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December 9, 2025

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Transmission, REV Dominate NYISO’s Landscape

By William Opalka

Bradley Jones, who stepped in as CEO of NYISO late last year, recently told RTO Insider that his three top initiatives “have always been transmission, transmission, transmission.”

He came to the right place. Transmission upgrades dominated activity in the NYISO footprint in 2015 and promise to occupy headlines in 2016.

The improvements are occurring amid a changing energy landscape. State officials and regulators are deciding how to handle aging and unprofitable power plants in western New York. Meanwhile, the Reforming the Energy Vision initiative seeks to encourage the growth of distributed and renewable resources throughout the state.

The New York Public Service Commission last month declared a public policy need for an expected $1.2 billion in upgrades to move 1,000 MW of power from upstate generation sites to load centers in and around New York City. The project has been discussed for more than three years; now, NYISO will seek bids on the projects. The PSC hopes to evaluate siting proposals by the end of the year, with approvals anticipated in 2017. The upgrades are expected to be in service in 2019. (See NYPSC Declares Public Policy Need; Directs NYISO to Seek Tx Bids.)

Future of Nuclear Uncertain

Will the transmission projects come too late to save aging and unprofitable nuclear and coal-fired power plants in the western part of the state? Or, as environmental and consumer advocates might ask: Are those plants even worth saving?

In his State of the State address on Jan. 13, Gov. Andrew Cuomo is expected to announce details of a plan to shift the state to 50% renewable energy by 2030, along with a strategy to keep the nuclear plants open until then by offering some financial recognition of their carbon-free emissions. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

Nevertheless, Entergy is standing by its decision to close the James A. FitzPatrick nuclear plant on Lake Ontario in late 2016 or 2017.

Exelon and stakeholders are finalizing a reliability support service agreement for the R.E. Ginna nuclear plant that would run through March 2017 — after which, the company says, the plant is likely to retire. The PSC has extended the negotiating window for that deal to Feb. 29. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)

At the same time, the state’s REV proceeding is continuing with development of demonstration projects, including microgrids and energy efficiency programs.

Much attention will be paid to the anticipated Track 2 Order that addresses rate design for the new business models. (See NYPSC Outlines Reforming the Energy Vision Changes.)

RMRs Winding Down

In the meantime, several reliability-must-run agreements that pay unprofitable plants above-market rates are starting to wind down. Some of the facilities hope to repower with natural gas, proposals that will be addressed by regulators this year.

One of these, the coal-fired Dunkirk station outside of Buffalo, was mothballed Dec. 31, when its RSSA expired. Owner NRG Energy has suspended the repowering plan pending resolution of a lawsuit filed by Entergy. (See NRG Plant Closures Could Impact Reliability in NY.)

The 312-MW Cayuga coal-fired plant outside of Ithaca is operating under an RSSA through mid-2017. Although its owner has proposed converting it to natural gas, a transmission project proposed by a distribution utility and endorsed by environmentalists could make the plant unnecessary.

Plans to convert the idled Greenidge power plant on Seneca Lake to gas are on hold as EPA has said it must undergo a “new source” review.

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SPP, ERCOT Set New Wind Peaks

SPP, which has already set six wind peaks this fall, established another on Dec. 19 with 9,948 MW, the second time it has eclipsed 9,000 MW. The RTO said wind’s penetration level was 33.5%, off the record 38.3% set Nov. 4.

ERCOT closed out 2015 with its eighth wind peak of the year, a record 13,883 MW on Dec. 20, representing more than 93% of its installed wind capacity and 44.7% of load served.

The wind generation easily topped the previous peak set Dec. 19, when the ISO exceeded 13,000 MW for the first time with 13,029 MW.

ERCOT generated almost 4.4 million MWh of wind energy in November, accounting for 18.4% of energy used.

— Tom Kleckner

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A Few Growing Pains for SPP as it Celebrates 75 Years

By Tom Kleckner

During the past two years, SPP has added new markets for its members, some 5,000 MW of peak demand and 7,600 MW of generating capacity in the Upper Great Plains, extending its footprint to the Canadian border in the process.

So what does it plan for an encore in 2016?

Celebrating its 75th anniversary, for one. SPP will mark the occasion this fall with several ceremonies and a commemorative publication chronicling the RTO’s history, which began in the days after the attack on Pearl Harbor.

