Page 1145 – RTO Insider

February 7, 2020

FERC Adopts NAESB Business, Communication Rules

By Rich Heidorn Jr.

FERC has adopted the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communication Protocols for Public Utilities as mandatory requirements, saying they are “necessary to increase the efficiency of the wholesale electric power grid.”

The commission approved the rulemaking at its Jan. 23 open meeting, but the order was not posted until Tuesday, following a review by the Office of Management and Budget (RM05-5-025, et al.).

FERC proposed adoption of Version 003.2 in May 2019 after its approval by NAESB’s Wholesale Electric Quadrant (WEQ). (See FERC Proposes Adopting NAESB Standards.)

The standards reflect changes from WEQ Version 003.1, which were the subject of an earlier Notice of Proposed Rulemaking that FERC never completed. The commission said it will help industry achieve efficiencies by streamlining utility business and transactional processes.

It includes common nomenclature for terms; the business practices for cutting transmission service during a transmission loading relief event; the cybersecurity framework and transaction processing requirements for parties making transactions over a transmission provider’s OASIS or e-Tagging system; a framework for transparency and accountability of demand response measurement and verification; and reflects modifications to the NERC reliability standards, including dynamic tagging. It incorporates the WEQ-022 Electric Industry Registry Business Practice Standards, which replace the NERC Transmission System Information Networks as the tool used for electronic tagging.

FERC NAESB — FERC headquarters in D.C. | *FERC*

“These practices will ensure that potential customers of open access transmission service receive access to information that will enable them to obtain transmission service on a nondiscriminatory basis and will assist the commission in maintaining a safe and reliable infrastructure and also will assure the reliability of the interstate transmission grid,” FERC said.

NAESB’s voluntary standards become mandatory for FERC-regulated public utilities after they are incorporated into the commission’s regulations. The rule requires public utilities and entities with reciprocity tariffs to modify their open access transmission tariffs to include the WEQ standards that FERC incorporated by reference.

The rule updates NAESB’s Smart Grid Standards (WEQ-018 and WEQ-019). The commission declined to incorporate by reference some smart grid portions of WEQ-018 and WEQ-019 that it has already adopted as nonmandatory guidance (Order 676-H).

AFC/ATC Standards

FERC also declined to incorporate the WEQ-023 Modeling Business Practice Standards in its entirety, which are the subject of a separate proceeding.

NAESB developed WEQ-023 after NERC asked it in 2014 to consider adopting standards covering the commercial and business aspects of the MOD standards proposed for retirement. WEQ-023 set out the requirements for calculating available flowgate capability (AFC) and available transfer capability (ATC) and adds two new requirements not previously included in the NERC reliability standards regarding contract path management.

NERC proposed replacing its six MOD A standards with standard MOD-001-2, focused exclusively on the reliability aspects of ATC and AFC.

The commission declined to incorporate the standard because it is still considering NERC’s proposed retirement of its ATC-related reliability standards (RM14-7) and is considering policies on the calculation and transparency of ATC (AD15-5).

Time-error Correction

The commission rejected the proposal to retire Time Error Correction Business Practice Standards, the subject of a separate NOPR, saying NAESB had not “adequately supported” it.

The commission said NAESB failed to justify retiring time-error correction as a business standard, saying the only support provided for its retirement is that NERC retired the corresponding reliability standard as unnecessary. FERC cited “unrebutted” comments noting “a continued need for, and possibly expansion, of such standards.”

“NOPR commenters provide significant evidence that time-error correction remains an important business practice that requires robust and meaningful business practice standards. Moreover, NERC continues to provide reliability coordinators serving as time monitors in the North American interconnections with a time-monitoring reference document that specifies how manual time-error corrections are to be implemented if needed and outlines procedural responsibilities assigned to the time monitor.”

The commission said public utilities should work through the NAESB business practices development processes to revisit the issue of whether the standards should be retained or revised.

Other Departures

The commission also declined to incorporate by reference into its regulations the:

Standards of Conduct for Electric Transmission Providers (WEQ-009), which NAESB has eliminated as duplicative of commission’s regulations;
Contracts Related Standards (WEQ-010), which set model contracts for the wholesale electric industry which are not mandatory; and
WEQ/WGQ eTariff Related Standards (WEQ-014), which provide an implementation guide for the submission of electronic tariff filings to the commission, which are governed by the commission’s eTariff regulations.

