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February 4, 2020April 9, 2024

MOPR Ruling Threatens to Upend Self-supply Model

By Christen Smith and Rich Heidorn Jr.

Old Dominion Electric Cooperative, which supplies power to 1.4 million people in Virginia, Maryland and Delaware, has been generating its own power since 1983, when it bought a share of Virginia Electric and Power Co.’s North Anna Nuclear Power Station.

It would add the 433-MW coal-fired Clover Power Station in 1995/96, and more than 1,600 MW of natural gas capacity in 2001-2004. Less than two years ago, it began operating the 1,000-MW Wildcat Point combined cycle plant. As a result of its investments, it got 64% of its energy and 88% of its capacity from its own assets in 2018.

But because of Is Self-Supply Suppressing Prices?)

Attack on Business Model

ODEC and other self-supply load-serving entities (LSEs) argue the order will unravel their business model and undermine their roles in local economic development. The National Rural Electric Cooperative Association (NRECA) and East Kentucky Power Cooperative (EKPC) called the expanded MOPR a “frontal attack” on practices used by cooperatives for decades.

“The longstanding business model of electric cooperative LSEs is to invest in generation for their long-term load obligations, not the short-term forward capacity construct,” ODEC said in its Jan. 21 rehearing request (EL16-49, EL18-178). “Therefore, capacity which might be excess to an LSE’s reliability requirement in the early years of a resource will decline in later years as load grows. This does not make the investment ‘uneconomic.’” (See PJM MOPR Rehearing Requests Pour into FERC.)

ODEC joined PJM in 1998 to aid in the delivery of power to its three member distribution cooperatives on the Delmarva Peninsula. But its wholesale power contracts (WPCs) with all of its 11 members have been on file with FERC as far back as 1992.

“Most if not all of these [WPCs] originated well before PJM’s capacity construct and MOPR” in 2006, the National NRECA and EKPC said in their own rehearing request.

Their filing referenced the Supreme Court’s 2016 ruling in Hughes v. Talen, which said states were free to subsidize new generation “through measures untethered to a generator’s wholesale market participation.”

“There can be no legitimate conclusion that the WPCs are directed at or tethered to the operation of generating resources in PJM’s capacity construct,” NRECA and EKPC said.

Economic Development Threatened

EKPC, which joined PJM about seven years ago, said it signed on “to bring the benefits of a competitive wholesale market” to its 16 member co-ops in Kentucky. “These benefits have made it possible to attract new commercial and industrial customers to locate in Kentucky,” it said.

EKPC said its economic development efforts are threatened by the expanded MOPR, which also appears to cover new demand response resources and renewable generation with voluntary renewable energy credits (RECs). EKPC filed a “green tariff” proposal with the Kentucky Public Service Commission in 2019 in response to increased customer interest in “renewable or sustainable” resources.

“The application of the MOPR to resources supporting voluntary clean energy initiatives may discourage new industries from locating in the PJM region of Kentucky despite the great efforts EKPC is making to advance economic development in the commonwealth of Kentucky,” EKPC said. “The December 2019 order may frustrate EKPC’s opportunity to court new industries seeking to ensure that their energy needs are met with renewable resources.”

EKPC, which sells DR from nine end-use customers into the capacity market, said one industrial load has invested millions to increase its DR capability. EKPC included the expansion in the DR plan for the 2022/23 Base Residual Auction, which has not been held because of the MOPR litigation. “It is unclear whether that capability will be considered to be existing and eligible for the exemption provided in the December 2019 order,” EKPC said.

No Longer ‘Residual’ Market

FERC approved PJM’s Reliability Pricing Model (RPM) and its BRAs in 2006 to procure capacity “after LSEs have had an opportunity to procure capacity on their own” and “as a last resort.”

EKPC said FERC’s ruling was “the most drastic and likely most destructive measure taken by the commission to date” in its attempt to transform PJM’s “resource adequacy market away from a residual capacity auction … to a mandatory sole source for PJM and its LSEs to meet regional capacity obligations.”

“The chilling effect this order will have on investment in new self-supply resources will convert PJM’s capacity market from a ‘Base Residual Auction,’ designed to procure capacity not otherwise procured through self-supply, to an auction in which capacity purchases from the market will be the only viable option for all LSEs, thus eviscerating the self-supply option,” North Carolina Electric Membership Corp. said in its rehearing request.

Expanding MOPR to public power self-supply resources is based on the “mistaken premise that all resource entry and exit must be coordinated solely by the RTO-administered market to be deemed economic,” consultant Marc D. Montalvo said in comments filed on behalf of the American Public Power Association (APPA) during the commission’s paper hearing on the docket.

“RPM is a mandatory resource adequacy construct that offers a single product, and ‘competitive’ prices are determined by PJM applying cost development guidelines with no empirical link to actual market conditions or consumer decisions,” said APPA, American Municipal Power (AMP) and Public Power Association of New Jersey (PPANJ). “Ironically, by its latest action, the commission has removed any remaining genuine market component of RPM by requiring all ‘competitive’ offers to be determined administratively in Valley Forge, Pa.”

MOPR History

The MOPR was introduced along with RPM in 2006. It does not apply to baseload resources that required more than three years to develop (nuclear, coal and integrated gasification combined cycle facilities), hydroelectric facilities, or any upgrade or addition to an existing generator. Also exempt was any new entry being developed in response to a state regulatory or legislative mandate to resolve projected capacity shortfalls for the delivery year.

In 2011, FERC approved revisions eliminating the state mandate exemption and adding a unit-specific review process to consider cost justifications submitted by resources whose sell offers fell below the established floor. Wind and solar facilities were also added to the list of resources permitted to make zero-priced offers; additions to existing capacity resources were no longer exempted.

In 2013, FERC approved a categorical exemption for self-supply for public power and vertically integrated utilities, subject to net-short and net-long thresholds. The commission also agreed to exempt “competitive entry” units that could prove they received no out-of-market funding other than that resulting from competitive auction.

