Page 1162 – RTO Insider

December 20, 2019

CAISO’s 2020 Vision Anticipates Big Change

By Hudson Sangree

CAISO will have its work cut out for it next year, with more than a dozen major policy initiatives moving forward as well as efforts to head off predicted electricity shortfalls starting in summer 2021.

At Thursday’s Board of Governors meeting, staff provided a rundown of the policies expected to occupy the ISO in the months ahead.

A major focus will be on managing operational risk from a transforming grid, one that must integrate increasing amounts of renewable electricity and battery storage, said Greg Cook, CAISO executive director of market infrastructure policy.

Meeting California’s clean energy goals and expanding the Western Energy Imbalance Market from a real-time-only to a day-ahead market also occupy the 2020 agenda.

“We’re going through an unprecedented amount of change,” Cook told the board.

CAISO 2020 — CAISO’s headquarters in Folsom, Calif. | © *RTO Insider*

An initiative on hybrid resources promises to be one of the largest and most complex of the ISO’s 14 policy initiatives in 2020, Cook said. Because of California’s move toward carbon-free energy and the limits of solar energy to meet evening peak demand, developers have proposed 25,000 MW of projects that pair storage with existing or new generation.

Those projects won’t all materialize, Cook said, but “we could easily see 2,000 to 3,000 MW coming online in the next few years,” particularly to meet the impending capacity shortfalls in 2021. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

In his presentation on the ISO’s 2020 outlook, Mark Rothleder, vice president of market quality, focused on the prospect of shortfalls starting in 18 months and the need to get ahead of the problem. Among the challenges are dealing with increased ramping needs and prolonged weather events that diminish solar generation, he said. Currently, rapid increases in demand are met by natural gas generation and electricity imported from other Western states, he noted.

In one slide, Rothleder showed a three-hour ramp on Jan. 1, 2019, that started mid-afternoon and required more than 15,000 MW of additional power, most of it coming from natural gas and imports.

To put the figure in perspective, “that’s like ramping 12 Diablo Canyons over a three-hour period,” Rothleder said, referring to California’s last operating nuclear generating station. The two-unit Diablo Canyon Power Plant, owned by Pacific Gas and Electric, is scheduled to retire starting in 2024, further exacerbating the state’s need for reliable electricity supplies.

The same three-hour ramp is expected to grow to 25,000 MW by 2030, he said. By that time, solar combined with batteries should be contributing more to ramping needs. However, to make that work, improvements in dispatching solar power are required, as is increased visibility and control of commercial and residential solar generation, he said.

Shifting focus, Rothleder expressed concern about multiday weather patterns that limit solar generation. A common California winter weather pattern consists of multiple rainstorms rolling in from the Pacific Ocean, with short breaks between the storms, over the course of a week.

Rothleder cited a period from Jan. 13 to 18 when storms washed over California, reducing solar generation to 20% of expected capacity. Gas power and imports can make up the difference now, but Senate Bill 100, enacted in 2018, requires elimination of fossil fuels from the state’s energy mix by 2045.

As reliance on solar power increases, and dependence on fossil fuels decreases, the state will require storage resources capable of dealing with prolonged cloud cover, he said. Batteries with a four-hour run time, the main type used today, won’t do the job, he said.

A similar situation in July on the Hawaiian island of Kauai resulted in rolling blackouts, he noted.

“If we want to get off gas, we need a solution, including storage,” Rothleder told the board.

December 20, 2019

FERC Rejects Rehearing over PJM-NYISO Proxy Bus

By Robert Mullin

FERC on Thursday rejected a request to rehear its October 2017 ruling approving changes to the PJM–NYISO joint operating agreement reflecting a new operational plan for the ABC and JK interfaces between New York and New Jersey (ER17-905).

PJM and NYISO developed the JOA interchange scheduling and market-to-market (M2M) coordination provisions after Public Service Enterprise Group and Consolidated Edison terminated a wheeling arrangement that facilitated the flow of energy between congested areas in southeastern New York and northern New Jersey.