February 7, 2020

Supply Chain Standard Posted for Comments

By Rich Heidorn Jr.

NERC has opened a 45-day formal comment period on proposed reliability standards addressing cybersecurity supply chain risks.

Project 2019-03 was initiated in response to FERC Order 850, which directed NERC to submit modifications to address electronic access control or monitoring systems (EACMS) that provide electronic access control to high- and medium-impact bulk electric cyber systems. (See FERC Finalizes Supply Chain Standards.)

The proposed standard also includes a recommendation from NERC staff’s supply chain ri s ks report in May, which called for requirements on physical access control systems (PACS) that provide physical access control (excluding alarming and logging) to high- and medium-impact cyber systems.

Comments will be accepted until 8 p.m. ET March 11 on CIP-005-7 (Cyber Security – Electronic Security Perimeter(s)); CIP-010-4 (Cyber Security – Configuration Change Management and Vulnerability Assessments); and CIP-013-2 (Cyber Security – Supply Chain Risk Management), which required responsible entities to “develop one or more documented supply chain cyber security risk management plan(s) for high- and medium-impact BES cyber systems and their associated EACMS and PACS” (emphasis added).

Ballot pools will be formed through 8 p.m. Feb. 25. An initial ballot for the standards and implementation plan, and a nonbinding poll for the associated violation risk factors (VRFs) and violation severity levels (VSLs), will be held March 2-11.

The comment form asks stakeholders whether:

they agree with FERC’s justification of adding EACMS to CIP-005, CIP-010 and CIP-013;
they agree with the addition of PACS to CIP-005-7, CIP-010-4 and CIP-013-2;
they agree with the designation of a violation for failing to have a method for determining or disabling PACS as a moderate VSL, and a violation for failing to have a method for determining and disabling as a high VSL;
the proposed 12-month implementation plan is sufficient; and
the modifications in CIP-005-7, CIP-010-4 and CIP-013-2 meet the FERC directives in a cost-effective manner.

The standards development team for the project will meet March 24-26 to consider the comments and plans a second posting in April, team members said during a webinar Tuesday.

The standard proposes a 12-month implementation plan. “However, if you feel 18 months is more appropriate, give us some reason why,” SDT member Tony Hall, of Louisville Gas & Electric and Kentucky Utilities, said in response to one question from the audience.

In November, the drafting team said it would leave the definitions of PACS and EACMS unchanged, at least in the first ballot. Some have called for replacing EACMS with EACS (electronic access control system) and EAMS (electronic access monitoring system) and removing alerting and logging functions from the current definition of PACS. These, along with monitoring functions, would be reclassified as physical access monitoring systems (PAMS). But some team members said accepting the changes now could lead to confusion with other standards teams that rely on the original definitions. (See Supply Chain Team Wary of Changing Access Control Terms.)

February 7, 2020

Bakersfield Balks at Electrification with CPUC

By Hudson Sangree

Members of the California Public Utilities Commission on Thursday met in Bakersfield, a stronghold of conservative interior California, and heard a much different kind of public comment than they’re used to in San Francisco.

Bakersfield is the county seat of Kern County, a hub of oil and natural gas production and home to some of the state’s largest solar arrays. Instead of insisting that state policies should speed the demise of fossil fuels, as Bay Area speakers tend to do, residents and local officials urged the commissioners to hang on to natural gas.

They said they don’t want to give up their gas appliances or pay more to transition to renewable energy. California’s environmental plans call for the retirement of its natural gas fleet and a reliance on carbon-free electricity.

“I’m here to talk about choice,” said Grace Vallejo, a city council member from Delano, Kern County’s second largest city. “I know there’s a lot of talk about renewable energy, about the solar, about the wind. But I think that as local governments, we should be given the choice for our residents.

