ERCOT Technical Advisory Committee Briefs

AUSTIN, Texas — Technical Advisory Committee Chair Randa Stephenson and Kenan Ögelman, ERCOT’s vice president of commercial operations, last week suggested a workshop to discuss how ERCOT and its market participants exchange data and handle changes to data reports.

Kenan Ogelman, VP Commercial Operations ERCOT - Technical Advisory Committee (TAC) — Ögelman *© RTO Insider*

Denton Municipal Electric’s Lance Cunningham raised the issue by noting that staff told the Market Data Working Group it was issuing a 30-day notice — as required by ERCOT’s protocols — to change an existing wind-projection data report. Cunningham said that change would require an estimated 30 person-hours to make changes to the muni’s systems.

Several stakeholders sided with Cunningham, pointing out modest software changes can cost tens of thousands of dollars.

“Multiply that cost by the number of [market participants] that have to do it, and you’re in the millions pretty quickly,” The Wind Coalition’s Walter Reid said. “We need to be aware of what we’re doing.”

“[ERCOT’s] ability to unilaterally change reports has been a concern of mine,” said Calpine’s Randy Jones, representing independent generators. “I realize there are passages in the protocols to provide data to ERCOT upon [its] request, but the time may be ripe for a discussion that we start putting criteria around that … and mitigate the huge impact it has.”

Ögelman, while noting the change will actually take place June 30, did agree with Cunningham that such changes create inconveniences.

“It can be burdensome to adjust to [changes],” he said. “Long term, do we need to start thinking about another way we exchange data, rather than people scraping it off a report? Right now, this is the only way certain people can get this data. I think it’s very important to consider whole systemwide impact of changes.”

“You need a report you can input and utilize,” said Sharyland Utilities’ B.J. Flowers. “Maybe you utilize the workshop as business-requirement gathering, and hand it over to the market data group to work on the details.”

Stephenson told stakeholders she is working with ERCOT to schedule the workshop.

NPRRs Approved, NOGRRs Tabled

TAC members approved five Nodal Protocol Revision Requests:

NPRR 741: Clarifications to estimated aggregate liability (EAL) and total potential exposure (TPE) credit exposure calculations.
NPRR 744: Reliability unit commitment trigger for the reliability deployment price adder and alignment with RUC settlement.
NPRR 745: Change emergency response system availability from an hourly to 15-minute interval evaluation, plus other minor changes.
NPRR 746: Adjustments due to negative load.
NPRR 748: Revisions associated with NERC reliability standard COM-002-4 and other clarifications associated with dispatch instructions.

Luminant’s Amanda Frazier, chair of the Protocol Revisions Subcommittee, said NPRR 744 exceeded ERCOT’s $100,000 impact-analysis threshold, but she noted staff filed comments that determined the ISO would have saved more than $9 million “over the last several months” if the revisions had been in place.

“We at PRS felt that was adequate justification for approving this process,” Frazier said.

The committee also tabled a Nodal Operating Guide Revision Request and an appeal of a second NOGRR:

NOGRR 151: Alignment with NPRR 748, revisions associated with COM-002-4 and other clarifications associated with dispatch instructions.
NOGRR 149 would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak is less than 25 MW. Jones expressed sympathy for the small municipalities most affected. “On the other hand,” he said, “it doesn’t seem to be fair to the market. Small entities are not carrying their obligations.”

Staff Share Reports, Updates

Staff shared the Emergency Response Service (ERS) report that is filed annually with the Public Utility Commission of Texas. ERCOT procures ERS three times during the year for four-month terms. Participants can provide the service for one or more of four time periods, which are designed to allow flexibility for customers during traditional business hours.

ERS expenditures are capped at $50 million. Staff said expenditures for last year were $48.8 million.

TAC also approved the Retail Market Subcommittee’s goals for 2016 and discussed staff updates on ERCOT’s debt strategy and changes to ERCOT’s antitrust admonition and guidelines.

ERCOT Treasurer Leslie Wiley shared feedback from her recent report to the Finance and Audit Committee. She said the ISO uses congestion revenue rights (CRRs) auction receipts — with a limit of $100 million — along with debt and revenue to fund its liquidity. Wiley said the committee encouraged her to use CRRs when available to fund long-term projects, but there are questions about how to pay for significant unbudgeted initiatives.

The ISO currently has an Aa3 credit rating. “We want to maintain that,” Wiley said.

ERCOT’s legal department is revising the antitrust guidelines to be a position statement. Nathan Bigbee, ERCOT’s senior corporate counsel, said there shouldn’t be any cause for concern, “as long as actions ERCOT takes fall within [its] authority under federal or state laws.”

April 4, 2016

FERC Extends Comment Period on Great Northern Agreements

By Amanda Durish Cook

FERC last week granted Missouri River Energy Services (MRES) an extension to comment on a series of “zonal agreements” submitted by ALLETE and Great River Energy to resolve revenue-sharing and cost recovery disputes (ER16-1107, et al.).

