Page 1390 – RTO Insider

October 17, 2016

SPP Markets and Operations Policy Committee Briefs

LITTLE ROCK, Ark. — The SPP Markets and Operations Policy Committee endorsed a 41% increase in a delayed 345-kV project along the Red River in southeastern Oklahoma as reasonable and reset the project’s baseline.

American Electric Power was supposed to have upgraded a pair of substations and built 76 miles of transmission line between Valliant, Okla., and a substation outside Texarkana, located on the Texas-Arkansas border, for $131.7 million. That total has grown to $185.8 million following a two-year delay attributed mostly to weather. The project was supposed to be energized in October 2014, but that date has now slipped to December 2016.

AEP’s Brian Johnson said the company was late to notify SPP of the delay because of internal communication problems between project management and those reporting costs. He said the company didn’t realize how far the project was outside its bandwidth until July, calling the situation “embarrassing.”

The company attributed 51% of the cost overruns to extensive flooding along the 76-mile route. The project was also hampered by siting problems and a landowner group’s opposition. “It was a combination of everything,” Johnson said.

The Project Cost Working Group, which reviews projects when updated cost estimates fall outside a 20% bandwidth, passed the recommendation on to the MOPC with a no vote from Kansas City Power & Light and two abstentions.

SPP Regional Entity: Wind Farms not Meeting New Standards

SPP Regional Entity General Manager Ron Ciesiel said wind farms unfamiliar with new NERC standards for reactive power, voltage controls and frequency caused a spike in reported reliability violations during the third quarter.

SPP Markets and Operations Policy Committee Briefs — | *SPP*

There were 71 violations of the MOD-025-2 (Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability), PRC-019-2 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection) and PRC-024-2 (Generator Frequency and Voltage Protective Relay Settings) standards, most of them by individually registered wind farms.

“The only good news is they aren’t operating problems,” Ciesiel said. He said the violations resulted from wind generators’ lack of awareness with the new standards’ implementation plan and a shortage of third parties to conduct testing. Only 40% of the generation units covered by the new standards had their capability tested or settings verified by July 1, when the standards took effect, Ciesiel said.

The RE expects to report more than 200 violations this year, a number it hasn’t topped since 2011.

Ciesiel said 33 new or revised standards will take effect over the next 12 months.

Members Vote to Cancel 69-kV line in West Texas

The MOPC approved staff’s recommendation to withdraw a notice-to-construct (NTC) for the Hobart City-Roosevelt Tap-Snyder 69-kV line in West Texas, based on the availability of an AEP operating guide that can mitigate the congestion through pre-emptive redispatch.

fas4qawysjmhwbnlo9qd_full_spp-mopc-committee-rto-insider-alt-fi — | © *RTO Insider*

The project was one of five withheld from the 2016 Integrated Transmission Plan (ITP) Near Term portfolio to determine whether they were needed to solve Scenario 5, which assumes renewable energy operating at 100% capacity.

Staff found while there have been 17 hours of congestion in the area since 2014, the 2017 ITP 10-year study indicated there were no congestion hours or future needs for the project, which had an estimated cost of $31 million.

Southwestern Public Service’s Bill Grant abstained from the vote, saying he did not want to live with operating guides forever.

The committee also endorsed staff’s recommendation to accelerate the NTC for an Oklahoma Gas & Electric 345-kV circuit upgrade project, but to leave a SPS 230-kV circuit upgrade in West Texas as is.

SPP staff said OG&E’s Amoco–Sundown project is necessary to meet additional congestion expected from more than 300 MW of wind energy added to the system this summer. With more wind energy on the way in Oklahoma, staff pushed the project’s in-service date to April 2018, a year earlier than originally planned.

SPP’s recent Wind Integration Study pegged both projects for further analysis. (See Study: 60% Wind Penetration Possible in SPP.)

MWG Clears 15 Change Requests

The Market Working Group brought five revision requests to the MOPC, which approved all over a small handful of no votes and abstentions. The committee unanimously approved 10 more changes as part of its consent agenda.

A revision request concerning the triggering of shortage pricing (MWG-MRR175) generated the most discussion among members — some concerned over sudden price spikes, others over a lack of scarcity events. The change incorporates language to comply with FERC Order 825 by using shortage pricing for any interval in which energy or operating reserves are short during the resources’ pricing. The change applies to any shortage, regardless of the duration or its cause. (See FERC Issues 1st RTO Price Formation Reforms.)

“Price spikes that occur over certain intervals can wipe out the entire day,” Nebraska Public Power District’s Paul Malone said. “There doesn’t seem to be any discussion about what can be done to mitigate this stuff. You can’t respond to a $500 price spike over five-minute intervals.”

The MWG recommendation was pushed for approval this month because it is a compliance matter. SPP staff and the group will both continue working to improve the process.

“We’re going to go back and see if we can make it better,” said Richard Dillon, SPP’s director of market design. “Scarcity pricing … is becoming more prevalent in the industry. We’d like to take a second look and see if we can do something better than the industry.”