The revisions combined NYISO’s ABC and JK interfaces with the 5018 line and PJM’s western ties, creating an aggregate PJM-NY AC proxy bus. The grid operators said the changes would make use of existing interchange scheduling constructs and support the phase angle regulators on the interfaces. Pricing on the proxy bus was expected to reflect the impacts of imports and exports on the NYISO and PJM transmission systems, weighted by power flow distribution percentages. (See Rejecting PJM ‘Wheel’-related Requests, FERC Sets Inquiry.)

PJM NYISO Proxy Bus — The PJM-NY AC proxy bus is intended to guarantee 400 MW of operational base flow between southeastern New York and northern New Jersey. | *PJM*

In approving the changes, the commission rejected a complaint by PSEG that the changes infringed on the rights of transmission owners and there was no reliability need for the 400 MW of operational base flow (OBF) provided by the arrangement. FERC instead said it recognized the OBF was necessary to address reliability concerns in northern New Jersey and to avoid additional power from being forced over the western ties and increasing flows over already congested transmission facilities.

In its Thursday decision, FERC denied a rehearing request by PSEG and the New Jersey Board of Public Utilities, saying the complainants were incorrect in their contention that the commission erred in approving JOA revisions that failed to allocate PJM Regional Transmission Expansion Plan costs to New York beneficiaries of the OBF arrangement.

FERC noted that PSEG concedes that the JOA “is an operational protocol and that it does not appear to meet the definition of firm point-to-point transmission service, transmission service or similar terms under the PJM or NYISO Tariffs.” Instead, the commission, said, the OBF is an operational protocol “that expressly does not provide firm transmission service and does not allocate costs to an entity like Con Ed.”

“This materially distinguishes the JOA from the now-terminated [wheeling transmission service agreements] to which Con Ed was a party and under which Con Ed was allocated costs due to its firm transmission service on both the NYISO and PJM systems,” the commission wrote.

FERC also disagreed with PSEG’s contention that the commission was wrong to rely on PJM and NYISO analysis showing the OBF was needed to maintain reliability. PSEG had argued the analysis was flawed because it combined an assumption of congestion during summer peak conditions with a level of interchange — 2,500 MW — that would never occur during the summer.

“PSEG does not address NYISO’s and PJM’s explanation that there were hours between 2014 and 2016 during which the net interchange between PJM and NYISO exceeded 2,500 MW. It was therefore reasonable for the commission to rely on PJM’s studies for demonstrating actual historical flows and a reasonable net interchange value,” FERC said.

The commission also said it found “unpersuasive” PSEG’s assertion that NYISO and PJM should rely on existing NERC transmission loading relief procedures instead of the OBF.

“As the commission explained in the October 2017 order, the NERC procedures are a less economically efficient outcome compared to the RTOs’ proposal to implement economic interchange over the ABC interface and JK interface and also utilize M2M PAR coordination at these interfaces,” FERC said. “PSEG does not disagree that transmission loading relief procedures are out-of-market mechanisms, and that in PJM they are specifically emergency in nature and in NYISO are used when necessary for maintaining reliability in NYISO.”

December 20, 2019

PJM TOs Challenge Monitor’s Competitive Tx Role

By Christen Smith

VALLEY FORGE, Pa. — PJM stakeholders endorsed manual language Thursday that memorializes the Independent Market Monitor’s role in analyzing competitive transmission proposals.

But incumbent transmission owners contend the revisions have no basis in Attachment M of PJM’s Tariff and undermine the yearslong vetting process stakeholders undertook to fine-tune cost-containment language for Manual 14F. (See PJM TOs Wary of Cost Containment Rules.)

PJM’s Markets and Reliability Committee debated manual language that detailed the role of the Independent Market Monitor in evaluating competitive transmission proposals. | © *RTO Insider*

Last week, PJM posted manual revisions that added two sentences outlining the Monitor’s ability to access data contained within competitive bids for transmission projects and to perform independent analysis using that information. Incumbent TOs took particular issue with the qualifying clause of the revisions that cite Attachment M of the Tariff as the prevailing source authorizing the Monitor’s involvement in the process.