The commission extended the commenting deadline to April 5, a week short of MRES’ request but four days longer than what ALLETE and GRE were willing to concede.

The agreements would resolve the two companies’ disputes over revenue-sharing and cost recovery for transmission projects in MISO’s Minnesota Power (MP) pricing zone — including the proposed Great Northern Transmission Line linking the region with hydro resources in Manitoba.

ALLETE and GRE filed a joint answer urging the commission to disregard the protest by MRES, which contends the agreements were negotiated “outside of commission processes” and could be inconsistent with MISO’s Tariff.

“These complex, interrelated agreements proposed by the applicants as a black box settlement that implicitly cannot be ‘pried apart,’ present a challenge of analysis because of their complexity and lack of transparency,” MRES wrote in a March 24 filing.

“All of MRES’ claims are either procedurally improper or unfounded and should not delay the commission’s approval of the zonal agreements,” the two companies countered.

MRES’ concerns have less to do with the revenue-sharing portion of agreements than with their possible implications for transmission cost allocation within the MP pricing zone. Chief among of those concerns is whether ambiguous language in the settlement opens the door for ALLETE to eventually roll costs related to the 500-kV Great Northern line into its revenue requirement, a move MRES said should be prohibited under MISO’s Tariff because the project is participant-funded.

ALLETE and GRE counter that MRES is pursuing its concerns under the wrong proceeding — that the revenue-sharing methodology under the zonal agreements represents a separate issue from Great Northern’s cost allocation. The companies say MRES should raise allocation concerns under the Tariff’s Attachment O protocol, which deals with project cost recovery.

The two companies also defended the settlement process and its outcome, saying their agreements “worked within the context” of MISO’s Transmission Owner Agreement, which spells out how transmission revenue should be distributed in pricing zones with multiple transmission owners.

“MRES’ protest, at best, reflects a misunderstanding of the process used to negotiate the zonal agreements as well as such agreements’ fundamental purpose,” the companies said.

ALLETE and Great River insist that if they “had not resolved their differences, they would have been forced to litigate complex and fact-intensive issues” regarding MISO pricing zone boundaries, asset classification for cost allocation purposes and revenue sharing for select facilities and load within the MP pricing zone.

“This litigation likely would have taken years and resources away from all parties (including MISO and commission staff), who all may prefer to focus on other areas,” the companies said.

April 4, 2016

FERC OKs MISO Use of Eastern Standard Time in Day-Ahead Market

MISO’s day-ahead market schedules may continue to use Eastern Standard Time instead of Eastern Prevailing Time even as the RTO alters scheduling deadlines to comply with updated gas nomination cycles, FERC said (ER15-2256).

The commission last week ruled that MISO could persist in having its day-ahead market become effective at 12 a.m. EST, despite using EPT for other scheduling deadlines.

In a Jan. 19 compliance filing related to gas-electric coordination, MISO sought permission to continue using EST because “accommodating transitions to and from daylight saving time would require significant implementation costs to MISO and its market participants, while providing little, if any, quantifiable benefits.” MISO explained that moving to EPT would “divert resources and funding from higher priority initiatives.”

FERC agreed that MISO “sufficiently explained the discrepancy between its using EST for establishing when its day-ahead market schedules become effective and its using EPT for all other scheduling deadlines.”

The commission also approved MISO’s request to begin posting day-ahead market results by 1:30 p.m. EPT (12:30 p.m. CT), saying the new deadline provides natural gas-fired generators sufficient time to procure fuel and secure pipeline transportation ahead of the 1 p.m. CT timely nomination cycle. FERC additionally accepted a related MISO provision to move the day-ahead market trading and interchange scheduling deadlines to 10:30 a.m. EPT (9:30 a.m. CT) in order to meet the new posting time. (See FERC Orders MISO to Shift Electric Schedule.)

The schedule changes become effective Nov. 5 for the Nov. 6 operating day.

— Amanda Durish Cook

April 4, 2016

Stakeholders React to MISO Proposed Auction Design

By Amanda Durish Cook

A MISO proposal to hold a separate forward capacity procurement auction for deregulated areas is meeting with skepticism from some RTO members.

Dynegy's-Baldwin-Energy-Complex-in-IL MISO auction — Dynegy’s Baldwin Energy Complex in southern Illinois. Some generators in retail choice regions of MISO such as southern Illinois have exported their power to PJM, where capacity prices have been higher *Source: MISO*

MISO stakeholders raised their concerns at a March 28 Competitive Retail Solution Task Team discussion focusing on the Forward Local Requirements Auction (FLRA) proposed last month. (See MISO Proposes Adding Forward Auction for Retail Choice Zones.) The task team plans to turn the proposal over to the Resource Adequacy Subcommittee (RASC) this month.