“This will happen,” said AEP’s Richard Ross, chair of the MWG. “We are motivated to do something else, and staff is motivated to do something else.”

The motion passed with three no votes and two abstentions.

Golden Spread Electric Cooperative cited Order 825 in opposing a related change, (MWG-MRR173), which replaces the terms “head-room” and “floor-room” with “instantaneous load capacity.” Golden Spread said procuring rampable capacity for instantaneous load change, hourly load forecast or variable resource output through reliability unit commitment “masks shortage conditions in a manner inconsistent with the requirements of FERC’s shortage-pricing rule.”

Other rule changes approved by the committee were:

MWG-MRR183: Updates the violation relaxation limits (VRLs) operating constraint based on staff’s annual analysis, allowing additional redispatch to solve cases with fewer violations. Golden Spread abstained.
MWG-MRR188: Gives staff the option to include up to 100% of instantaneous load capacity (as opposed to the current 0% of capacity) in clearing the day-ahead market, an effort to minimize the gap between day-ahead and real-time energy prices. The motion received nine abstentions.
MWG-MRR193: Adds rules for solar resources to the market protocols and Tariff, including incorporating a solar forecast in SPP studies, increasing the solar forecast’s accuracy and including solar resources in dispatchable variable energy resource registration. Nebraska Public Power District cast an opposing vote, contending behind-the-meter generation would be required to register in the market should their loads change and they end up injecting power onto the system.
BPWG-RR123: Removes obsolete language and clarifies SPP’s current practices for short-term service requests and the system impact study process.
MWG-MRR178: Specifies that SPP’s Market Monitoring Unit will review the costs included in each mitigated resource offer, on an ex-post basis.
MWG-MRR179: Aligns the protocols with FERC-approved language (ER15-2265) ensuring long-term congestion rights are not affected by potential resource hub terminations, and that resource hubs used in bilateral contracts can’t be unilaterally terminated by the hub’s owner.
MWG-MRR181: Corrects outdated references in the Tariff and protocols related to the allocation of annual auction revenue rights, an oversight noted by FERC (ER16-13).
MWG-MRR182: Removes the term “control area,” which is no longer used by SPP, from the market protocols.
MWG-MRR184: Exempts resources from charges when they clear the day-ahead market with real-time meter readings of zero following either decommitment by SPP or dispatch to zero.
MWG-MRR185: Clarifies which document — SPP Planning Criteria or SPP Operating Criteria — is referenced when used in the market protocols and Tariff.
ORWG-RR168: Requires transmission owners to provide the highest available emergency ratings and specifies SPP’s interpretation of those ratings.
RTWG-RR176: Corrects and clarifies the responsibilities and requirements under the process that allows generation resources to be compensated for reactive support.
TWG-RR174: Revises Attachment AQ of the Tariff to no longer require transmission customers to submit a request for changes in delivery point facilities without a corresponding change in load.

– Tom Kleckner

October 17, 2016

Board OKs Pay Hike, Change to Independence Rules

By Amanda Durish Cook

Members of MISO’s Board of Directors last week expressed support for increasing their pay and relaxing their independence requirements, saying the changes were needed to ensure the RTO can attract strong candidates.

Directors at an Oct. 14 conference call of the board’s Corporate Governance and Strategic Planning Committee indicated support for MISO’s proposal to prune the current two-year pre- and post-service prohibition on affiliations with RTO members, affiliates and market participants.

director independence requirements miso board of directors pay raise — MISO Board of Directors at its September meeting in St. Paul, Minn. | © *RTO Insider*

MISO first proposed reducing the prohibitions in August with three options: eliminating the rule entirely, reducing it to one year, or reducing the pre-service restriction to one year and eliminating the post-service one. The directors chose the third option.

The board had postponed action on the service restrictions at its September meeting. (See “For Now, MISO Bylaw Changes Minimal,” MISO Board of Directors Briefs.)

MISO Managing Senior Corporate Counsel Corrie Bilke said the pre-service restriction in MISO’s Principles of Corporate Governance is in line with other RTOs, but only MISO mandates a post-service restriction.

“Initially I was in favor of a post-service restriction, but after reviewing [other RTOs], I’m comfortable with eliminating the post-service restriction,” Director Phyllis Currie said.

“We are competing for talent. It seems like we shouldn’t place ourselves at a competitive disadvantage,” Director Paul Feldman said. He also said MISO should include language forbidding sitting board members from engaging in job interviews with prohibited entities.

Bilke said three MISO sectors that responded to a call for feedback on the proposed changes were supportive. After all members have weighed in on the changes through stakeholder meetings, the entire board will review the proposal at its December meeting.

MISO Proposes Upping Director Compensation

The committee also voted to approve a proposal by a consulting firm to increase board member compensation by $4,000 annually.

“We want to remain competitive in our compensation of board members,” MISO Vice President of Human Resources Greg Powell said.

