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December 25, 2024

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NERC Adds to Warnings on Gas Dependence

By Rory Sweeney

Joining others in raising the alarm, NERC released a short-term special assessment last week that highlighted the reliability risks created by increased dependence on natural gas for electricity generation.

nerc, natural gas
Aliso Canyon Relief Well Source: Southern California Gas

The report focused on the four regions with gas-fired generation penetration of more than 40%: New England, New York, ERCOT and California. It found that most regions, while potentially at risk if a major supply interruption occurs during a period with exceptionally high load, are prepared to address it with contingency plans and alternative pipeline routes.

The lone exception was the Southern California region, where the shutdown of the Aliso Canyon storage facility earlier this year is straining the system. NERC reiterated warnings that the Los Angeles area could be at risk for outages for the next year. (See Aliso Canyon Gas Restrictions Cloud CAISO Summer Outlook.)

NERC recommended that it and the Western Electricity Coordinating Council convene a meeting with industry stakeholders to identify reliability impacts and develop mitigation strategies.

18-Month Forecast

NERC compared generation expected to be unavailable with forecasted loads over the next 18 months to identify potential times when demand might outstrip supply. The report then analyzed the region’s infrastructure and planning to determine the likelihood of service disruptions.

The assessment pointed out that supply disruptions are possible in both the winter, when gas is needed for heating, and the summer, when air conditioning increases electric demand. Greater coordination between the natural gas and electric industries would help mitigate those risks, the report said.

The report recommended continuing to account for reliability risks from extreme weather events and large-scale supply disruptions and enhancing coordination during supply shortages. It also recommended two strategies ISO-NE and PJM have encouraged through new capacity market rules: dual-fuel generators and firm gas-delivery contracts.

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Companies Dispute FERC Ruling on Crisis Contracts

By Robert Mullin

Iberdrola Renewables last week struck back at a FERC judge’s April ruling that could subject the company to more than $370 million in penalties over an electricity contract signed with California near the end of the Western Energy Crisis.

In a brief on exceptions filed with FERC on May 27, the Spanish energy giant contends that Administrative Law Judge Steven Glazer’s initial decision “contradicts” a landmark Supreme Court ruling, “undermines” commission precedent and “ignores” the commission’s directive when the case was sent to the judge (EL02-62-006, EL02-60-007).

“The [initial decision’s] misapplication of [the Supreme Court decision in] Morgan Stanley reflects a results-driven approach that permeates the entire opinion,” Iberdrola wrote.

Iberdrola’s filing attempts to poke holes in the complex legal reasoning underpinning Glazer’s ruling, which relied on the application of the Mobile-Sierra rule “as reinterpreted by Morgan Stanley.” In addition to finding that the contract imposed an excessive “down the line” burden on California residents based on an examination of comparable marginal production costs, Glazer also reinstated the company as a party to the proceeding following a previous dismissal. (See FERC ALJ: Shell, Iberdrola Owe California $1.1B over Energy Crisis.)

Iberdrola is contesting both findings, arguing first that FERC should once again dismiss any claims against the company and — barring that — asking the commission to uphold the company’s contract rates as “just and reasonable.”

Shell also Responds

Shell North America, which Glazer said imposed an “excess burden” of $779 million on California consumers, submitted a brief contesting the judge’s ruling that Mobile-Sierra protections were both “avoided” and “overcome” in the company’s contract with CDWR. Glazer based that determination on the finding that Shell traders manipulated the spot market through practices such as false exporting, false load scheduling and “anomalous” bidding strategies — all designed to drive up market clearing prices.

The company — like Iberdrola — contended that its contract did not impose an excessive burden on California consumers, saying that “even the most pessimistic economic assessment credited by the [initial decision]” showed the agreement added no more than 9 cents to the average $75 residential bill in the state.

Shell also attempted to root its appeal to the commission in FERC’s historical support for market-based rates and the Mobile-Sierra presumption of the “integrity of contracts.” The company argued that CDWR “carefully evaluated” the company’s proposal before signing, and that the weighted average price of the contract “sat well below the commission’s own just-and-reasonable benchmark.”

“Rejecting the [initial decision] is therefore essential to the continued viability of the commission’s market-based-rate program and, more generally, of the country’s energy markets,” Shell said.

[Editor’s Note: An earlier version of this story incorrectly reported that Shell had not filed a brief before the May 27 deadline.]

2006 Acquisition

Iberdrola’s connection to the energy crisis-era case is a complicated one. In 2006, the company acquired Scottish Power, previously the parent of Portland-based utility PacifiCorp. During the previous year, Scottish Power had sold PacifiCorp to Warren Buffet’s MidAmerican Energy Holdings but retained ownership of merchant affiliate PacifiCorp Power Marketing (PPM), which was absorbed by Iberdrola — renamed Avangrid in February 2016 — in the 2006 buyout.

As the energy crisis abated in summer 2001, PPM signed a long-term tolling agreement with the California Department of Water Resources (CDWR) to ensure power supplies to constrained areas in the northern part of the state. Capacity would be supplied by PPM’s gas-fired Klamath Falls plant in southern Oregon.

| Dr. Richard E. Goldberg via FERC

By that time, the department had assumed the role of electricity buyer of last resort after widespread manipulation drove Pacific Gas and Electric and the now-defunct California Power Exchange into bankruptcy. The state’s other two investor-owned utilities (IOUs) teetered on the brink of insolvency because of soaring wholesale power costs.

After the crisis passed, the California Public Utilities Commission initiated proceedings to recover the state’s costs for sustaining operation of the IOUs. Shell Energy North America and Iberdrola are the only suppliers involved that have not settled with the state or renegotiated the terms of their contracts, which expired in 2011 and 2012. The ALJ’s April decision also determined that Shell’s long-term agreement saddled California consumers with an “excess burden” of $779 million.

Novel Interpretation

Glazer’s decision to overturn the companies’ agreements with CDWR was rooted in a novel interpretation of Mobile-Sierra, the Supreme Court doctrine that holds that bilateral energy contracts can be voided only when shown to adversely affect the public interest.