Zone 4 an ‘Island’

Much attention was focused on the fully deregulated Zone 4 in southern Illinois — MISO’s only fully deregulated zone.

Aaron Patterson with The NorthBridge Group pointed out that Zone 4’s local clearing requirement of about 5 GW during the 2016/17 planning year would leave more than half the zone’s supply unused in a forward auction.

“What I’m wrestling with is — we have 10 to 11 GW of supply [in Zone 4] and sort of structurally only 5 GW” under the local clearing requirement, Patterson said. “The supply that doesn’t clear is getting a price signal that it’s not needed.”

Jeff Bladen, MISO executive director of market design, responded that leftover supply would be applied to the planning reserve margin requirement.

“A lack of a forward signal is not lack of a need,” Bladen said. “It is a lack of need for it to be a local resource.”

Others said the FLRA would make Zone 4 even more of an “island.”

Bladen said MISO would not introduce a new import constraint for the auction. Instead, the RTO plans to examine system-wide import capability. And while the grid operator does not intend to impose a minimum offer price rule, it would update its Tariff with a bright line reliability test for forward procurement.

Multiple stakeholders asked what data and forecasting methods MISO would use to calculate local clearing requirements three years into the future, questions that Bladen deferred to the April RASC. “We’ll need to discuss that with stakeholders in a little more detail,” he said.

Bladen also said the RASC could best address the concerns of stakeholders who think the FLRA will produce extremely low prices and want MISO to run simulations and present the results. Price formation is “something we’ve given extraordinary amounts of attention to,” he said.

“This might work for a partially deregulated zone, but this won’t work for a zone that’s been fully deregulated,” said Exelon’s Marka Shaw, who asked for another CRSTT meeting specifically focused on affected Illinois customers. “I don’t like the idea of this rolling into the RASC and this getting shortchanged given the tight timeline.”

David Sapper of Customized Energy Solutions wanted to know how generators could use the five-year FLRA opt-in to participate, but Bladen clarified that the opt-in applies only to load-serving entities, not generators.

In response to a question about how MISO’s new two-season construct would align with forward procurement, Bladen said seasonal constructs — currently scheduled to be enacted in the 2018/19 planning year — would apply to the FLRA as well.

“These filings are effectively being looked at in parallel,” Bladen said.

Jim Dauphinais, counsel for Illinois Industrial Energy Consumers, asked how the downward sloping demand curve would apply to market supply. Bladen stressed the curve is only applicable to the demand — not the supply — side of the auction.

“It is very feasible to have different purchase price sensitivities for different consumers, if you will, in the same market,” Bladen said.

March 31, 2016

UPDATED: FERC Action Awaited Following PUCO OK on PPAs

By Ted Caddell and Rich Heidorn Jr.

Having won Ohio regulators’ approval of their controversial power purchase agreements, American Electric Power and FirstEnergy now are hoping the PPAs will pass muster with FERC.

The Public Utilities Commission of Ohio on Thursday unanimously approved modified versions of two PPAs, which the companies said are crucial to keeping some of their underperforming plants running in the state (14-1297-EL-SSO and 14-1693-EL-RDR).

On Monday, AEP and FirstEnergy formally notified FERC of the approvals.

Competing merchant generators have asked FERC to revoke the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure a Section 205 review of the above-market deals (EL16-33, EL16-34). (See PJM Joins EPSA’s Call for FERC Review of Ohio PPAs.)

In addition, 11 generating companies, including Calpine, Dynegy and NRG Energy, asked FERC on March 21 to expand PJM’s minimum offer price rule to prevent state subsidized plants from making below-cost offers that would suppress capacity prices (EL16-49). (See Generators to FERC: Expand MOPR for Subsidized FE, AEP Plants.)

The companies have asked FERC to rule before PJM’s next Base Residual Auction, which begins May 11.

Since PUCO’s ruling, seven organizations, including the Pennsylvania Public Utility Commission, the PJM Power Providers Group and CPV Power Holdings, have filed to intervene in the cases. On Monday, FERC denied AEP and FirstEnergy’s request for more time to respond to the MOPR filing, leaving the April 11 comment deadline intact.

Sale Likely?

Guggenheim Securities analyst Shahriar Pourreza said in a research note Thursday that he expects AEP to sell the remaining 5 GW of generation not covered by the PPAs, “a path for the company to move toward a fully regulated business profile.”

“We estimate the sale could generate $1.9 [billion to] $2.3 billion, which we expect to be redeployed into transmission to offset lost earnings,” Pourreza wrote.

For FirstEnergy, Pourreza said, the PPAs will strengthen its balance sheet without requiring the issuance of additional equity. “We see FE as a turnaround story with the PPAs approved,” he wrote.

The analyst said FERC is unlikely to change PJM’s MOPR “to apply specifically to AEP and FE’s plants.” The MOPR plaintiffs have asked FERC to order PJM to develop a long-term solution by Nov. 1.