Willis Towers Watson recommended increasing the director retainer from $55,000 to $89,000 while eliminating meeting fees for the first six scheduled board meetings and two annual strategic retreat meetings.

The firm also recommended eliminating board committee fees in return for a $9,000 committee retainer for the first six meetings with compensation of $2,000 for each additional meeting.

MISO should keep its director and committee chair retainers at $15,000 and $7,500, respectively, Willis said.

Board members’ total compensation would increase to $116,000 from $112,000. Committee chairs would be paid $124,000, up from $120,000, and the board chair would be boosted to $131,000 from $127,000.

Under MISO’s Transmission Owners Agreement and bylaws, the consulting firm’s recommendations will be enacted unless two-thirds or more of the members vote to reject them. No date has been set for a vote.

October 14, 2016

NRC IG Cites Cybersecurity, Licensing, Inspections

By Ted Caddell and Rich Heidorn Jr.

WASHINGTON — The Nuclear Regulatory Commission’s Inspector General last week issued his annual report on the agency’s most serious management and performance challenges, highlighting concerns over cybersecurity, reactor inspections and licensing.

The report, which summarizes previous audit findings, noted that “challenges do not necessarily equate to problems.”

“These challenges represent what [the Office of the Inspector General] considers to be inherent and continuing program challenges relative to maintaining effective and efficient oversight and internal management controls,” IG Hubert T. Bell said. “As a result, it is likely they will continue to be challenges from year to year.”

In addition to regulating about 100 commercial nuclear power generators and 31 research and test reactors, the commission is responsible for overseeing the safe use of radioactive materials used in medicine, academia and industry.

The IG cited the “increasing risks” to the security of NRC information systems and urged the agency to continue its efforts to develop new regulations for the “unique requirements of decommissioned nuclear power plants, which present different security considerations than operating plants.”

Bell cited concern over the commission’s Network Security Operations Center (SOC), staffed mainly by contractors, which is responsible for ensuring the security of the agency’s networks and monitoring it for suspicious activity. The commission’s contracts do “not clearly define SOC performance goals and metrics” and different departments work with different security function descriptions, the IG said.

nrc cybersecurity — NRC Operations Center | *NRC*

The result, as detailed in an audit in January, is confusion among NRC staffers and contractors about which policies and responsibilities govern the security work protecting NRC computer systems.

Another audit in March found the commission failed to collect identification cards from one-third of the 1,452 employees and contractors it terminated from 2014 through November 2015. “As a result, there is a risk of unauthorized physical access to NRC and other federal facilities,” the IG said.

The report also cites the IG’s second review of NRC’s response to the Reducing Over-Classification Act of 2010, which was enacted over concern that excessive classification increases information security costs and improperly limits public access to information.

The IG found that the commission had implemented the recommendations from a 2013 audit and said a review of NRC classification actions from April 2013 through January 2016 “revealed no systematic misclassification.” However, it said the agency “lacks a cohesive approach to records management of classified information” and has not reviewed classified records for disposition and declassification as required.

Other previous findings cited by the IG included:

A call for improving NRC’s licensing of Advanced Passive 1000 (AP1000) pressurized water reactors, a new design for which operators have never been licensed. Four AP1000 reactors are under construction in the U.S. and about 70 licensed operators will be required by 2020.
A risk of inconsistent reactor inspections because of a lack of clarity in the definition of mandatory and discretionary inspection procedures.
A finding that NRC lacked “a well-structured approach” for enforcing regulations governing the conditions under which licensees may make changes to their facilities or procedures, and conduct tests or experiments, without prior NRC approval.
Weaknesses in NRC’s process for determining the significance of reactor inspection findings. The IG said the the agency has not regularly evaluated resources needed for its Significance Determination Process workflow and has not communicated clear expectations to employees.

October 13, 2016

CAISO Seeks Process to Keep EIM, Governing Body in the Policy Loop

By Robert Mullin

CAISO is seeking stakeholder input on developing procedures to ensure that the Energy Imbalance Market’s governing body and participants have a say in ISO policy initiatives that affect the operation of the market.

The objective is to create a “guidance document” that spells out how CAISO staff should interact with the EIM, including a schedule for notifying the market’s governing body about ISO initiatives and the processes by which that body and EIM market participants will provide feedback on the issues.

The EIM governing body was appointed in June and convened its first meeting in late August. (See EIM Governing Body Convenes First Meeting, Selects Leadership.)

The idea for the guidance document originated with the EIM’s Transitional Committee, the West-wide stakeholder group that was responsible for creating the market’s overall governance plan.

“The purpose of [the plan] was to give stakeholders throughout the region a voice in the market rules that affect the EIM,” CAISO Lead Counsel Dan Shonkwiler said during an Oct. 11 call to discuss a draft proposal for the document. He said it is now up to the ISO to translate that plan into actual procedures.

Driving the effort is the fact that the governing body and the ISO’s Board of Governors hold overlapping authority over the approval of policies that affect both the EIM and the ISO’s broader market.

