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November 5, 2024

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Z2 Task Force Looks at Incremental Congestion Rights

By Tom Kleckner

DALLAS — Stakeholders working to improve SPP’s cumbersome Z2 crediting process for network upgrades met here last week to learn about how potential solutions might affect the RTO’s other functions — leaving one stakeholder pining for the good old days when he worked in an operations center.

Another stakeholder, the Kansas Power Pool’s Larry Holloway, expressed mild frustration as the Nov. 29 conversation turned to long-term and incremental long-term congestion rights (LTCRs and ILTCRs, respectively) and their potential addition to the Z2 process.

“There seems to be a bit of mission creep. I thought we were looking at a better way to do business with Z2,” said Holloway, KPP’s assistant general manager of operations. “I thought we were looking at a less complex way of handling [Z2] going forward and handling the burden of these historic costs. Now it sounds like we’re keeping Z2 and having another process moving forward.”

“Our goal is to come up with a better process,” Bruce Rew, SPP’s vice president of operations, reminded the task force. “We’re working through the process of how we would transition to a different process.”

Cates and Walkup at the spp z2 task force meeting
SPP’s Charles Cates and AECC’s Bruce Walkup during the Z2 Task Force meeting. | © RTO Insider

SPP staff suggested LTCRs and ILTCRs could serve as potential alternatives to Z2 credits. LTCRs cover the entire June-May year and can be renewed annually or converted into TCRs. ILTCRs, already used by most RTOs, would provide the option of long-term rights for participant-funded transmission upgrades.

“The TCR process tries to forecast what the [congestion] pool will be,” said Charles Cates, SPP’s manager of transmission services, explaining that solving congestion at one point on the system can create congestion elsewhere. “A TCR is your share of the congestion pool. The value of the TCR may increase as more transmission requests come onto the system. Some bidders may try and predict where that congestion will be and seek TCRs.”

‘Nightmare’

Richard Ross Gold Star for "taking the Z2 bullet for the team." | given at the spp z2 task force meeting
Richard Ross Gold Star for “taking the Z2 bullet for the team.” | © RTO Insider

“I’d like to ditch this Z2 nightmare, but the problem is, [when] you give away the TCR to a project sponsor whose project resolves the issue and there’s no congestion, he’s getting nothing [of value],” American Electric Power’s Richard Ross said. “I’m afraid this will give incentives for some sort of twisted sponsorship where sponsors will want to solve some, but not all, of the congestion. If there’s still congestion and you’ve given that TCR away to that sponsor, it’s not available for that transmission customer that wants, needs and expects it.”

“I keep hearing the word ‘incentives,’ but we’re really looking at reimbursement mechanisms,” said Oklahoma Gas & Electric’s Greg McAuley, agreeing with Ross. “We’re looking to pay [upgrade sponsors] back and make them whole for what they’ve added to the system, but we’re not trying to provide incentives for new transmission construction.”

Cates noted SPP’s TCR market is still going through growing pains since it was implemented as part of the RTO’s Integrated Marketplace in 2014. In recent months, the TCR market’s funding has just reached a 90% funding level.

“To be fair, we don’t have much of an ILTCR market because no one takes them,” SPP’s Lanny Nickell said.

The TCR market’s inability to provide a one-for-one offset with hedges against congestion has become a growing concern for load-serving entities. They point to wind farms being granted non-firm service while being allowed to put physical energy on the system.

“How do they get away with not paying for non-capacity upgrades, and why are we being forced to pay for sponsored upgrades?” Ross asked rhetorically. “That doesn’t make a bit of sense. Why are we paying $10 for something that’s not worth a nickel?”

Kansas City Power and Light’s Denise Buffington, the task force’s chair, asked staff to provide more information on how the capacity versus non-capacity issue is handled in other markets. The task force will meet again before January’s Markets and Operations Policy Committee meeting in Dallas, where it will take an even deeper dive into SPP’s ILTCR proposal.

‘And’ vs. ‘Or’

The group also discussed SPP’s aggregate and planning studies, generation interconnection process and the auction revenue rights and TCR processes. Staff also explained the Z2 process was used as a mitigation for FERC’s concern about “And” pricing for service, embedded costs and any other upgrade costs.

In a 2001 order, the commission said the pricing of transmission service could reflect either the greater of the network’s average cost (with expansion costs rolled-in) or the incremental cost of the expansion, known as “Or” pricing. It prohibited pricing based on a combination of average and incremental costs, known as “And” pricing.

SPP’s Tessie Kentner said any changes to the Z2 crediting process must not violate those principles. She said the commission accepted the RTO’s compliance filing and its use of Z2 credits for sponsored upgrades for Order 681, which requires organized electricity markets to make available long-term firm transmission rights.

“I think we have a deeper understanding of the complexity of Z2 and may have highlighted that Z2, as implemented today, still has many unknown impacts to participants,” Buffington said.