In 2003, FERC ruled that it was not in the public interest to break the contracts, a decision that California appealed to the 9th Circuit Court of Appeals. A 2008 Supreme Court decision in Morgan Stanley Capital Group Inc. v. Public Utility District No. 1 of Snohomish County ultimately boosted the state’s prospects for cost recovery. That decision required the commission to apply an additional standard to Mobile-Sierra, testing whether the terms of a contract were the result of market manipulation.

Glazer’s decision against Shell rested on evidence that the company manipulated spot electricity prices during the crisis employing many of the same strategies as Enron, practices that directly influenced the forward prices forming the basis for the company’s CDWR contract. For that reason, Shell’s contract “avoided” Mobile-Sierra protections as reinterpreted through Morgan Stanley.

While Glazer determined that Iberdrola — then PPM — had engaged in its own manipulation during the crisis, he also found that CDWR had not relied on forward prices to negotiate the contract, as the department by that time no longer found forward price curves to provide a reliable benchmark for setting prices. Still, the ALJ decided the Mobile-Sierra doctrine was “overcome” because of the long-term costs of the contract carried by California, which was forced to issue bonds to fund the capacity purchases.

Iberdrola Reinstatement

Key to Glazer’s ruling was the decision to reinstate Iberdrola as a party to the proceeding. The company had been previously dismissed from the case largely because its contract was signed July 6, 2001, two weeks after FERC imposed price caps across the state, ending the crisis. Glazer reasoned that, regardless of the signing date, the contract was still negotiated during the height of the crisis, which resulted in rates far exceeding those even in September of that year.

Iberdrola’s rebuttal takes up the issue of the contract date as evidence of what it called the flawed reasoning behind the ALJ’s decision. The company contends that it is “undisputed” that the energy crisis ended with FERC’s June 19, 2001, order instituting price caps and that “spot market volatility had ended and forward prices had largely returned to pre-crisis levels” by early July.

“Yet, so as to sweep up the Iberdrola contract into the group of energy crisis contracts that should be abrogated for no reason other than the timing of their execution, the [initial decision] pronounces that the energy crisis ran through July 6, 2001,” Iberdrola wrote.

‘Peanut Buttering’ Analogy

The company also contests Glazer’s use of a “fundamentals-based” price standard that calculates the “excessive burden” on California consumers by comparing the contracts pricing with assumed marginal costs of production.

“In so doing, the [initial decision] contradicts Morgan Stanley, which holds that ‘a presumption of validity that disappears when the rate is above marginal cost is no presumption of validity at all, but a reinstitution of cost-based rates,’” Iberdrola said.

Iberdrola further contends that the ALJ — and the California complainants — failed to provide convincing evidence for how the contract constituted an “excessive burden” on California consumers through increased electricity rates, an explicit requirement of FERC’s order on remand. The company objected to Glazer’s adoption of Commissioner Mike Florio’s “peanut buttering” analogy, which says that a burden analysis that focuses on consumer rates spreads costs too thinly.

“But, of course, the question of whether a rate impact on individual consumers is excessively burdensome is the very inquiry that Morgan Stanley requires, and that the commission has evaluated in each of the cases on remand post-Morgan Stanley,” the company countered.

Having provided that context, Iberdrola noted that its contract produced an average rate impact of 5 cents/month for residential customers of PG&E. FERC had previously ruled that a 27-cent impact wasn’t excessive.

Still, Iberdrola’s strongest appeal to the commission might be an argument that moves from the specific to the general, contending that the ALJ’s reliance on a marginal cost test undermines FERC’s “historic market-based rate program.”

“[U]nless the commission intends to alter the nature of the energy industry, marginal cost simply cannot be where the commission draws the line in determining whether an excessive burden exists,” Iberdrola said.

CPUC Weighs In

The California PUC filed its own brief with FERC largely supporting the ALJ’s ruling and the conclusion that Shell and Iberdrola overcharged the state by more than $1 billion through the energy crisis contracts. The brief did contest a handful of other conclusions, however, including the finding that Mobile-Sierra protections were “overcome” rather than “avoided” in the case of the Iberdrola contract. The agency contended that PPM’s manipulation “altered the playing field for the Iberdrola contract negotiations such that the Mobile-Sierra presumption is avoided.”

“Still, the initial decision sent a powerful message that anti-competitive and manipulative behavior that imposes an undue burden on consumers will not be tolerated,” the PUC said.

Briefs opposing exceptions must be submitted to FERC by June 27.

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Company Briefs

Kinder Morgan formally withdrew its application for the Northeast Energy Direct natural gas pipeline in a filing with FERC (CP16-21).

Tennessee Gas Pipeline, a Kinder Morgan subsidiary, in April suspended development of the $3.3 billion project that would have brought 1.3 million dekatherms per day into the New York-New England power markets from Pennsylvania. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.) It cited a lack of customers and low natural gas prices.

“Tennessee provides notice of its withdrawal of the application in this proceeding,” the company wrote to FERC, with no further explanation.

More: New Hampshire Union Leader

Talen Energy Signals Retreat from Colstrip

Talen Energy gave notice that it will pull out of its operator role at the Colstrip coal-fired power plant in Montana by May 2018. The Pennsylvania-based merchant generating company co-owns the plant near Billings, part of the fleet it inherited from its predecessor, PPL.

Talen notified the other owners of the plant that its role as operator of the giant complex is “not economically viable” and that they should start seeking a new operator. “This decision is part of Talen Energy’s overall strategy to conclude our business operations in the state,” said Todd Martin, the company spokesman. Talen is obligated to give two years’ notice.

The other owners are Avista, Puget Sound Energy, Portland General Electric, PacifiCorp and NorthWestern Energy.  Unlike the plant’s other shareholders, Talen is an unregulated entity and unable to recover costs related to the plant.