But in 2017, the D.C. Circuit Court of Appeals remanded the 2013 order, saying the commission had exceeded its authority in modifying PJM’s proposal by retaining the unit-specific review process, which the RTO had wanted to eliminate. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

The commission responded by returning to the market design in effect before the 2013 MOPR proceeding, which applied the MOPR to all new, nonexempted gas fired resources but allowed zero-priced offers by nuclear, coal, wind solar and hydro. (See On Remand, FERC Rejects PJM MOPR Compromise.)

That set the stage for the commission’s June 2018 order, which declared the MOPR unjust and unreasonable for failing to address price suppression from growing state subsidies for nuclear and renewable resources. (See FERC Orders PJM Capacity Market Revamp.)

FRR not an Option

FERC said self-supply entities “remain free” to provide for their own resource adequacy through the existing fixed resource requirement (FRR) alternative.

But APPA, AMP and PPANJ say that neither the FRR option nor the unit-specific review process is a “reasonable accommodation” for self-supply.

They cited a 2014 ruling by the 3rd U.S. Circuit Court of Appeals that “participating in the FRR option is an all-or-nothing proposition and appeals as a practical matter only to large utilities that still follow the traditional, vertically integrated model.”

Public power LSEs’ capacity needs can change over time as they add new members, if new locational deliverability areas (LDAs) are added or their boundaries change, the groups noted. “The creation of a new binding Cleveland LDA could impact 100% of the municipality’s load, whereas only a portion of the load of FirstEnergy, would be impacted,” they said.

“The FRR may not be a workable alternative for smaller LSEs, given the requirements to opt out of the capacity construct for both purchases and sales, for a five-year period with onerous financial consequences if the ability to do so becomes untenable,” ODEC said.

The unit-specific exemption only offers an alternative to the default offer floor, APPA, AMP and PPANJ said. Resources using the unit-specific exemption must still bid above an administratively determined level, leaving them at risk of not clearing the auction.

They cited the example of Delaware Municipal Electric Corp. (DEMEC), which was required to use a unit-specific exemption to qualify a then-new gas-fired generator in 2011 for the 2014 BRA. They said PJM’s Independent Market Monitor sought to add 200 basis points to DEMEC’s actual financing rate. After negotiations, DEMEC and the Monitor agreed to a mitigated offer “substantially” higher than what the company had planned to bid.

“Fortunately, DEMEC’s offer price for the new resource did clear the 2014 BRA. However, had DEMEC acceded to the IMM’s original proposed upwardly mitigated offer price, DEMEC’s generation resource would not have cleared the 2014 BRA, thereby stranding DEMEC’s investment and causing irreparable harm to DEMEC and its communities,” the groups said.

EKPC said it and other co-ops have been snared in a catch-22.

“Since the commission broadly swept the cooperative electric utility business model into the definition of state subsidy, it is not clear how an electric cooperative could certify that it is foregoing receiving the state subsidy in order to take advantage of the competitive offer exemption,” it said. It asked the commission to clarify how PJM should apply the competitive exemption to co-ops. It also sought rehearing of the commission’s determinations that voluntary RECs are state subsidies and that the MOPR should apply to DR.

“Regardless of the characterization of the MMU’s actions in a prior 2011 MOPR review, the MMU reviews unit specific MOPR requests under the existing rules based on unit specific details, including the cost of capital,” IMM Joe Bowring said in response. “The MMU has always respected the public power business model and recognizes that the cost of capital for public power entities is not the same as it is for private entities. The commission, in [the December] order, has not stated that the financing options of public power entities constitute a state subsidy.”

Fear of ‘Balkanization’

EKPC said blocking vertically integrated utilities from seeking a competitive exemption for future resources “will have a negative impact on the existing market and will hamper future prospects of growing the PJM wholesale market to include new territories.”

“Given the 10 cooperatives and three vertically integrated utilities that currently participate in the capacity market, EKPC is concerned about the potential for balkanization in the PJM region if many or all of these entities utilize the FRR alternative as the better way to satisfy their load-serving obligations.”

The Brattle Group had expressed similar concerns in a 2011 report for PJM, saying that not clearing self-supplied resources would “make it more difficult and costly to hedge capacity prices and will likely force many load-serving entities that rely on self-supply to opt out of RPM through the FRR option. More widespread use of the FRR option would reduce market efficiency and increase costs.”

February 4, 2020February 18, 2025

EIM Reports $60M in Q4 Benefits

By Hudson Sangree

CAISO’s Western Energy Imbalance Market delivered more than $60 million in benefits to its participants in the fourth quarter of 2019, bringing the total benefits of the interstate real-time market to nearly $862 million since it began operating in November 2014, the ISO announced Thursday.

The biggest beneficiary among the EIM’s nine active participants was Arizona Public Service, which saved $17.4 million in in the last three months of 2019, followed by PacifiCorp and Portland General Electric, each of which saw approximately $11 million in benefits, CAISO said.

“When we launched the Western EIM, we knew it would be a win for consumers,” CAISO CEO Steve Berberich said in a statement. “These benefits prove that increased coordination creates operational savings and greater integration of variable resources to meet the evolving demands of consumers.”

November marked the EIM’s fifth anniversary. By 2022, it’s expected to serve 77% of load in the Western Interconnection with 11 more participants scheduled to join in the next three years. Arizona’s Salt River Project and Seattle City Light will enter the market this year.

The utilities scheduled to join in 2021 include the Los Angeles Department of Power and Water, Public Service Company of New Mexico and NorthWestern Energy. The Bonneville Power Administration and three other entities are expected to join in 2022.

In December, four Colorado utilities — Xcel Energy, Black Hills Colorado Electric, Colorado Springs Utilities and Platte River Power Authority — announced they will join the EIM as soon as 2021, filling in part of the last Western state that’s currently blank on the EIM map. (See EIM Lands Xcel, 3 Other Colo. Utilities.)

It also represented a major win over the EIM’s nascent competitor, SPP’s Western Energy Imbalance Service, which has sought to attract utilities unhappy with the idea of forming close ties with California and CAISO. The economic benefits of the EIM, however, have attracted participants even from more conservative states of the interior West.

In its latest quarterly report, CAISO said the financial benefits derive mainly from transfers across balancing areas, “providing access to lower-cost supply, while factoring in the cost of compliance with greenhouse gas emissions regulations when energy is transferred into the ISO.”