SPP Z2 task force meeting
Left to right: SPP’s Steve Purdy and Tessie Kentner, and AEP’s Richard Ross during the Z2 Task Force meeting. | © RTO Insider

Ross did provide a moment of levity when he presented “Richard Ross Gold Stars,” in the form of Christmas ornaments, to SPP’s Steve Purdy and Charles Locke. Ross said it was a sign of appreciation to the two for representing the RTO’s position on Z2 credits.

“Somebody has to take the shots for the organization,” Ross said.

KEPCo Files FERC Complaint

The Kansas Electric Power Cooperative became the first SPP member to pursue legal action over the Z2 revenue-crediting process when it filed a complaint with FERC under Sections 206 and 306 of the Federal Power Act and Rule 206 of the commission’s Rules of Practice and Procedure (EL17-21).

KEPCo said in its Nov. 22 filing that SPP’s direct cost assignment of approximately $6.2 million to KEPCo violated the RTO’s Tariff and the filed rate doctrine, and is “otherwise unjust, unreasonable and proscribed” by the FPA. The complaint seeks relief from directly assigned Z2 obligations and a refund for payments already made.

KEPCo COO Les Evans had hinted at the filing when his request for a waiver from directly assigned Z2 network upgrades was rejected by the SPP board in October. (See SPP Board Lets Action on Z2 Stand; Litigation Likely.)

Seven parties have already intervened in the case, including SPP members KCPL, Sunflower Electric Power, Western Farmers Electric Cooperative and the Arkansas Electric Cooperative Corp.

Competitive Transmission, Strategic Planning, Other Groups Meet

The Z2 task force’s meeting was just one of several held in Dallas last week in and around AEP’s offices.

The Competitive Transmission Process Task Force met Wednesday to revise draft revision requests that reflect input from the October Board of Directors meeting and to incorporate changes in SPP’s annual transmission revenue requirement template. The group will conduct a conference call next week to prepare for the January board meeting.

The Strategic Planning Committee met Thursday to review and discuss the operational challenges facing SPP as a result of the 22,000 MW of wind power in the interconnection queue.

Stakeholders shared their concerns that the expected expiration of renewable tax credits is leading to a surge of additional generation being added to the system, citing congestion concerns. Wind and solar resources account for 98% of SPP’s current generation interconnection queue.

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Texas PUC Sets Questions in NextEra-Oncor Merger

By Tom Kleckner

The Public Utility Commission of Texas on Thursday approved a preliminary order outlining numerous issues NextEra Energy and Oncor must address to win approval of NextEra’s acquisition of Texas’ largest distribution utility.

Two of the PUC’s three commissioners, Chair Donna Nelson and Ken Anderson, also filed memos with additional questions for the docket (No. 46238).

PUCT Commissioners left to right: Ken Anderson, Donna Nelson and Marty Marquez | © RTO Insider
PUCT Commissioners left to right: Ken Anderson, Donna Nelson and Marty Marquez | © RTO Insider

“I want to be sure we cast a wide net,” said Nelson, who included a set of questions from the Texas Industrial Energy Consumers, during the commission’s open meeting.

She focused her questions on whether NextEra should be able to expense federal taxes for ratemaking purposes and if so, whether those savings should be shared with ratepayers. Similar directives from the PUC scuttled Hunt Consolidated’s attempted takeover of Oncor earlier this year. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)

Nelson also asked whether NextEra’s commitment to preserve Oncor’s staffing levels for two years after the transaction’s close was enough time, and what would constitute a “material involuntary workforce reduction,” quoting from the company’s promise of no layoffs.

Anderson directed the companies to answer whether the recent appellate court decision regarding Energy Future Intermediate Holdings’ make-whole claims to lien holders would affect the transaction and require an amended application. (See Appeals Court Ruling for Bondholders Clouds EFH Reorganization.)

He noted the commission faces a hard deadline of April 29 to issue a decision on the transaction. Because the PUC is hearing the case rather than an administrative law judge, the commissioners will have some flexibility when they conduct a hearing on the merits Feb. 21-24, Anderson said.

“Everyone needs to be mindful that in the absence of a unanimous settlement, once the record closes, that’s it,” Anderson said. “There’s no sweeteners … there’s no ability to change the deal” without an amended application.

NextEra announced in late July it had reached an agreement to acquire Energy Future Holdings’ 80.03% indirect interest in Oncor for $18.6 billion. On Oct. 31, it announced an affiliate would acquire an additional 19.75% from a pair of private venture funds, for an additional $2.4 billion. NextEra also plans to acquire the remaining 0.22% interest owned by Oncor Management Investment, giving the Florida-based company complete control of the company.

PUCT, NextEra, Oncor
| NextEra

Intervenors in the case include the Steering Committee of Cities Served by Oncor, the Office of Public Utility Counsel, the Texas Industrial Energy Consumers, IBEW Local 16 and NRG Energy.