More: Billings Gazette; The Associated Press

TVA’s Watts Bar 2 Nuke Goes Critical

The Tennessee Valley Authority’s Watts Bar Unit 2 went critical last week, the first new nuclear reactor to achieve a self-sustaining nuclear reaction in 20 years. When it comes online and is synchronized to the grid, it will bring 1,411 MW of generation to the region.

The plant’s $4.7 billion cost is far less than another new reactor in the wings, Southern Co.’s Plant Vogtle in Georgia, which has an estimated $14 billion price tag. Construction of Watts Bar began nearly 30 years ago.

More: Times Free Press

Ameren Illinois Touts Savings Secured Through Auction

Ameren Illinois is touting the lower prices it secured in April during MISO’s annual capacity auction. The company said its 2016 $72/MW-day capacity prices — compared with $150/MW-day in last year’s auction — will translate into a $1.75/month savings for the average utility customer.

“This year’s capacity planning auction resulted in a much more equitable distribution of charges for customers in the MISO footprint,” said Richard J. Mark, president of Ameren Illinois.

However, watchdog group Citizens Utility Board said more can be done to lower costs, including purchasing electricity at off-peak times. “Nobody thinks their electric bills are low, so we’ve got a lot more to do to fix the Illinois electricity market,” said CUB spokesman Jim Chilsen.

More: Herald & Review

Invenergy to Build 25-MW Solar Plant on Long Island

Invenergy announced that it will build a 25-MW solar facility on the grounds of Long Island’s former Tallgrass Golf Course in Brookhaven.

The Long Island Power Authority will buy the output, the company said. The plant, to be called the Shoreham Solar Commons project, still needs the approvals of the New York attorney general’s office and the state comptroller, according to a company spokeswoman. Construction is expected to begin in October.

More: Bloomberg

Lincoln Electric Accelerates Local Transmission Project

Lincoln Electric System, the public utility serving Nebraska’s capital city, is accelerating the timeline for a $17.7 million transmission line and substation that will help meet increasing electric demands. The SPP member plans to complete its Southeast Reliability Project in in 2018, two years earlier than planned.

LES held three open houses for the project last year and is now expediting the project to stay ahead of continuing development in the area, LES representatives said during the monthly meeting of the utility’s board.

The project includes construction of three substations and a 7.5-mile-long 115-kV overhead transmission line, as well as the relocation of a 345-kV line that will follow the same route.

More: Lincoln Journal Star

Chinese American Subsidiary Acquires Texas Wind Farm

China’s Xinjiang Goldwind Science & Technology says its American subsidiary, Goldwind Americas, has signed an agreement with Renewable Energy Systems Americas to acquire the 160-MW Rattlesnake Wind Project in West Texas.

Goldwind says the Rattlesnake project will be its largest U.S. wind project once it is operational.

Located approximately 125 miles northwest of Austin, the project will use 64 Goldwind 2.5-MW permanent magnet direct-drive wind turbines. According to Goldwind, the development represents the first phase of an expected 300-MW wind project, which will be constructed under a balance-of-plant agreement by RES.

More: North American Windpower

ND Allam Cycle Project Sponsors Seek More Funding

North Dakota researchers and regional energy companies are asking the state’s Lignite Research Council for $3.5 million to continue research on what the industry considers a promising carbon-capture technology.

Energy & Environmental Research Center, Basin Electric Power Cooperative, 8 Rivers and ALLETE say the funds are needed for further lab testing and pre-planning for a synthetic gas-fired pilot plant using the Allam Cycle system for lignite coal. The Allam Cycle, invented by 8 Rivers, uses pressurized carbon dioxide rather than steam to generate power more efficiently, cheaply and cleanly.

A $140 million, 50-MW natural gas-fired Allam Cycle pilot power plant in Texas will start up in 2017. If the technology is proven to work with natural gas, the lignite coal industry is hopeful the system and processes can be adapted to handle gasified lignite.

More: The Bismarck Tribune

New York Hydro Owner Says It Has Buyer

The owner of the 33-MW Glen Park hydro facility near Watertown, N.Y., says it has a prospective buyer for the plant.

Calgary-based Veresen did not identify the prospective buyer, but it expects to close the $61 million transaction by the end of September, pending FERC approval.

Veresen, previously known as Fort Chicago Energy Partners, acquired the facility in 2010 for $80.1 million.

More: HydroWorld.com

Caithness II Plant Proponents Urge PSEG, LIPA to Deal

Proponents of Caithness II, a proposed 750-MW natural gas-fired power plant, are calling for PSEG Long Island and the Long Island Power Authority to enter into power purchase agreements with the plant. Caithness Energy already operates a 350-MW plant in Yaphank on Long Island and sells the output to PSEG and LIPA.

PSEG hasn’t committed to Caithness II and questions the need for it. But local elected officials and others say the area is served by outdated, inefficient plants that should be replaced.

“Caithness II will help offset Long Island’s reliance on aging power plants that are inefficient and costly,” said Brookhaven Councilman Kevin LaValle. “Brookhaven and the entire region stands to prosper greatly from a modernized electric power supply, and this project brings us closer to the goal of providing Long Island ratepayers with more affordable and reliable energy.”

More: Long Island Business News (subscription required)

Fluor Says Brunswick County Generating Station Complete

Fluor, the primary contractor for Dominion Resources’ Brunswick County Power Station in Virginia, said that it has completed constructing the 1,358-MW natural gas-fired plant. Final testing will be needed before it goes into operation.

Fluor is now scheduled to begin construction of another Dominion project, the 1,600-MW gas-fired Greensville County generating station, which will be located 7 miles from Brunswick Station.

More: Fluor

Duke Signs Deal to Use Captured Swine Manure Gas

Duke Energy has signed a deal with pork producers in North Carolina to use captured methane to run two power stations.

Methane from the Smithfield Foods farms in the Kenansville area will be captured by Optima KV, converted to pipeline-quality fuel and transported  to the H.F. Lee and Sutton power plants. Optima has a 15-year contract with Duke.