That’s when 11 regional power companies in the Southwest — including predecessors of today’s SPP member companies — signed an agreement to pool their energy resources and ensure Central Arkansas’ aluminum production could maintain 24/7 operations. When World War II ended, an executive committee decided to continue the organization to maintain reliability and coordination.

From those modest beginnings, SPP has grown into a sprawling member-driven organization, coordinating electricity flows over 56,000 miles of high-voltage transmission lines across 575,000 square miles in all or parts of 14 states, from the Deep South to the Dakotas and westward. It counts 97 members representing cooperatives, power producers, marketers and independent transmission companies along with the usual transmission owners, and has 170 registered participants in its markets.

A ‘Success Metric’

SPP’s growth has been good news for its members.

The RTO projects the addition of the Integrated System (IS) last October will yield $334 million in member benefits over a 10-year period. It also has said the Integrated Marketplace — comprising day-ahead, real-time balancing and congestion-hedging markets — generated approximately $210 million in total regional net savings in its first year, in addition to $170 million in savings from SPP’s previous energy imbalance service market. SPP plans to release a study quantifying the transmission benefits its members receive in January.

“It’s been another interesting year for the corporation and our members,” SPP CEO Nick Brown said during October’s board meeting. “If ever there’s a success metric, it’s the members who have decreased costs or rates.”

SPP will focus much of this year on improving its rapidly maturing markets with three projects: enhanced combined cycle (ECC) logic, gas-electric “harmonization” and the Z2 crediting tool.

Improved Economic Dispatch

The ECC project is designed to provide more sophisticated modeling that captures the flexibility of combined cycle plants. Each combined cycle configuration will be modeled in the market-clearing engine as a separate resource.

SPP expects the increased flexibility to allow “optimization of the combined cycle resource configuration throughout the unit commitment processes,” projecting in its 2016 budget a $3 million to $5 million reduction in generation costs. The savings are expected to grow as new combined cycle plants join SPP in the future.

SPP has targeted March 2017 for completion of the $1.5 million project. (See “Enhanced Combined-Cycle Project Moves Forward” in SPP Board of Directors/Members Committee Briefs.)

The ECC work will be done in conjunction with system changes needed to close the Integrated Marketplace’s day-ahead market earlier and shorten the solution time for posting results by 30 minutes. Both have significant impacts on the market operating system’s solution time.

SPP said the gas-electric harmonization work will be completed by the fall, at a projected cost of $6.2 million.

The initiative is a result of FERC Order 809, which moved the timely nomination cycle deadline for gas from 11:30 a.m. CT to 1 p.m. (See “Board Approves Gas-Electric Timeline Change” in SPP BoD/Members Committee Briefs.)

SPP says the schedule changes are “an incremental improvement over the existing timeline.”

Years of Incorrect Credits

The Z2 crediting project dates back to the last decade as a result of years of incorrect credits for transmission upgrades. (See “Z2 Crediting Task Force Remains on Track” in SPP Markets and Operations Policy Committee Briefs.)

A project team is developing software that will properly credit and bill transmission customers for system upgrades under SPP’s Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.

The task force has estimated creditable upgrades of $750 million, with up to $90 million in transmission customer improvements and the remainder from sponsored upgrades.

The task force hopes to present a better estimate during the Markets and Operations Policy Committee and Board of Directors/Members Committee quarterly meetings in January.

SPP says the new system should reduce errors, disputes and resettlements.

Eyes on Expanded Footprint

SPP’s day-to-day business in 2016 will remain focused on maximizing the addition of the IS to its footprint.

The IS tripled SPP’s hydroelectric capacity, which represented only 1.1% of the RTO’s capacity in 2014. It also added winter-peaking regions, increased seams coordination issues and greatly expanded the geographic area for SPP’s reliability monitoring function.

SPP says the addition of the IS has “opened opportunities to expand SPP’s services to affiliated entities in the Western Interconnect” through membership or contracted services. SPP has an ongoing market-consulting contract with the Northwest Power Pool, which has been exploring the possibility of opening an energy market for several years.

Because of the surge in wind production, the RTO will refresh its 2009 wind-penetration study in February.

Navigating the Clean Power Plan

SPP will continue its work helping states comply with EPA’s Clean Power Plan. The RTO expects “significant impacts in the near term and well into the future.”

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone. Several SPP states have joined litigation to block the rule.

“The lawsuits will muddy the water in terms of how SPP interacts with its stakeholders as they work to comply with the standards,” it said.