The U.S. Bankruptcy Court in Delaware was to begin confirmation hearings for the exit of EFH (rebranded as Vistra Energy) from Chapter 11 bankruptcy Thursday, but those proceedings have been postponed until February. EFH filed a modified reorganization plan Thursday to compensate for the appeals court’s ruling that gives first- and second-lien noteholders an additional $800 million payout.

AEP Units’ Merger OK’d

Also Thursday, the PUC approved a State Office of Administrative Hearings’ proposal for decision in American Electric Power’s merger of its AEP Texas Central, AEP Texas North and AEP Utilities subsidiaries (No. 46050) into AEP Texas. An ALJ found the merger “consistent with the public interest if certain conditions are imposed.”

Those conditions include AEP maintaining separate divisions until the commission can approve consolidated rates and tariffs, AEP Texas providing rate credits to its customers and combining current reliability benchmarks into a single metric.

Anderson suggested modifying the proposed decision to direct AEP to prepare a study on consolidating the companies’ rates and share it with stakeholders.

“That will inform stakeholders, including [PUC] staff, whether to call AEP in for a rate case,” he said.

The commissioners and AEP representatives debated whether to set a June 2017 or June 2018 deadline for the study’s completion. They eventually settled on finishing the study “four months in advance of a rate case.”

“Our position is the rates are different in the two different areas,” said the industrial consumers’ Katie Coleman. “There will be winners and losers. We’re not sure if we want the rates combined.”

Actions Delayed

The commissioners delayed until its Dec. 16 open meeting a final rulemaking on distributed generation interconnection agreements (No. 45078) and final reports to the Texas Legislature on alternative ratemaking mechanisms (No. 46046) and competitive electric markets (No. 45635).

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Environmental Group Files Second Challenge to NY Nuke Subsidy

By William Opalka

The New York environmental group Hudson River Sloop Clearwater sued New York regulators on Wednesday over their subsidies for upstate nuclear power plants.

new york nuclear subsidy environmental group
Manna Jo Greene | Hudson River Sloop Clearwater Inc.

Clearwater wants the court to vacate the “Tier 3” requirement included in the state’s Clean Energy Standard, which would pay zero-emission credits to three generators that that could have closed as early as next year. Critics say the program could cost ratepayers $7.6 billion over 12 years.

The suit, filed in state Supreme Court in Albany, alleges the program was illegally enacted and fails the New York Public Service Commission’s mandate to provide just and reasonable rates.

This is the second legal challenge to the ZEC program. In October, fossil fuel generators and a trade association filed suit in federal court attacking the program on the grounds that the state was interfering in FERC-regulated wholesale markets. (See Federal Suit Challenges NY Nuclear Subsidies.)

ZECs “would bring about one of the largest transfers of wealth from the ratepaying public to a single corporate entity in New York state history,” Clearwater’s suit says.

The PSC last month approved Exelon’s purchase of the James A. FitzPatrick nuclear plant from Entergy, making it the sole owner of the three nuclear power plants on Lake Ontario, all of which are eligible for ZEC payments. Exelon also is the beneficiary of a bill approved by Illinois legislators Thursday to provide similar credits to keep its Clinton and Quad Cities nuclear plants operating for another decade. (See related story, Illinois Lawmakers Clear Nuke Subsidy.)

Clearwater says the PSC rushed the subsidy through the regulatory process in 14 days after a staff report first publicly broached the subsidy. The ZEC price will be determined by the federal “social cost of carbon.”

“Tier 3 contains many deficiencies, including implementing a program beyond the legal authority of the PSC, numerous assumptions and statements not supported by any technical basis, errors of fact and legal procedural defects preventing public comment and review in violation of multiple sections of the State Administrative Procedures Act,” the suit alleges.

A PSC spokesman defended the program. “Clearwater’s opposition to nuclear energy is based on ideology, not reality, and ignores the many benefits these upstate nuclear plants provide. Our zero-emission credit plan is a cheaper, sensible way to have the existing carbon-free nuke fleet serve as a bridge to renewables as opposed to importing fracked gas and using dirty oil,” spokesman Jon Sorensen said in a statement.

“Opposing this subsidy will demonstrate to the country that nuclear power is not where our dollars need to be spent. Many of these nuclear plants are aging, leaky and dangerous,” Manna Jo Greene, Clearwater’s environmental action director, said in a statement. “Clearwater strongly supports N.Y. state’s goal of 50% renewable energy generation by 2030 but opposes the nuclear subsidy. Moving toward a fully renewable energy economy as rapidly as possible is the direction that New York should model for the nation.”

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FERC OKs PJM RTEP Allocations, Denies DPL Objection

By Rory D. Sweeney

FERC last week approved PJM’s cost-responsibility assignments for its updated Regional Transmission Expansion Plan, dismissing complaints from Dayton Power and Light that one of the projects should have been allocated completely to Dominion Resources (ER16-2539).