Duke in March joined in a similar project with Carbon Cycle Energy to capture manure gas to fuel four of its plants in the state.

More: Charlotte Business Journal

Union, Talen Offer Conflicting Reports on Job Losses

Talen Energy plans to eliminate 125 union jobs at three Pennsylvania power plants, according to the International Brotherhood of Electrical Workers 1600.

A Talen spokesman, however, disputed the report and would confirm only job cuts at the Susquehanna nuclear plant. The other two plants slated for job losses, according to the union, are the Brunner Island and Montour coal-fired facilities.

The company and the union cited the depressed cost of electricity as a driver in the restructuring.

More: The Morning Call; The Daily Item

PSE&G Says Upgrades Will Help Meet Summer Demand

Public Service Electric and Gas this year has deployed $2.7 billion in infrastructure improvements that it said will help it meet summer demand.

“Equipment has been replaced, facilities upgraded and additional redundancies added systemwide in order to maintain reliability,” said John Latka, vice president of electric and gas operations.

The summer peak is expected to hit 10,090 MW, compared with last year’s peak of 9,579 MW, set July 20.

More: Transmission & Distribution World

Utah Supreme Court Upholds PacifiCorp Fine

The Utah Supreme Court last week voted to uphold a $130.7 million jury award against PacifiCorp and its lawyers for violating trade secrets when the company constructed a power plant similar to a nearby facility being built by Dallas-based USA Power.

In bringing the suit in 2005, USA Power argued that PacifiCorp — parent of Utah’s Rocky Mountain Power — had copied the plans for the air-cooled, gas-fired Spring Canyon plant, which was designed to limit impact on the local environment. PacifiCorp had previously entered negotiations to buy the plant, but it later backed out and constructed a similar unit a mile away.

After a five-week trial in 2012, a jury awarded USA Power $18.2 million in damages for stealing trade secrets and $112.5 million in damages because PacifiCorp unjustly profited from the theft.

More: KSL.com

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Massachusetts Clean Power Bill Hit from All Sides

By William Opalka

A long-awaited bill introduced in the Massachusetts House of Representatives last week that would ease the path for Canadian hydropower and offshore wind into the state and New England electricity markets was criticized by both clean energy advocates and power generators.

Massachusetts Clean Power Bill
Daniel-Johnson Dam and Manic Generating Station Source: Hydro-Quebec

The bill calls for power distribution companies and the state Department of Energy Resources to procure 1,200 MW of offshore wind and 9,450 GWh of hydropower annually by June 30, 2017. The contracts would last between 15 and 20 years.

Gov. Charlie Baker called the proposal “a very strong bill that’s built around the idea of expanding our portfolio, diversifying our energy sources and incorporating big slugs of hydro and wind into our portfolio here in Massachusetts and across New England.” (See Baker: Hydropower Contracts Best Way to Lower Costs.)

The bill isn’t as comprehensive as many stakeholders had hoped for, lacking provisions for solar, nuclear power, energy efficiency or other technologies. An extension of the solar net metering cap earlier this year was the only significant issue addressed this session. (See Massachusetts Raises Net Metering Cap, Cuts Payments.)

The New England Power Generators Association said the bill interferes with market mechanisms that had delivered lower-cost power.

“The proposal would carve up one-third of the Massachusetts electricity marketplace into decades-long contracts that have the potential to dramatically increase electricity costs for consumers,” NEPGA president Dan Dolan said in a statement.

Some environmental advocates see the bill as weighted too heavily toward hydropower. “The Massachusetts House deserves full credit for recognizing the urgent need to address our state’s energy future. However, this bill is not strong enough,” said Caitlin Peale Sloan, a staff attorney for the Conservation Law Foundation. “We need to take bold action to counter climate change and that means choosing the cleanest energy that we can. Wind is one of the cleanest energy sources — cleaner than imported hydropower.”

A coalition of offshore wind developers said the bill begins a new era for the state.

“Offshore Wind Massachusetts looks forward to continuing to work with the House and Senate to fashion a final bill that will enable Massachusetts to make use of one of its greatest resources — abundant and reliable wind that will power a new industry and benefit our citizens for the rest of this century and beyond,” said Matthew A. Morrissey, its managing director.

The bill would exclude the Cape Wind project in Nantucket Sound by limiting eligible offshore wind projects to those in a “competitively solicited federal lease area” south of Massachusetts and Rhode Island. The project, once expected to be the country’s first offshore wind farm, has struggled to obtain financing.

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MISO Advisory Committee Briefs

MISO’s Advisory Committee last week settled on five priorities for 2016 after adding an obligation to “improve coordination across market and non-market seams” under the seams optimization priority.

In approving the priorities, the committee also called for:

  • Improving operational coordination when dealing with federal regulations such as the Clean Power Plan;
  • A focus on price formation under the grid technology advancement priority; and
  • Refinement of the competitive transmission development process under the infrastructure development enablement priority.
MISO Advisory Committee Briefs
AC Vice Chair Tia Elliot (L) and AC Chair Audrey Penner discuss retirement of the Stakeholder Governance Working Group © RTO Insider

The changes were made in response to recommendations from MISO sectors. (See “AC to Finalize Priority-Setting for May Vote,” MISO Advisory Committee Briefs.)

Advisory Committee Chair Audrey Penner noted that the priorities would be revisited during the committee’s October strategic session. “I want to remind folks that … we will review this again,” she said. “It’s meant to be a reiterative, back-and-forth document.”

With priorities set for this year, work on 2017 begins immediately. Penner said the committee should focus on deciding if this year’s priorities have a shelf life that can continue into 2017 or if they should be reworked.

Committee Retires Stakeholder Governance Working Group

The committee retired the Stakeholder Governance Working Group after the group concluded modifications on the governance guide.

Vice Chair Tia Elliott said the Steering Committee will absorb the group’s responsibilities, and task teams could be formed to deal with more specific issues involving the governance guide. Outstanding governance issues could also be addressed at the annual stakeholder workshop.