Bakersfield Electrification CPUC — Kern County, home to Bakersfield, is a major oil producer. | *BLM*

“I think the gas is something we should never eliminate or even try to control because, for us, if we want to have gas in our homes, that should be our choice,” she said. Vallejo said she has asthma and cares about air quality, but “I don’t want to be told that I have to put solar on my home. I don’t want to be told if I have to have all of the items in my home be electric.”

Electrification of buildings, including new and existing structures, is seen as a way for California to meet its goal under Senate Bill 100 of eliminating the state’s use of fossil fuels by 2045. (See West Coast Pushes for Building Electrification.)

Insisting that new homes include solar panels will raise the price of new houses in a state where affordable housing is in short supply, Vallejo said. “I’m only asking that you do a balanced decision for balanced energy,” she told the commission.

Alan Christensen, Kern County’s chief administrative officer, said he was concerned about the costs of the state’s ambitious greenhouse gas-reduction goals being passed on to disadvantaged communities.

He praised Pacific Gas and Electric’s recent proposal to the CPUC to regionalize its operations after it emerges from Chapter 11 reorganization. The state’s largest utility is in bankruptcy following years of catastrophic wildfires in Northern California. (See PG&E Tries to Appease Governor with New Plan.)

“Whenever you can get to the locals, that’s always a good thing,” Christensen said. But “we feel the system should be set up so that when fires occur in other areas, we should not have the responsibility to receive the rate increases associated with those issues. Those responsibilities ought to be borne by the areas where they occur.”

Wildfire costs in California are passed around, or socialized, through the state’s uniquely broad use of “inverse condemnation,” a legal principle that treats utilities as insurers of last resort, regardless of negligence.

The major fires of 2015, 2017 and 2018, ignited by PG&E equipment, occurred in the northern Sierra Nevada foothills and in the relatively wealthy Napa and Sonoma counties. Much of the costs of those fires could be passed on to ratepayers throughout PG&E’s 70,000-square-mile service territory, which stretches from near the Oregon border to Kern and Santa Barbara counties in the south.

Kern County covers a vast area of the agricultural San Joaquin Valley and Mojave Desert and hasn’t experienced the massive, deadly wildfires of its coastal neighbors and counties to the north.

When fire costs are shared by ratepayers throughout PG&E’s system, “those costs will be borne by many of the disadvantaged communities in Kern County,” Christensen said. “We have many of them [that are] below the poverty level.”

February 7, 2020

Rules Will Limit MISO Capacity Resource Outages

By Amanda Durish Cook

CARMEL, Ind. — MISO is wrapping up implementation of recently approved outage rules designed to dissuade capacity resources from taking long outages that could risk supply.

Approved last month by MISO Eases New Rules on Extended Outages.)

MISO Capacity Resource Outages — Tim Bachus, MISO | © *RTO Insider*

Speaking at the Resource Adequacy Subcommittee’s meeting Wednesday, Tim Bachus, MISO capacity market administration analyst, said the policy change will be in place for the April PRA.

Nearly final BPM language states that the rule applies to “resources with pending full or partial outages that are planned and/or scheduled and reasonably expected to encompass” 90 or more days of the first 120 days of the planning year. MISO has committed to reviewing outages and derates prior to opening the PRA offer window to determine which capacity resources might be excluded from the auction.

“Market participants with resources that are affected by this rule will be given the chance to adjust those planned outages/derates to permit PRA participation,” MISO said.

Gabel Associates’ Travis Stewart said that MISO’s plan still “doesn’t have any teeth” and criticized the lack of consequences for resources that aren’t candid ahead of time regarding their availability.

MISO counsel Jacob Krouse pointed out that there are other protections against such behavior, notably the ability of the RTO’s Independent Market Monitor to notify FERC’s Office of Enforcement about resources that exhibit signs of withholding.

MidAmerican Energy’s Greg Schafer said it would be troubling if MISO began establishing penalties in BPMs that weren’t included in proposals to FERC. “We’re always concerned about things creeping into the BPM that were explicitly excluded from the Tariff,” he said.

FERC last month granted a Feb. 1 effective date for the plan. The commission’s order also dismissed as moot Wolverine Power Supply Cooperative’s September complaint that the rules lacked adequate consequences for planning resources that take extended outages.