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone.

The RTO will include CPP compliance in the 2017 Integrated Transmission Planning 10-year assessment. A near-term transmission study also will be conducted this year, with the results presented to MOPC and the board in April.

At that time, MOPC and the board should be taking up for consideration SPP’s first Order 1000 project, the 21-mile, Walkemeyer-North Liberal 115-kV project in Kansas. An industry expert panel is currently evaluating responses to SPP’s request for proposals.

SPP expects to receive 3,200 proposals for competitive projects in 2016, double the number it saw in 2014.

It also expects a “significant increase” in generation interconnection studies. SPP projects a 12% bump in transmission volume to more than 407 MWh in 2016.

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FERC Again Rebuffs Brayton Point Union

FERC on Wednesday denied rehearing of its June decision certifying the ninth Forward Capacity Auction results in ISO-NE, dealing another blow to a utility union’s claim that supply of the Brayton Point plant was illegally withheld to raise prices (EL15-1137).

The Utility Workers Union of America, which represents workers at the Massachusetts plant, in July asked FERC to void the auction results. (See Fourth Time the Charm? Brayton Point Union Again Challenges ISO-NE Auction.)

Energy Capital Partners, former owner of the 1,517-MW plant, did not offer it in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.

FERC previously rejected the union’s challenge to results of FCA 8 on similar grounds. FERC said a non-public investigation by its Office of Enforcement failed to uncover any evidence of wrongdoing.

“This conclusion remains valid for FCA 9,” FERC wrote.

The commission also reiterated its acceptance of the conclusion of ISO-NE’s Internal Market Monitor that no anti-competitive behavior existed before the auction.

FERC also rejected the union’s contention that the ISO-NE Tariff requires a determination that a unit is uneconomic before it is allowed to retire.

“The Tariff contains no provision requiring a resource to demonstrate that it is uneconomic before it is allowed to retire, and UWUA does not point to any such provision. There is no test as to whether the unit can economically provide capacity, nor is there a mechanism by which ISO-NE can compel the resource to continue operating under any circumstances,” the commission wrote.

— William Opalka

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FERC Accepts Order 1000 Compliance Filing

FERC has accepted NYISO’s fourth Order 1000 compliance filing, turning aside the protests of transmission developers that claimed it unfairly favored incumbent transmission owners (ER13-102-007).

LS Power and NextEra had protested the ISO’s right to terminate development agreements if a force majeure event prevents a non-incumbent developer from completing its project by the in-service date. (See Tx Developers Challenge NYISO, SPP, ISO-NE Order 1000 Filings.)

NYISO and the New York Transmission Owners submitted their fourth Order 1000 compliance filing in May. It included a pro forma development agreement for NYISO’s reliability transmission planning process.

“NYISO argues that it must have the option to terminate the development agreement and identify alternative means of satisfying an identified reliability need if a developer cannot complete its project by the required project in-service date,” FERC wrote on Dec. 23.

The commission cited a similar provision at PJM, ordering NYISO to add comparable language in its development agreements with incumbent transmission owners to prevent discrimination.

In a second order Dec. 23, FERC rejected a NYISO filing that the commission said was unfair to competitive transmission developers (ER15-2059).

FERC said the proposal “subject[s] nonincumbent transmission developers to an interconnection process with different requirements than the interconnection process that applies to incumbent transmission owners.” While all interconnection customers are required to obtain system impact and facility studies, the nonincumbents were required under the proposal to additionally submit a feasibility study and deposits for all three studies.

NYISO had argued the incumbent would have already conducted a feasibility study in its normal planning process, but FERC said that would create two different processes that are not comparable.

— William Opalka

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FERC Orders Tech Conference on PJM FTR Rule Changes

By Rich Heidorn Jr.

FERC on Monday ordered a technical conference to sort out conflicting claims over PJM’s proposed rule changes to reduce underfunding of financial transmission rights.

PJM’s proposed changes, filed in October, were challenged by the Financial Marketers Coalition and others, who said they would be ineffective and discriminatory. The commission said the conference was needed to develop more evidence before it rules (EL16-6-001, ER16-121).

The conference will explore PJM’s claim that its existing rules on FTRs and auction revenue rights are unjust and unreasonable and that the problems would be remedied by its proposed changes. Specifically, the conference will look at ARR modeling and allocation processes; treatment of portfolio positions in allocating underfunding or surplus among FTR holders; and the potential for market manipulation.

pjm
Crews install towers as part of Commonwealth Edison’s Grand Prairie Gateway project, which is expected to go into service in 2017. PJM said the need for the project might have been approved earlier under its proposed FTR rule changes.

