Page 1644 – RTO Insider

June 5, 2016April 15, 2025

10 Years After: FERC Conference Focuses on Grid Resiliency

By Rory Sweeney

While FERC’s technical conference last week was ostensibly focused on reliability, resiliency became the theme as many panelists agreed: It’s not possible to avoid a major grid disruption forever (AD16-15).

Miranda Keating Erickson - FERC grid reliability

Erickson © RTO Insider

Speaking from recent experience, Miranda Keating Erickson, vice president of operations for the Alberta Electric System Operator (AESO), put a fine point on it.

“We must remember that no amount of standards can prevent all events from happening that will impact the reliability of our electricity system. Snow storms will happen. Ice storms will happen. Tornados and hurricanes will happen. As I well know, floods and wildfires will happen,” she said, referring to the Fort McMurray wildfire, which has destroyed 2,400 homes and buildings and caused the largest wildfire evacuation in the province’s history since it began May 1.

Koonce © RTO Insider

“And let’s not kid ourselves; at some point, somewhere, cyber and physical attacks will happen. That means resiliency is just as important as prevention. It is critical that we also focus on our ability to minimize impacts and improve response and recovery time when these events do occur.”

FERC called the conference to mark the 10 years since Congress gave the commission the power to impose mandatory reliability standards. The commission asked speakers to identify the accomplishments of the last decade and the challenges of the future.

Weather vs. Operational Failures

Cauley © RTO Insider - FERC grid reliability — Cauley © *RTO Insider*

Gerry Cauley, CEO of NERC, which was designated by FERC to develop and enforce the standards, started the conference by noting that the 10 largest grid “integrity events” each year from 2012 through 2015 were caused by weather. The last operational issue to make the list was in September 2011.

Cauley, however, cautioned that the shift to natural gas and intermittent generation will require renewed focus on issues such as ramping, frequency control, voltage control and inertia. “As we move forward with this evolution, however, we are experiencing a change of operating characteristics for the grid,” he said.

He highlighted measures being recommended by NERC’s Essential Reliability Services Task Force that would provide better monitoring and control of frequency and voltage.

Gas Dependence

Clark © RTO Insider - FERC grid reliability — Clark © *RTO Insider*

Others agreed that the increasing dependence on natural gas generation is impacting grid stability.

FERC Commissioner Tony Clark noted that it’s a “challenging prospect to conceive how those [gas] assets can be physically protected.”

Paul Koonce, CEO of Dominion Generation Group, who spoke on behalf of the Edison Electric Institute, urged the importance of building out the necessary natural gas infrastructure, including long-haul pipelines, to ensure the gas can be moved easily.

Honorable © RTO Insider

Paul Stockton, the managing director of D.C.-based consulting firm Sonecon, thanked FERC for its recent reports on the interdependence of the natural gas and electricity industries, calling them “terrific work.”

“I would ask you to continue to focus on the challenges of the resilience of black-start capabilities … [and] the increasing reliance of many companies on natural gas as a source of fuel for their generators,” said Stockton, former assistant secretary of defense for homeland defense. “This, my friends, deserves careful attention.”

Physical Security, Cyber Threats

Stockton © RTO Insider - FERC grid reliability — Stockton © *RTO Insider*

Stockton was among several speakers who noted growing concerns with cyber and physical security. Cauley cited the threat of a physical attack on infrastructure as his greatest worry “because of the potential long-term impact and the difficulty recovering, possibly lasting weeks and months.” (See Critics: Koppel Doomsday Scenario Ignores Prep.)

Patricia Hoffman, the Energy Department’s assistant secretary for electricity delivery and energy reliability, said the growing impact of distributed energy resources has created new needs. “The need for new metrics, new kinds of data and new data-sharing protocols is just as important at the distribution level as at the bulk-power level,” she said. “In fact, this need is probably more challenging than at the bulk-power level, if only because we are starting from a less developed base.

Hoffman © RTO Insider

“The grid is the battery for the system. It’s basically the backup for the system,” she said. She voiced concern that security threats will be “malicious in nature” and not addressed simply by preparing for N-1 contingencies. “Unfortunately, these investments are not valued by the market.”

Clark expressed hope that NERC’s cost-effectiveness method pilot program will result in new strategies. “Personally, I hope [it] will lead us to some important discoveries regarding how costs can be better contemplated and assessed in the standards-development process.”

Koonce also supported many of NERC’s recommendations and counseled that FERC review issues in a “broad context and with systemwide considerations.”