DP&L protested PJM’s request that the costs to rebuild the Carson-Rogers Road 500-kV transmission line in Virginia (project b2744) be distributed as part of regional reliability maintenance and should instead go completely to Dominion. DP&L said PJM’s choice wasn’t the most cost-effective, as the grid operator had presented a $24 million option at its Transmission Expansion Advisory Committee meeting in May but selected a $48.5 million project proposed by Virginia Electric and Power Co. because it also resolved a local-planning criterion for Dominion.

Carson - Rogers Project Map | dayton power and light ferc, pjm RTEP allocations
Carson – Rogers Project Map | PJM

Additionally, DP&L argued the reliability violation came from an outdated load growth forecast and that “updated forecasts suggest that there may be no regional reliability violation.”

“Dayton Power contends that there appears to be a disconnect in PJM’s planning process such that a generation interconnection study, using one set of assumptions, may permit the interconnection of a generator without charging the generator for network service upgrades, while an RTEP study, using a different set of assumptions may find that there are network service upgrades that are needed with that generator interconnecting,” FERC summarized in its ruling.

PJM responded that DP&L was missing the point of the filing and should have raised any concerns it had at the May TEAC meeting. The RTO said the filing is for FERC to determine if PJM’s decisions conform with FERC’s approved methods, not whether individual allocations are accurate.

It’s also not a question of cheapest option, PJM said, but most cost-efficient and effective according to its engineering analysis. Although it reviewed other proposals, it explained, none of them also addressed the local criterion concerns.

Transmission lines from Dominion's Calvert Cliffs Nuclear Plant - ferc pjm rtep dayton power and light
Transmission lines from Dominion’s Calvert Cliffs Nuclear Plant | © RTO Insider

Dominion said that just because the project also solves its local issue doesn’t mean it’s not suitable for inclusion in the RTEP.

The commission said “Dayton Power has not supported its assertion that this issue was not adequately vetted within the stakeholder process. We find that while Dayton Power disputes PJM’s selection of project b2744, Dayton Power makes no assertion that the process that PJM undertook in selecting project b2744 in the PJM regional transmission plan for the purposes of cost allocation is inconsistent with Schedule 6 of the PJM Operating Agreement.”

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EIM Leaders OK Governance ‘Guidance’ Proposal

By Robert Mullin

The Western Energy Imbalance Market’s governing body voted to implement procedures to ensure market participants have input into CAISO policy initiatives that affect the market.

The CAISO staff’s proposed “guidance document” sketches out how ISO staff will interact with the EIM, providing a schedule for notifying the governing body about ISO initiatives and laying out the processes by which body members and EIM participants will provide feedback on proposed policy changes.

ISO staff initiated development of the document in October in response to a recommendation by the EIM’s Transitional Committee — the West-wide stakeholder group charged with developing the market’s governance plan. That committee decided to leave it to market participants to parse out that plan into specific procedures. (See CAISO Seeks Process to Keep EIM, Governing Body in the Policy Loop.)

“The Transitional Committee envisioned a more user-friendly document, something that’s different from corporate bylaws or the charter for EIM governance,” CAISO General Counsel Dan Shonkwiler told the EIM governing body during its Nov. 30 meeting. “It may be a more accessible document for stakeholders trying to understand what you do and how to interact with you.”

eim energy imbalance market
EIM Map | CAISO

Not a Rubber Stamp

Governing body member Valerie Fong said her support for the guidance document came only “after a number of questions and comments that were addressed and are answered very specifically through” the final proposal.

“This isn’t just a rubber-stamp ‘OK,’” Fong said ahead of the vote to approve the document. “It took a lot of work on Dan’s part to consider the comments and suggestions — and the questions” submitted by EIM stakeholders.

The proposal still requires approval by the ISO board, which is expected to issue a decision on the matter during its December meeting.

Significantly, the guidance document provides solutions to the overlapping authority between the ISO board and the EIM governing body resulting from the EIM’s delegation of a portion of its authority over Federal Power Act Section 205 filings to the ISO.

The document describes how ISO staff and board members will interact with the EIM governing body to determine whether a proposed Tariff amendment affecting the EIM falls under the body’s “primary authority” — giving EIM leaders the right to effectively approve or reject an amendment.

In those instances, the ISO board — which technically retains final authority over all Tariff changes — is expected to give “great deference” to the governing body’s decisions and place those matters into a consent agenda.

The document also spells out an “advisory” — and non-voting — role for the governing body regarding policy initiatives covering general market rules that also affect the EIM.

‘Hybrid’ Initiatives

“Hybrid” initiatives — proposals that would amend multiple Tariff provisions affecting both the EIM and the ISO at-large — will get more complicated treatment. In cases when the EIM is the key driver of an initiative, primary authority will fall to the governing body. In other cases, the body could retain primary authority over just EIM-specific portions of a broader ISO initiative — a sort of line-item veto power.

EIM Governing Board members left to right: Fong, Prescott, Howe, Linvill, Schmidt | CAISO
EIM Governing Board members left to right: Fong, Prescott, Howe, Linvill, Schmidt | CAISO

The governing body will also have a voice in how any policy initiatives are designated with respect to primary authority, providing the body the right to challenge any “initial” designation made by ISO management.