An FTR entitles its holder to credits based on LMP differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.

PJM improved funding under current rules by modeling more transmission outages, clearing more counterflow FTRs and improving its modeling of loop flow, the alignment of the FTR, day-ahead and real-time energy markets, and market-to-market coordination with MISO.

PJM said the changes raised FTR revenue adequacy from as low as 69% during planning years 2010/11 through 2013/14 to at least 110% since the 2014/15 planning period.

However, PJM said the changes resulted in an unfair shift of revenues from ARR holders to FTR holders. It said the load-serving entities receiving reduced Stage 1B ARRs are largely different from the LSEs receiving the over-allocation of infeasible Stage 1A (10-year) ARRs.

To correct the cost shift, PJM proposed eliminating the netting of negatively valued FTRs against positively valued FTRs within portfolios. It also proposed increasing current ARR results by 1.5% annually — equal to the average ARR 10-year growth rate since 2007 — in the Stage 1A 10-year simultaneous feasibility process. (See PJM to File FTR, ARR Rule Changes with FERC.)

PJM said the changes will increase the likelihood of infeasible ARRs, potentially identifying needed transmission upgrades such as Commonwealth Edison’s Grand Prairie Gateway project sooner. The 60-mile 345-kV line through four counties in northern Illinois began construction in the second quarter of 2015 and is expected to begin service in 2017. The company says it will allow the import of cheaper wind power from the west, saving customers about $250 million net of all costs within the first 15 years.

Commenters including utilities and the Independent Market Monitor told FERC they generally supported the proposed changes. But the Financial Marketers Coalition (representing DC Energy, Inertia Power, Saracen Energy East and Vitol), Shell Energy N.A. and others protested the elimination of netting, saying PJM failed to show the current rules are unjust and unreasonable and that the change would cure underfunding.

Without netting, the coalition argued, underfunding risks would shift to those that take on counterflow FTR obligations and could encourage market manipulation.

Opponents also questioned whether the proposed 1.5% escalation would be as effective in preventing ARR infeasibilities as claimed by PJM.

[Editor’s Note: An earlier version of this article mistakenly reported that J. Aron & Co. is a member of the Financial Marketers Coalition.]

 

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PJM Seeks Changes to AEP, FirstEnergy PPAs

By Suzanne Herel

Power purchase agreements proposed by American Electric Power and FirstEnergy need changes to preserve competition and Ohio’s ability to attract merchant generation, PJM said this week.

The RTO made the recommendations in testimony to the Public Utilities Commission of Ohio (14-1693-EL-RDR, 14-1694-EL-AAM, 14-1297-EL-SSO).

The filings were virtually identical and offered two amendments to the eight-year agreements. The first would define a “reasonable bidding practice” as offering the output of units covered by the deals into PJM’s markets at no lower than their actual cost, with no consideration of offsetting revenue being provided by Ohio retail customers.

“Bidding at actual cost, consistent with the definition of acceptable costs included in the PJM Tariff and manuals, ensures that the PPA does not have the effect of artificially suppressing prices in any of PJM’s markets,” Stu Bresler, senior vice president of markets, said in the AEP case. The phrasing for the FirstEnergy case was changed only to reflect the term that company is using for its request, a retail rate stability rider (RRS).

Bresler also recommended that if the commission accepts the agreements, it should make clear in its order whether generation owners or their customers would bear the risk of non-performance under the new Capacity Performance model, which aims to ensure reliability by rewarding over-performing units and penalizing under-performing generators.

Bresler said PJM takes no position on the proposed stipulations but felt it necessary to weigh in on aspects that could affect its wholesale markets.

The consequences of “unreasonable” actions when selling AEP’s and FirstEnergy’s output would be “severe,” yet the agreements do not clarify “reasonable” or “unreasonable” actions, Bresler said.

“This provision, more than any other in the stipulation, has the potential to impact the PJM marketplace as a whole and the marketplace in Ohio for new investment, depending on how the provision is implemented,” he said.

PJM’s recommendations are in Ohio’s interest because the output of units covered by the agreements falls substantially short of the companies’ peak loads — 10,500 MW in AEP Ohio’s case and 11,900 MW for FirstEnergy, Bresler said. New generation resources are critical to Ohio’s future, he said, but they would be discouraged from investing in the state if others were allowed to bid below their costs.

