of the feasibility study and due to the other interconnection process improvements,” citing expanded use of consultants and a streamlined approach for managing SIS models and data.

FERC NETO — EDF Renewables’ Williston solar project in Vermont became operational in 2016. | *EDF Renewables*

Under the previous rules, many interconnection customers that chose the separate feasibility study later modified their projects before the SIS, reducing the time savings from conducting the feasibility study first. The new rules eliminate the option to integrate the feasibility study within the SIS and allow customers to forgo the feasibility study. Feasibility studies will be reduced to a limited power flow analysis, instead of the full power flow analysis allowed previously.

Regarding the LGIP filing, the commission found that it proposed, “without justification, language that differs in one respect from the commission’s requirements related to the process for analyzing surplus interconnection service requests.”

The filing parties explained in their transmittal letter (but did not specify in proposed Tariff revisions) that ISO-NE would limit the analysis it performs to its existing 10-business-day material modification framework for accommodating technological changes. The commission said it “may be inadequate to complete the evaluation required under Order No. 845.”

The commission required a further compliance filing to address the stand-alone network upgrades definition; interconnection customers’ ability to exercise the option to build; NETOs’ proposal to recover actual costs rather than a negotiated amount for oversight costs related to the option to build; the method for determining contingent facilities; requests for interconnection service below generating facility capacity; provisional interconnection service; and both the process and definition for surplus interconnection service.

FERC Partially Accepts Emera Maine Filing

FERC on Thursday also accepted amendments to Emera Maine’s LGIA and LGIP but ordered a further compliance filing within 120 days (ER1 9 -1887).

The commission found that the revised dispute resolution procedures in the company’s LGIP comply with Orders 845/845-A and that the variations are “consistent with or superior” to them. “However, the deadlines in Emera Maine’s proposed dispute resolution timeline contain an apparent incongruity,” the commission said, ordering a further compliance filing to address a five-day discrepancy in stated terms.

The commission found that the LGIP’s method for determining contingent facilities is in partial compliance but that proposed criteria for identifying contingent facilities “lack the requisite transparency.” It ordered the company to describe the specific technical screens, analyses, triggering thresholds or criteria it will use to identify such facilities.

The commission also ordered further compliance filings to incorporate pro forma revisions to section 3.1 of its LGIP; to revise section 4.4.6 to clarify how it will assess changes to a generating facility’s technical specifications; to clarify the deposit amount the interconnection customer is required to tender; and to specify that Emera Maine will complete its assessment and determination of whether a proposed technological change is a material modification within 30 days of an interconnection customer submitting a technological change request.