Page 1641 – RTO Insider

June 2, 2016May 27, 2025

FERC Approves CAISO’s Aliso Canyon Response Plan Ahead of Summer

By Robert Mullin

FERC on Wednesday approved CAISO’s plan to temporarily alter its market rules and operations in response to natural gas pipeline restrictions stemming from the closure of the Aliso Canyon storage facility (ER16-1649).

The grid operator last month sought expedited approval for the Tariff changes, designed to ensure reliable operations in Southern California in the face of potential gas shortages this summer — the region’s peak period for power generation. (See CAISO Board Approves Aliso Canyon Response.)

The commission also directed staff to convene a technical conference to evaluate the effectiveness of the provisions and determine the need for additional longer-term measures, addressing a concern of a number of CAISO stakeholders.

“Substantial efforts have been made by CAISO, California regulators and the energy companies to enhance planning and preparation, communication and coordination, and situational awareness,” FERC Chairman Norman Bay said in a statement. “That being said, the situation remains a serious one, and we will continue to monitor Aliso Canyon very carefully.”

Under new pipeline requirements effective June 1, Southern California Gas customers face penalties as high as 150% of daily gas indices when their daily burn deviates from nominated flows by more than 5%. The region’s generators have complained they would likely incur financial losses when the ISO’s real-time dispatch instructions cause them to burn more or less gas than planned for on a given operating day.

The new market rules will help generators manage their burns to avoid system-balancing penalties and allow them to recover costs after the fact, while ensuring the ISO is capable of moving generation into the region when gas supplies are constrained.

Key provisions of the plan include:

The release of advisory schedules by CAISO two days ahead of an operating day to help scheduling coordinators plan for gas procurement further in advance;
Inclusion of a gas adder and an after-the-fact cost recovery mechanism for generators connected to the SoCalGas system, allowing those units to recover costs based on same-day gas prices — including potential penalties — rather than day-ahead gas indices;
Implementation of a new constraint in the CAISO market that limits the minimum and maximum amount of gas that can be burned by generators in the affected area during periods of restricted gas supply;
Reservation of transmission capability on the Path 26 transmission line linking the Pacific Gas and Electric (PG&E) and Southern California Edison service territories in order to ensure adequate capacity to deliver energy into the southern part of the state during gas restrictions; and
Suspension of virtual bidding in circumstances when CAISO determines the practice could produce market inefficiencies.

FERC rejected a request by NV Energy and Calpine for CAISO to develop a gas adder for generators located outside the SoCalGas network. The two companies contended that limited gas supplies in that system would likely drive up fuel prices in neighboring areas. The commission instead determined that the adders are designed to specifically address the conditions confronted by Southern California gas-fired generators, which “need a mechanism by which to manage gas-balancing requirements within tightened tolerance bands.”

“This is not the case with resources outside of Southern California,” the commission said.

The commission also rejected PG&E’s request that the ISO perform a market simulation before rolling out the plan, saying that “timely implementation of these market changes outweigh the potential benefits of requiring market simulation in this instance.”

The commissioners additionally declined a request by NRG Energy that CAISO be ordered to implement long-term changes to its market rules related to gas cost recovery by Dec. 1, 2016. During stakeholder calls earlier this year, the company repeatedly raised concerns about its exposure to increased gas costs and balancing penalties.

“We find that it is premature to require CAISO to implement long-term changes by a date certain when the scope and duration of any potential problems are currently unknown,” the commission said, adding that those measures should be addressed in the upcoming technical conference.

June 2, 2016

Exelon to Close Quad Cities, Clinton Nuclear Plants

By Suzanne Herel

Exelon will close its Clinton and Quad Cities nuclear plants after the Illinois General Assembly adjourned this week without acting on a bill that would have subsidized the money-losing stations, the company said Thursday.

Clinton will shut down next June 1, and Quad Cities will close the following year. Together, the plants have lost $800 million in the past seven years, Exelon said.

exelon, clinton, quad cities, — Clinton Nuclear Plant *Source: Exelon*

The company will be submitting permanent shutdown notifications to the Nuclear Regulatory Commission within 30 days. Among other steps toward closure, Exelon will be ending capital investment projects at the plants, taking a one-time charge of $150 million to $200 million for the year, accelerating about $2 billion in depreciation and amortization and canceling fuel purchases and outage planning, Exelon said.

Ceasing the investment projects will impact more than 200 workers, and more than 1,000 outage workers will be affected, according to the company.

“We have worked for several years to find a sustainable path forward in consultation with federal regulators, market operators, state policymakers, plant community leaders, labor and business leaders, as well as environmental groups and other stakeholders,” CEO Christopher Crane said. “Unfortunately, legislation was not passed, and now we are forced to retire the plants.”

Crane had given legislators a May 31 deadline to help shore up the struggling generators if the 1,819-MW Quad Cities station did not clear the PJM Base Residual Auction for delivery year 2019/20. It failed to do so. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)

While the 1,065-MW Clinton plant won contracts in the MISO auction, its clearing price was insufficient to cover operating costs, Crane said.