PUCO’s approval appears to have had little effect on Wall Street. AEP has risen just 53 cents (0.8%) from Thursday’s open, closing Monday night at $66.58. FirstEnergy has dropped 37 cents (1%), closing at $35.68.

‘Rate Stability’

In approving the eight-year PPAs, Ohio regulators said they were striving for “rate stability” by building in safeguards intended to protect consumers, modifying the plans to limit bill increases. The commission also added provisions meant to “encourage” grid modernization and retail competition.

“The commission’s order strikes an appropriate balance between consumers’ interests in cost-effective electric service and diverse stakeholder interests,” Chairman Andre Porter said. “Today’s opinion and order affirms Ohio’s commitment to encourage a modernized grid and retail competition.”

Although the PPAs guarantee the generators receive revenue streams above current market prices, AEP and FirstEnergy contend the deals will save customers money if natural gas prices increase.

“The Public Utilities Commission of Ohio recognized the significant benefits of this plan for Ohio consumers. This plan will ensure more stable electricity prices in Ohio and promote the development of new, renewable generation to support the state’s economy,” AEP CEO Nick Akins said in a statement.

“Today’s decision will help protect our customers against rising electric prices and volatility in the years ahead, while helping to preserve vital baseload power plants that serve Ohio customers and provide thousands of family-sustaining jobs in the state,” FirstEnergy CEO Charles E. Jones said in a statement.

Opponents Denounce PUCO Ruling

Opponents of the plan were quick to respond to the decision.

“Today the PUCO failed more than 100,000 Ohioans who opposed the multi-billion dollar FirstEnergy and American Electric Power bailouts,” said Rachael Belz, executive director of Ohio Citizen Action. “Ohioans don’t want utilities raiding their pockets to prop up 18th-century technology in a 21st-century world.”

“The Alliance for Energy Choice is dismayed that the PUCO did not reject outright FirstEnergy’s and AEP’s demands to force consumers to pay unnecessary, additional electric charges of at least $6 billion over eight years,” the competitive energy supplier group said in a prepared statement.

“Anything short of rejection damages markets and competition,” tweeted former Pennsylvania PUC Commissioner John Hanger, now a private energy industry attorney. “Good for crony capitalism.”

Rate Freeze

The two utilities sought the long-term PPAs to provide guaranteed income for plants facing competition from cheaper gas-burning plants. Both companies had earlier reached settlements with PUCO’s staff and others, leading to Thursday’s rulings by the commission.

AEP’s plan calls for guaranteed income for the company’s 2,671-MW ownership share of nine plants, as well as a 423-MW contractual share of Ohio Valley Electric’s generating fleet, until May 2024.

FirstEnergy’s agreement provides similar guarantees for its 908-MW Davis-Besse Nuclear Power Station, the 2.2-GW W.H. Sammis coal-fired plant and the company’s 105-MW share of Ohio Valley Electric’s generation.

In both cases, ratepayers would make the generating units whole if capacity and energy sales in the competitive market were not sufficiently profitable. While the companies testified that the market would eventually prove profitable for their plants, the Ohio Consumers’ Counsel said the plans left consumers open to excess costs that could top $8 billion over the life of the deals.

“FirstEnergy’s Ohio utilities expect to file new rates with the PUCO by May 2, following the completion of a competitive auction process to buy electric generation supply for their non-shopping customers,” FirstEnergy said in a press release. “FirstEnergy expects that the vast majority of its Ohio utility customers will see lower total bills after these auctions.”

But Todd Snitchler, former PUCO chairman and now with The Alliance for Energy Choice, said FirstEnergy’s claim of static or lower bills is disingenuous.

“It’s not out of the goodness of their hearts,” he scoffed. “It’s because that’s what the commission said.”

PUCO’s order freezes FirstEnergy’s base distribution rates during the PPA and ensures that average customer bills will not increase for the first two years.

PUCO’s order on AEP limits rate increases to 5% during the first two years of the PPA. The company also promised $100 million in rate credits to reduce increases during the final four years.

Both companies originally requested 15-year PPAs, but they scaled back those requests in the face of opposition from consumer advocates and other merchant generators. The companies worked behind the scenes to construct settlements with some of the opposition, adding environmental incentives and consumer protections in exchange for their approval.

AEP won over the Sierra Club with a promise to double the state’s wind generation and nearly quintuple its solar capacity — translating into 900 MW of new renewable energy.

Criticism from All Sides

Critics see the agreements as an attempt at re-regulation in a deregulated Ohio electricity market, coming after the generating companies were already provided stranded cost compensation to give up their monopolies. FirstEnergy, for instance, was compensated for $6.9 billion in stranded costs in 1999.

But the companies say that times have changed and that the PPAs are crucial for keeping the plants operating and Ohioans employed.

The companies’ proposals were immediately met with protests from environmentalists, ratepayer advocates and rival generators in PJM, with Dynegy and Talen Energy threatening litigation to block the agreements. (See Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement.)