“Attachment M is silent on what the Market Monitor has access to as it relates to the competitive process,” said Amber Thomas, PPL’s utility regulatory specialist. “Where in the Tariff does it say in Attachment M that the IMM has access to this data? The Attachment M does not say that. To make these big policy changes in Manual 14F to codify something Attachment M does not say does not sit well with PPL.”

The revisions, borne out of a stakeholder motion endorsed by the Markets and Reliability Committee last year, will codify the framework the RTO will use to evaluate competitive transmission projects. (See “PJM Unveils Flat Fee Cost-containment Plan,” PJM PC/TEAC Briefs: Aug. 8 , 2019.) Since implementation of FERC Order 1000 in 2014, PJM has reviewed 850 competitive proposals, of which less than 20% included cost-commitment provisions.

Interim PJM CEO Susan Riley | © *RTO Insider*

Interim CEO Susan Riley clarified Thursday that the revisions represent a compromise about the Monitor’s collaborative role and don’t obligate PJM to share its project analyses, just the data used to support their conclusions.

“The intent is not to have an oversight process over the work that PJM is doing, merely to allow an independent review,” she said. “I don’t think it’s a big give. [The Monitor] does not have approval authority over these projects as to whether they go forward or not. He will just get the data.”

Monitor Joe Bowring said Attachment M, part V “makes clear that the IMM’s access to data is all inclusive.” he added.

“Attachment M is also quite clear and explicit that the IMM has authority to address issues of competition in PJM markets. Competition to build transmission facilities is clearly part of PJM markets,” Bowring added. “These sentences in the manual don’t reflect a compromise; they reflect what our duties are as defined by the Tariff. Under Attachment M, the IMM has the authority to look at competitive issues in the PJM markets.”

The overtures from PJM and the IMM did little to ease incumbent TOs’ concerns. Alex Stern, manager of transmission strategy and policy for Public Service Electric and Gas, questioned PJM’s “procedural gymnastics” in bringing the revisions forward with no opportunity for review or vetting and in defiance of a stakeholder vote overwhelmingly endorsing language that did not include reference to the Monitor.

Stern suggested the MRC instead approve an earlier version of Manual 14F language that excluded the two sentences regarding Attachment M. He said that language was properly vetted by the Planning Committee and through special sessions, as required by the original MRC motion, unlike the revisions PJM and the Monitor crafted and posted online just last week.

PJM — Alex Stern, PSE&G | © *RTO Insider*

He added that expanding the scope of the revisions to include the Monitor’s role was not a part of the discussion until recently — and that it was not driven by stakeholder interest but rather by the Monitor itself. Even so, the recent conversations at the MRC never referenced Attachment M, Stern said.

“The marketplace is not made up by what PJM and the IMM come up with in agreement on their own,” he said. “It’s legally suspect and raises a whole host of questions.”

Bowring called Stern’s accusations “demonstrably false,” pointing to special PC sessions discussing his role in the process and corresponding manual language dating back to August.

“The role of IMM was identified explicitly by a vote of the MRC more than a year ago at the beginning of this process. The specific language about the role of the IMM has been discussed for months in this process,” he said. “In fact, language about the IMM role in the manual was jointly drafted by the IMM and PJM but was removed months ago at the insistence of the TOs.”

Ken Seiler, PJM’s vice president of planning, reiterated the RTO’s interpretation of the Tariff, even if it doesn’t spell out exactly what incumbent TOs say it should.

“As I understand it, there’s language in the Tariff in Attachment M that specifies [the Monitor’s] roles and responsibilities,” he said. “Is it explicit? No. The Tariff is high level. We would try to fulfill those [data] requests based on the spirit of what’s in the Tariff.”

PJM stakeholders overwhelmingly approved the PJM-Monitor language with a sector-weighted vote of 3.92 to 1.08.

December 20, 2019

FERC Denies IPPNY Complaint over Capacity Imports

FERC on Thursday denied a complaint by the Independent Power Producers of New York seeking to bar NYISO from allowing PJM resources to sell installed capacity into the ISO’s Zone J using unforced capacity deliverability rights facilities (EL18-189).