“EIM uses state-of-the-art technology to find and deliver low-cost energy to meet real-time demand across eight Western states and extends to the border with Canada,” it said. “The Western EIM has proven extensive financial and operational benefits since its inception in November 2014, and cumulative gross economic benefits now total $861.79 million.”

Trading now occurs only in the 15-minute and real-time markets, but through its stakeholder initiatives, the EIM is evaluating expanding to a day-ahead market and studying the potential for participants to benefit from wheel-through transfers, a proposal that’s proven controversial in the past. (See EIM Members Wary of Need for CAISO Wheeling Charge.)

“Currently, an EIM entity facilitating a wheel-through receives no direct financial benefit for facilitating the wheel; only the sink and source directly benefit,” the EIM said its Q4 report. “As part of the Western EIM Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel-through volumes to assess whether, after the addition of new EIM entities, there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits.”

February 4, 2020

FERC Order Keeps Z2, Aids EDF’s Sponsored Project

By Tom Kleckner

SANTA FE, N.M. — FERC on Friday rejected SPP’s request to eliminate Z2 revenue credits for sponsored transmission upgrades, allowing the RTO to submit a revised proposal for the commission’s consideration without a cap limiting the terms and potential value of the credits’ replacement (ER20-453).

SPP had proposed using incremental long-term congestion rights (ILTCRs) instead, but the commission found modifications to the existing ILTCR compensation term to be unjust and unreasonable. The grid operator had suggested changing the compensation from a range of 10 to 20 years, to 20 years or until the upgrade sponsor recovers the directly assigned upgrade costs with interest, whichever occurs earlier.

FERC noted it previously found that “a similar cap on recovery only up to the cost of the facility would not serve as an incentive for entities to build merchant transmission projects and that an LTCR could provide such an incentive if the value of the LTCR is greater than the cost of the investment.”

Under Attachment Z2 of SPP’s Tariff, sponsors that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade.

Stakeholders in October approved the elimination of Z2 credits, to be replaced by ILTCRs. Several stakeholders opposed the decision, saying they wanted to wait until SPP could fully develop the ILTCR mechanism. (See “Stakeholders Endorse Eliminating Z2 Revenue Credits,” SPP MOPC Briefs: Oct. 15-16, 2019.)

SPP Z2 revenue credits — The Pauline-to-Hastings sponsored upgrade | *SPP*

‘Sandbagged’

The FERC decision short-circuits an animated discussion that erupted over a $12 million sponsored upgrade during SPP’s Board of Directors meeting on Jan. 28. Nebraska Public Power District pulled the upgrade from the consent agenda, asking to delay an approval vote until April to ensure that “financing issues” are worked through and that the agreement complies with IRS regulations and Nebraska law.

EDF Renewable Energy, the project’s sponsor, questioned NPPD’s concerns, saying they could have been dealt with sooner. The project had already been endorsed by the Markets and Operations Policy Committee during its Jan. 14-15 meeting.

“I’m curious as to what needs to be done here,” said EDF legal counsel Dan Simon, calling in to the board meeting. “It sure seems like there’s been some intention to delay here.”

Simon’s ire was raised by NPPD’s suggestion to delay negotiations over the project, which involves reconductoring and rebuilding 13 miles of 115-kV line in southern Nebraska. EDF plans to pay for the upgrade, which would be a creditable upgrade eligible for cost recovery through Z2 credits rather than ILTCRs.

Given that SPP had asked for a Feb. 1 effective date in its filing before FERC, Simon’s frustration was understandable. “It sounds like a tactical way at the last minute to preclude us from getting Z2 credits,” Simon said, alleging EDF had been “sandbagged.”

“All this gets back to the Z2 issue,” he said.

NPPD’s Tom Kent, who chaired the Holistic Integrated Tariff Team that recommended eliminating Z2 credits, responded as Board Chair Larry Altenbaumer tried to bring the discussion to a close. (See SPP Board Approves HITT’s Recommendations.)

“I totally disagree with the characterization that [Simon] made,” Kent said. He noted NPPD had no intent to delay the project.

FERC’s rejection would seem to give EDF a clearer path to meet a Dec. 5 deadline to execute its agreement with NPPD and be eligible for a notification-to-construct from SPP.

The board eventually endorsed the sponsored upgrade, directing staff to work with NPPD and EDF to negotiate an agreement for the project.

“SPP has an obligation to ensure that whatever needs to be done is done consistently with what the legal requirements are and consistent with the parties’ negotiating and addressing that,” Altenbaumer said. “The goal … is to direct staff to get this across the finish line as expeditiously as possible.”

The board discussion was briefly interrupted by the Eldorado Hotel & Spa’s fire alarm system. Stakeholders briefly vacated the meeting room, jokingly blaming the false alarm on NPPD.

That led Altenbaumer to later say he had received some “really good advice”: reviewing safety protocols before the start of each meeting. “That’s good guidance,” he said.

February 4, 2020

Draft Climate Bill Would Make RTO Membership Mandatory

By Michael Brooks

House Democrats last week released a draft bill that received attention for its ambition to set a national clean electricity standard, requiring utilities to get 100% of their power from net-zero-emission resources by 2050.

But tucked away in the 622-page draft Climate Leadership and Environmental Action for our Nation’s (CLEAN) Future Act is a provision making it mandatary for utilities to join an ISO or RTO.

Section 217c of the bill (page 91) would amend Section 202a of the Federal Power Act, which gave FERC the power to approve RTOs, by removing the word “voluntary” and adding: “The commission shall require each public utility to place its transmission facilities under the control of an ISO or an RTO not later than two years after the date of enactment of the CLEAN Future Act.”

The provision is part of a larger series of desired changes at FERC, reading as a wish list for Democrats and the agency’s critics.

Draft Climate Bill — Rep. Frank Pallone (D-N.J.), chair of the House Energy and Commerce Committee, announced the framework for what would become the CLEAN Future Act on Jan. 17. | *Frank Pallone*

The bill would create an Office of Public Participation and Consumer Advocacy at FERC; clarify that the commission must consider climate change in its environmental assessments of natural gas pipelines; prevent pipeline companies from using eminent domain until they have obtained all necessary federal and state permits; and allow the commission to approve carbon pricing regimes for wholesale power.