Even Exelon, which is seeking a similar deal for its own nuclear stations in Illinois, came out against FirstEnergy, and upped the ante by offering its own offer to Ohio. It called on PUCO to reject the FirstEnergy plan as “grossly lopsided” and offered to supply the 3,000 MW covered in the PPA with its own generation, at a proposed $2 billion savings to Ohio consumers.

March 29, 2016

Maryland PSC Member Scrutinized over Contacts with Governor

By Rich Heidorn Jr.

A newly appointed member of the Maryland Public Service Commission insisted Monday there was nothing improper about his emails with Gov. Larry Hogan’s administration, communications that critics say raise questions about his independence.

Richard Source: Maryland PSC — Richard *Source: Maryland PSC*

Hogan named Michael T. Richard, his former deputy chief of staff, to the PSC in a recess appointment in late January. Richard, a former director of the Maryland Energy Administration (MEA), is seeking Senate confirmation to a full term.

Shortly after his appointment, according to emails obtained through a public records request, Richard shared non-public information with Hogan’s administration regarding an offshore wind application and discussed strategy with the governor’s office on energy efficiency and community solar programs.

The emails were obtained by Public Citizen and the Energy and Policy Institute, which said the records showed Richard had engaged in improper ex parte communications and should not be confirmed.

At a hearing of the Senate Executive Nominations Committee on Monday night, Chairman Jamie Raskin expressed concern that Richard was “coordinating strategy” with Hogan’s administration.

Richard said his communications were merely an effort to brief members of the governor’s office on energy issues they were taking over from the “portfolio” he held before his PSC appointment. Richard did offer a mea culpa. “I am sorry that I created a doubt about my independence,” he said.

After an hour of questioning, Raskin adjourned without calling for a vote on the nominee, saying he would schedule another meeting next week.

Offshore Wind Application

On Jan. 29, Richard sent Hogan’s director of policy, Adam Dubitsky, an email regarding an application for offshore wind renewable energy credits (OREC). “This is NOT yet public information, but I wanted you to be aware,” he wrote.

Dubitsky responded by asking whether the filing preempts “our taking action to protect ratepayers from a potentially $1.7B rate increase as indicated in OREC’s fiscal note?”

Richard had been informed of the application in an email from an advisor to PSC Chair Kevin Hughes. The email noted that the application is supposed to be confidential during a 30-day internal administrative review and a 180-day period in which other developers can apply for the credits.

“It was designed this way because the application window is supposed to be equivalent to a closed bid process,” the advisor wrote.

At the hearing Monday, however, Richard said the information was not confidential and that PSC General Counsel Robert Irwin had approved his communication. “It was discoverable. It was available,” he said.

EmPower Maryland

A second communication that concerned some committee members came on Feb. 11, when Richard sent Mary Beth Tung, deputy secretary of the state Department of the Environment, an email discussing the administration’s position in upcoming hearings on the EmPower Maryland energy efficiency program.

The governor’s office is a party to the EmPower hearings through the MEA. The agency intervened in PSC dockets involving the program, noting that the state’s utilities are required to consult with the agency regarding the “design and adequacy” of their plans to achieve the electricity savings and demand reduction targets set by the 2008 legislation creating the program. The act requires that the PSC consider MEA’s comments on the utilities plans.

Richard wrote Tung regarding hearings scheduled for May to review the utilities’ performance in the second half of 2015.

“This will begin our first potential opportunity to begin putting our imprint on this significant energy tax policy,” Richard wrote. “This will be a significant and very public PSC action, so early governor’s office direction, planning and executive [branch] coordination on related policies will be important.”

Richard also offered Tung “policy advice” on the state community solar program, suggesting a shift from “grant-based” to “financing-based” energy efficiency and renewable energy incentive programs.

Business as Usual?

Like Hogan, Richard is a Republican. The Senate is controlled by Democrats.

Republicans on the committee said Richard’s communications were similar to those Hughes and then-Commissioner Kelly Speakes-Backman had in 2012 with the administration of former Gov. Martin O’Malley, a Democrat. Hughes was O’Malley’s deputy legislative officer before joining the commission.

“We’re beating a dead horse,” said Republican Sen. George Edwards.

But Democratic Sen. James Brochin told Richard the communications created “a reasonable question of who’s team you’re on.”

“I can assure you that I understand very well what it means to be a Public Service Commissioner and that it demands independence,” Richard responded.

March 28, 2016

MISO Markets Committee of the Board of Directors Briefs

NEW ORLEANS — MISO energy prices declined this winter along with loads and natural gas costs in the face of above-normal temperatures, RTO staff said during a March 22 Board of Directors meeting.

Real-time prices in the MISO footprint averaged $21.80/MWh, down 13% from the prior quarter and 29% from the same period a year ago. Average system-wide load fell 2.7% compared with last winter, with seasonal load peaking at 98.2 GW on Jan. 19, well below January 2014’s all-time winter peak of 109.3 GW.