The ruling ended a year and a half of back-and-forth filings among IPPNY and intervenors. IPPNY contested the rights of several PJM-controlled merchant transmission facilities (MTFs) in New Jersey to export power to Manhattan and Staten Island, alleging that New York’s use of PJM capacity withdrawals threatened system reliability.

NYISO Zone J — Con Edison’s Goethals Substation on Staten Island | *Con Edison*

NYISO argued that IPPNY incorrectly assumed that transactions across Zone J MTFs would be subject to curtailment on the same basis as non-firm service within PJM. (See NYISO Business Issues Committee Briefs: Sept. 12, 2018.)

The commission concluded that NYISO’s Tariff does not require that MTFs, as external capacity suppliers, have firm transmission withdrawal rights in the external control area to qualify to supply capacity to NYISO.

“Rather, the Services Tariff requires only that the external capacity supplier show to NYISO’s ‘satisfaction’ that its capacity is deliverable to NYISO and ‘will not be recalled or curtailed,’” the commission said.

December 20, 2019

Parties to EPE Acquisition Reach Settlement Agreement

By Tom Kleckner

El Paso Electric and the investment funds seeking to buy the utility have reached a settlement with most of the parties with an interest in the transaction, they told Texas regulators on Wednesday.

EPE, Sun Jupiter Holdings and Infrastructure Investments Fund (IIF) US Holding 2 said that the agreement’s “negotiated resolution” is in the public interest, will conserve the parties’ and the public’s resources, and eliminate controversy (49849).

The Public Utility Commission of Texas had set a Dec. 17 deadline to finalize a stipulated agreement but granted an extension to noon Wednesday. (See “Commission Denies Extension Request in EPE Acquisition,” Texas PUC Briefs: Dec. 13, 2019.)

EPE’s Rio Grande Plant in Sunland Park, N.M. | *El Paso Electric*

Parties to the agreement include the city of El Paso, PUC staff, the state’s Office of Public Utility Counsel, and several consumer and labor groups. The El Paso City Council approved the agreement on Tuesday, although it is still pondering EPE’s municipalization.

The signatories agreed that the transaction will not result in a transfer of jobs outside of Texas, adversely affect customers’ and employees’ health and safety, or result in degraded service.

Administrative Law Judge Hunter Burkhalter directed the two remaining intervenors not party to the settlement — a local activist who once served on EPE’s board and a group consisting mostly of local school districts — to respond by Dec. 30 as to whether they want to proceed with a scheduled Jan. 7-8 hearing on the sale. He warned that if the hearing goes forward, the PUC will rule on the stipulation, not the original application. The PUC had rescheduled the hearing from November to January in order to allow intervenors time to reach a unanimous agreement. (See Parties Near Agreement on El Paso Electric Purchase.)

EPE, Sun Jupiter and IIF, which is advised by J.P. Morgan, announced their proposed $4.3 billion purchase of the utility in June. The sale must be approved by the PUC, FERC and other regulators before becoming final.

December 18, 2019April 11, 2024

ReliabilityFirst Warns of Inaccurate Facility Ratings

By Christen Smith

ReliabilityFirst said Monday that inaccurate facility ratings continue to undermine the safety and reliability of the bulk electric system.

The regional entity said transmission and generation owners must shore up internal controls during the planning process to ensure that a facility’s rating remains accurate post-construction.

Speaking during an open forum conference call, Jim Uhrin, RF’s director of compliance monitoring, said that gaps in program execution — identified by NERC as an area of focus in the 2019 and 2020 ERO Implementation Plans — leaves owners noncompliant with the FAC-008 standard for facility ratings.

Uhrin said a majority of outages between 2015 and 2018 were caused by failed AC circuit and substation equipment and protection systems, according to information gathered from NERC’s Transmission Availability Data System.

ReliabilityFirst outages by cause, TADS 2015-2018 | ReliabilityFirst

While Uhrin said the exact reason for this is unknown, other issues occur alongside this data point. Often, he said, changes to equipment — from breakers to wave traps to line conductors — during the planning and construction process of a facility may not make it into the database used to calculate system operating limits and create planning models.