Elliot said an “expertise safety net” already exists in the Steering Committee with MISO liaison Eric Stephens, who is able to assist with the governance guide and data requests from the recently retired Data Transparency Working Group.

Final Advisory Committee Priorities (MISO) - MISO Advisory Committee BriefsGary Mathis, representing the Transmission-Dependent Utilities sector, said more work is needed on stakeholder redesign implementation and that task teams are not the ideal venue.

“The Stakeholder Governance Working Group doesn’t meet very often, it’s efficient, has a chair and vice chair and, unlike a task team, follows the governance guide,” Mathis said.

He said the decision to retire the working group should rest with its parent entity, the Steering Committee.

Dynegy’s Mark Volpe said he has viewed the working group as a “transitional body” since February, when it first dodged retirement through an Advisory Committee motion. (See “Stakeholder Governance Working Group Sidesteps Retirement,” MISO Advisory Committee Briefs.) Elliott said the committee retained the right to retire the group.

— Amanda Durish Cook

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ERCOT Stakeholders Reject Ancillary Service Revisions

By Tom Kleckner

AUSTIN, Texas — ERCOT members last week voted down the ISO’s attempt to salvage a revision request that would have replaced several ancillary services with four new products.

Frazier © RTO Insider
Frazier © RTO Insider

The nodal protocol revision request (NPRR), rejected earlier in the month by the Protocol Revision Subcommittee, was shot down again when the Technical Advisory Committee upheld the subcommittee vote by a 23-3 margin Thursday.

NPRR 667 would have improved regulation service and replaced non-spinning reserve and responsive reserve service with a combination of four new services: fast-frequency response, primary frequency response, contingency reserve and supplemental reserve.

However, staff was unable to convince stakeholders the revisions were ready for prime time. Speaking for the subcommittee, Luminant’s Amanda Frazier said ERCOT did not demonstrate a current or future reliability need for the services and did not adequately address their costs and funding.

“What I heard from PRS members is [ERCOT has] exceptional performance from a reliability perspective,” said Frazier, the subcommittee’s chair. “It has consistently improved over time, so even though we’ve seen growth of intermittent resources over the last decade — exponential growth — we also see performance that is improving.”

Frazier said stakeholders also had concerns over market liquidity for the new services and would prefer to see ERCOT focused on identifying reliability needs and alternatives to NPRR 667. “ERCOT has expressed a preference for a vote on 667 before examining alternatives,” Frazier said. (See “NOGGR Tabled, Other Revision Requests Approved,” ERCOT Technical Advisory Committee Briefs.)

Woodfin © RTO Insider; ERCOT Ancillary Service
Woodfin © RTO Insider

“ERCOT doesn’t do this very often,” said Dan Woodfin, the ISO’s director of system planning, of the appeal by staff. “I can’t recall [something like] this in my 13 to 14 years here.”

Woodfin based his case to the TAC on ERCOT’s changing resource mix since the ancillary service framework was built. Whereas ERCOT was 75% reliant on coal- and gas-steam energy in the late 1990s, half the current resource mix comes from gas turbines, combined cycles and renewables.

He said the current bundled framework will keep more expensive generation online, extend negative price periods and curtail less expensive resources, resulting in increased ancillary service prices and higher overall costs — especially with an increase in high-wind, low-load periods.

Ancillary service “was designed around the characteristics of those steam boilers,” he said. “We have a whole lot of new resources … that has changed both the needs and the ability of different resources to provide those services. We’re expecting the resource mix to continue to change. We’re seeing some pretty tremendous changes on wind in the system … solar is growing exponentially.

“[ERCOT’s current] ancillary service requirements … provide a barrier to entry to new types of resources that don’t have inherent characteristics of the old steam boilers.”

Woodfin pointed to The Brattle Group’s recent report on the ERCOT market, which he said found the ancillary service proposal to be a good, cost-effective market design. (See Brattle Study Sees ERCOT Continuing to Rely on Nat Gas, Renewables.)

Proposed Future Ancillary Services (ERCOT)“We don’t want to maintain barriers of entry for any technology,” said Frazier in questioning the benefit of ERCOT’s proposed changes. “It seems expensive to invest millions of dollars for new technology that would only bring in 200 MW.”

Frazier said several market participants (MPs) believed ERCOT’s estimated impact analysis of $12 million to $15 million was too low. She also acknowledged “the good work done in the last several years to think through the future resource mix.”

“We think there are also many MPs that believe there are incremental changes that can be made to the ancillary service suite that can deliver the value Dan mentioned,” Frazier said.

ERCOT was unfazed by losing its appeal of NPRR 667, which was first filed in November 2014 after a year of stakeholder discussions. Spokesperson Robbie Searcy said the ISO will continue its work with stakeholders to plan for future ancillary service needs.

“ERCOT continues to believe the concepts set forth in” the NPRR, she said. “As grid characteristics evolve, it is important that we are planning ahead to ensure we have appropriate market tools in place to maintain system frequency and overall reliability.”

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NYISO Monitor: Modify Capacity Export Planning

By William Opalka

RENSSELAER, N.Y. — NYISO’s Market Monitoring Unit is recommending changes to the capacity market and planning processes in import-constrained zones as a result of a New York generating plant’s successful offers into the last two ISO-NE Forward Capacity Auctions.

NYISO Market Monitor: Modify Capacity Export PlanningPallas LeeVanSchaick of Potomac Economics outlined the recommendations in a presentation on the monitor’s 2015 State of the Market Report to the NYISO Management Committee meeting on Wednesday.

The changes would better account for capacity that is exported to neighboring control areas from import-constrained capacity zones, he said. “This is new this year and we see it as high priority.”

The Roseton 1 generator, a 1,242-MW dual-fuel generator in Newburgh, N.Y., sold 511 MW of capacity in ISO-NE’s FCA 9 for the 2018/19 commitment period and 532 MW in FCA 10 for 2019/2020. The plant will have simultaneous capacity obligations in New York and New England. Roseton 1 is in Zone G in the Lower Hudson Valley, which has been designated as import-constrained.