“Part of the ease in making our way through the winter was the relatively mild temperature conditions,” said Jeff Bladen, MISO’s executive director of market design.

Bladen said the higher temperatures and historically low gas prices also reduced revenue sufficiency guarantee payments to “some of the lowest market uplift charges since 2012.” Uplift charges averaged $0.09/MWh, down from $0.23/MWh last winter and $0.46/MWh in 2014.

Natural gas costs should stay low in the near term, said Michael Wander, of MISO Independent Market Monitor Potomac Economics. Prices at both the Chicago City Gate and Henry Hub ended February under $2/MMBtu.

Other winter highlights:

MISO set an all-time wind output record of 13.1 GW on Feb. 19, surpassing the previous peak of 12.7 GW set a month earlier. For an hour, more than one-fifth of MISO’s power came from wind resources.
Coal generated 47.7% of electric production, down 25% since 2014. Most retired coal generation has been replaced by gas.

MISO board member Michael Curran said he wanted a review of MISO’s metrics, as so many “boil down to a dollar amount.” He worried that low gas prices could be “masking” uneconomic activity.

MISO Prepped for Summer Demand

MISO Markets Committee of the BoD — At the meeting *© RTO Insider*

MISO officials are concerned about tightening reserve margins despite a preliminary assessment showing that the RTO is comfortably positioned to meet demand this summer.

MISO is projecting an 18.2% reserve margin this summer, exceeding the 15.2% requirement and a slight increase from last year’s 18% margin.

Available supply, however, dropped to 149 GW from 150.3 GW.

MISO CEO John Bear said declining demand contributed to this year’s slightly higher reserve margin. He added that retirements driven by EPA’s Mercury and Air Toxics Standards were on par with the RTO’s predictions.

A final summer analysis will be presented at MISO’s Summer Readiness Workshop in May.

– Amanda Durish Cook

March 28, 2016

CAISO Seeks Rapid Response to SoCal Gas Restrictions

By Robert Mullin

CAISO has kicked off an “expedited” stakeholder process to help Southern California’s gas-fired generators mitigate the financial impact of proposed pipeline restrictions stemming from the closure of the Aliso Canyon gas storage facility.

The initiative seeks to identify what measures the ISO can implement to allow those generators to recover — or avoid — penalties for violating new daily balancing requirements that SoCalGas has proposed for the region’s pipeline system.

Under the requirements, any customer whose daily gas burn deviates from nominated pipeline flows by more than 5% would face per-unit penalties as high as 150% of daily gas indices. Generators say those penalty costs would put them out of the money in instances when the grid operator’s dispatch instructions force their units to burn more or less gas than scheduled.

Leak Forced Closure

SoCalGas and San Diego Gas & Electric asked state regulators to approve the requirements ahead of summer to support reliable gas delivery during the region’s peak season for electricity consumption. SoCalGas said it needs more precise scheduling to ensure proper pipeline pressure without the ability to backfill from Aliso Canyon.

The storage facility north of Los Angeles was closed following a leak that spewed massive amounts of methane between October and February.

Aliso Canyon Relief Well Source: SoCalGas (CAISO, gas restrictions) — Aliso Canyon Relief Well *Source: SoCalGas*

The new requirements are expected to take effect May 1, pending approval by the California Public Utilities Commission. That makes a rapid response essential for CAISO’s most exposed market participants, who worry about the costs they will incur in the period between that date and the implementation of any necessary ISO market mechanisms.

“The gap [in time] could be disastrous for us,” said NRG Energy Director of Market Affairs Brian Theaker during a March 23 teleconference to discuss CAISO’s response. “We’re very concerned about our exposure in that gap.”

For its part, CAISO supports the tighter balancing requirements as a way to prevent last-minute gas curtailments to generators called on to respond to unpredictable summer cooling loads.

“Depending on the scope of curtailment, the ISO’s ability to redispatch might be hindered,” said Mark Rothleder, CAISO vice president of market quality and renewable integration.

But CAISO also recognizes the reliability risks that come with the balancing penalties, which could deter some gas-fired units from committing to the short-term market when most needed.

“When it comes to commitment, that’s where we see the disconnect,” said Erik Johnson, principal energy trader with the city of Pasadena. “It’s not the hardest thing to figure out when a unit is going to be out of compliance with SoCalGas.”

Better Gas-Electric Coordination

CAISO is taking a twofold strategy in response, considering both ways to prevent pipeline penalties and revised rules to allow generators to recover the fines. Cathleen Colbert, CAISO senior market design and regulatory policy developer, said any solutions will be “interim” — lasting until Aliso Canyon reopens.

The first approach would seek to prevent pipeline penalties through improved coordination of ISO market instructions with gas balancing requirements. That could entail posting a “two-day-ahead” forecast to inform gas procurements as early as possible or moving the day-ahead market to earlier in the day in advance of the timely gas nomination cycle, when supplies are most liquid.