In the event that the governing body objects to an initiative’s final designation, the body chair — currently Christine Schmidt — can trigger a dispute resolution process ultimately involving a joint session of the body and the ISO board.

In response to requests by current and future EIM members, the final document also clarifies that CAISO’s Department of Market Monitoring and Market Surveillance Committee should interact directly with the EIM governing body in the same manner in which both groups currently consult with the ISO board.

On Oct. 1, Arizona Public Service and Puget Sound Energy joined the EIM, which launched in November 2014 with PacifiCorp and NV Energy. Portland General Electric and Idaho Power are expected to join in 2017 and 2018 respectively. Others that have indicated an interest in joining are Mexico’s Baja California Norte, the Sacramento Municipal Utility District and Seattle City Light. (See Council OKs Seattle City Light Bid to Explore Joining EIM.)

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MISO IMM Sees Deliberate Over-Forecasting by Wind Operators

By Amanda Durish Cook

CARMEL, Ind. — Some wind generators appear to be deliberately over-forecasting their output to inflate their revenues, according to MISO Independent Market Monitor David Patton, who called for rule changes to discourage gaming.

Patton said wind units on average produced 146 MW less than their MISO dispatch instructions in 2015 and 2016 (excluding economic curtailments and manual redispatch), a higher deviation than any other resource class in the RTO.

miso imm demap payments wind resources
| Potomac Economics

Patton told the Market Subcommittee on Nov. 29 that much of the problem lies with MISO’s day-ahead margin assurance payment (DAMAP), which guarantees day-ahead profit when real-time dispatch is less than the day-ahead schedule. MISO uses wind operators’ forecasts to determine their dispatch level.

Two-thirds of MISO’s $7.5 million in DAMAP payments to wind resources in 2015 and 2016 was because of over-forecasting and only $2.5 million was spent on curtailment, Patton said. “Most of our wind DAMAP payments are unjustified,” he said.

Patton: Eliminate DAMAP for Wind

Patton said the DAMAP should be eliminated for wind resources once MISO adopts five-minute settlements. He reasons that because wind is a fast-ramping resource, operators will want to be paid in real-time prices rather than collecting DAMAP.

Patton also called for a change in rules that encourage wind generators to err on the high side in their forecasts to ensure they receive a dispatch signal that does not limit their output. Wind resources producing above their dispatch signal can be subject to excess energy penalties, but MISO settlement rules are less punitive for wind resources that fall below their forecast output.

Patton recommended wind suppliers be incentivized to submit accurate forecasts by giving them more “headroom” and relaxing excessive energy charges when the system is unconstrained. He also suggested MISO automate its validation of market participant forecasts.

“If we balance these objectives well, the wind suppliers will be happy, the grid operators will be happy and those that have to contribute to the DAMAP payments will be happy,” Patton said.

Over-forecasting leads to supply-demand imbalances, he said, with MISO deploying regulating reserves and under-utilization of the grid as the RTO dispatches the system to make room for the over-forecasted energy.

‘Sustained Biases’

Patton said that although larger wind producers generally have lower forecasting errors than smaller ones, “a number of large and small wind suppliers exhibit large sustained forecast biases.” Patton said over-forecasting is more prevalent in summer, when energy prices are higher.

He said wind operators might be violating their obligation to provide accurate information to MISO. He noted that FERC is similarly concerned about evidence of over-forecasting.

Patton also said more research is needed to put a price on how much the over-forecasting costs MISO and that he may offer more definitive solutions in his 2016 State of the Market Report.

MISO Responds

Jeff Bladen, executive director of market services, said MISO staff will work with the Monitor on potential fixes. “We aren’t seeing broad-based market manipulation for sure, but we may have a market inefficiency that we want to close up as soon as practical. Certainly there’s work in front of us to assess and get advice,” Bladen said.

DTE Energy’s Nick Griffin said he would like to see MISO and the Monitor provide similar deviation averages for other asset classes. But he said he could support removing forecasting capability from wind units if gaming is discovered.

“Wind resources are in a difficult position because they face different challenges than other resources,” Patton said. “They have to manage something that’s fundamentally different than other resources. When we suggest that wind resources should be treated differently, it’s because they have a challenge that other asset owners do not have to face.”

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Illinois Lawmakers Clear Nuke Subsidy

By Rory D. Sweeney and Rich Heidorn Jr.

Illinois legislators on Thursday approved a bill to keep Exelon’s Clinton and Quad Cities nuclear plants operating for another decade.

The “Future Energy Jobs Bill” was approved by the state Senate by a 32-18 vote, an hour after clearing the House 63-38 on the last day of the legislature’s session for the year (SB 2814). The product of two years of negotiations, it was sent to be signed by Gov. Bruce Rauner, who issued a statement in support.

clinton, exelon, illinois, nuclear power
Exelon’s Clinton Nuclear Plant | Exelon

The bill “shows that when all parties are willing to negotiate in good faith, we can find agreement and move our state forward,” Rauner said.