The co-op had argued that the Tariff was unjust and unreasonable because it allowed a resource to participate in the PRA even when taking an approved outage for the entire planning year — including a large resource in Michigan that bid into the 2019/20 auction. As a rule, MISO doesn’t reveal which generators plan outages, citing confidentiality.

“MISO’s proposed Tariff revisions address this problem by ensuring that resources that are unavailable for the entire planning year will not qualify for participation in the auction or inclusion in a fixed resource adequacy plan. By specifically addressing resource availability during the first 120 days of the planning year, which begins June 1, MISO’s approach is consistent with current loss-of-load expectation study parameters, which indicate that the highest risk of resource adequacy concerns occurs generally from June through September,” FERC said.

Bachus said other than in that one instance, MISO doesn’t typically see capacity generation taking substantial outages.

MISO staff have said the temporary change is only meant for the 2020/21 PRA, though Bachus said the RTO could keep it in place for the 2021/22 cycle.

February 7, 2020

Little Change in MISO 2020/21 PRA Assumptions

By Amanda Durish Cook

CARMEL, Ind. — Early data for MISO’s spring capacity auction shows a 1-GW uptick in the RTO’s capacity supply needs but essentially no change in year-over-year peak forecasts.

MISO forecasts a 121.6-GW systemwide coincident peak and a nearly 136-GW planning reserve margin requirement for 2020/21. The peak forecast is identical to last year’s early prediction, which was later upped to 122 GW. (See MISO Preliminary PRA Data up Slightly from Early Prediction.)

The zonal coincident peak forecast is predicted to be slightly more than 125 GW, also nearly identical to last year’s estimate. MISO also noted that coincident peak forecasts “across the footprint were flat or showed slight decreases.”

“The numbers are very similar to last year’s. This is the second year that we haven’t seen meaningful increases or decreases,” Tim Bachus, MISO capacity market administration analyst, said at a Resource Adequacy Subcommittee meeting Wednesday.

MISO PRA — MISO local resource zones | *MISO*

However, zonal reserve margin requirements are up slightly because of a 1% increase in the overall margin from 2019/20. (See MISO Planning Reserve Margin to Climb in 2020.) Local clearing requirements increased by less than 200 MW in half of MISO’s 10 local resource zones. The RTO last year estimated an almost 135-GW planning reserve margin requirement.

Bachus said fuller and updated predictions will be presented at the March RASC meeting.

MISO also released updated subregional import and export constraints for transmission linking the Midwest and South for the 2020/21 Planning Resource Auction. The RTO is limited to directional flows of 3,000 MW southbound and 2,500 MW northbound, but it conducts annual feasibility studies on the limits and reduces flows according to firm transmission reservations.

MISO said the southbound flow limit will remain unchanged at 3,000 MW this year, but the northbound limit will be 1,900 MW, an increase of 400 MW from last year’s flow cap of 1,500 MW based on the feasibility study. The RTO reported 600 MW worth of transmission service requests in the northbound direction.

MISO Manager of Capacity Market Administration Eric Thoms said firm transmission requests that expired last year will allow more capacity across the limit in the upcoming planning year.

February 6, 2020

Exelon Challenges PJM Monitor’s ComEd FRR Analysis

By Christen Smith

VALLEY FORGE, Pa. — Exelon said Wednesday that a report from the PJM Independent Market Monitor uses faulty assumptions and anti-subsidy rhetoric to exert undue policy influence and cast a negative light on the fixed resource requirement (FRR) alternative some members may pursue in the face of an expanded minimum offer price rule (MOPR).

The Monitor himself responded to concerns at a Market Implementation Committee meeting when he presented his analysis of how capacity prices would change if Commonwealth Edison’s zone opted for FRR instead of participating in PJM’s capacity auctions.

ComEd, a subsidiary of Exelon, supplies more than 4 million customers across northern Illinois. The state is one of several in PJM that could consider the FRR construct to shield its portfolio of subsidized resources from the new MOPR rules. Exelon’s Quad Cities plant, one of five nuclear facilities in the state, began receiving zero-emission credits (ZECs) in 2017 — the very type of subsidy that FERC Extends PJM MOPR to State Subsidies.)