Market participants are skeptical about the effectiveness of those measures.

“The idea of doing a two-day-ahead forecast is appealing,” said NRG’s Theaker. “But in summer, when loads can get blown pretty high, that could leave you exposed.”

Generator participants also point out that earlier gas procurements — even in the day-ahead cycle — would incur additional costs that might not be recovered under current market rules.

“Does the ISO understand that Intra-day Cycle 3 [day-ahead evening gas procurement] requires storage?” said Pasadena’s Johnson. “We have the ability to procure for day-ahead, but we’ll be paying a premium.”

Johnson also noted that, under the new balancing requirements, it will be impossible to economically cover last-minute gas needs in light of a CAISO Tariff provision that caps gas cost recovery at 125% of daily gas indices.

“Get into the second half of tomorrow [real-time], and it’s going to be impossible to get gas,” Johnson said. “Any dispatch you force on us is going to put us outside the 5%. The 125% [cost cap] doesn’t give enough room.”

David Francis, vice president of West power for EDF, said it is difficult to obtain gas close to real-time operation, a potential strategy to avoid incurring overscheduling penalties. “The amount of volumes that are traded in the cycles after the daily are fairly limited,” he said. “It becomes more challenging to get more [gas] into the [Los Angeles] basin as you get into the cycle.”

Market Changes on the Table

CAISO’s second approach to the new requirements would require revising market rules, both to make dispatch more predictable and to allow generators to recover the cost of the penalties after the fact. Among the multiple options CAISO is putting on the table for stakeholder consideration:

Enforcing day-ahead commitments for all resource types as binding in the real-time market;
Constraining dispatch decisions around day-ahead market schedules;
Limiting real-time market instructions to exceptional dispatches (manually issued orders used when reliability requirements cannot be resolved through market software); and
Allowing resources to request outages to manage their fuel constraints.

Market-based solutions include allowing energy bids to reflect intraday gas prices and including the gas balancing penalties in bid cost estimates, both of which would likely require Tariff revisions. CAISO said it could ask FERC for a waiver of 50-day notice to expedite any such changes.

“Including these costs in the market optimization is great,” said NRG’s Theaker. “Not just including it in the market, but allowing generators to recover it [after the fact].”

Pasadena’s Johnson concurred: “After-the-fact recovery through [bid cost recovery] resettlement sounds more appropriate.”

Whatever the solutions, CAISO has set an ambitious schedule to arrive at an outcome. The ISO plans to issue a straw proposal on the subject April 1, with a draft final proposal scheduled for April 15. Final stakeholder written comments are due April 29. But even that aggressive timeframe is causing some discomfort among market participants.

“At the risk of stating the obvious, SoCalGas has asked for the daily balancing to be implemented May 1, and the stakeholder process runs right up to that,” Theaker said. “What does CAISO plan to do?”

“This timeline could be compressed even further,” said CAISO’s Colbert.

March 28, 2016

DOE Agrees to Join Clean Line’s Plains Eastern Project

By Tom Kleckner

The dream of transporting wind energy east from the Great Plains took a major step toward reality Friday with the U.S. Department of Energy’s approval of Clean Line Energy Partners’ Plains & Eastern project.

The Energy Department issued a record of decision, saying it would “participate in the development” of the 700-mile, HVDC transmission project and designated a preferred route through Oklahoma and Arkansas. The decision caps nearly six years of study and evaluation by the department.

Clean Line says the $2.5 billion, privately funded project will deliver 4,000 MW of wind power — enough to power more than 1 million homes — from the Oklahoma Panhandle through Arkansas to the Mississippi River. The Plains & Eastern line would interconnect with the Tennessee Valley Authority near Memphis after first dropping off 500 MW at a converter station in central Arkansas.

DOE: Need for Transmission

The Energy Department said development of the panhandle’s “consistent and lowest-cost [wind resources] in the nation” has been constrained by a lack of “cost-effective transmission capacity to major load centers.”

“The project would, therefore, unlock the potential for significant new development of wind energy and deliver that energy to a region of the United States that has seen relatively scarce wind development,” the department said. “By increasing the availability of renewable energy from the Panhandle region across a wide geographic area, the project will facilitate market competition that will ultimately benefit consumers and the renewable energy industry as a whole.”

Clean Line President Michael Skelly welcomed DOE’s participation. “The Department of Energy’s decision shows that great things are happening in America today,” he said, calling Plains & Eastern the “largest clean-energy infrastructure project in the nation.”

DOE RFP

Clean Line proposed the project in response to the Energy Department’s 2010 request for proposals for transmission projects under Section 1222 of the Energy Policy Act of 2005, which authorizes the department to participate in “designing, developing, constructing, operating, maintaining or owning” new transmission.

With major regulatory approvals in hand, Clean Line says construction can begin in 2017.