“The core of this [effort] is that the Board of Governors has delegated a part of its authority related to [Federal Power Act] Section 205 filings to amend the ISO Tariff to the EIM governing body,” Shonkwiler said.

That delegation of authority gave rise to the concept of “primary authority” for the EIM’s governing body: the right to approve or reject Tariff amendments specific to the operations of the EIM. When body members vote to approve a change, the board is expected to give “great deference” to the decision and place the matter into a consent agenda.

For amendments covering general market rules that also affect the EIM, the governing body is expected to play an “advisory” role in the initiative process, but it will not have a vote on the outcome.

Initiatives designated as “hybrid”— proposals that would amend multiple Tariff provisions affecting both the EIM and the ISO at-large — get more complicated treatment.

If the EIM is the primary driver of such an initiative, approval authority falls to the governing body. If the ISO is driving the changes, the governing body has primary authority over EIM-specific elements only. In either case, the ISO board must issue the final decision through a full vote.

The guidance document will seek to describe exactly how the governing body will exercise its advisory function for initiatives over which it has no voting power.

More important, the document will detail the process by which the governing body and EIM stakeholders can voice opinions about the ISO’s “tentative decisional designation” for an initiative.

To facilitate that process, the ISO is proposing to provide quarterly updates to the governing body about all upcoming initiatives including its decisional designations. After receiving an update, the body can decide which general ISO initiatives will require its advisory contributions. If the body thinks an initiative has been designated incorrectly, it can take up the matter with ISO staff, possibly heading off a future dispute over decisional authority.

After receiving stakeholder comments on a draft final proposal, ISO management would decide on an initial designation. If the chair of either the governing body or the board objects to the designation, they will meet to discuss the matter. In cases when the two disagree on a proper classification, a dispute resolution process is triggered in which public comment is solicited followed by a combined vote of both the governing body and the board.

CAISO is also proposing to implement a procedure that would split up hybrid initiatives to facilitate decisions.

Comments on the guidance document are due Oct. 18. The ISO plans to present a proposal to the EIM governing body in late November and seek approval from the board in mid-December.

With the Oct. 1 addition of Arizona Public Service and Puget Sound Energy, the EIM now has four market participants, with other additions expected over the next two years. (See Smooth EIM Transition for Arizona Public Service, Puget Sound Energy.”)

October 12, 2016

SPP Market Savings Hit $1 Billion Mark

LITTLE ROCK, Ark. — SPP said Tuesday its wholesale electricity markets have reduced electricity costs by more than $1 billion since its Integrated Marketplace became operational in March 2014.

The RTO said it crossed the $1 billion threshold in September.

“Our markets provide tremendous value to the SPP region. That’s something we’ve known and demonstrated since they launched,” said Bruce Rew, SPP’s vice president of operations, in a statement. “The billion-dollar mark is an exciting milestone, and I’m proud that we reached it so quickly.”

Southwest Power Pool Control Room (Source: SPP) — SPP Control Room | *SPP*

SPP noted the milestone came just weeks before it celebrates its 75th anniversary. The organization formed in December 1941, when 11 utilities pooled resources to power an aluminum plant near Malvern, Ark., that supplied the Defense Department during World War II.

The RTO now numbers almost 100 members in all or part of 14 states.

“This is just one more example of the value that comes out of our stakeholder process,” said SPP CEO Nick Brown in a statement. “We’ve demonstrated through decades of success that our business model is built to stand the test of time, and we’ll keep on providing exceptional value and service to our members just like we’ve always done.”

— Tom Kleckner

October 12, 2016

MISO Directors Back Forward Capacity Auction Filing

By Amanda Durish Cook

After a brief discussion, the Markets Committee of the Board of Directors on Tuesday approved MISO’s forward auction proposal. The RTO expects a FERC filing in three weeks.

Director Baljit Dail said there was no reason not to go ahead with the filing date. “I think it was a very good piece of work,” he said.

MISO hopes the auction will ensure adequate capacity resources in Illinois and other retail-choice areas in the RTO’s footprint, most of which have traditional monopoly utility structures overseen by state integrated resource planning.

Director Michael Curran said he is “comfortable” with MISO’s plan for serving both structures. “I take a lot of comfort in the ability to look at metrics and adjust. I think as a community, MISO has adjusted a lot over the years, and it makes us successful,” Curran said.

Curran also thanked Independent Market Monitor David Patton for his recommendations and his “viable” alternative proposal. “I think he created a lot of healthy contention,” he said. Patton, who favors a prompt auction, has been sharply critical of MISO’s plan, calling it “fundamentally unsound.” (See MISO Backs Forward Auction Plan, Rejects Prompt Proposal.)