Perhaps as, if not more, significant than the RTO provision is a directive that would require FERC to conduct a rulemaking to increase the effectiveness of interregional transmission planning. Section 212 of the bill spells out what exactly this would entail, directing the commission to emphasize that “interregional benefit analyses made between multiple regions should not be subject to reassessment by a single regional entity” and “the elimination of arbitrary voltage, size or cost requirements for an interregional transmission solution,” among other requirements.

The bill would also require FERC to submit a report on its efforts to encourage deployment of technologies that increase transmission efficiency, such as dynamic line ratings.

Clean Energy Credits

The draft bill is an ambitious, sweeping plan to dramatically reduce the country’s emissions and address global climate change that includes requirements for states, FERC, EPA and the Department of Energy, and targets emission reductions from the grid, vehicles and buildings.

The core provision of the bill would require utilities to begin transitioning to net-zero-emission electricity in 2022, giving them 28 years to reach 100%.

This would be facilitated by a clean energy credit trading program, established by DOE, that would function similar to existing state renewable energy credit programs, but the department would dole out credits to generators based on their carbon intensity, not on their resource type. Non-emitting resources would receive credits equal to the amount of megawatt-hours they sell. Generators that emit less than 0.82 metric tons of CO2/MWh would be eligible for credits based on how far below the threshold they are, incentivizing their owners to clean them up.

Utilities would then be required to purchase credits from generators and submit a certain amount, increasing each year, to the department. Utilities that fail to submit enough credits would be subject to a penalty.

While the overall bill drew praise from environmental groups, their reaction to the credit trading program was mixed.

“This broad legislative package includes some policies that would be clear steps forward to address the climate crisis, but it’s concerning that on what is perhaps the central question of climate policy — what counts as clean energy — this bill includes options that could leave a door open to gas and coal,” the Sierra Club said.

The criticism from environmentalists could mean the bill would face some pushback from the more liberal wing of the party, which has supported more aggressive decarbonization plans such as the Green New Deal.

“The legislation includes a national clean energy standard that could be transformational if designed well,” said Rob Cowin, director of government affairs for the Union of Concerned Scientists’ Climate and Energy program. “A national clean energy standard must not increase our reliance on natural gas generation, as natural gas use economywide now contributes more to U.S. carbon emissions than coal. We will continue to work towards enacting legislation consistent with the science and that will provide a just and equitable transition to a clean energy economy.”

“This credit system would encourage emissions reductions through changes in dispatch or investments at a facility, consequently further reducing emissions and lowering costs by allowing low-carbon technologies to participate,” nonprofit Resources for the Future said in a brief on clean energy standard published a year ago.

“The provision of credits to clean resources will likely create an incentive to expand energy supply and consequently lead to lower wholesale market prices. This effect notably differs from that of a carbon price, which would likely raise wholesale prices,” RFF said. “The extent to which decreased wholesale market prices will lead to lower retail prices could vary with the policy target but would be especially likely when customers are served by a vertically integrated utility that generates more clean energy credits than it needs to comply with the standard.”

It is unclear if Democrats intend to introduce the bill this year given its assured death in the Republican-controlled Senate and the upcoming elections. In its press release announcing the draft, the House Energy and Commerce Committee only said that “as it continues to expand and refine” the draft, “hearings and stakeholder meetings will continue throughout the coming year.”

“The CLEAN Future Act treats this climate crisis like the emergency that it is, while also setting the foundation for strengthening our economy and creating good paying jobs for a clean and climate-resilient future,” committee leaders said. “We look forward to continuing to work with all impacted stakeholders on this proposal in the coming months.”

Republicans are also planning to release their own bills to address climate change, as soon as this week. The package aims to boost research and development funding in nuclear energy and carbon capture, as well as increase tree planting. Legislation being drafted by Rep. Bruce Westerman (R-Ark.) would commit the U.S. to planting some 3.3 billion trees each year over the next 30 years.

February 4, 2020

CPUC Proposes New Power Shutoff Guidelines

By Hudson Sangree

The California Public Utilities Commission issued proposed guidelines Thursday for utilities to follow in the 2020 fire season when intentionally blacking out areas to prevent electrical equipment from starting wildfires.

At the same time, CPUC President Marybel Batjer issued a ruling calling Pacific Gas and Electric’s reporting to the commission on its public safety power shutoffs (PSPS) “fundamentally inadequate” in detail and substance and ordering it to immediately fix the situation.

“PG&E’s performance during PSPS events in 2019 was unacceptable and cannot be repeated in 2020,” Batjer said in a statement. “The reports that I ordered PG&E to submit are part of the CPUC’s comprehensive review of the 2019 PSPS events.”

The proposed guidelines, issued for public comment, would require the state’s investor-owned utilities to restore power no more than 24 hours after the end of weather conditions that led to a safety shutoff. The IOUs would also have to convene monthly regional workshops with local governments and others on fire safety practices and to conduct PSPS exercises with public safety agencies in fire-prone areas.

The proposed PSPS guidelines would augment the guidelines established by the CPUC in a June decision (19-05-042).

PG&E was heavily criticized for failures in preparedness and communication when it blacked out 2.4 million residents in October. Officials, including Gov. Gavin Newsom and his appointee Batjer, have insisted the situation can’t reoccur. (See California Officials Hammer PG&E over Power Shutoffs.)

The utility is in bankruptcy following two years of catastrophic wildfires in 2017 and 2018 that killed dozens of people and destroyed thousands of structures. It mostly avoided a repeat of the past two fire seasons in 2019, but its decision to de-energize vast swaths of Northern and Central California for days at a time caused controversy.

CEO Bill Johnson told state lawmakers in November that the power shutoffs had prevented fires, though improvements were needed.

“Turning off power for safety is an effective tool and really only one of the many tools we are using,” Johnson said. “We will get better at using it.”

In her assigned commissioner’s ruling Thursday, Batjer said PG&E’s reports to the commission on the shutoffs last fall had “serious deficiencies” — and that the utility eventually stopped filing reports altogether in December because it unilaterally decided it had fulfilled its obligations to the CPUC.