Exelon itself has been a vocal proponent of state legislation that would value resources based on emissions attributes, implement rate caps to better protect consumers and support expanding Illinois’ ZEC program to the four other nuclear plants. Exelon’s merchant generation subsidiary owns all five facilities.

Exelon PJM FRR — Jason Barker, Exelon | © *RTO Insider*

The Monitor’s report “really isn’t a credible or useful tool for understanding the value of an FRR for Illinois customers,” said Jason Barker, director of wholesale development for Exelon. “It’s telling that no one asked the IMM to develop this report.”

Monitor Joe Bowring noted that there had not been an explicit request for the report. The Monitor “routinely creates reports in order to provide facts and objective analysis to the market participants so that they can make reasonable decisions,” he said. “We plan to do additional analyses of the impacts of the MOPR order, including additional FRR analyses.”

Bowring’s report concludes that net load charges would increase 23.6% if ComEd procured all of its capacity obligations outside of the Base Residual Auction at the same rate as the offer cap — $254.40/MW-day — assigned to the zone in the 2021/22 delivery year.

In a second scenario, the Monitor calculated that ComEd’s load charges would decrease just 5% if the price negotiated for its capacity were equal to the zone’s 2021/22 BRA clearing price of $195.55/MW-day. In the report, Bowring said that the first scenario seemed more reasonable, “given Exelon’s assertions that the current total revenue from energy, ancillary and capacity markets is not adequate for its nuclear plants.”

The report also found that carving ComEd’s load delivery area out of the auctions would reduce capacity payments across the rest of the RTO, regardless of the prices charged in the FRR area.

Barker pushed back against the report’s methodology and argued that it ignored the political situation in Illinois, as well FRR rules that don’t dictate a single price be paid to resources with “different attributes.”

“These faulty assumptions and repeated anti-ZEC rhetoric indicate that the purpose of the report is to cast a negative light on the development of a ComEd FRR and its impact on customers, rather than to objectively and independently analyze potential policy outcomes,” Barker said. “The report confuses debate instead of advancing it.”

‘Reasonable Range’ Sought

In response to Exelon’s assertion that the specifics of the state’s varied FRR legislative packages had not been included in the report, Bowring said, “We very consciously and explicitly tried not to incorporate the details of the various forms of draft legislation.

“We were not trying to tell Illinois what to do,” he said. “Who knows what may happen? What we did was very simple. We tried to define a reasonable range of the impacts of the FRR option. We think we did that in a clear and non-rhetorical way.”

Bowring reiterated that the report was meant to educate and that he was open to doing additional sensitivity analyses for Exelon or any other market participant.

“Our primary point about the FRR option is that once you’ve chosen to do that, you are giving some degree of market power to the owners of that capacity,” he said. “The state will have to negotiate with one or two generators to set the compensation for the generation that the state requires for reliability.

“We are not saying we know what the exact compensation would be; we are just showing what the impact of taking ComEd out of the auction would be for a range of prices,” Bowring added. “Ultimately the price paid would be a function of the price negotiated between the owners and the state entity. We think market power is an issue in the creation of any FRR.”

February 6, 2020

ISO-NE Capacity Prices Hit Record Low

By Rich Heidorn Jr.

ISO-NE’s 2020 capacity auction cleared at a record low of $2/kW-month, a nearly 50% drop from $3.80/kW-month in 2019.

ISO-NE Capacity Prices — ISO-NE Forward Capacity Auction prices (2013-2020) | *ISO-NE*

Forward Capacity Auction 14, which began Monday, cleared 33,956 MW of capacity for 2023/24 after five rounds of bidding. That gives the region a 1,466-MW surplus over the net installed capacity requirement of 32,490 MW, at a total cost of about $980 million.

ISO-NE noted that auction rules allow it to acquire less than the capacity target or more if it can ensure “enhanced reliability at a cost-effective price.”

More than 600 MW of new resources cleared the primary auction, including 317 MW that received their capacity obligations under the renewable technology resource (RTR) designation, which allows a limited amount of renewables to participate in the auction without being subject to the minimum offer price rule.