Bowring: PPAs Inconsistent with Competition

PJM Market Monitor Joe Bowring also filed testimony, saying that the retail rate stability rider requested by FirstEnergy and AEP’s proposed power purchase agreement both “constitute a subsidy which is inconsistent with competition in the PJM wholesale power market.” He urged the commission to reject them.

The purpose of the AEP agreement, he said, “is to shift costs and risks from shareholders to customers, to remove the incentives to make competitive offers in the PJM capacity market and to provide incentives to make offers below the competitive level in the PJM capacity market.”

The agreement also does not explicitly address how AEP plans to operate within PJM’s new capacity market design.

However, Bowring said, “I would expect that the proposed PPA rider would require ratepayers to pay any performance penalties associated with the assets included in the PPA rider. I would also expect that AEP would retain any performance payments at other AEP units not included in the PPA rider, even if paid for in part by these ratepayer penalties.”

That removes the risk from shareholders, along with the incentive to manage the performance of the units, he said.

Like Bresler, Bowring expressed concern about the agreements enabling the companies to offer output into the market at artificially low prices, edging out competition.

AEP’s request, he said, indicates that PJM should expand its minimum offer price rule to include any new units with subsidies, requiring them to bid into the market at a level no lower than the cost of new entry.

Bowring also testified that the rider requested by FirstEnergy would transfer all “historic and future costs” for certain plants to ratepayers and set up the same paradigm involving its participation in PJM’s capacity market.

Together, the agreements essentially would re-regulate about 6,300 MW of generation. AEP announced its PPA on Dec. 14. FirstEnergy released its proposal Dec. 1. PUCO is expected to rule on the cases in early 2016.

In addition to its testimony, PJM plans to issue a market analysis of both deals this spring. (See PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces.)

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API, ANGA Merge in Cost-Cutting Move for Oil Gas Lobby

By Tom Kleckner and Rich Heidorn Jr.

WASHINGTON — With low oil and gas prices crimping the petroleum industry’s budgets, two major energy lobbying groups are combining forces. The American Petroleum Institute and America’s Natural Gas Alliance will begin 2016 as a single organization under the API banner.

API-ANGA-Form-990-Data-Charts-web

The move appears to be driven by a desire by members of ANGA — a smaller, newer organization — to trim costs. Seven of the 17 members listed on ANGA’s website are also API members.

API, founded about 85 years ago, has more than 625 members, including refiners, suppliers and pipeline operators. In 2013, according to its IRS filings, it had a staff of about 300 and a $49 million payroll, one-fifth of its $238 million budget.

ANGA, founded in 2009, has a staff of about 22 representing 17 dozen independent natural gas exploration and production companies. It reported $7.2 million in payroll in its $67 million budget for 2013.

Ominously, ANGA’s biggest source of income, program service revenue — dues — dropped by more than a quarter in 2013, from $76.7 million in 2012 to $56.5 million in 2013. API’s program service revenue dropped from $225 million to $210 million over the same period.

ANGA ran an operating deficit of more than $10 million in 2013, following a shortfall of $7 million in 2012 — this after running a surplus of $53 million as recently as 2010.

Data for 2014 is not yet available.

api
Jack Gerard (Source: API)

“As a single organization, the combined skills and capabilities bring an enhanced advocacy strength to natural gas market development,” API CEO Jack Gerard, who will remain in his position, said in a statement. “The combined association’s expanded membership will provide additional lift to API’s ongoing efforts on important public policy issues.”

ANGA president Marty Durbin will lead a new group at API that will handle the gas lobby’s interests. ANGA members not already affiliated with API will become full members.

The organizations did not return requests for comment on whether the merger would result in layoffs. In an email to “colleagues” Tuesday, Durbin named four ANGA staffers he said would be joining him in the transition, promising they would provide “a continued high level of engagement and expertise.”

Gerard earned $14.1 million in 2013. Durbin earned $767,000 after becoming CEO in May of that year.

According to The Hill, API spent $9 million lobbying Congress last year — more than any other energy trade group —  while ANGA spent $1.4 million.

Congress’ approval last week of a repeal of the decades-long ban on crude oil exports gave API a rare chance to celebrate lately. It said the legislation “will help bring U.S. energy policy into the 21st century.”