The bill provides Exelon with $235 million in ratepayer-funded zero-emission credits annually for 10 years of continued operation.

Exelon said Commonwealth Edison ratepayers are likely to see increases averaging about 25 cents/month during the life of the plan, but critics have said the increase could exceed $4. Ameren customers are likely to see increases of 12 cents/month on average, the Associated Press reported.

It caps price increases for all business classes at 1.3% over 2015 rates, Exelon said.

“This forward-looking energy policy levels the playing field and values all carbon-free energy equally, positions Illinois as a national leader in advancing clean energy and will provide a major boost to the Illinois economy,” Exelon CEO Chris Crane said in a statement.

The bill also requires “hundreds of millions of dollars” in energy efficiency spending, which has garnered environmentalist support, the AP reported.

Critics have called the bill a corporate bailout under the guise of maintaining reliability in a state that produces much more energy than it needs.

Exelon's Quad Cities Nuclear Plant | Exelon
Exelon’s Quad Cities Nuclear Plant | Exelon

Governor’s Reservations

The bill has gone through several iterations in the Democrat-controlled legislature and almost failed until Rauner, a Republican, joined the negotiation to pare down the cost. He initially offered his support then removed it after seeing language he didn’t like, according to Crain’s Chicago Business.

Rauner’s statement said the bill’s cost was reduced by exempting new renewable energy projects from prevailing wage rules and “eliminating billions of dollars in special interest” funding.

Dynegy, which saw proposed subsidies for its coal plants in southern Illinois cut in the final version of the bill, told Crain’s that it would sue to overturn the law.

Exelon said the bill, which will take effect June 1, will save 4,200 direct and indirect jobs, including 900 workers at Quad Cities and 700 at Clinton. The company threatened in May to shut down the money-losing plants if they did not receive state aid. (See Bill to Save Coal, Nuclear Plants Introduced in Illinois.)

Reaction

Among those hailing the bill’s approval were the Nuclear Energy Institute, the Illinois Clean Jobs Coalition, which represents the wind, solar and energy efficiency industries, and the Environmental Defense Fund, which called it “the most significant clean energy economic development package in the state’s history.”

The EDF said the legislation “will fix Illinois’ broken renewable portfolio standard and significantly expand the state’s successful energy efficiency programs.”

The Alliance for Solar Choice said it was pleased that the final bill reinstated net metering and removed proposed demand charges that would have discouraged rooftop solar.

The bill increases the RPS target to 35% by 2030, up from the current 25% by 2025.

“Prior to this agreement, Illinois was meeting the criteria of its less-audacious RPS goals by investing in clean energy projects being built by neighboring states,” the Alliance said. “Illinois was not only sending money to help grow the economies of other states, but it was also missing out on countless clean energy jobs and economic growth in-state.”

The group said it will press policymakers to ensure there’s a full stakeholder process before state regulators when the bill’s 5% net metering cap is reached “to guarantee a fair valuation of the benefits of rooftop solar.”

AARP Illinois called on Rauner to veto what it called the largest rate increase in “our nation’s history.”

“The bill just passed by the legislature will send monthly consumer bills through the roof for the next 25 years, will impose massive cuts to low-income energy assistance programs and even though it will supposedly save the jobs at the nuclear plants, down the road it will cost Illinois an additional 44,000 jobs,” said AARP Illinois Director Bob Gallo.

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FERC Rejects $400,000 Fuel Bill from Dominion

By Rich Heidorn Jr.

FERC rejected Dominion Resources’ request to recover almost $400,000 in uncompensated costs incurred when it ran four dual-fuel units on fuel oil rather than cheaper natural gas in June.

dominion fuel bill ferc rejects
| Matcor

The commission’s Nov. 30 order said Dominion’s Virginia Electric and Power Co. is not entitled to recover the additional costs because it only submitted to PJM cost-based offers for natural gas operations at its five combustion turbines in Ladysmith, Va. (EL16-109).

The units, totaling 783 MW, primarily operate with natural gas but can also run on fuel oil. They did not clear in the day-ahead market for June 25, and after the rebidding period, VEPCO learned of a pipeline constraint that left the Ladysmith units unable to operate on natural gas.

At 11 a.m. on June 25, PJM ordered the utility to operate four of the units beginning at noon for reliability reasons. The company said it notified PJM of its need to operate on more expensive fuel oil and PJM reiterated its dispatch order. VEPCO said it operated three units for 10 hours and one for 11 hours, spending $387,588 more on fuel than it was paid for.