“Things are being missed,” Uhrin said. “What we believe is happening … as things change in the field, there is not a … ‘post-as-built’ field verification.”

The impact, he said, is obvious: Inaccurate data will create a host of errors that could jeopardize the safe operation of facilities.

“Each and every one of those things need to be accounted for as far the facility goes when establishing a line rating,” he said. “These are critical to make sure that everybody has it right.”

In April, FERC approved a $40,000 fine against Duquesne Light Co. for inaccurate ratings of some substation conductors and a 138-kV circuit, violations of FAC-008-3 R6. (See FERC OKs NERC Violation Settlements.)

Cycle for facility planning and modeling. | ReliabilityFirst

The substation inaccuracy — caused by entering an incorrect input value into one of the rating equations — resulted in a reduction of the overall facility rating for three transformers.

The violation extended for more than two years because Duquesne “lacked an effective verification control” to quickly detect and correct the error, NERC said. The company alerted RF of the problem in a self-report in August 2017, after completing its mitigation plan.

NERC credited Duquesne for its cooperation in the investigation but said the company’s FAC-008/FAC-009 compliance history was an aggravating factor in determining the penalty.

RF said Monday it will consider making substation visits when necessary if internal controls are not sufficiently tightened.

“We strongly encourage you to do whatever you need to do those post-field verifications,” Uhrin said. “Focus on high-risk assets first that are more impactful for the grid, and work backwards from there.”

December 18, 2019

Entergy Touts $1.3B in Savings Since Joining MISO

By Amanda Durish Cook

Customers of Entergy’s five utility subsidiaries have saved about $1.3 billion since they joined MISO in 2013, the company said Monday.

Entergy said the savings — earned between 2014 and 2018 — can be “largely” attributed to participation in “a large pool of generating facilities that stretch across the vast MISO footprint.”

“By sharing in that large pool, Entergy can maintain reliability with less power generation capacity than if it were on its own — and pass the resulting savings along to customers,” the company said in a statement, adding that its dispatch is also more efficient since joining the RTO.

Entergy broke down the five-year savings by subsidiary. Unsurprisingly, Entergy Louisiana — the largest division serving about 1.08 million customers — realized the greatest share at $561 million. Savings at the other utilities generally followed in order of customer base:

$223 million for Entergy Arkansas’ 711,000 customers;
$207 million for Entergy Mississippi’s 450,000 customers;
$198 million for Entergy Texas’ 454,000 customers; and
$118 million for Entergy New Orleans’ 202,000 customers.

“When we proposed joining MISO, we told our customers this would be a good business decision that would benefit them each month. We believe we have made good on that promise,” said Rod West, Entergy’s group president of utility operations. “Our membership in MISO has been a highly effective tool in helping our customers keep more of their hard-earned money in their pockets. It has also helped us control costs and keep our rates among the lowest in the nation. Since joining MISO five years ago, Entergy customers have saved an average of $261 million per year. These are real savings for our customers.”

Entergy integrated into MISO at the end of 2013 after coming under pressure from state regulators and a U.S. Department of Justice antitrust investigation examining the company’s “exclusionary conduct” in its service area. The department said Entergy would “resolve” the Antitrust Division’s concerns if it followed through on promises to join an RTO and divest its transmission system to ITC Holdings. The actions would eliminate “Entergy’s ability to maintain barriers to wholesale power markets,” DOJ said at the time.

Three years prior to DOJ’s integration, a FERC-commissioned study estimated that if Entergy’s operating companies and Cleco Power joined SPP, they could stand to save a net $1.3 billion from 2013 to 2022.

Entergy on Monday also noted that its residential rates are about 27% below the national average, according to 2018 data from the U.S. Energy Information Administration.

MISO Chief Customer Officer Todd Hillman said he was pleased the company and other members are “realizing the benefits of MISO membership.”

“Our vision to be the most reliable, value-creating RTO remains strong as we help our members pass on savings to their customers. MISO’s Value Proposition affirms our core belief that a collective, regionwide approach to grid planning and management delivers the greatest benefits,” Hillman said in a statement emailed to RTO Insider.