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FERC Orders MISO to Shift Electric Schedule

By Amanda Durish Cook and Tom Kleckner

FERC ordered MISO Thursday to post its day-ahead market results earlier, saying the RTO’s current schedule doesn’t allow gas-fired generators enough time to procure fuel.

The commission said MISO had failed to comply with Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m.

The commission ordered MISO to move the posting of its day-ahead market results “at least” 30 minutes earlier to 12:30 p.m. CT. It also ordered the RTO to set a notification time for its forward reliability assessment commitment (FRAC) that is “sufficiently in advance” of the gas evening nomination cycle (ER15-2256 and EL14-25).

In separate orders, FERC accepted Order 809 compliance filings by SPP and CAISO. Order 809, issued in April, also added a third intraday nomination cycle. (See FERC Approves Final Rule on Gas-Electric Coordination.)

MISO Filing

MISO submitted a compliance filing in July that proposed posting day-ahead market results one hour earlier at 1 p.m. CT and the FRAC notification time two hours earlier to 5 p.m. CT. It also proposed moving its day-ahead market trading deadline one hour earlier during daylight saving time, so that the deadline would be 10 a.m. CT year-round.

fercThe RTO also proposed reducing the day-ahead market solve time from four hours to three, saying that would meet Order 809’s requirement for posting post market results “sufficiently in advance” of the evening nomination cycle to allow gas-fired generators to obtain fuel and pipeline capacity while minimizing the impact on market participants.

MISO said the earlier publication of the day-ahead results would reduce costs by making up to 1,600 MW of longer lead notification generation capacity available. Similarly, the 5 p.m. CT FRAC notification time would allow consideration of up to 4,214 MW of longer lead notification resources.

MISO said its proposals were an effort to balance the Order 809 requirements against stakeholder preferences to maintain a day-ahead market deadline no earlier than 10 a.m. CT. Because most of its footprint operates in the Central Time Zone, MISO said, market participants use the morning hours to determine generation availability, develop forecasts and formulate bids and offers.

FERC not Persuaded

FERC said posting results ahead of the evening gas nomination cycle is not a substitute for posting in advance of the timely nomination cycle, which it said is “the most liquid time to acquire both natural gas supply and pipeline transportation capacity.” MISO’s proposed day-ahead notifications would overlap with the timely gas deadline, leaving generators no time to submit nominations.

The commission said MISO failed to demonstrate that moving its posting at least 30 minutes earlier “will be unduly burdensome or disrupt its markets.”

While MISO said it was not currently experiencing the gas scheduling challenges faced by PJM and the Northeast markets, FERC said, it had “recognized that in the future it could have scheduling difficulties as coal-fired plants retire.”

“For at least part of the year, MISO, like PJM, NYISO and ISO-NE, generally schedules its day-ahead market using Eastern Prevailing Time, which means that it has more time compared to SPP and CAISO during the morning hours to complete its day-ahead schedule in time to meet the 2 p.m. ET (1 p.m. CT) revised timely nomination cycle deadline,” the commission said. “Thus, it is not apparent how requiring MISO to move its day-ahead posting deadline in advance of the timely nomination cycle places an undue burden on the staffs of MISO and its stakeholders.”

The commission acknowledged that MISO’s stakeholders generally prefer to purchase natural gas during its most liquid period (natural gas price certainty) over being able to obtain pipeline service during the timely nomination cycle (quantity certainty). It said MISO should work with stakeholders to reduce its market solve times further “to allow market participants to submit bids reflecting increased fuel price certainty.”

MISO has 30 days to submit a new compliance filing.

SPP Change Approved

FERC, meanwhile, accepted Tariff revisions SPP submitted in August that moved the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT (ER15-2377).

The RTO will now post day-ahead results at 2 p.m. CT, up from 4 p.m., and shorten the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 p.m. CT and results posted by 5:15 p.m. (See “Board Approves Gas-Electric Timeline Change” in SPP BoD/Members Committee Briefs.)

FERC said SPP had “identified characteristics on its system that justify its proposal not to publish its day-ahead market results prior to the timely nomination cycle,” noting its low risk of natural gas pipeline constraints and the impact changes would have on weather forecasting for its “extensive wind resources.”