The department’s involvement could help Clean Line in acquiring the right of way for the line, although it said the company will need to demonstrate the commercial viability of the project by executing “significant” firm transmission service agreements before obtaining land through eminent domain. It will also need to complete technical studies required by SPP, MISO and TVA.

Clean Line says the project “will support thousands of jobs in Oklahoma, Arkansas and Tennessee, including hundreds of manufacturing jobs.” Clean Line has a $300 million contract with Pelco Structural, of Oklahoma, to build the project’s tubular steel transmission towers and has selected three Arkansas companies to build related infrastructure such as transmission conductors and glass insulators.

The American Wind Energy Association said the project will “create the opportunity” for $7 billion in new wind farm development. “The project supports economic opportunity, often in rural areas that need it most, and potential energy bill savings for Americans,” said AWEA CEO Tom Kiernan. “Over 99% of all installed utility-scale wind capacity is located in rural areas.”

Opposition to Project

As a condition for its approval, the department required Clean Line use environmental-protection measures during the development, construction and operation of the project “to minimize impacts to landowners and the environment.”

Still, the project has drawn opposition from landowners and political figures. (See DOE Issues Favorable EIS on Plains & Eastern Project and Plains & Eastern Tx Line Foes Cry Foul over DOE Review.)

The Arkansas congressional delegation issued a statement lamenting the Energy Department’s involvement. “Today marks a new page in an era of unprecedented executive overreach, as the Department of Energy seeks to usurp the will of Arkansans and form a partnership with a private company — the same private company previously denied rights to operate in our state by the Arkansas Public Service Commission,” the legislators said. “Despite years of pushback on the local level and continuous communications between our delegation and Secretary [Ernest] Moniz, DOE has decided to forgo the will of the Natural State and take over the historic ability of state-level transmission control through this announcement.”

Although Clean Line won public utility status in Oklahoma and Tennessee, its request was rejected by Arkansas. “They couldn’t find a way to regulate [an] interstate transmission provider,” Clean Line General Counsel Cary Kottler said in an interview. The department’s imprimatur allows the company to overcome that hurdle, he said.

The department will participate in the project through the Southwestern Power Administration, a federal agency that markets hydroelectric power from 24 dams in six states.

It will not make any financial contribution. Instead, Clean Line will pay any Energy Department costs in advance, as spelled out in a participation agreement that also obligates the developer to contribute 2% of its revenues to federal hydropower-infrastructure improvements.

March 28, 2016

Generators to FERC: Expand MOPR for Subsidized FE, AEP Plants

By Suzanne Herel

Eleven generating companies, including Calpine, Dynegy and NRG, have asked FERC to expand PJM’s minimum offer price rule in time for May’s 2019/20 Base Residual Auction, as the Public Utilities Commission of Ohio is poised to rule on power purchase agreements for FirstEnergy and American Electric Power.

ohio ppas — Sammis power plant *Source: Chris Dilts via Creative Commons*

“Complainants respectfully request that the commission expand the MOPR to prevent the artificial suppression of prices in the Reliability Pricing Model (RPM) market by below-cost offers for existing resources whose continued operation is being subsidized by state-approved out-of-market payments,” the companies said (EL16-49).

The companies also voiced support for related complaints asking FERC to void the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure commission review of the proposed eight-year agreements, which are supported by PUCO staff. The Ohio commission is expected to rule on the requests in the coming weeks. (See PJM Joins EPSA’s Call for FERC Review of Ohio PPAs.)

Similarly, the complainants have asked that FERC address the waiver issue in time for the May BRA.

Currently, the MOPR applies only to certain new resources.

Recently, the generators argue, “a new threat has emerged in the form of subsidies to existing resources that create incentives for noncompetitive offers and that may prevent the exit of uneconomic resources.”

The proposals from AEP and FE would have “just that effect with respect to over 6 GW of capacity in PJM,” they said.

The companies said they recognized that PJM stakeholders have not had a chance to discuss changes to the MOPR and that Tariff revisions addressing the upcoming BRA might not be an appropriate permanent remedy. Therefore, they are requesting narrowly tailored revisions and a directive to PJM to develop a long-term solution by Nov. 1.

Regardless of whether the PPAs are approved, PJM should initiate a stakeholder process to expand the MOPR, the generators said.

The companies invoked testimony to PUCO by Independent Market Monitor Joe Bowring saying the PPA proposals “highlight the fact that the MOPR needs to be expanded to address all cases where subsidies create an incentive to offer capacity into the PJM capacity market at less than an unsubsidized, competitive offer. This would include offers from all new and existing units that receive subsidies.”

Other parties to the filing are Eastern Generation, Homer City Generation, Carroll County Energy, C.P. Crane, the Essential Power PJM Companies, GDF SUEZ Energy Marketing, Oregon Clean Energy and Panda Power Generation Infrastructure Fund.