According to Exelon, their closures will represent a $1.2 billion loss in economic activity and 4,200 direct and indirect jobs. The plants employ 1,500.

Next Generation Energy Plan

The Exelon-backed legislation, called the Next Generation Energy Plan, incorporates pieces of a similar bill the company proposed last year as well as part of the competing Clean Jobs Bill. The latter proposal aimed to reduce energy demand by 20% through energy efficiency; increase the renewable portfolio standard from 25% by 2025 to 35% by 2030; and create an estimated 32,000 jobs annually by creating a market mechanism to reduce carbon emissions.

A key element of the new plan is a shift to a zero-based emission standard, which would provide financial support for struggling nuclear plants in recognition of their lack of carbon emissions.

Exelon said the standard would address stakeholder concerns by requiring state regulators to review plants’ expenses to ensure that only those whose revenues are insufficient to cover their costs and “operating risk” would receive compensation.

On Friday, the bill received the endorsement of Ameren Illinois, but on the condition of an amendment changing energy efficiency targets that could make it unpalatable to environmentalists.

In introducing the energy plan, Exelon said it was an outgrowth of discussions among it, Commonwealth Edison and members of the Clean Jobs Coalition, a group representing Illinois’ environmental, business and faith communities.

The coalition supports the bill’s expansion of ComEd’s energy efficiency programs, which it said would save customers at least $4 billion over a decade. But it said the Ameren amendment would exclude that utility’s customers from the expansion.

“While ComEd has offered a strong energy efficiency plan, the Ameren proposal … is a half-measure that will leave downstate customers with fewer jobs and higher bills than people in Chicago and Northern Illinois. Ameren is really leaving Central and Southern Illinois in the dark,” the coalition said in a statement.

Exelon said it will continue to push the legislation.

“While these needed policy reforms may come too late to save some plants, Exelon is committed to working with policymakers and other stakeholders to advance an all-of-the-above plan that would promote zero-carbon energy, create and preserve clean-energy jobs, establish a more equitable utility rate structure and give customers more control over their bills,” it said.

A ‘Tragedy’

Marvin Fertel, CEO of the Nuclear Energy Institute, issued a statement calling the plants’ closure “a tragedy” that threatens the “nation’s ambitious clean air commitments.”

“At-risk nuclear plants are struggling because the electricity markets do not appropriately value the attributes of nuclear plants, including reliable electricity generation and their carbon-abatement value. This is fixable, but federal and state policymakers, the Federal Energy Regulatory Commission and regional electric system operators must address these shortcomings with urgency to prevent other power plants from shutting down prematurely.”

June 1, 2016

Ill. Lawmakers Fail to Address Exelon, Dynegy Legislation

By Suzanne Herel and Amanda Durish Cook

The Illinois General Assembly adjourned Tuesday without acting on a bill that Exelon says it needs to save the Clinton and Quad Cities nuclear plants.

“At this time, the future of the Next Generation Energy Plan remains unclear,” Exelon said. “We’ll have more to say about the path forward within the next few days.”

Lawmakers also failed to act on a proposal by Dynegy to transition all of Illinois generation into the deregulated PJM market. (See Dynegy Introduces Bill to Move all of Ill. into PJM.)

“We knew it would be a challenge when the legislature is working through competing budget shortfall issues. We will continue to work with the legislature and other interested parties throughout the summer to implement a comprehensive energy solution for Illinois,” said David Onufer, external communications manager at Dynegy.

The Houston-based company wants to move the Commonwealth Edison and Ameren service areas in Central and Southern Illinois from MISO Zone 4 into PJM, saying the retail-choice state is a mismatch in MISO’s markets.

Exelon’s Deadline

exelon, clinton, quad cities, illinois legislature — Clinton Nuclear Plant *Source: Exelon*

CEO Christopher Crane had given legislators a May 31 deadline to help shore up the money-losing nuclear plants if Quad Cities did not clear the PJM Base Residual Auction for delivery year 2019/20. It failed to do so. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)

While the 1,065-MW Clinton plant won contracts in the MISO auction, its clearing price was insufficient to cover operating costs, Crane said.

If Exelon sticks to its word, it will close Clinton next June and the 1,819-MW Quad Cities plant the following year.

Together, the facilities have lost $800 million from 2009 to 2015, Crane said. According to Exelon, their closures would represent a $1.2 billion loss in economic activity and 4,200 direct and indirect jobs. The plants employ 1,500.

Revised Plan

The Next Generation Energy Plan incorporates pieces of similar legislation introduced last year by Exelon along with the competing Clean Jobs Bill. The latter proposal aimed to reduce energy demand by 20% through energy efficiency; increase the renewable portfolio standard from 25% by 2025 to 35% by 2030; and create an estimated 32,000 jobs annually by creating a market mechanism to reduce carbon emissions.

A key new element of the plan is a shift to a zero-based emission standard, which would provide financial support for struggling nuclear plants in recognition of their lack of carbon emissions.

The company said the standard would address stakeholder concerns by requiring state regulators to review plants’ costs to ensure that only those whose revenues are insufficient to cover their costs and “operating risk” will receive compensation.