MISO has scheduled a Feb. 14 stakeholder presentation to discuss its 2019 Value Proposition, where it documents the savings it provides to all members. The RTO estimated it provided members between $3.2 billion and $3.9 billion in regional benefits in 2018. It doesn’t estimate savings to individual members.

December 18, 2019

Judge OKs PG&E Deals with Fire Victims, Insurers

By Hudson Sangree

Pacific Gas and Electric scored major wins Tuesday in its effort to emerge from Chapter 11 bankruptcy with its shareholders still in control of the utility.

In U.S. Bankruptcy Court in San Francisco, Judge Dennis Montali approved PG&E’s $13.5 billion settlement with wildfire victims, despite objections from Gov. Gavin Newsom and lawyers for a group of bondholders trying to seize control of the company.

PG&E settlement — Judge Dennis Montali | *Commercial Law League of America*

Montali also approved a controversial $11 billion settlement between PG&E and the subrogation claimants, a coalition of insurance companies and hedge funds that hold claims against the utility for insurance payments to businesses and homeowners.

And PG&E announced it had made a pact with the California Public Utilities Commission’s Safety and Enforcement Division over its role in starting wildfires in its service territory in 2017 and 2018, agreeing to not seek reimbursement from ratepayers for more than $1.6 billion in wildfire-related costs.

“If approved, this would be the largest dollar amount ever imposed by the commission in connection with alleged wildfire-related violations,” lawyers for the parties wrote in a joint motion to the CPUC.

Lawyers argued on Tuesday for six hours before Montali, who weighed the ramifications of the utility’s deal with fire victims and the governor’s harsh criticism of the restructuring support agreement between PG&E and the Tort Claimants Committee (TCC), which represents fire victims.

The judge noted that Newsom — in a court filing Monday and a letter to PG&E CEO Bill Johnson last week — had not objected to the $13.5 billion amount but had said the utility’s amended bankruptcy plan failed to meet the requirements of AB 1054, a law the governor championed last summer.

Newsom told Johnson that he wanted wholesale change in PG&E’s governance as well as provisions to let the state more quickly takeover the utility if needed. (See PG&E Chapter 11 Plan Won’t Do, Governor Tells Judge.)

Cecily Dumas, a lawyer representing the TCC, told Montali she believed the company’s reorganization plan could be amended to meet the requirements of AB 1054 and satisfy Newsom.

“Notwithstanding the fact that the governor is sending nastygrams to PG&E every few days, we have not lost hope that the debtor will be able to improve the plan so that it is AB 1054-compliant and can be confirmed,” Dumas said.

Montali said he wouldn’t overrule the decision by fire victims to back PG&E’s proposal. It was the same reasoning he used to admit the bondholders’ reorganization plan in early October. Fire victims initially backed the bondholder plan because it offered them $13.5 billion. When PG&E met that offer two weeks ago, the TCC switched its allegiance. (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)

Dumas and other lawyers said they think PG&E’s plan has a better chance than the bondholders’ proposal to be quickly confirmed by the court and CPUC, allowing PG&E to exit bankruptcy by June 2020, as AB 1054 requires. If it can meet that deadline, the utility can participate in a $21 billion wildfire recovery fund established by the state.

Lawyers for wildfire victims also switched their stance on PG&E’s $11 billion settlement with the subrogation claimants. After initially opposing the settlement, the victims withdrew their opposition when PG&E agreed to up its offer to them.

Victims weren’t thrilled that their $13.5 billion settlement with PG&E will consist of cash and stock but agreed to accept it as the best deal they were likely to get from the utility. Under the agreement, a trust to pay fire victims will receive shares equal to about 20% of a reorganized PG&E.

“We see this as the most expedient path forward,” Dumas told the judge. “This is by no means a perfect solution.”

The agreement between PG&E and the CPUC was announced Tuesday afternoon as lawyers argued in bankruptcy court. It provides that the utility will spend $1.625 billion on transmission and distribution line inspections and repairs and other wildfire measures without seeking rate recovery.

It also requires PG&E shareholders to spend $50 million on system enhancements and community engagement.