The weekly reports were instituted in response to a letter Batjer wrote to Johnson on Oct. 14, citing serious “failures in execution” in the shutoffs and ordering corrective action. (See CPUC Orders Changes to PG&E Shutoff Rules.)

The reports initially took the form of letters from PG&E to Batjer, but an administrative law judge later formally incorporated the reports into the CPUC’s rulemaking on de-energization. Batjer’s ruling Thursday was part of that proceeding (18-12-005). In it she ordered PG&E to resume regular (biweekly) reports on its PSPS corrective actions and to provide the CPUC with a detailed plan in 15 days describing PG&E’s anticipated improvements and challenges regarding PSPS events in the fire season that starts this summer.

Within 45 days, the utility must update its PSPS protocols and be prepared to exercise the measures, without prior notice, in conjunction with the state Office of Emergency Services and the California Department of Forestry and Fire Prevention, Batjer said. She did not propose any penalties in her ruling.

“Based on the identified deficiencies in PG&E’s reporting on its post-PSPS corrective actions to date, I am directing further action to ensure that PG&E is adequately operationalizing the clear guidance we have provided and implementing corrective actions that will meaningfully mitigate the impact of any future PSPS,” the CPUC chair wrote.

February 4, 2020

Texas PUC Delays AEP Texas, CenterPoint Rate Orders

The Texas Public Utility Commission last week declined to issue final orders in a pair of rate cases involving CenterPoint Energy and AEP Texas, but it did approve several other rate recoveries.

During an open meeting Friday that lasted less than half an hour, the PUC signed off on nearly $6.4 million in rate case expenses for Entergy Texas (48 439) and Southwestern Electric Power Co.’s request to implement a net interim fuel refund of more than $15 million (49974).

Texas PUC — Commissioners Shelly Botkin and Arthur D’Andrea proceed without Chair DeAnn Walker.

The commission also approved a $475,000 administrative penalty against EDF Energy Services for failing to reserve sufficient capacity to meet its responsive reserve service for 113 operating hours between March 27, 2016, and Dec. 28, 2017 (50304).

Finally, the PUC approved a $10,000 fine for Shell Energy North America related to over-procurement of ancillary services (50227).

Commissioner Arthur D’Andrea said the PUC will be intervening in a pair of FERC proceedings involving MISO:

Proposed Tariff revisions to expand, modify and clarify the identification and cost allocation of transmission facilities providing regional and local economic benefits to MISO customers (ER20-857, ER20-858, ER20-862).
A proposal to remove the exemption from physical withholding penalty charges for resources not categorized as planning resources (ER20-665, ER20-668, ER20-669).

Chairman DeAnn Walker missed the meeting with an undisclosed illness. D’Andrea chaired the meeting in her absence.

— Tom Kleckner

February 4, 2020March 12, 2025

NEPOOL Markets Committee Briefs: Jan. 28, 2020

ISO-NE’s External Market Monitor last week presented the New England Power Pool Markets Committee a conceptual design for mitigating market power in the RTO’s day-ahead ancillary services market.

Monitor David Patton led off with a memo describing the advantages of the conduct-impact approach, a two-step process that uses reference levels to test both a participant’s conduct as it relates to a competitive norm and its impact on the market.

The first part of the test considers whether a unit’s offer exceeds its reference level by some pre-established threshold. If the threshold is exceeded, then a second part of the test determines whether the conduct (i.e., the offer) has caused an impact on the market clearing price for energy or ancillary services or affected an uplift payment.

Patton said the conduct-impact framework has been effective in protecting MISO, Monitor Strengthening Mitigation Measures.)

“Our general recommendation is that the conduct-and-impact framework should be applied to the day-ahead ancillary products and should be effective at addressing the market power concerns,” Patton said.

“The nice thing about the conduct-and-impact mitigation framework is, if the market is very competitive, it will rarely if ever mitigate any offers, but the fact that it exists … actually does discipline the behavior of the suppliers of the products,” he said. “We think that this framework, regardless of the outcomes of the simulation analysis, will be effective to mitigate the potential competitive concerns.”

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to amplify their presentations.]

In addition to various components of short-run marginal costs, suppliers’ offer prices can be affected by their varied expectations around LMPs, risk preferences and price volatility, even if they have no market power, Patton said. Those differences can prompt suppliers to submit offers that vary substantially from supplier to supplier.

Under the ISO-NE External Market Monitor’s framework, the RTO would use a pre-established price threshold to check participants’ market power. | Potomac Economics

In his presentation, Patton pointed out that price volatility can cause suppliers to limit their exposure by adding a risk premium, to reduce the likelihood of covering an option at a loss. He said reasonable risk premiums should be allowed.

Such latitude would require a model to estimate the variation in such premiums to ensure that the pre-established thresholds accommodate the variation under a wide range of conditions, he said. Setting the thresholds appropriately can change the incentives of suppliers to offer more competitively, with the analysis showing that a pivotal supplier does not have an incentive to raise prices under conduct thresholds of $50/MWh.

The EMM recommended ex post market power mitigation measures to deter physical withholding and provide an alternative to a must-offer obligation. He said the most common forms of such measures are financial sanctions based on the impact of a market participant’s conduct or subjecting a supplier with market power to a must-offer obligation.

“We are worried about the overstepping of bounds,” Brett Kruse of Calpine said. “Traditionally, as we saw in the California Energy Crisis, FERC’s always had the ability to look at something and say, ‘You didn’t violate any rules; you didn’t violate the tariff; you didn’t violate any NERC criteria; but what you did, at its core, was to defraud. You had the intent to defraud people.’ … And they’ve held people accountable for that.” He pointed out that the ex post mitigation that Patton is proposing would occur many months after decisions on LNG arrangements were made and that the Monitor had effectively proposed a “backdoor” must-offer requirement.

“By definition, most exercises of market power do not violate any rules; it’s not fraudulent,” Patton said. “I’m an economist, and if you have market power, I expect you to attempt to exercise it. If you’re a rational economic actor in a market, and you have market power, you exercise it. In fact, you’re under an obligation to your shareholders to exercise market power, which is why market power mitigation must be effective.”