Bladen at MISO stakeholder meeting (© RTO Insider) - leading forward capacity auction discussion — Bladen | © *RTO Insider*

Director Phyllis Currie asked MISO staff how stakeholders view the proposal. Jeff Bladen, executive director of market services, said that while some stakeholders wanted more time for discussion, the majority “ultimately concluded they’ve had enough. … There remains some disagreement, as is expected in processes like these; consensus is nearly impossible to reach. The details of proposals like these are always ripe for disagreement.” (See “MISO to Move Ahead with Brattle Demand Curve for Forward Auction,” MISO Resource Adequacy Subcommittee Briefs.)

Bladen also said a “clear majority” of stakeholders agree that a problem exists in MISO’s retail-choice areas. He also pointed to the two years spent on the proposal. The RTO used 2015 to define the problem and gather ideas from members and the Monitor and worked to refine the proposal over 2016.

A few stakeholders, however, used the meeting’s public comment period to express concern.

David Sapper, representing the Transmission-Dependent Utilities sector, said MISO has only released draft — and not final — Tariff language. “With all due respect, I still think there’s some uncertainty on the proposal,” Sapper told the board.

Jim Dauphinais, counsel for Illinois Industrial Energy Consumers, agreed: “There are just going to be some details that have to be worked out by FERC.”

Curran asked about MISO’s ability to adjust the auction after it is fully implemented in 2019. Bladen said the RTO could consider changes as soon as the transitional auctions planned for 2018.

Dail asked if MISO was confident in The Brattle Group’s modeling, which left out MISO South. Bladen said while MISO South was “not explicitly modeled, it was implicitly modeled” through “stress tests” of various levels of non-merchant offers into a hypothetical forward auction.

Currie asked if the modeling anticipated future transmission additions. Bladen said while specific transmission projects or transmission topology changes weren’t modeled, greater and reduced import/export transmission capability was analyzed.

Director Paul Feldman asked if PJM’s forward auction might inform MISO’s, and if the RTOs plan to schedule their auctions at the same time. Bladen said he wasn’t sure how the auctions would interact because MISO was still so early into the process. “We’ve got some time ahead of us for coordination with PJM. I’m not in a position to recommend something now,” he said.

October 12, 2016

PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M

By Ted Caddell

Ohio regulators Wednesday rejected FirstEnergy’s request for an annual $558 million rider for eight years, voting instead to give the company $204 million annually for only three years.

FirstEnergy, whose request would have totaled $4.46 billion, will receive $612 million (nominal dollars) under the unanimous decision by the Public Utilities Commission of Ohio.

FirstEnergy, PUCO — FirstEnergy has 1,360 employees at its Akron, Ohio, headquarters. The company says its total economic impact in the state is $568 million annually.

The company said the eight-year retail rate stability (RRS) rider was necessary to ensure the corporation’s financial health at a time in which its coal- and nuclear-fueled generation is challenged by low natural gas wholesale energy prices.

The commission said its staff proposal for a distribution modernization rider (DMR), introduced in July, would do that. (See PUCO Staff Recommends $131M Annual Rider for FirstEnergy.)

The staff’s proposal “will provide FirstEnergy with an infusion of capital so that it will be financially healthy enough to make future investments in grid modernization,” the commission said in a statement. The commission’s unanimous order limited the rider to three years, with the possibility of a two-year extension.

The company reported a $1.1 billion loss in the second quarter, much of it related to the closure of five coal-fired units. (See FirstEnergy Posts $1.1B Loss, Eyes Exit from Merchant Generation.)

‘Not a Bank’

Chairman Asim Z. Haque said the rider is not meant to solve all of FirstEnergy’s financial problems.

“If FirstEnergy truly needs $4.5 billion to achieve full financial health, then the commission decision today falls well short of that expressed need,” he wrote in his concurring opinion. “The commission does not intend to be, nor will it be, nor should it be the entire solution for FirstEnergy’s current financial difficulty. … The commission is an economic regulator. It is not a bank. It is not a trust fund. We authorize rates and charges that come directly from the pockets of consumers and businesses in this state. We have no rainy day fund to dip into.

“I do, however, want our regulated utilities to be healthy so that they can invest in bettering the delivery of services to consumers and businesses in the state of Ohio,” he went on. The rider “is meant to assist FirstEnergy in deploying the grid of the future while simultaneously providing it with a boost to improve its credit rating and financial health.”

FirstEnergy Unhappy

FirstEnergy will collect $132.5 million a year, with the balance of the $204 million going to taxes, said company spokesman Doug Colafella. Haque concurred with that figure “assuming current tax rate.”

The charge will boost monthly bills $3 (about 3%) for a typical residential customer using 750 kWh, the company said.

The company was not pleased with the decision.

“Today’s decision is disappointing for our customers,” said CEO Charles E. Jones. “While we clearly demonstrated to the PUCO what is essential to ensure reliability for customers in the future, the amount granted is insufficient to cover the necessary and costly investments. The decision also fails to recognize the significant challenges that threaten Ohio utilities’ ability to effectively operate.”

FirstEnergy said it is evaluating the order and considering its next steps. It has 30 days to appeal.