The exempt resources included land-based and offshore wind, solar PV, and solar PV paired with batteries. About 19 MW remain under the exemption for the 2021 auction, which will be the last to include the RTR.

Generation represents 85% of the capacity acquired, followed by demand resources (e.g., energy efficiency, load management, distributed generation) at 12% and imports from New York, Québec and New Brunswick at 3%.

Some 42,219 MW, including 34,905 MW of existing capacity and 516 new resources totaling 7,314 MW, qualified to participate in FCA 14.

“New England’s competitive wholesale electricity markets are producing record low prices, delivering unmistakable economic benefits for consumers in the six-state region,” Robert Ethier, ISO-NE vice president for system planning, said in a statement.

Auction rules allow existing resources interested in retiring to trade their capacity supply obligations with new state-sponsored resources that did not clear in the primary auction. But no such trades occurred, the RTO said.

Before the auction, 258 MW of resources submitted retirement bids, and another 21 MW filed permanent delist bids to leave the capacity market. All of the bids cleared before the auction.

Outside of the auction, ISO-NE has contracted to keep Exelon’s Mystic 8 and 9, which had been slated for retirement, operating for fuel security in 2023/24.

The RTO said the results are preliminary. Final results, with resource-specific results, will be submitted for approval by FERC by the end of February.

The results of FCA 13 became effective “by operation of law” Sept. 24 because FERC was unable to muster a quorum following the departure of Commissioner Cheryl LaFleur and the recusal of Commissioner Richard Glick. (See FCA 13 Results Stand Without FERC Quorum.)

Reaction

Generators tried to put the best face on the low prices, with the Electric Power Supply Association calling it “great news.”

“With one of the cleanest generation fleets in the US, the region should enjoy reliable, clean, cost-competitive power for years,” said Dan Dolan, president of the New England Power Generators Association.

Dolan said the prices were depressed because of the Inventoried Energy Program for reliability and the retention of the Mystic station, noting that neither program is expected to be in place for next year’s auction.

Dolan said the Competitive Auctions with Sponsored Policy Resources (CASPR) program was not needed this year because of the Mystic plant, the RTR renewables exempt from MOPR, and “ongoing siting challenges for state-sponsored projects.”

“Next year’s auction may provide a clearer window of the efficacy of the CASPR program. Longer term, NEPGA continues to believe that the region should move toward a meaningful price on CO₂ emissions to match environmental and clean energy goals.”

Other observers were ready to call CASPR a bust.

“Well NE governors,” tweeted Joe LaRusso, the EE and DR finance manager for the city of Boston. CASPR “which was supposed to `balance state public policies [supporting increasing renewable generation] with the competitive wholesale electricity market’ has failed. What will you do?”

“So much for @isonewengland approach to [accommodating] state policy,” agreed consultant Rob Gramlich, executive director of Americans for a Clean Energy Grid (ACEG). “CASPR approach cleared 0 MW this time and 50 MW (for $0) last time. Meaning renewables are not getting paid for the capacity they provide and consumers are paying twice. #MOPRmadness.”

February 6, 2020

SPP Sets 71.3% Wind Penetration Mark

SPP set a new record for the amount of wind energy in its resource output mix early Monday morning when it recorded a penetration level of 71.3%.

The new mark came at 3:15 a.m., when wind served 17,346 MW of the total 24,329-MW load, breaking the record of 68.8% on Oct 19. It also backed up Senior Vice President of Operations Bruce Rew’s 2018 prediction that SPP had a “good chance” of breaking the 70% threshold.

Rew was at it again during January’s governance meetings in Santa Fe, N.M.

“We predict wind will overtake coal as the region’s No. 1 energy source in 2021,” he said during SPP’s joint quarterly stakeholder meeting.

SPP currently has 22.5 GW of installed wind capacity, much of it on the plains of Oklahoma and Kansas. Rew told stakeholders that both states have recently seen multiple days when they produced more wind energy than was necessary to meet their load.

— Tom Kleckner

February 5, 2020

SPP MMU: Reduce Self-Commitments, Improve Market

By Tom Kleckner

S P P‘s Market Monitoring Unit said it is not looking to end self-commitment but that a reduction in the practice would result in a more efficient market.