“FERC set up these markets with the notion that people were going to exercise market power, that we were going to get noncompetitive pricing, so either people have to not have market power, or it has to be effectively mitigated,” Patton said.

Market Power Assessment

ISO-NE is also making progress on the market power assessment (MPA) being conducted concurrently with the mitigation design work, Chief Economist Matt White said. (See “Market Power Analysis and Mitigation,” NEPOOL Markets Committee Briefs: Nov. 12-13, 2019.)

An MPA should determine whether market power is empirically supported, and if so, help to identify the specific conditions, frequency and extent to which individual participants may be able to profitably exercise market power, White said.

RTO staff have largely completed the first of four steps in the MPA, White said, presenting a memo.

The four major steps are: developing co-optimized market clearing software; producing study cases and input data; modeling participants’ option offers; and evaluating and analyzing of the market clearing outcomes.

White said the RTO is developing, coding and validating a day-ahead co-optimized market clearing engine model, or study model, by itself because the vendor would not be able to do so before 2024.

After the RTO assembles the data, White said, it must develop the assumptions and construct the offer behavior, using actual numbers, which has to be done under two scenarios: competitive conditions, and conditions in which a participant is able to exercise market power.

The model incorporates the functions and logic of the existing day-ahead market and includes the proposed new day-ahead ancillary services, pricing and co-optimization clearing logic.

ESI Central Case Update

Results for the critical winter months — or Central case — in the RTO’s latest model of its Energy Security Improvements initiative reflect limited changes in assumptions relative to those presented at the prior January MC meeting, Todd Schatzki of Analysis Group said.

The RTO has until April 15 to file a long-term fuel security mechanism with FERC (EL18-182). The Participants Committee plans to vote on the new market design at its April 2 meeting.

Modifications included minor changes to the hourly strike price inputs used in all cases and extending the date of the last barge refueling from Feb. 1 to 14, expanding the available fuel supply. In the cold snap of 2017/18, sea and river ice affected ship and barge deliveries to fuel oil terminals located in Maine and New Hampshire and on the Hudson River.

ESI increases total customer payments in some cases (Frequent, Infrequent) and decreases it in others (Extended). | Analysis Group

Changes result in minor decreases in total customer payments in the Frequent and Infrequent cases, with other results similar to those reported on Jan. 14. The full set of tables is provided in the presentation appendix, Schatzki said. (See NEPOOL Markets Committee Briefs: Jan. 14-15, 2020.)

Customer payments increase because of forecast energy requirement (FER) payments plus the net cost of new day-ahead energy options, with the higher payments partially or more than fully offset by reduced energy (LMP) costs caused largely by the incremental energy inventory under the market design, he said.

The new analysis showed that in the “frequent” stressed conditions scenario, total payments by load would increase 3.2% to $4.23 billion, with $250 million in FER payments and $66 million in net day-ahead option payments partially offset by a $184 million reduction in payments for energy and real-time operating reserves.

Under the “extended” stressed conditions case — based on 2017/18, with its one long cold snap — load costs would decrease $62 million (-2.3%) to $2.66 billion.

The “infrequent” stressed conditions case, based on 2016/17, showed $1.8 billion in load costs, a $35 million (2%) increase.

— Michael Kuser

February 4, 2020

ERCOT Technical Advisory Committee Briefs: Jan. 29, 2020

ERCOT stakeholders last week endorsed a final batch of key principles (KPs) that will guide the Texas grid operator’s implementation of real-time co-optimization into its energy market.

“We’re in a transition period today,” ERCOT’s Matt Mereness told the Technical Advisory Committee during its meeting Wednesday. “We have to button up a lot of business to get on with our work.”

Mereness, chair of the Real-Time Co-optimization Task Force, said staff have already begun to draft the revision requests necessary to add real-time co-optimization (RTC), a market tool that procures both energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements.

ERCOT is recommending the task force serve as a clearinghouse to address protocol language changes and stakeholder comments. Staff plan to file an expected full set of 10 RTC change requests and a single impact statement in March, Mereness said.

The grid operator has estimated it will cost at least $40 million to add RTC to the market, with a projected implementation in mid-2024. Staff hope to submit all comments to the Protocol Revisions Subcommittee (PRS) in November and gain the TAC’s endorsement and the Board of Directors’ approval by year-end.

“This is the critical path to getting the program off and running,” Mereness said, promising that stakeholders will continue to be heavily involved.

“We’ll be done with the protocols in the relatively near future, but I think it’s very important we keep you updated on how the project’s going,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “Ultimately, your feedback is really valuable as to how you’d like us to keep you updated. If you think there’s something that we’re not providing informationally and that’s of value to you, we’re all ears.”

The approved principles included the need to modify the market participants’ disclosure reports on 15-minute settlement intervals filed 60 days before the current operating day. With RTC, each five-minute interval will now include more than 45,000 values and numbers.

The other KPs included:

KP 1.1 (2), (6), (7), (8): Continues use of a pricing run to capture the effects of reliability deployments and the existing triggers to execute the deployment process. The pricing run will be modified to also co-optimize energy and AS. The real-time online reliability deployment price adder process will apply to both energy and AS; the adder for each AS product will be the positive increase in market clearing price for capacity between the dispatch and pricing run.
KP 1.2 (3): The values of and interaction between systemwide offer cap, value of lost load and the power balance penalty price and their potential changes must be evaluated as part of RTC’s implementation.
KP 1.3 (11 ), 14: The security-constrained economic dispatch (SCED) tool will use the most recently available AS offer as qualified scheduling entities (QSEs) continuously update their AS offers. A behavioral rule will be created to prevent QSEs from submitting confirmed trades for AS sub-types in excess of their day-ahead market self-arrangement quantity.
KP 1.4 (3), (4): QSEs will continue to send up and down normal ramp rates that represent a resource’s five-minute ramping capability but will submit new telemetry to inform ERCOT of a qualified resource’s physical capability to provide AS. These telemetry points will be used as additional limits on AS awards given the resource’s other constraints.
KP 1.5 (14-16): RTC systems will consider AS awards from the most recent SCED execution. No new settlement calculations will be needed to address a SCED failure. Fast-responding regulation service will be removed as a subset of regulation AS. Energy storage resources will be required to qualify and provide the same regulation service as other resources.
KP 1.6 (5): Credit exposure calculations will be revised to account for RTC AS activity.
KP 3 (13-20): Reliability unit commitment (RUC) will review available scheduled resources and consider moving AS among qualified resources to meet the real-time forecasted conditions.
KP 5 (2)(a), (7)(b), (7)(j): Identifies necessary changes for the day-ahead market to bring day-ahead AS procurement into alignment with RTC’s implementation.
KP 6: Identifies performance-monitoring changes necessary to reflect RTC’s implementation.
KP 7: Captures design concepts that were considered during the RTC principles’ development but were deemed to be outside the implementation’s scope.