“Today’s filing sets in motion the next steps,” which include review by an administrative law judge and the CPUC, the commission said in a news release.

PG&E declared bankruptcy in January after a series of catastrophic wildfires in 2017 and 2018 saddled it with potentially billions of dollars in liabilities. The blazes included the Camp Fire, the deadliest and most destructive in state history, which killed 86 people in and around the town of Paradise.

December 18, 2019

FERC Releases Documents in PJM Fuel-cost Dispute

By Christen Smith

FERC on Monday released the disputed fuel-cost policy (FCP) at the center of a redacted complaint that PJM’s Independent Market Monitor filed last year against the RTO for not assessing a penalty against a generator (EL19-27).

The commission posted a mostly unredacted version of Tenaska Power Services’ response to the Monitor’s complaint, including the FCP in use Jan. 5-6, 2018, when the alleged violations occurred at the dual-fuel Brandywine Power Facility in Prince George’s County, Md.

The Monitor protested the release after FERC’s notice last month proposing to sunshine the docket, arguing that the confidential filings contain information that would undermine the markets and potentially give other participants insight into how Tenaska structures its energy offers.

PJM FCP — The Brandywine Power Facility in Prince George’s County, Md. | *Brandywine Power*

FERC was unconvinced by that argument.

“While the fuel-cost policy details how the market seller develops its fuel cost, the fuel-cost policy lacks specific information that would be necessary for other competitors to estimate its actual energy offer,” FERC said Dec. 12 in its order approving the release. “The majority of the relevant cost data at issue here is not competitively sensitive information, but information available from a publicly available source. Moreover, these data are no longer current, as the data relate to a specific event that occurred nearly two years ago on Jan. 6, 2018.”

Tenaska Defends Actions

Tenaska’s unredacted response — originally filed in January — shows the company insisting it didn’t violate its FCP when it used third-party quotes for natural gas prices after no applicable trades became available on the Intercontinental Exchange in time to calculate day-ahead market offers.

The Monitor interpreted the language of Brandywine’s FCP to prohibit Tenaska from making offers in such an event — a choice that would leave the capacity resource facility subject to nonperformance penalties should extreme weather conditions disrupt its fuel oil supply, Tenaska said.

“In short, there is no reasonable basis for limiting PJM’s dispatching options, or for putting generators in a position where they are potentially subject to severe penalties or are unable to recover their costs, simply because the Market Monitor is taking an overly restrictive view of a PJM-approved FCP,” Tenaska said.

Houston-based KMC Thermo owns Brandywine and maintains a contract with Tenaska that allows the company to sell energy and ancillary services in PJM’s markets. KMC authored the disputed FCP using a standardized template available on Monitoring Analytics’ website, approved by PJM and subsequently reviewed by the Monitor before implementation, Tenaska said.

In defense of its actions, the company pointed to a statement from the FCP that says, “under a set of defined market conditions, natural gas costs may be based on independent third-party quotes.”

“At the end of the day, the broad language in the FCP permitting the use of third-party quotes was provided to both the Market Monitor and PJM and, absent any objections by the Market Monitor, was properly accepted by PJM,” Tenaska said. “Regardless of the Market Monitor’s hindsight dissatisfaction, there is no basis for claiming that the FCP must now be read in such a manner that it ‘does not allow the use of offers from ICE or estimates from an affiliate company or from an independent third party.’”

Market Power Precedent

The Monitor, in its initial complaint against Tenaska filed in December 2018, said the case “presents an important precedent for the role of fuel-cost policies in protecting the PJM energy market from market power abuse.”

“If PJM accepts market sellers’ unreasonable after-the-fact arguments to justify developing fuel costs using a method not defined in the fuel-cost policy, fuel-cost policies become meaningless and fail to serve the functions that the commission identified,” the Monitor said.

The Monitor first alerted Tenaska and PJM to the alleged violation in February 2018. Tenaska defended its actions to PJM the following April, with the RTO notifying the Monitor four months later that it would not penalize the company.