The company said the commission’s June 2015 ruling that PJM’s Tariff and Operating Agreement were unjust and unreasonable because they did not permit day-ahead offers that vary by hour or allow market sellers to update their offers in real time supported its request for relief. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)

| Matcor For plant photo: Ladysmith Power Station | Dominion
Ladysmith Power Station | Dominion

The commission disagreed, saying the company’s “inability to recover its fuel oil costs for the Ladysmith units resulted from its own business decisions regarding which cost-based offers to submit and is not the result of the offer limitations that the commission addressed in the offer flexibility proceeding.”

FERC also rejected the company’s request to make it whole through a waiver of PJM’s rules, saying it would cause harm to load, which “would be assessed unanticipated additional charges inconsistent with the current PJM Tariff and Operating Agreement on file and without adequate prior notice.”

“Granting waiver here would send the wrong signal to market sellers, namely, that a resource can submit an offer that PJM uses to dispatch the resource, and then seek to increase that offer after-the-fact to receive additional compensation,” FERC said.

PJM’s proposed Tariff revisions to increase offer flexibility, filed in August, is pending before the commission (ER16-372-002).

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UPDATE: CAISO Monitor Proposes End to Revenue Rights Auction

By Robert Mullin

A new report from CAISO’s internal Market Monitor contends that the ISO’s program for auctioning off congestion revenue rights (CRRs) suffers from inherent design flaws that have allowed speculators to reap enormous gains at the expense of outmatched ratepayers.

Adding to previous calls to reform or eliminate the auction process, the Department of Market Monitoring report spells out flaws in the current system and suggests a possible alternative. (See CAISO Monitor Seeks Congestion Revenue Rights Auction Reforms.)

Skeptics say the Monitor’s conclusions are ill-considered and that more analysis is necessary before the ISO takes any steps to alter the CRR auction process.

The Monitor, headed by Eric Hildebrandt, said that California ratepayers lost $520 million in 2012-2015 through a market that pays $1 to CRR holders for every 45 cents in revenues received from auctions.

congestion revenue rights crr caiso
Congestion revenue rights (CRR) auction revenues have significantly lagged payments to CRR holders since the system was put in place nearly five years ago. | CAISO

“This consistent underpricing of CRRs calls into question a fundamental assumption of the CRR auction design that competition will drive auction prices to equal the CRR’s expected value,” the Monitor said. “It is unlikely that rules similar to the CRR auction design would emerge in many competitive markets that are not designed by a regulatory process.”

‘No Clear Rationale’

The Monitor contends that there is “no clear rationale” for the ISO to provide a market for price swaps, echoing criticism voiced by PJM Independent Market Monitor Joe Bowring and others. (See Role, Value of Financial Trading Debated by OPSI Panel.)

CAISO’s Monitor says the main beneficiaries of the current system are “purely financial entities” sophisticated enough to identify which CRRs are likely underpriced at auction but stand to pay off handsomely because of a disconnect between how the CRRs are packaged at auction and how they’re compensated at settlement.

To illustrate that disconnection, the Monitor first explicates its view on what exactly a CRR does and doesn’t represent.

“A CRR is not a day-ahead market transmission right,” the Monitor said. “All day-ahead market bidders have access to the transmission system regardless of whether or not they hold a CRR.”

CRRs are not needed to ship power between nodes because the ISO’s centrally cleared LMP market is linked to its transmission operation, meaning that market participants are not responsible for moving power from one location to another.

Rather, a CRR purchased at auction should be understood as a forward contract that allows an auction participant to hedge financial exposure to — or speculate on — day-ahead price differences between two locations, the Monitor explained. The demand for such hedging stems not from the ISO’s own market but from forward power contracting occurring outside the market.

“A supplier may sell a forward power contract at a location different than its generator’s location,” the Monitor said. “When this occurs, the day-ahead price on which the forward contract settles will be different than the day-ahead price the generator receives for selling power into the day-ahead market.”

The differing settlement locations expose the supplier to possible price discrepancies not accounted for in the forward power contract. So it’s the CRR auction that provides for acquiring forward contracts for differences to hedge price differentials between two points.

The problem with this setup?

“Unlike most other forward contract markets, the CRR auction allows participants to take positions without a counterparty offering to take the opposite position,” the Monitor said.

Instead, transmission ratepayers become unwilling counterparties to the CRR contracts because they’re on the hook to provide payment when auction revenues come up short of CRR payouts.

Ratepayers Outgunned

To avoid that outcome, those ratepayers would have to enter the auctions to buy the contracts themselves. This is problematic for a couple reasons, the Monitor points out.

First, the load-serving entities that effectively act on behalf of ratepayers in ISO markets may obtain CRRs to hedge risk, but they are explicitly barred from financial speculation in any transactions. In any case, LSEs would lack the incentive to manage ratepayers’ CRR forward contracts in the auction because they can pass on CRR costs to those ratepayers.

Second, participation in CRR auctions as a speculator requires knowledge of power flow analysis, finance and transmission/generation outages and operations, as well as meeting collateral requirements to engage in the market. In short, ratepayers would be outmatched by the companies that employ electrical engineers and other experts to transact in the highly complex market.