SPP — MMU Executive Director Keith Collins | © *RTO Insider*

“We do note that a high volume of make-whole payments [for self-commitments] is not considered desirable. It creates inefficiencies in the market,” Monitor Executive Director Keith Collins said Monday during a webinar on a report it released in December on self-commitments.

Collins capitalized on the previous day’s Super Bowl to put the issue into terms that might make more sense to his audience. “Imagine your favorite sports team, and imagine it’s the players who decide will play, rather than the coach,” he said. “The outcome you get may not be as efficient as the coach optimizing that for you.”

In the re p ort, “Self-committing in SPP markets: Overview, impacts, and recommendations,” the Monitor recommends SPP and stakeholders work to reduce the number of self-commitments to improve price formation and market efficiency. The Monitor also suggests SPP modify its market design by adding another day to the market optimization period.

MW dispatched by commitments, self-commit MWs by fuel type | *SPP MMU*

The report says a smaller distortion of prices and investment signals “will likely help market participants make better short-run and long-run decisions, which tends to coincide with improved profit maximization.

“Enhanced profit maximization, combined with effective regulation and monitoring, will likely lead to ratepayer benefits in the form of cost reduction,” the Monitor said.

Monitor staff studied offer behavior from March 2014, when SPP’s day-ahead Integrated Marketplace went live, to August 2019. They re-solved past market cases by running two simulation series of a week per month from September 2018 to August 2019, assuming all generation was offered in market status and that it could be started economically by the day-ahead market.

The analysis found that:

The volume of self-committed MW has declined over time but remains nearly half of the total MW volume generated during the study’s time frame.
Prices and production costs were systematically lower when at least one self-committed unit was on the margin.
In almost all cases, self-committed generators had lower revenues because of negative congestion prices. Market-committed generators typically had a more balanced congestion profile.
Resources with long lead times and/or high start-up costs tended to be self-committed instead of market-committed.
Self-committed units generally had much higher capacity factors than those that are market-committed. The largest portion of self-committed dispatch MW were from coal units, exceeding the second-largest fuel type by a 4-to-1 ratio.

In its simulations, the Monitor found that:

When the market made unit commitment decisions and lead times were unchanged, both market-wide production costs and market-clearing prices for energy increased.
When the market made unit commitment decisions and lead times were modified to allow the day-ahead market to commit the resources with long lead times, market-wide production costs were essentially unchanged and market-clearing prices for energy increased about 7% ($2/MWh) on average. Congestion prices fluctuated from -$1/MWh to $1/MWh on average.

Having the economic commitment process solve over a two-day period rather than one would optimize long-lead time resources’ participation in the market, the report says.

“Simply eliminating self-commitment without any additional changes could result in an increase in total production costs,” the report warns. “However, when lead times were shortened to reflect an additional day in the market optimization and self-commitment was eliminated, producers were paid more and production costs declined.”

The Monitor is taking its presentation on the road. Having already shared its recommendations with the Market Working Group, it also plans to meet with the Cost Allocation Working Group.

“We’ll be speaking in different committees and venues,” Collins said.

February 5, 2020

GridLiance Gains Entry into MISO

By Amanda Durish Cook

Transmission owner GridLiance Heartland has gained access to the MISO system through an acquisition of transmission lines in Illinois and Kentucky after an unsuccessful first attempt to join the RTO.

In a trio of orders Jan. 31, FERC conditionally approved GridLiance Heartland’s acquisition of eight transmission assets from Vistra Energy subsidiary Electric Energy Inc. (EEI) (E C 20-13), set an annual transmission revenue requirement at about $7.4 million (ER19-2 0 50-002) and OK’d a separate open access transmission tariff (OATT) for the two lines that won’t be under MISO functional control immediately (ER19-2092, e t al.).

The third order also established settlement judge proceedings to examine the reasonableness of GridLiance Heartland proposing the MISO base return on equity in the OATT for non-MISO assets. GridLiance proposed a 10.32% ROE for the OATT, the ROE rate in use in MISO at the time of its filing in December 2018. FERC in late November adopted a new 9.88% return on equity for transmission owners. (See FERC Adopts ROE Methodology in MISO Complai n ts.)