Eto © RTO Insider

“Corporate strategic and management actions rest on a strong foundation, and decisions are made with great care and deliberation. Application of these business principles to NERC and electric reliability would naturally invite broad long-term strategic questions, questions that will very likely yield different answers when compared to looking at day-to-day problems or events, or individual components,” he said.

Koonce said that EEI believes version 5 of NERC’s Critical Infrastructure Protection standards is an “appropriate and reasonable approach.” But, he added, “vendor management risks under consideration by the commission for potential new NERC requirements to address cyber-related asset procurement raises some broad questions on the business risks beyond the control of jurisdictional entities, as well as the reach of commission jurisdiction.”

Ilic © RTO Insider - FERC grid reliability

Ilić © RTO Insider

Flexibility was also a big concern for Erickson, who noted AESO’s ability to consider NERC standards and decide if they want to adopt them.

For Joseph Eto, a staff scientist with Lawrence Berkeley National Laboratory, the question was what’s not being considered? “Not all that counts can be counted and not all that can be counted counts,” he said, quoting an adage. He urged expanding metrics on interruptions to calculate the economic impacts on customers.

Complexity, Standardization

Anna Scaglione - ferc grid reliability — Scaglione © *RTO Insider*

Carnegie Mellon University professor Marija Ilić summed it up, saying what worries her most is the sheer complexity of the system. The 2003 blackout could have happened anywhere, she said, but also could have been prevented if complexity were handled in more systematic way.

“It’s my belief that we’re going to have more of those events,” she said.

While there was consensus on the importance of maintenance and tree trimming, there was disagreement over whether the industry should standardize equipment. Several industry representatives noted that equipment is sized specifically for its intended use. Arizona State University professor Anna Scaglione, however, said resistance to standardization was as much about lack of vision as engineering — a “cultural problem of industry,” she called it, where no one is considering the interoperability of equipment.

Mexico Looking to Interconnect

There was also input from the Navy and Mexico.

LaFleur © RTO Insider

Chris Murray, the project support lead for the Navy’s Renewable Energy Program Office, said the military branch is highly supportive of efforts to increase energy security and is open to having infrastructure projects sited on its properties throughout the country. “If there’s land on our base that you think makes sense, let us know,” he said. “We are marching down a path that most folks haven’t done in the government. … Things are changing and we need your help.”

Chris-Murray-web - ferc grid reliability

Murray © RTO Insider

Hector Beltran, the director general of Mexico’s Energy Regulatory Commission, said his country is making strides to develop its bulk-power systems and hopes to create a system reliable enough to integrate with the North American system very soon.

Mexico awarded its first round of long-term generation contracts in March, he said, and plans to build a series of interconnections along the border with the U.S. so that the networks can freely interact with each other. He noted that the following day, representatives from both the Mexican and American power industries were meeting in Mexico City to identify collaboration opportunities.

June 3, 2016May 27, 2025

Riverstone to Acquire Talen in $1.8B Deal

By Rory Sweeney

Barely a year after it went public as an independent company, Talen Energy is going private.

The company announced Friday that it had agreed to be acquired by Riverstone Holdings, which is offering $14/share in cash for the company’s outstanding shares, a $2 premium to the closing price Thursday. While the total cost of the stock will be approximately $1.8 billion, the deal has a total value of approximately $5.2 billion including assumed debt. It is expected to close by the end of the year.

Talen was formed last June from the merger of PPL’s generation assets with some of Riverstone’s power plants. Through its affiliates, Riverstone already owns a 35% stake in the Allentown, Pa.-based competitive power producer, which owns or controls 16 GW of capacity in eight states. Most of Talen’s capacity — which is divided between gas (47%), coal (39%) and nuclear (14%) — is in PJM and ERCOT.

Tough competition and tight profit margins battered Talen’s valuation from the beginning, and analysts saw Riverstone’s move as a chance to buy the assets at a bargain.

Formed during a period of historically low natural gas prices, Talen’s stock started to drop the day it hit the exchange and never fully recovered, losing more than half its initial value of $21.23/share within five months. On news of the deal, Talen’s stock — which had been rising amid rumors of the deal — jumped nearly $2/share to settle just shy of the $14 Riverstone is offering.

Talen noted in its announcement that the purchase price represents a 56% premium to the closing price of $9/share on March 31, 2016, the last trading day before public reports of the potential sale CEO Paul Farr said the deal “offers compelling value to our stockholders.”