The commission ordered SPP to submit an annual informational report for the next three years on its efforts to further align its gas and electric scheduling practices. SPP staff have said they can implement the changes — which will require new software — by next fall. The work is being done in conjunction with an enhanced combined-cycle project, at an estimated combined cost of $7.7 million. (See “Enhanced Combined-Cycle Project Moves Forward” in Board of Directors/Members Committee Briefs.)

No Change for CAISO

The commission also said CAISO had shown good cause why its existing day-ahead practices should not be changed (EL14-22).

CAISO’s July compliance filing said its load-serving entities feared less accurate supply forecasts with an earlier start to the day-ahead market. FERC agreed, saying “moving the close of the day-ahead market earlier could reduce the accuracy of demand, hydroelectric supply and variable energy resource output forecasts.”

The ISO’s day-ahead market closes at 10 a.m. PT and market results are published at 1 p.m. PT.

As with SPP, the commission ordered annual informational reports on CAISO’s efforts to improve coordination of gas and electric schedules.

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Appeals Court Upholds FERC on West Coast Energy Crisis Case

By Rich Heidorn Jr.

The 9th Circuit Court of Appeals last week sided with FERC in the latest chapter of the long-running legal dispute over the California-West Coast energy crisis of 2000-2001.

A three-judge panel declined to overturn FERC’s decision to apply the Mobile-Sierra doctrine — which presumes that the rate set in a freely negotiated wholesale-energy contract is just and reasonable — in determining whether Pacific Northwest power buyers are entitled to refunds.

The judges also dismissed a challenge to the scope of evidence FERC considered in the Mobile-Sierra review, saying the issue was not ripe for its review.

California Deregulation

The case before the 9th Circuit stems from the turmoil that followed California’s deregulation of the electricity market in the mid-1990s, which resulted in skyrocketing spot prices in California and the Pacific Northwest, largely driven by market manipulation by Enron and other power marketers.

The petitioners, which include the city of Seattle, challenged several FERC orders issued following the 9th Circuit’s 2007 remand of the Port of Seattle case. In that case, the court reviewed challenges to FERC’s denial of refunds to wholesale buyers that purchased power in the Pacific Northwest spot market at unusually high prices.

The court ruled that FERC’s failure to consider evidence of market manipulation was arbitrary and capricious. FERC had to “consider the possibility that the Pacific Northwest spot market was not … functional and competitive,” the court ruled.

FERC was ordered to examine evidence of market manipulation “in detail and account for it in any future orders regarding the award or denial of refunds in the Pacific Northwest proceeding.”

In response, FERC said it would invoke the Mobile-Sierra doctrine, meaning the presumption that the contracts were just and reasonable could be overcome only if specific criteria were met, such as “where it can be shown that one party to a contract engaged in such extensive unlawful market manipulation as to alter the playing field for contract negotiations.”

FERC’s invocation of the Mobile-Sierra presumption meant electricity buyers would need to “demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.”

FERC said it would not consider “general allegations of market dysfunction” because the Pacific Northwest spot market operated solely through bilateral contracts, unlike the California spot market, which used a central clearing price and a centralized power exchange.

In last week’s order, the court rejected FERC’s contention that it lacked jurisdiction to review the commission’s application of Mobile-Sierra. But it deferred to what it called “FERC’s reasonable determination” that Mobile-Sierra applies to short-term sales.

“The mere short-term nature of these spot sale contracts does not render FERC’s application of the Mobile-Sierra doctrine unreasonable,” the court said. “Although long-term contracts may play a special role in stabilizing the energy market … the Supreme Court has drawn the rule so that the presumption may be invoked with regard to any contracted for rate.”

Evidentiary Challenges not Ripe

The court said, however, that it lacked jurisdiction to rule on the petitioners’ challenges to restrictions that FERC imposed on the evidentiary proceeding. The petitioners said they should be permitted to introduce evidence of reporting violations, violations of obligations under the Uniform Commercial Code and state contract law, and violations by sellers that were not parties to the challenged contracts.

The court said the evidentiary orders are preliminary and lack the “definitive substantive impact” required for the court to assert jurisdiction.

It noted that “FERC has already shifted course on the ‘shape’ of the proceeding in a way that suggests some elements of its orders may not be sufficiently final for review. … Significantly, it appears that despite arguments raised by the petitioners, at least some evidence of bad faith may have been admitted in the [evidentiary] proceeding.”

The court said FERC’s final order resulting from the remand hearing will be reviewable and will allow a “more effective review of the evidentiary decisions since the court will be able to review all of the evidence taken together.”