The deal involves two 161-kV substations and six 161-kV transmission lines 8-10 miles in length that cross the Ohio River and connect to the EEI-owned Joppa Power Plant in southern Illinois. Vistra owns an 80% interest in EEI, with Kentucky Utilities controlling the remaining 20%. The assets are currently outside the MISO footprint. GridLiance said it would transfer all assets to MISO control by 2022: Four of the six lines will be turned over immediately to MISO, while two must wait for existing power supply agreements to run their course.

The six lines were originally constructed to power the U.S. Department of Energy’s now-defunct Padu c ah Gaseous Diffusion Plant uranium facility. EEI reconfigured its transmission system to disconnect from the Paducah plant in 2017. Four of the lines connect with TVA, while the other two connect with the Louisville Gas & Electric/Kentucky Utilities balancing authority area. The lines currently don’t serve any load.

GridLiance MISO — Paducah Gaseous Diffusion Plant | *U.S. Department of Energy*

MISO’s Board of Directors approved GridLiance Heartland’s application to join the RTO as a transmission-owning member in September 2018 subject to the outcome of the proposed transaction.

FERC had blocked the transaction in August, deciding GridLiance and EEI failed to prove the acquisition wouldn’t adversely affect MISO rates. (See FERC Blocks GridLiance’s Door into MISO.) The move will increase revenue requirements in the Ameren Illinois transmission pricing zone by about 2.6%.

GridLiance proposed rate mitigation credits to offset the $3.6-million difference between the projected revenue requirements of EEI and itself. The TO said the credits would appear in accounting as a fixed revenue credit and lower its revenue requirement every year for the five years after MISO takes control of the lines.

GridLiance said the credits “balance the risks and rewards for a start-up transco with a small initial rate base.” It also noted that it plans to participate in “proactive” planning studies on how the lines “may be optimized to solve documented transmission constraints.” The company said the lines may prove useful in lessening the strain on the transfer constraint linking MISO’s Midwest and South subregions.

GridLiance also noted that as a MISO member, it could help address “underinvestment” in transmission by MISO’s municipal and cooperative utilities.

Ameren Objects

The commission approved the deal over multiple objections from Ameren.

Ameren faulted GridLiance for using estimated, “snapshot in time” revenue requirements for its rate credits rather than actual amounts. It also said the commission was failing to consider that GridLiance would seek recovery of its $23.6 million regulatory asset that FERC approved last year. Ameren asked that FERC create further protections from the impact of GridLiance’s regulatory asset costs.

The company also said GridLiance’s claims of future benefits to MISO or the Ameren pricing zone were “tenuous.”

But FERC said GridLiance’s rate mitigation proposal addressed its concerns over the rate increase. The commission also said GridLiance Heartland is not to recover any amounts related to its regulatory asset during the first five-year rate mitigation.

“The regulatory asset is related to past development activities by GridLiance Heartland and not to costs that [EEI] would have incurred if it had retained ownership,” FERC warned.

FERC accepted GridLiance’s unorthodox rate mitigation proposal instead of the more commonplace five-year rate freeze based on the company’s assertation that forces out of its control could have increased even EEI’s revenue requirement, such as storm damage, or a new NERC requirement.

Ameren also protested the use of a stand-alone OATT for the non-MISO lines, saying it represented a “step backward in terms of the efficiencies created by having an RTO footprint.”

“We are not persuaded by Ameren’s argument that this proposal is a step backwards because GridLiance Heartland is eschewing the efficiencies of an RTO footprint. RTO participation is not mandatory and Order No. 888 requires that an OATT be on file in order to provide transmission service,” FERC responded.

GridLiance said it also plans to use the OATT to provide transmission service over “any future facilities it acquires in the MISO region but does not transfer to MISO’s functional control.”

FERC granted a one-time waiver of Order 1000’s competition requirements for the OATT. The commission said since GridLiance is proposing to transfer control of the lines and substations to MISO, it afforded no “practicable opportunity” for the TO to adhere to Order 1000. The commission noted the “unique circumstances” present in the transaction and said the waiver would be reassessed if GridLiance decides to build additional facilities under the same OATT.