The modified RRS was FirstEnergy’s latest attempt for a state bailout. Its first attempt, submitted as a power purchase agreement, was approved by PUCO but collapsed after FERC said it — and a similar deal involving American Electric Power — would be subject to stringent reviews. (See FERC Rescinds AEP, FirstEnergy Affiliate-Sales Waivers.)

FirstEnergy and AEP went back to the drawing board. While FirstEnergy went with the modified rider request, AEP has chosen to go a different route: It is currently working with Ohio legislators to reverse customer choice and reregulate the industry.

Opponents also Miffed

Environmental groups and consumer advocates argued that the FirstEnergy request was unreasonable.

“Today’s decision takes hundreds of millions of dollars out of customers’ pockets in order to create a massive slush fund for FirstEnergy Corp. and its shareholders,” said Shannon Fisk, attorney at the nonprofit environmental law firm Earthjustice.

“The fact that FirstEnergy asked for billions more does not make this decision any less unreasonable. Rather than forcing customers to prop up profits for a corporation that made a bad bet on aging coal plants, the commission should be looking after customers and ensuring investments in job-creating renewable energy, energy efficiency and smart grid initiatives.”

The Sierra Club said PUCO could have used the ruling to encourage FirstEnergy to make further efforts to move toward more renewable energy.

“In this long-awaited and complicated decision, PUCO missed a critical opportunity to seriously focus FirstEnergy on the more diversified, cleaner energy future that tens of thousands of customers wrote the commission asking for,” said Dan Sawmiller, senior representative for the Sierra Club’s Beyond Coal campaign in Ohio.

“A few months ago, FirstEnergy took an important step in moving beyond coal when it announced closure of four units at its Sammis coal plant. With PUCO’s decision now issued, we hope to be able to work with FirstEnergy to accelerate its path beyond coal and nuclear and toward new investments in clean energy, energy efficiency and other modern grid initiatives like infrastructure for electric vehicles.”

IPPs Weigh in

The Alliance for Energy Choice, an organization funded by independent power producers, said FirstEnergy is still getting a good deal at ratepayers’ expense.

“The PUCO once again granted the utility’s request for more money with no corresponding benefit to customers,” Alliance spokesman and former PUCO Chair Todd Snitchler said. “Businesses and families will again be required to pay more for the same service they already receive with only a hope that customers will gain an upgraded grid if and when the utility elects to do so.”

“FirstEnergy should simultaneously be required to file a distribution rate case to document the need for, and amount of, a true grid modernization program,” Snitchler said.

October 12, 2016

Public Citizen Challenges NY Nuclear Subsidy, FitzPatrick Sale

By William Opalka

Consumer advocate Public Citizen on Tuesday protested Energy’s proposed sale of the James A. FitzPatrick nuclear plant to Exelon, saying the companies’ FERC application failed to include information about the state subsidy that makes the transaction possible (EC16-169).

Public Citizen says omission of the subsidy makes the application incomplete. It also said the subsidy itself distorts the New York market and violates the NYISO Tariff.

Entergy had said it would close FitzPatrick in the spring, until Exelon came to the plant’s rescue this summer. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)

entergy, fitzpatrick, exelon, public citizen, nuclear power — FitzPatrick Nuclear Plant | *Entergy*

“Exelon’s application to acquire FitzPatrick must be considered incomplete because, inexplicably, it fails to incorporate any mention or analysis of New York’s proposed ZEC payment subsidy scheduled only for FitzPatrick and for both of Exelon’s two in-state nuclear facilities. This payment subsidy, estimated at a total of $8 billion in six two-year increments, will significantly distort the NYISO energy and capacity markets and fundamentally alter the economics of Exelon’s power generation operations in NYISO, including FitzPatrick,” Public Citizen wrote.

“We believe the structure of the ZEC may conflict with elements of the NYISO … Tariff, particularly FERC’s mandate for incentives through the NYISO installed capacity market,” the protest continued.

“While the … proponents claim the ZEC is designed to combat climate change, a realistic analysis shows that the primary purpose of the ZEC is to keep select economically uncompetitive nuclear power plants operating, regardless of the impact on greenhouse gas emissions. And the state’s decision to discriminate between different nuclear generating stations for reasons other than climate change or the environment further complicates the true purpose of this expensive ZEC subsidy,” Public Citizen says.

Entergy’s downstate Indian Point facility, which is not financially stressed, is not currently eligible to participate in the ZEC program.

Opponents of the subsidy say it will cost ratepayers up to $8 billion over its 12-year life. Supporters say the state will enjoy a net economic benefit when it is calculated using the federal social cost of carbon analysis.

Public Citizen wants FERC to declare the application incomplete, require a market analysis that incorporates the full impact of ZECs and determine if the subsidies conform with FERC rules.

Public Citizen was the only party to file responses to the application before the comment deadline expired Oct. 10, except for U.S. Rep. John Katko (R-N.Y.), who sent a letter to FERC urging action on the deal. Katko, whose district includes FitzPatrick, said the plant provides more than 600 jobs and is “a vital part of the region’s economy.”