The agreement provides a 40-day period for Talen to find a better deal and another 20 days to enter into a transaction. Should Talen accept a superior proposal during the “go-shop” period, Talen will pay $25 million to Riverstone. Otherwise, its cost to terminate the agreement for a superior proposal will be $50 million.

The deal is being funded by conversion of Riverstone’s existing Talen stock, Talen’s cash on hand and a $250 million new secured-term loan.

In a research note Friday, UBS Securities suggested Talen shares might rise further on expectations of a better offer.

“With a relatively small go-shop fee and even more secured debt capacity … we would not be surprised to see shares even trade above $14,” UBS said.

UBS said Talen fared worse than its peers in last month’s PJM capacity auction, with fewer assets clearing than last year. It estimated that Talen’s PJM capacity revenue will decline by $230 million to $320 million.

The deal is subject to approval by FERC and the Nuclear Regulatory Commission as well as the 65% non-Riverstone shareholders.

“The scenario under which a deal might not be approved [by shareholders] is if commodities rallied prior to shareholder approval date such that the bid was no longer commensurate with the market environment,” UBS said.

But the analysts said shareholders are unlikely to see another suitor willing to pay more because other independent power producers already have concentrations of generation that would likely trigger market power screens. Talen’s coal generation is anathema to Calpine, and its Susquehanna nuclear plant is likely to scare off anyone not already running a nuclear fleet, UBS said. Dynegy and NRG Energy are in restructurings and unlikely to be able to make a purchase, they added.

“Despite the argument that the company is being bought effectively using its own liquidity and leverage capacity, we do not see an obvious outside bidder desiring to pay such a premium,” they said.

June 2, 2016

Court Dismisses Complaint vs. Northern Pass

By William Opalka

A New Hampshire court has dismissed a complaint by a conservation organization seeking to block development of land alongside a state highway needed to bury a section of the Northern Pass transmission line.

The Coos County Superior Court said the Society for the Protection of New Hampshire Forests cannot deny access to project developers in its attempt to halt the line, saying the decision ultimately rests with state transportation officials (15-CV-114). (See Northern Pass Facing Challenges over Siting.)

The organization owns a parcel of land along Route 3 in northern New Hampshire known as the Washburn Family Forest, and it granted easements to the state Department of Transportation in 1931 for road construction through the land.

The society argued that those easements did not include underground construction, but the court disagreed.

“The court finds that under the plain language of [state law], NPT’s proposed use is a proper use of the public highway easement … [and] the DOT has exclusive jurisdiction over whether to grant NPT a permit to install the proposed transmission line below the stretch of Route 3 at issue,” Judge Lawrence A. MacLeod Jr. wrote in the May 26 opinion.

The court also declined to consider the merits of the 192-mile line, which would transmit 1,090 MW of Canadian hydropower to the New England market. It said such questions were “speculative” until the DOT gave its approval.

“The DOT, not this court, must decide … whether a proposed project meets the ‘public good’ requirement of” state law, the court said.

The society said it was not surprised by the ruling.

“The decision effectively kicks the can down the road relative to the ultimate resolution of important property rights issues involving Northern Pass, the DOT and private landowners,” spokesman Jack Savage said in a statement. “We note that the state Constitution expressly prohibits the use of the state’s power of eminent domain for elective transmission projects and would have preferred not to wait for the DOT to potentially issue a license before resolving that constitutional conflict.”

Savage told RTO Insider on Wednesday an appeal to the New Hampshire Supreme Court is one option under consideration.

Project developer Eversource Energy lauded the ruling.

“We are pleased the court recognized long-standing New Hampshire law that allows for the use of public roadways for projects like Northern Pass,” Bill Quinlan, president of Eversource Operations in New Hampshire, said in a statement. “We look forward to continuing the permitting process and moving one step closer to delivering the clean energy and economic benefits to New Hampshire and the region.”

Developers Seek Shorter Schedule

On Tuesday, Northern Pass Transmission, an Eversource subsidiary, asked the state’s Site Evaluation Committee for a written decision on its application by June 30, 2017.

“The proposed schedule seeks to strike a balance between the statutory requirement to complete the evaluation within 12 months and the need for adequate time to evaluate a project the size and scope of Northern Pass,” NPT said in a statement.

The committee last month informally indicated it would need nine more months than the year required by state law for its study of the project route, which would push its decision back to about Sept. 30, 2017. In a motion filed Monday, NPT is asking for a ruling three months earlier. A formal ruling by the committee on its schedule is pending. (See Northern Pass Decision Delayed Nine Months.)

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

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.”