TAC Endorses 7 Energy Storage Concepts

The TAC endorsed seven key topic/concepts (KTCs) as part of the Battery Energy Storage Task Force’s (BESTF) effort to integrate battery storage resources into ERCOT. The task force is considering operational and market design policies that could eventually be implemented.

KTC 1: Proposes that energy storage systems participating in SCED and AS markets register as an energy storage resource (ESR).
KTC 3: Recommends ESRs suspend charging, unless instructed otherwise by ERCOT, during all levels of an energy emergency alert.
KTC 5: Would score ESR performance using ESR energy deployment performance (ESREDP) percentages and megawatts. The BESTF recommends ESREDP tolerance to be the greater of 3% or 3 MW.
KTC 6: Allows limited-duration resources to submit updates to energy offer curves immediately before an operating hour begins.
KTC 7: Sets requirements for settling ESRs in the day-ahead and real-time markets.
KTC 8: Conforms to Public Utility Commission rules that wholesale storage load (WSL) occurs when stored energy is “subsequently regenerated and sold at wholesale as energy or ancillary services” by requiring batteries serving retail load behind their interconnection point to be ineligible for WSL treatment.
KTC 10: Proposes ERCOT and the Supply Analysis Working Group develop a threshold above which ESRs will be included in the Capacity, Demand and Reserves (CDR) report. It also proposes near- and longer-term methodologies for considering ESR capacity in outage coordination studies, operations studies other than RUC and transmission planning studies.

ERCOT: DC Economic Dispatch not ‘Feasible’

Members endorsed ERCOT’s determination that developing systems to enable economic dispatch over DC ties between the grid operator and other systems would be “prohibitively complicated and expensive” and is not “presently feasible.”

Staff said such an effort would require ERCOT to coordinate the development of a joint-dispatch mechanism with the system operators at the other end of each affected tie. “Such a mechanism would almost certainly require ERCOT and each other affected system operator to enter into a binding commitment to use the dispatch mechanism and to accept the output in system dispatch, which would limit ERCOT’s authority over one aspect of its market design,” staff said in a memo to the TAC.

ERCOT had been directed by Texas’ Public Utility Commission to study and determine whether some or all DC ties should be economically dispatched or whether implementing a congestion management plan or special protection scheme would more reliably and cost-effectively manage congestion caused by DC tie flows.

The directive was one of a number to the grid operator related to the Southern Cross Transmission DC tie-line, a proposed Pattern Development HVDC transmission project in East Texas that would ship more than 2 GW of energy between the Texas grid and Southeastern markets (46304). (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

The committee’s six consumer representatives — the Texas Office of Public Utility Counsel, independent consultant Eric Goff, CMC Steel Texas, Air Liquide, and the cities of Lewisville and Eastland — abstained from the vote, as did ENGIE’s Bob Helton and Exelon’s Marka Shaw. An earlier Goff amendment to the motion that would have required ERCOT to re-evaluate its congestion management plans for DC ties fell short by a 63-37 margin.

ERCOT said it would consider any constraint management plan (CMP) or remedial action scheme (RAS) that it developed or other entities properly proposed “at the appropriate time.”

Helton, Lange Re-elected to TAC Leadership

Committee members re-elected Helton and South Texas Electric Cooperative’s Clif Lange as chair and vice chair, respectively. The elections will give Lange a full year as vice chair before potentially assuming the chairmanship a year from now.

Helton welcomed several new members to the committee including Goff, a former TAC member when he was at Citigroup Energy. Also joining the committee this year are ACES Power’s Roy True, representing Brazos Electric Power Cooperative; AP Gas & Electric’s Jennifer Schmitt in the Independent Retail Electric Provider segment; and Shaw in the Independent Generator segment.

Members also approved the 2020 subcommittee leadership.

RUC Resource-hours Fall 67%

ERCOT staff’s annual RUC report revealed a 67% drop in effective resource-hours, from 613 in 2018 to 201.7 last year. The total RUC make-whole payment was about $48,000, almost exclusively covered through capacity-short charges, staff said.

Resources in the petroleum-rich Permian Basin accounted for more than 53% of the total resource-hours, necessary to help resolve local issues associated with the area’s high load and transmission outages.

Staff credited several TAC-endorsed system changes, including the application of an offer floor when a RUC resource was previously awarded a supply offer, for the reduction.

“We’re seeing some of the fruits of our work,” Reliant Energy Retail Services’ Bill Barnes said.

Staff also told the committee that ERCOT’s system administration fee, currently 55.5 cents/MWh and level since 2016, is forecast to be adequate for 2021. The notice fulfilled a market participant request for more advance notice of any future rate increases.

TAC Approves 19 Change Requests

The committee approved the PRS’ two-month backlog of revision requests, including the first one to address the BESTF’s key topics and concepts. The change (NPRR986) gives energy storage resources more flexibility in updating real-time energy offer curves and bids.

Stakeholders discussed extending the flexibility to make real-time updates to all generators. Ögelman said potential system “performance issues” would pose a challenge that needs to be resolved.

“Once we’re through with [NPRR986’s implementation], we’re willing to work on extending the flexibility to other resources as well,” Ögelman said.