Potomac said rules were needed to prevent inefficient capacity prices and anticompetitive outcomes.

“If such rules are not devised soon, clearing prices will be set above competitive levels in the Lower Hudson Valley. Therefore, we recommend rules to account for these transactions that would ensure efficient pricing in NYISO’s capacity zones,” according to the report.

The monitor said planning for this now would reduce uncertainty regarding future prices and reliability.

“This would avoid the scenario where prices would be inflated in June 2018 by $40/kW-year” in zones G-J, (Lower Hudson Valley and New York City), LeeVanSchaick said.

Potomac said underlying principles of the adjustments should be that the capacity clearing price is equal to the value of the additional megawatts in the area and that the capacity payment is equal to the reliability value to NYISO.

It proposed:

  • Accounting for the reliability benefits provided by a Southeast New York resource that exports to another control area when clearing zones G-J;
  • Compensating exporters based on local/rest-of-state price differentials; and
  • Adjusting planning assumptions to recognize these benefits.

ISO Seeking Feedback on Potomac

Separately, NYISO will collect comments on Potomac’s performance until July 15 in its annual solicitation of market participant input.

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Federal Briefs

The House of Representatives voted 241-178 to pass an amended version of the Senate’s Energy Policy Modernization Act of 2016, tacking on drought relief aid for California, among other provisions. The passage means the House can now enter a conference with the Senate to reconcile the two versions.

repfreduptonsourcegov
Upton

“This has been a multiyear, multi-Congress effort, and a lot of work has gone into making sure that the bill we put forward to support the future of American energy is truly comprehensive,” Rep. Fred Upton (R-Mich.) said.

The House’s version would make it more difficult for the federal government to use endangered fish species protections to increase the flow of water from California’s dams into the sea. Republicans say this practice wastes precious fresh water for humans in the drought-plagued state, while Democrats say the provision would damage fisheries.

More: The Hill

Obama Proposes Emissions Rules for Contractors

The Obama administration has put forward new rules that would mandate federal contractors disclose their greenhouse gas emissions.

The White House’s Federal Acquisition Regulation Council filed the proposals in the Federal Register requiring contractors to say if they disclose emissions numbers, if they have reduction goals and what effect climate change will have on business operations.

“We’ll be able to better assess supplier greenhouse gas management practices, manage direct and indirect greenhouse gas emission, address climate risk in the federal government’s supply chain and engage with contractors to reduce supply chain emissions,” White House officials said.

More: The Hill

Trump Vows to Undo Environmental Regulations

trumpsourcewiki
Trump

Donald Trump, the presumptive Republican presidential nominee, vowed to end President Obama’s Climate Action Plan, of which the Clean Power Plan is the centerpiece, within his first 100 days in office if he’s elected.

“Any regulation that’s outdated, unnecessary, bad for workers or contrary to the national interest will be scrapped and scrapped completely,” he said. “Any future regulation will go through a simple test: Is this regulation good for the American worker? If it doesn’t pass this test, this rule will not be under any circumstances be approved.”

Trump also said he would kill EPA’s Waters of the United States rule, “cancel” the Paris Agreement and ask TransCanada to apply again for the Keystone XL Pipeline.

More: Morning Consult

DOE: Keep Funding International Fusion Effort

ITERsourceITERAn Energy Department official said the U.S. should continue funding an international attempt to develop fusion technology, despite the project’s overruns and delays.

Franklin Orr, undersecretary for science and energy, says the U.S. government should increase its support for ITER, a magnetic fusion device being built in France and initiated by President Ronald Reagan in 1985. The department says the U.S. contribution needs to be $230 million in 2018, or $105 million more than it has budgeted.

If successful, ITER would be the first device to maintain fusion for long periods of time and develop more energy than it consumes. Thirty-five nations are now contributing to the project, whose price has escalated dramatically over decades of development.

More: Science

NRC Sets Sliding Fee Scale For Small Modular Reactors

nrcsourcegovThe Nuclear Regulatory Commission finalized rules that set a sliding fee scale for small modular reactors, aimed at encouraging development of the technology.

The annual fee for light water SMRs will be set according to how much heat they generate, according to the commission. The rules set a minimum fee, a variable fee and a maximum fee.

The commission said applying the same fee to smaller reactors that is applied to large reactors would be unfair, as smaller reactor designs pose a “lower regulatory oversight burden.”

More: Bloomberg

NRC Approves La Crosse License Transfer

lacrossenuclearsourcewikiThe Nuclear Regulatory Commission has approved the transfer of the license of the shuttered La Crosse Nuclear Plant in Genoa, Wis., to La Crosse Solutions, a subsidiary of radioactive waste disposal specialist Energy Solutions.

Dairyland Power Cooperative retired the plant in 1987 and filed with the commission last year to transfer the decommissioning and fuel storage license to La Crosse Solutions, which will lease the above-ground structures and assume decommissioning responsibility.

Energy Solutions has a similar arrangement with Exelon’s retired Zion nuclear plant in Illinois.

More: Nuclear Street

Environmental Groups Call for End to FERC Pipeline Review

penneastsourcepenneastNew Jersey opponents to the $1.2 billion PennEast natural gas pipeline project urged FERC to halt its review, contending the developers have failed to provide required information on the project.

The organizers of the 118-mile project, which would deliver 1 Bcf/d from the Marcellus Shale region in northeastern Pennsylvania primarily to New Jersey utilities, say they have provided all necessary information. “As PennEast moves through the FERC process, PennEast will continue to provide application information to FERC,” a company spokeswoman said.

The project has aroused organized opposition, especially in New Jersey, where opponents say 70% of the property owners along the proposed path refused to allow PennEast to survey their land, and municipalities have passed resolutions opposing it.