The most fundamental problem with the ISO’s CRR market, the Monitor contends, is its financial structure and lack of a consistent definition for a particular set of CRRs. Although CRRs are auctioned as “a bundle of forward contracts on specific transmission constraints,” they are not settled as the same bundle at day-ahead market prices. That’s because the day-ahead market network model that forms the basis for settlement cannot be known when the auction is run. New transmission constraints can be introduced after the auction,” effectively making the CRR a different product when bought than when it is settled.

“A CRR will only be consistently defined if the bundle in the auction is the same as the implied bundle from the day-ahead market price differences,” the Monitor said. “When the transmission models are different in the auction and day-ahead market, the bundles will not be the same.”

Proposal

As an alternative to the CRR auction, the Monitor proposes a bilateral or exchange market for forward contracts-for-difference for pairs of ISO nodes — otherwise known as locational basis price swaps. The swap buyer would pay the seller a price in the forward market and in return be paid the spot price difference between the two locations.

A key difference from the current CRR market: Price swaps would be traded between willing counterparties. And unlike the inconsistently defined CRR contract, the swap would be consistently defined in both the forward and day-ahead market.

‘Robust’ Analysis Needed

Gary Ackerman, executive director of the Western Power Trading Forum (WPTF), said his organization “strongly” disagrees with the Monitor’s call for ending CRR auctions.

“The CRR platform is a market,” Ackerman said. “Buyers and sellers value risk and opportunity differently. Scrapping it is a FERC question and seems like a radical step when indeed the CAISO makes the rules.”

Ackerman pointed out that FERC requires organized wholesale power markets to provide instruments that allow participants to hedge risk.

“This isn’t about who is getting what money or under-collecting the transmission revenue requirement,” Ackerman said. “It’s about [providing] market value for relieving congestion.”

Carrie Bentley with Resero Consulting, which frequently works on behalf of the WPTF, elaborated on the group’s position.

“If the CAISO had more transparency surrounding the transmission system — and in particular how the CAISO represents the transmission system in both the CRR model and the day-ahead market model — participants would have information at the time of the auction about the expected day-ahead market and any differences between the day-ahead market and the CRR market,” Bentley said.

Increased transparency could incentivize bidders to offer a higher value for CRRs in the auctions, Bentley said, noting that recent improvements in the ISO’s transmission outage reporting might account for the reason that CRR auction revenues exceeded payouts during the third quarter of this year.

Both Ackerman and Bentley dismissed the Monitor’s proposal for a new bilateral market for price swaps.

“There cannot be an effective market without buyers and sellers fluidly engaging in commerce, and there does not appear to be buyer interest in long-term power and power basis hedging,” Ackerman said.

Bentley said the CRR auction process is “invaluable” because it allows market participants to adjust their CRR positions “to get just the right hedge” based on portfolios and risks.

“Because the grid is so complex, achieving this fine tuning of one’s CRR holdings would be nearly impossible if participants had to trade bilaterally,” Bentley said.

Bentley also contends that market participants have not been provided with “robust analyses” on the precise cause for the revenue shortfalls in the auctions.

“It seems to make more sense that [the Monitor] could perform further analysis — or make such analysis public if they have already performed it — and then parties could consider how the CAISO could converge the day-ahead and CRR markets and models as a first step — before jumping to the conclusion the auction simply isn’t useful,” Bentley said.

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MISO Granted Winter Waiver on Offer Cap

FERC has granted MISO a waiver of its $1,000/MWh offer cap for winter, providing the RTO relief before the commission’s pre-Thanksgiving order that doubled the hard offer cap for all grid operators takes effect.

FERC’s Nov. 17 ruling setting the offer cap for day-ahead and real-time markets to $2,000/MWh in all RTOs and ISOs won’t take effect until 75 days after publication in the Federal Register (RM16-5). (See New FERC Rule Will Double RTO Offer Caps.)

Thus the commission on Nov. 29 granted MISO’s request that resources with incremental energy costs above the current $1,000/MWh offer cap be allowed to recover costs effective Dec. 1 (ER16-2685). FERC approved similar MISO requests for the winters of 2014/15 and 2015/16.

The waiver and FERC’s new rule require that energy costs that exceed $1,000/MWh must be verified before the offer is used to set LMPs. FERC acknowledged the rule in the order granting the waiver, calling it “a long-term solution.”

| Ohio Power Siting Board
| Ohio Power Siting Board

“MISO’s experience during the polar vortex of the 2013/14 winter demonstrates that fuel costs can increase to a level such that the current $1,000/MWh offer cap prevents resources from submitting incremental energy offers that reflect their marginal production costs. If similar weather and natural gas supply conditions materialize in the 2016/17 winter, some resources could face the untenable position of being forced to offer electricity at levels below their actual cost,” the commission said.

As with MISO’s two previous waivers, the order instructs MISO’s Market Monitor to file a report within 30 days after the waiver period ends April 30 with statistics on offers above $1,000/MWh.

– Amanda Durish Cook