The committee approved 15 additional NPRRs, single revisions to the Nodal Operating Guide (NOGRR) and Verifiable Cost Manual (VCMRR), and a system change request (SCR), with only a pair of abstentions:

NPRR826: Creates a new process for determining the mitigated offer cap for reliability-must-run (RMR) resources.
NPRR838: Revises the RMR process by deleting the requirement for a unit to submit operations and maintenance estimates and canceling the requirement for RMR resources to submit quarterly O&M updates.
NPRR955: Defines a limited-impact RAS to accommodate NERC Reliability Standard PRC-012-2.
NPRR963: Allows an ESR’s components to be considered in aggregate for generation resource energy deployment performance scoring, controllable load resource energy deployment performance scoring and settlement of base point deviation charges.
NPRR964: Removes from the RMR process the term “synchronous condenser unit” and its related agreement.
NPRR967: Removes the 10-MW limit for limited-duration resources.
NPRR970: Clarifies the fuel-dispute process for RUC make-whole payments.
NPRR971: Updates the energy offer curve’s cost cap value.
NPRR974: Requires ERCOT to include additional data about the amount of projected capacity available in the short-term system adequacy report.
NPRR977: Requires ERCOT to post a report of canceled RUCs to the market information system.
NPRR978: Incorporates revisions to address recent changes on the PUC’s resource adequacy reporting rules.
NPRR980: Changes how forced outages longer than 180 days are treated in ERCOT’s CDR report.
NPRR982: Clarifies that a deployed block-load transfer will be appropriately compensated.
NPRR985: Modifies the time period used to compute the forward adjustment factor components of the total potential exposure calculation and clarifies that the three forward weeks commence on the applicable operating day, rather than following the operating day.
NPRR988: Corrects NPRR929’s intended implementation by clarifying that conditions in its language are necessary for determining whether a point-to-point obligation with links to an option bid is eligible to be awarded.
NOGRR183: Aligns the guides with NERC’s RAS reliability standard.
SCR806: Adds resource-specific offer information to all individual disclosure reports on ERCOT’s website.
VCMRR026: Removes an appendix to align the manual with NPRR970’s proposed protocol language and NPRR617’s revisions.

— Tom Kleckner

February 2, 2020

WEC Energy Wind Boom to Follow Strong 2019

The winds of change will continue to favor WEC Energy Group after a strong 2019 performance, the company indicated last week.

“In 2019, we benefited from additional capital investment, production tax credits and continued emphasis on cost control,” CFO Scott Lauber said during an earnings call Thursday that largely focused on the company’s growing investments in wind generation.

Executive Chairman Gale Klappa reported on the list of projects, including the 97-MW Coyote Ridge Wind Farm in South Dakota, which is now in service and “will contribute a full year of earnings in 2020,” he said, particularly from the project’s tax credits.

“We invested approximately $145 million for our 80% share of the wind farm, and we’re entitled to 99% of the tax benefits,” Klappa said. He also noted that the project has a 12-year offtake agreement with Google Energy for all energy produced.

Klappa pointed out that WEC also will acquire an 80% ownership interest in Invenergy’s Thunderhead Wind Energy Centre in Nebraska for $338 million. The 300-MW project is expected to be in service at the end of the year. Klappa said he expects it will qualify for PTCs, and it also comes with a “long-term” offtake agreement with AT&T for all its output.

WEC also expects to earn PTCs from its 80% ownership in Invenergy’s 250-MW Blooming Grove Wind Farm in Illinois for $345 million. Commercial operation is also expected by the end of 2020.

We Energies’ Glacier Hills Wind Park | *WEC Energy Group*

“Blooming Grove has a 12-year offtake agreement with affiliates of two multinational companies that are investment grade,” Klappa said. “Overall, we’re very encouraged about these investments in renewable energy, which will serve strong businesses for years to come. We expect the return on these investments to be higher than our regulated returns. Of course, we’re being very selective as we vet future projects. We’re only interested in projects that achieve our financial return metrics and do not change our risk profile.”

And a little sunshine was mixed in with the long list of wind topics.

WEC CEO Kevin Fletcher reported the utility has broken ground in Wisconsin on two solar projects for subsidiary Wisconsin Public Service: Two Creeks and Badger Hollow 1.

“Our share will total 200 MW with an expected investment of approximately $260 million. Both projects are scheduled to begin producing energy by the end of this year,” Fletcher said.

He also noted that subsidiary We Energies in August filed with the Wisconsin Public Service Commission to acquire 100 MW of capacity at the Badger Hollow II Solar Park for a $130 million investment. He said he expects the commission’s decision in spring.

Finally, Fletcher reported that in early 2019, the utility completed construction on two new natural gas-fired power plants in Michigan’s Upper Peninsula. The projects were “on time and on budget,” Fletcher said.

“These plants are now providing a cost-effective, long-term power supply for our customers in the Upper Peninsula. With these new units operating, we were able to retire our older, less efficient coal-fired plant at Prescott. This resulted in significant operations and maintenance savings and reduced CO2 emissions,” he said.

– Amanda Durish Cook

February 2, 2020

Xcel Energy Reports Solid 2019 Earnings

Xcel Energy last week reported year-end earnings of $1.372 billion ($2.64/share), up from 2018’s performance of $1.261 billion ($2.47/share) and marking the 15th straight year the company has met or exceeded its guidance.

Minneapolis-based Xcel attributed the positive results to favorable regulatory rulings in its utilities’ states. Colorado’s Public Utilities Commission verbally awarded Xcel a $41.5 million rate increase and a 9.3% return on equity, below its requests of $158 million and 10.2%. In December, Minnesota’s PUC approved a one-year deferment of Xcel’s three-year $465 million rate case.

“I would challenge anybody to find a utility that is more focused and has … 100% of their growth coming from regulated operations,” CEO Ben Fowke said during a conference call with analysts Thursday. “There’s nobody that’s more pure-play and vertically integrated than Xcel Energy, and that’s the way we mean to keep it.”

Fowke said Xcel’s operations and maintenance costs were down almost 1%, “even while making incremental investments in our system,” and noted three wind projects, representing almost 700 MW of capacity, were completed under budget. The company has another 2 GW of wind projects under construction, he said.

For the quarter, Xcel posted earnings of $292 million ($0.56/share), as compared to 2018’s final quarter earnings of $215 million ($0.42/share).

The company’s share price opened down at $67.10 on Thursday but finished the week at $69.19, after setting a new all-time high of $69.52 Friday morning.

— Tom Kleckner