More: NJ.com

FERC Fines Coaltrain $37.5M For Sham UTC Trades

FERC last week fined Coaltrain Energy and its owners $37.5 million for fraudulent up-to-congestion trades in PJM.
It also demanded the company disgorge $4.1 million in unjust profits. (See Traders Deny FERC Charges; Seek Independent Review.)

Coaltrain attorney Ken Irvin, of Sidley Austin, said the order “reflects the flawed process FERC uses and reiterates the need for our judicial system to impose the rigors due process provides. With ample transparency and cooperation on our part, we have shown compliance with the market rules and regulations. Our confidence remains that we have proven our case before FERC and will prove it in court too.”

More: IN16-4

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Order 719: FERC Balanced MMU Independence Against RTO Autonomy

After allegations of management interference led PJM to replace its internal market monitoring unit with an independent monitor in 2008, FERC had an opportunity to prohibit other RTOs from using the internal structure. Because it chose not to do so, the temptation for RTO officials to muzzle their MMUs still exists.

First in a Series

By Rich Heidorn Jr.

The independence concerns raised by former SPP Squelching MMU Independence, Former Monitors Say.)

FERC HQ (Copyright RTOInsider) - Order 719 - FERC Balanced MMU IndependenceFERC said the rules, which updated a 2005 policy statement, were needed to “improve the performance and transparency of organized RTO and ISO markets.” They prohibited RTO management from supervising their MMUs, and required, in most instances, that MMUs report directly to their RTOs’ board of directors.

But the commission rejected protections urged by some stakeholders — allowing RTOs to choose their structures and declining to provide job security protections for MMU employees.

RTO Choice on Structure

The commission allowed each RTO to decide through its stakeholder process whether it will have an external or internal MMU, or a hybrid structure using both. FERC also declined to remove MMUs from any oversight by the RTOs.

The commission ruled that the RTO boards would supervise market monitoring functions and that RTO management representatives on the board “be excluded from this oversight function.” However, it permitted MMUs to report to management “for administrative purposes, such as pension management, payroll and the like.”

“Removing the MMU from reporting to management will give it the separation needed to foster independence,” the commission said, promising to revisit the decision “if occasion demands.” However, it declined to conduct periodic reviews, as requested by the Federal Trade Commission.

Both internal and external monitors can face conflicts of interest, the commission noted. As the market operator, the RTO is one of the players a monitor is expected to critique. So are market participants, who are essentially the RTO’s constituents, with the ability to leave or switch RTOs.

Inherent Tension

Order 719 acknowledged this, citing the “inherent tension between [market] mitigation and the RTO or ISO goal of promoting new markets.”

An external monitor that is too critical could find itself unemployed when it comes time to renew its contract. In 2013, some PJM board members considered seeking a new monitor before state regulators pressured them to renew the RTO’s contract with Monitoring Analytics.

An internal MMU, on the other hand, can face peer pressure and management interference.

The commission also rejected a proposal by the American Public Power Association, Exelon and the Pennsylvania Public Utility Commission that it use the settlement that created PJM’s independent monitoring structure as a “best practice.”

“The provisions of that agreement were specific to one RTO and represented a negotiated balancing of interests,” the commission said. “It would be inappropriate to impose the specifics of that settlement on all other RTOs and ISOs.”

Core Duties

The Transmission Access Policy Study Group, an association of transmission-dependent electric utilities in 35 states, recommended that the “core” MMU duties — reviewing market performance, identifying ineffective market rules and making confidential referrals to the commission — be assigned exclusively to the external monitor in hybrid structures.

FERC disagreed.

“This solution might impose upon the RTO or ISO an MMU structure that it does not want,” the commission said, insisting its requirement that the monitors performing the core functions report to the board was sufficient. “This solution allows the RTO or ISO to structure its MMU function in the way it deems most suitable, while also ensuring that the market monitor that performs the core MMU functions enjoys the independence from management that reporting to the board accomplishes.”

It also rejected the Public Utility Commission of Ohio’s proposal that monitors report to a federal-state board independent of both the management and boards of RTOs. “Not only does an arrangement of this type raise jurisdictional concerns, it is difficult to see how such a potentially cumbersome structure could oversee MMUs in a timely and responsive manner. … Should the reforms we adopt in this final rule fail to achieve the needed independence we envision for MMUs, we will not hesitate to rectify the situation.”

Employee Protections

Some commenters proposed that major changes in MMU status, such as termination of employment, be subject to FERC review, a requirement included in the contracts that PJM, MISO, ISO-NE and SPP (which then had a hybrid structure) signed with outside monitors. The commission, however, said it did not want to impose “a ‘one size fits all’ requirement on the remaining RTOs or ISOs absent their consent.”

“Should the situation arise in which an RTO or ISO terminates its MMU in such a way as to violate its tariff requirements concerning MMU independence, the commission will address such a violation on a case-by-case basis,” it said.

Order 719 in Summary

Below is a summary of Order 719’s requirements. Except in direct quotations, this article will use “RTOs” or “grid operators” to refer to RTOs and ISOs.

Functions

The commission limited MMU functions to three: evaluating the effectiveness of market rules, tariff provisions and market design elements (and proposing changes where needed); reporting on market performance; and referring suspected wrongdoing to the commission.

It also broadened the monitors’ reporting duties — requiring them to refer to the commission any misconduct by the grid operators as well as by market participants — and expanded their referral obligations to include market design flaws in addition to tariff and rule violations.

RTO Review of MMU Reports

FERC said RTOs may require their MMUs to submit reports in draft form for RTO review and comment but could not alter the reports “or dictate the MMU’s conclusions.”

“RTOs or ISOs need not require submission of draft reports, but if they do, input from knowledgeable employees may serve to strengthen the end product or catch errors of fact or reasoning,” the commission said. “In any event, the MMU is free to disregard any suggestions with which it disagrees.”

APPA opposed giving RTOs advance review of MMU reports, saying FERC should impose the same prohibition against such review as was included in the PJM-MMU settlement. The settlement resulted from Monitor Joe Bowring’s complaint at a FERC technical conference in 2007 that PJM ordered him — then a PJM employee — to modify the State of the Market Report and delayed the release of another MMU report because management disagreed with his conclusions.