October 10, 2016

SPP Briefs

SPP’s Exit Study Task Force, formed to provide technical support and advice regarding Lubbock Power & Light’s move to ERCOT, conducted its first meeting last week.

The Public Utility Commission of Texas asked SPP and ERCOT to work together to study the implications of LP&L’s plans to migrate 430 MW of its load from SPP to ERCOT in June 2019. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)

One issue is who will pay for the studies. PUC Chair Donna Nelson has said the burden shouldn’t fall on ERCOT ratepayers, suggesting during a Sept. 22 meeting LP&L should either fund the work or that the issue should be open “pending the outcome of the studies.”

“‘Depending on the outcome’ … I don’t know what that means,” said LP&L legal counsel Chris Brewster during the task force’s first meeting Friday.

Oklahoma Gas & Electric’s Jake Langthorn, the group’s chair, told the group the study costs will become clear once the scope and schedule are developed. SPP staff will begin its assessment by using its normal base cases from its near-term and 10-year studies.

“We’ll evaluate the system with Lubbock in SPP and without. In each case, we’ll evaluate the system against SPP planning criteria and NERC criteria to see whether we’re outside the acceptable ranges,” said Antoine Lucas, SPP’s director of transmission planning. He said the study will seek to identify any new transmission projects needed — or planned projects that can be deferred — as a result of Lubbock’s move.

LP&L representatives pushed SPP, which has targeted an April completion date, to accelerate its timeline.

ERCOT has said it will complete its assessment by the end of the year.

SPP says its existing planning workload will keep it from completing its work by the end of the year as ERCOT has promised.

“Having said that, we’re expecting it’s more than 90% in place right now,” said Lanny Nickell, SPP’s engineering vice president. “Once we put the schedule together, we can identify when we need it 100% finalized.”

SPP staff said it is meeting with ERCOT staff next week to review all questions posed by LP&L.

The task force is composed of four members of the Strategic Planning Committee and two each from the Transmission and Economic Studies working groups.

Wind, Coal Generation Continue to Rise, Fall

uos7aimrsccelhh5hhcg_full_spp-real-time-wind-generation-and-capacity-factor-spp-market-monitoring-unit-alt-fi — | *SPP Market Monitoring Unit*

Wind energy continues to rise in the SPP footprint and coal-fired generation continues to drop, according to the Market Monitoring Unit’s State of the Market report for this past summer.

The MMU said wind generation accounted for more than 12% of all energy produced in 2016, compared with 10% in 2015 and 9% in 2014. At the same time, coal generation’s share dropped to 51%, down from 62% in 2014.

Natural gas prices rose from this spring’s record low levels, the MMU said. The average price at the Panhandle Hub was $2.51/MMBtu this summer, compared with $2.60/MMBtu in 2015 and $4.00/MMBtu in 2014.

southwest power pool, lubbock power & light, ercot — | *SPP Market Monitoring Unit*

The “wind alley” of the Texas panhandle, western Oklahoma and western Kansas continues to experience most of the SPP footprint’s congestion. However, the MMU said, congestion has increased in southeast Kansas and parts of Arkansas, which it attributed to higher summer loads and planned generation and transmission outages.

SPP, MISO Shared Joint Study Needs List

SPP staff told the Seams Steering Committee last week it has made available to stakeholders the final needs list for the 2016 Coordinated System Plan study with MISO and is asking for solutions by Nov. 30. Four of the needs were identified by both RTOs and three were cited by SPP. (See MISO-SPP Study Scope Finalized; Stakeholders Doubtful Projects will Result.)

Staff will review the submittals and share them at their next Interregional Planning Stakeholder Advisory Committee meeting.

SPP staff said a joint model is being developed, but it will likely have differences with each RTO’s regional models, and that some of the identified regional needs may not show up in the model.

Separately, SPP and Associated Electric Cooperative Inc. have developed models and assessed the needs for the target areas, posting them to allow stakeholders to submit solutions. The two organizations requested input be submitted by Nov. 7.

SPP Interregional Coordinator Adam Bell told the committee the Northeast Oklahoma target area will no longer be evaluated in the SPP-AECI joint study because of a change of power suppliers in the region. He said the change “resulted in there no longer being potential needs observed on both sides of the SPP-AECI seam.”

— Tom Kleckner

October 10, 2016

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — After months of debate on proposed definitions for operating parameters, PJM and the Independent Market Monitor rankled some Market Implementation Committee members last week by introducing an unexpected, last-minute compromise package that included one key change but largely maintained the status quo.

The proposal leaves many of the definitions untouched, except for minimum runtime and soak time. The endorsed definition of minimum runtime replaces a unit’s “breaker closure” with simply when a unit is “dispatchable” as the starting point. It also “un-nests” soak time from minimum runtime, differentiating it as its own parameter.

“We think it’s a big step forward,” Monitor Joe Bowring said.