On Friday, the bill received the endorsement of Ameren Illinois, but on the condition of an amendment changing energy efficiency targets that could make it unpalatable to environmentalists.

In introducing the energy plan, Exelon said it was an outgrowth of discussions among it, ComEd and members of the Clean Jobs Coalition, a group representing Illinois’ environmental, business and faith communities.

The coalition supports the ComEd bill’s expansion of energy efficiency programs, which it says would save customers at least $4 billion over a decade. But it says the Ameren amendment would exclude that utility’s customers from the expansion.

June 1, 2016

FERC Rejects Ramp Rate Exception in PJM Capacity Rules

By Suzanne Herel

FERC on Tuesday rejected PJM’s Tariff changes that would have exempted a capacity resource from nonperformance charges if it was following the RTO’s dispatch instructions and operating at an acceptable ramp rate during periods of high load.

The changes, approved in April by the Members Committee after months of stakeholder debate, were designed as an interim solution to guard against generators self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges. Such behavior, PJM said, would pose operational challenges and create reliability issues. (See “MRC, MC Endorse Interim Ramp Rate for Performance Assessment Hours,” PJM Markets and Reliability and Members Committee Briefs.)

“Given the importance of the penalty structure to the Capacity Performance design, we … must carefully weigh whether the operational concerns documented in the record justify the negative impact that PJM’s proposed penalty exemption would have on these performance incentives,” FERC ruled. “We conclude that PJM has not met that burden here” (ER16-1336).

Under PJM’s proposal, resources’ energy offers would include a historical three-month average ramp rate.

The Independent Market Monitor and LS Power said that PJM had not proven its assertion that self-scheduling before an emergency period would cause operational issues.

“According to the Market Monitor, if resource owners self-schedule their resources in anticipation of tight conditions in the energy market, it is less likely that emergency procedures would be triggered and would instead indicate that nonperformance charges are working as intended to incent generation to operate during high-demand conditions,” FERC said.

“The Market Monitor argues that PJM’s proposal is discriminatory and disincents flexibility by holding more flexible resources (i.e., those with faster ramp rates) to a higher standard for expected incremental megawatts during a performance assessment hour than less flexible reserves.”

Calpine and Rockland Capital argued that generators should not be excused from penalties because of their choice of the type of capacity they offer into the market.

The PJM Power Providers Group, the Delaware Public Service Commission and Dayton Power and Light supported PJM’s proposal.

In rejecting the Tariff changes, FERC quoted from PJM’s own initial filing proposing Capacity Performance, which said, “Parameter limits should not be viewed as a permanent entitlement to underperform. Instead, those limits should be exposed to financial and market consequences: If sellers of resources with fewer operating limits earn more from the capacity market … than sellers of resources with more restrictive operating limits, then all sellers will be incented to find ways to minimize those operating limits, which should over time increase overall fleet performance and benefit loads in the region.”

May 31, 2016

KCPL’s Parent Great Plains Energy to Buy Westar for $12.2 Billion

By Ted Caddell

Great Plains Energy, the parent of Kansas City Power and Light, announced Tuesday it would buy Westar Energy for $12.2 billion in a deal that will give Great Plains a customer base of 1.5 million in Kansas and Missouri, nearly 13,000 MW of generation and 10,000 miles of transmission lines.

Great Plains will pay $8.6 billion in cash and stock while also assuming $3.6 billion in Westar debt.

Under the terms of the agreement, Westar shareholders will receive $60/share, consisting of $51 in cash and $9 in Great Plains common stock. Westar closed at $52.92/share on Friday.

Talk of a Westar acquisition has been percolating through the industry for weeks, with Ameren named as one of the potential buyers. Bloomberg reported earlier in the month that an investment group from Canada was also eyeing Westar.

But it was Great Plains that clinched the deal. Great Plains and Westar currently co-own and operate the 1,200-MW Wolf Creek Nuclear Generating Station, as well as the 1,418-MW La Cygne and 2,155-MW Jeffrey coal plants.

“Westar and KCP&L are trusted neighbors and have worked together for generations in Kansas. The combination of our two companies is the best fit for meeting our region’s energy needs,” said Terry Bassham, CEO of Great Plains Energy and KCP&L.

“This is an important transaction for Kansas and our entire region. By combining our two companies, we are keeping ownership local and management responsive to regulators, customers and regional needs, while enhancing our ability to build long-term value for shareholders.”

Bassham said the merger would create efficiencies that would help reduce future rate increases resulting from increasing environmental standards, cybersecurity threats and slow demand growth.

Great Plains, which operates as KCP&L and KCP&L Great Missouri Operations, has been growing. In 2008, it acquired Aquila, an electric utility that operated adjacent to its territory in Missouri. Headquartered in Kansas City, Mo., it has more than 838,000 customers in Missouri and Kansas and owns about 6,446 MW of generation.

Westar, based in Topeka, Kan., has about 700,000 customers in east and east-central Kansas and about 6,267 MW of generation, mostly coal fired.

May 30, 2016

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.

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.

May 30, 2016June 5, 2024

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

May 30, 2016

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.

May 30, 2016

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.

Gary 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

May 30, 2016

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.)

“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.”