Market Mitigation Role

The market mitigation role of external MMUs was limited to retrospective mitigation and the calculation of inputs required for the RTOs to conduct prospective mitigation. The separation was made because of concerns that an MMU would have a conflict of interest in proposing prospective market mitigation and then opining on how the resulting market rules worked. It also separated the duties of internal and external MMUs for RTOs with hybrid structures.

In its Notice of Proposed Rulemaking, FERC proposed that MMUs be removed from tariff administration, including market mitigation, “to free MMUs from a role that might make them subordinate to the RTO or ISO.” The proposal “engendered heated disagreement” by commenters, the commission said.

SPP, the Electric Power Supply Association, some industrial customers and several utilities supported the commission’s proposal. But more commenters opposed it, including Potomac Economics, other industrial customers and utilities, the Organization of MISO States, the National Association of Regulatory Commissioners and regulators from California, Maine, New York and Ohio.

The opponents said RTO officials who have designed and implemented the markets — and whose compensation may be based on market growth — may have a greater conflict of interest than the MMU. As FERC described the argument, RTOs would be disincented from imposing enforcement measures “on what in effect are their customers, or in refraining from mitigating a member that threatens to leave the RTO or ISO.”

FERC said it took seriously comments that “the MMU serves as a useful buffer between the RTO or ISO and the market participants, performing what is often viewed as a hostile act.”

Ultimately, the commission chose a compromise that it said “strikes the appropriate balance between allowing modified participation by the MMUs in mitigation, while protecting against the conflict of interest and subordination inherent in their unfettered participation.”

The commission said RTOs may allow their MMUs to conduct retrospective mitigation because it is only prospective mitigation — that which can affect market outcomes on a forward-going basis, such as altering the prices of offers —  that creates a potential conflict of interest for an MMU.

The commission also said the MMU may provide inputs required by the RTO to conduct prospective mitigation, including determining reference levels, identifying system constraints and calculating costs.

Information Sharing

The order required MMUs to report on market performance at least quarterly to commission staff, state commissions and RTO management and boards. MMUs must conduct regular conference calls for FERC, state commissions and RTO staff, as well as market participants.

It cut the lag time for the release of offer and bid data to three months from six but allowed RTOs to propose a shorter period — or, if the RTO demonstrates a collusion concern, it may propose a longer lag. The identity of market participants remained masked, although RTOs were permitted to propose a time period for eventual unmasking.

Requests for Information

State commissions were permitted to make “tailored” requests for information from the MMUs, limited to information regarding general market trends and the performance of the wholesale market. “If this limitation were not imposed, the MMU could rapidly become an unpaid consultant for the states, and would be unable to perform its core functions,” the commission said.

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PJM Markets and Reliability Committee Briefs

Barry Trayers of CitiGroup Energy won endorsement from the Markets and Reliability Committee for his proposal to add an acceptable reason for early capacity replacement to Manual 18: PJM Capacity Market.

After Trayers agreed to remove the words “wind” and “solar,” the motion passed with three objections and six abstentions.

The change adds the following as an acceptable reason for early replacement: “If the replacement resource’s capacity is not affected by its outage rate, such as cleared incremental auction buy bids, the replacement transaction can be completed at any time.”

“The reason is the deal’s already done,” Trayers said. “There’s a sale and a purchase, and you’d like to merge those in your portfolio and know where you stand.”

End of Life Senior Task Force has New Name, Charter

Members approved a charter for the Transmission Replacement Process Senior Task Force, previously referred to as the End of Life Senior Task Force.

The group will be tasked with developing ways to provide more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)

New Issue for Energy Market Uplift Senior Task Force

virtual transactions - PJM Markets and Reliability Committee BriefsThe committee approved revisions to the Energy Market Uplift Senior Task Force charter to incorporate a problem statement and issue charge regarding the review of virtual transaction rules.

The group will study biddable nodes and the application of uplift and determine whether recommendations from PJM’s
October 2015 white paper on virtual transactions should be implemented. (See PJM Suggests Changes to Virtual Transactions.)

PJM is awaiting a related FERC Issues Request for Comments in UTC Uplift Docket; Ruling by October?)

Stricter Standards OK’d for Project Queue Submittal

Members approved the Earlier Queue Submittal Task Force’s recommended Tariff revisions, which would require earlier submittal of documentation in order for projects to secure a place in the interconnection queue.

The revisions will be presented for endorsement to the Members Committee at its June 30 meeting. (See “New Project Submittal Process to Require Earlier Filing of Documents,” PJM Planning Committee and TEAC Briefs.)

Tweaks to DER Problem Statement OK’d

Members approved clarifications to the previously approved distributed energy resources problem statement. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM Markets and Reliability Briefs.)

The changes recast the entry of distributed resources into the PJM market as having “unique challenges” instead of being “cost-prohibitive and time-consuming.”

Members Hear First Reads on PLS, Tx Equipment Upgrades

  • Members heard the first read of a proposal to update the parameter limited schedule exception process to permit more flexibility.
  • Paul McGlynn, senior director of planning, presented a first read of a proposal to except transmission substation equipment upgrades from the competitive window. (See “Typical TO Upgrades Would be Excluded from Competitive Window Under Proposal,” PJM Planning Committee and TEAC Briefs.)

Real-Time Values Added to Manual 11

The committee approved changes to Manual 11: Energy and Ancillary Services Market Operations that incorporate real-time values.

The changes allow a market seller to communicate a unit’s actual operating parameters to PJM before and after the day-ahead market closes when the unit cannot operate for certain reasons.

The language stipulates that real-time values may be used to modify the turn-down ratio, minimum run time, minimum down time, maximum run time, start-up time and notification time, and they can be made whole due to an actual constraint.

Committee Unanimously Endorses Manual Changes

The following manual changes were approved Thursday:

– Suzanne Herel