PJM asked FERC to dismiss the complaint in January 2019 on the grounds that the Monitor lacked the authority to override the RTO’s interpretation of Tenaska’s FCP. Ultimately, in a separate docket, FERC reaffirmed the Monitor’s right to protest FCPs. (See Another Win for PJM Monitor on Fuel-cost Policies.)

Collusion Concern

The Monitor reiterated its confidentiality concerns to FERC on Nov. 27, after the commission notified it of its intent to release documents in the proceeding.

“Release of such information could damage the efficient and competitive operation of PJM markets by facilitating tacit collusion and disseminating substandard fuel cost policy provisions,” the Monitor wrote. “The release of market sensitive information harms the public interest in maintaining competitive PJM wholesale power markets. That Tenaska Power Services Co. consents does not change the harm to the public interest. … In fact, Tenaska has a conflict of interest because it could benefit from the release of information that harms the public interest by weakening fuel-cost policy standards.”

December 18, 2019January 18, 2024

EIM Lands Xcel, Three Other Colorado Utilities

By Rich Heidorn Jr.

CAISO’s Western Energy Imbalance Market is expanding its footprint to Colorado. Xcel Energy, Black Hills Colorado Electric, Colorado Springs Utilities and Platte River Power Authority announced Tuesday they will join the EIM as soon as 2021.

Although the companies “have different business models, customers and geography,” they said in a press release, “all share a commitment to leading the clean energy transition and believe the WEIM will provide the most benefit to their collective Colorado customers.”

Three of the companies currently share resources and balance demand through a joint dispatch agreement, and the fourth, Colorado Springs Utilities, will join in March.

The news is further evidence of the momentum of the EIM and a disappointment for SPP, which had hoped to lure the utilities to its proposed Western Energy Imbalance Service (WEIS). The four utilities serve almost 2 million customers and reported $3.7 billion in sales in 2018.

The companies said that a Brattle Group study concluded that the EIM had more potential to lower production costs “due to the size of its market footprint and the diverse resources available.”

The companies said the EIM also offered lower administrative costs and noted its exploration of a day-ahead market, which they said will allow the integration of more renewables.

“We’re very excited with their announcement,” CAISO spokeswoman Vonette Fontaine said. “Utilities are recognizing the savings the EIM brings to its customers, along with their ability to integrate carbon-free resources.”

SPP spokesman Derek Wingfield said the announcement “confirms that wholesale electricity markets can benefit the Western Interconnection, and we’ll bring significant value to participants of our Western Energy Imbalance Service Market like we’ve done through our other markets for more than a decade already. We are on track to launch the WEIS in Feb. 2021, and a number of western utilities have already expressed interest in joining it. We’re confident the WEIS’s performance will prove its value in lowering the cost of wholesale electricity and enhancing reliability, and that our roster of market participants will continue to grow over the next several years.”

“This decision is an important next step in our efforts to keep our customers’ bills low and provide more 100% carbon-free energy like wind and solar,” said Alice Jackson, president of Xcel Energy Colorado, the state’s largest load-serving entity.

The companies said they will work to finalize their implementation agreement with the EIM over the next several months and have set a target of 2021 for joining the market.

The companies announced they were evaluating the EIM and WEIS in September, after the state enacted legislation requiring utilities to submit greenhouse gas-reduction plans and instructing state regulators to investigate the potential benefits of joining a regional energy market. (See Colorado Utilities Examine Market Membership.)

In April 2018, Xcel had pulled out of a plan for the Mountain West Transmission Group to join SPP, saying it wasn’t in its best interests. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

Xcel’s Public Service Company of Colorado had almost 1.5 million customers and $2.7 billion in revenue in 2018, according to the Energy Information Administration.

Colorado Springs has more than 231,000 customers, with Black Hills serving almost 97,000.

Platte River Power Authority provides wholesale electric generation and transmission to the utilities of Estes Park, Fort Collins, Longmont and Loveland, which have more than 162,000 customers.

CAISO says the EIM has saved its nine current participants $801 million since it launched in 2014. Nine other entities will join the EIM next year, with the Los Angeles Department of Water and Power following in 2021.

Hudson Sangree contributed to this article.