Several stakeholders said they wouldn’t have enough time to give the proposal a reasonable review that day, but a seconded motion to vote on the issue forced them to act. The vote, which was planned for the morning session, was delayed until the afternoon to provide extra time.

pjm market implementation committee — | *PJM*

It was enough: The joint package received support from 75% of stakeholders — far exceeding competing proposals. It also won more than 60% support in a head-to-head vote against the status quo, meaning it will be forwarded to the Markets and Reliability Committee. (See “Members Hear First Read on Plan to ‘Un-Nest’ Operating Parameters,” PJM Market Implementation Committee Briefs.)

The last-minute proposal by PJM and the Monitor caused several stakeholders to question the functionality of the stakeholder process. “Do we just not care about the stakeholder process anymore?” Ed Tatum of American Municipal Power asked during the initial discussion. “What’s the idea of bringing something that no one’s been able to look at?”

After the vote, PJM’s Dave Anders thanked the members “for working through the issue.” He acknowledged their frustration, but he said this was an example of “the stakeholder process actually working.”

He invited members who have thoughts on reforming the process to attend the Stakeholder Process Forum Oct. 24.

Stakeholders Debate ARR Changes

In response to a problem statement approved earlier this year, PJM has begun revisiting its procedures for allocating residual auction revenue rights and hopes to file a solution with FERC on Dec. 31.

Exelon and Direct Energy issued a proposal last week for reducing potential revenue fluctuations under the current allocation. Their proposal would eliminate any residual ARR paths that could receive negative values based on monthly financial transmission rights clearing prices. PJM would then rerun the simultaneous feasibility test before allocating residual ARR megawatts for the month.

PJM’s proposal would give stakeholders the opportunity to opt out of allocations on a path-by-path basis. Sharon Midgley of Exelon said both proposals solve the issue but differ on the approach taken to address the current forced allocation of negative paths to customers. The Exelon/Direct Energy package puts an additional administrative requirement on PJM, while the RTO’s proposal places new analytical requirements on load-serving entities.

PJM’s Asanga Perera explained that the stakeholder proposal puts a heavy burden on PJM staff to process the data for negative pathways within a few days to have the results back to stakeholders in time for the next round of ARRs. He said it creates the potential for PJM to miss a deadline and leave stakeholders without the information necessary to identify negative pathways.

He pointed out that the process for stakeholders under PJM’s plan uses what they already do for the annual ARR process.

However, several stakeholders criticized PJM’s plan, saying their companies don’t have the staff to analyze the thousands of potential pathways each month. “I think PJM’s proposal with the burden placed on the stakeholders, that would be too overwhelming,” said a stakeholder who asked not to be identified. “It would give an advantage to the stakeholders that have the staff and the resources available to do that.”

PJM Looks to Revise Shortage Pricing Procedures

PJM’s Adam Keech presented a shortage pricing proposal to avoid potential volatility posed by implementation of FERC Order 825 (RM15-24).

Under the order’s transient shortage pricing rules, even brief shortages will trigger the maximum penalty factor, which could cause volatility as market participants attempt to respond. (See FERC Issues 1st RTO Price Formation Reforms.)

PJM’s proposal would create steps below the maximum penalty factor based on historical performance so that the maximum penalty does not apply until the reserve is down to the largest single resource’s actual output as opposed to its economic maximum. The measurement would change every five minutes.

Keech noted that in the past 21 months, PJM has observed 845 instances where, under the rules in Order 825, reserve prices would have hit the maximum $850/MWh penalty factor in the Mid-Atlantic and Dominion regions. He hadn’t analyzed the data enough to explain why 759 of them were in 2015 compared with 86 in 2016.

Attachment Q Modified; Credit Requirements Unaffected

Stakeholders endorsed by acclamation changes to PJM’s credit policy. The revisions to Attachment Q of the Tariff reorganize provisions and make five minor changes to them, none of which affect credit requirements, according to PJM’s Harold Loomis.

The changes also specify that collateral may not be encumbered or restricted and provide PJM “reasonable time” to investigate breaches of credit requirements before implementing remedies, ensuring the RTO’s action is not foreclosed if it does not act immediately.

The revised attachment also replaces a section on peak market activity (PMA) collateral requirements with one specifying PMA credit requirements.

‘Working Groups’ Removed from MIC Charter

Stakeholders endorsed edits to the MIC charter that removed references to “working groups,” as they no longer exist. Working groups were eliminated as part of a larger reorganization of the stakeholder process starting in 2009 that standardized the purposes for and creation of task forces and subcommittees.

Stakeholders Develop Interest List for Black Start Requirements

PJM is soliciting stakeholder feedback on the priorities that should be considered in developing annual revenue requirements for new black start units. The current interest identification includes 13 concerns, including that the Monitor calculate revenue within six months of units entering black start service.

Bowring said the calculations can’t be made without explicit documentation to support “every penny of requested revenue changes” and that documentation must be submitted in a timely fashion. Members asked Bowring to specify what documentation is required.

– Rory D. Sweeney