Page 1449 – RTO Insider

April 18, 2016

Wind Growth Causes SPP to Take 2nd Look at Tx Projects

By Tom Kleckner

SANTA FE, N.M. — With wind energy reaching unprecedented penetration levels, SPP’s Markets and Operations Policy Committee asked staff last week to re-evaluate whether two transmission projects in the windy Texas-Oklahoma Panhandle region should have their need dates accelerated.

Staff had been hoping to receive approval to accelerate the two projects, a recommendation that had already been OK’d by three working groups. However, stakeholder concerns over a lack of technical input, outdated studies of wind energy and going outside normal planning processes caused the MOPC to request further staff analysis.

The motion was unanimously approved. SPP staff will return the recommendation to July’s MOPC meeting and will eventually need approval from the Regional State Committee.

“We can accommodate [the motion] and not impact reliability if we come back in July and make a decision,” said Casey Cathey, SPP’s manager of operations engineering analysis and support.

SPP said it set a new record for North American ISOs and RTOs when it registered a 48.32% wind-penetration peak April 5. (See “SPP Leapfrogs ERCOT with 48.32% Wind Penetration Mark,” SPP Briefs.)

SPP’s 2015 wind integration study recommended 19 transmission projects with notices-to-construct (NTCs) as candidates for acceleration. Ten of the projects have already been voluntarily sped up by transmission owners, four were found to be not feasible for acceleration and three were withdrawn as part of a near-term assessment and will be incorporated into the RTO’s new planning process.

The two remaining NTCs — a 230-kV Southwestern Public Service project in the Texas Panhandle and a 345-kV Oklahoma Gas & Electric project in West Oklahoma — were recommended for acceleration. Cathey said accelerating the projects will reduce existing congestion and ease voltage-collapse fears.

Existing Congestion

“Both [systems] have congestion on them right now. … It’s not wind coming three years from now,” Cathey said. “The longer we delay, the more your benefits are reduced.”

Cathey said SPS could shave half a year off its timeline without a cost to its sponsors, while the OG&E project could reduce its timeline by almost two years, saving $437,000 in the process.

The acceleration recommendation was approved by the Transmission, Economic Studies and Operating Reliability working groups.

Some MOPC members, however, expressed concern about re-evaluating projects outside the Integrated Transmission Planning (ITP) process and a lack of involvement by some of the working groups.

“I do not think the Tariff supports a re-evaluation or acceleration of an NTC outside of the ITP process,” Sunflower Electric Power’s Al Tamimi said in opposing the ESWG recommendation.

“My biggest concern is the lack of involvement, or minimal involvement, with the TWG through this process,” Westar Energy’s John Olsen said. “I get very uncomfortable sitting around this table to be making those kind of calls without having our technical folks review them.”

American Electric Power’s Richard Ross asked whether the re-evaluations could be conducted through SPP’s high-priority study process. The RTO can conduct up to three such studies a year at the stakeholders’ request.

“It seems we’re tying SPP’s hands here,” Ross said. “To me, it makes sense to accelerate these projects, if this is the proper way of doing this. Has legal bought off on sprinkling some high-priority magic dust on this?”

“It may be we need a supplemental analysis to warrant the two accelerations,” SPP Vice President of Engineering Lanny Nickell said. “Now we have to figure out a way legally to justify the acceleration of the projects in accordance with the Tariff. If the two TOs want SPP to direct acceleration, that’s a change in the planning processes.”

Wind Integration Study

The MOPC also unanimously approved staff’s proposed scope for a second phase of a wind integration study, but only after revising the recommendation to ensure the TWG and ESWG are included in the review process.

The study will build on last year’s analysis, with updated models and assumptions looking at wind cases as high as 60%. The results are to be published before next January’s MOPC meeting.

Cathey said the report is intended to be a reliability study rather than a high-priority study and will use 2017 planning models. He said the Electric Power Research Institute will help staff on the report, which will also use data from PowerTech Labs’ voltage security assessment tool.

“Phase II is about what we didn’t have time to assess in Phase I,” he said. “We’re trying to do something that’s [defensible] and accurate. We’d like to get a more dynamic, up-to-date look.”

Cathey noted that with firm transmission rights now part of SPP’s transmission congestion rights market, “We don’t know what firm rights are any more.

spp wind energy texas — Smoky Hills Wind Farm in Kansas *Source: Wikipedia*

“The wind blows, and it’s in the money. We’re backing down coal, and that’s the reality of what’s happening on the system.”

Cathey said he expects the study to recommend policy and procedure changes, but that it “won’t mandate anything.”

“There’s a good chance we’ll be at 60% wind penetration in 2017,” said Bruce Rew, SPP’s vice president of operations. “The sooner we can get [the study] done, the sooner we can be prepared for that.”

Staff said the study will cost approximately $145,000, but it is waiting on further information from vendors.

April 18, 2016

FERC to Examine RTO Rules for Energy Storage

By Michael Brooks

FERC is seeking comment on energy storage’s participation in the wholesale energy markets, questioning whether RTOs’ rules are creating barriers for the resource (AD16-20).

The commission’s Office of Energy Policy and Innovation last week sent identical letters to each of the grid operators under its jurisdiction, requesting data on “the eligibility of electric storage resources to participate in the RTO and ISO markets; the technical qualification and performance requirements for market participants; required bid parameters; and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.”

FERC staff simultaneously issued a request for comments on the same issues. Staff said it expects comments to take into account the RTOs’ responses to their data requests, which are due May 2. Comments are due May 23.

There have “been some key developments in the technology and cost-effectiveness of electric storage resources,” FERC staff said. “In light of these developments, staff is interested in examining whether barriers exist to the participation of electric storage resources in the capacity, energy and ancillary service markets.” The commission also expects to examine whether tariff changes are needed if barriers to participation exist, staff added.

“Many energy storage project developers have experienced difficulty in accessing wholesale markets. Grid operations and markets were not originally designed with energy storage in mind,” Jason Burwen, Energy Storage Association policy and advocacy director, said in a statement. “The Energy Storage Association supports efforts that increase access to wholesale markets for storage and establish market structures to realize energy storage’s full value in lowering system costs and increasing system reliability.”

5 Categories

The commission divided its questions to the RTOs into five categories:

Eligibility: Which types of storage resources are qualified to participate in the markets and which are not? Are there different rules for different types? If so, why?
Requirements: What are the minimum and technical requirements for storage to participate in the markets? What are the bases for these requirements (NERC reliability standards, for example)?
Parameters: What are the required bid parameters for storage resources? Are there any parameters unique to storage?
Distribution: Are there opportunities for aggregate storage resources or those connected at the distribution level to participate at the wholesale level? If so, what are they?
Load: When would storage be considered a buyer of energy in the wholesale markets? What are the requirements when storage resources purchase electricity? Are they required to pay LMPs? Are there circumstances when storage can receive electricity but not be considered load?

Current RTO Discussions

FERC also asked the RTOs if there are any ongoing discussions or pending rule changes concerning energy storage.

Here is a snapshot of where they stand:

CAISO last month asked FERC to approve a new Tariff provision that would allow storage and other distributed energy resources to participate in California’s energy and ancillary services markets. An ongoing stakeholder initiative is focused on refining the ISO’s market model to lower barriers for grid–connected DER. (See CAISO Tariff Change Would Extend Market to DER.)
ERCOT last year created a Distributed Resource Energy and Ancillaries Market (DREAM) Task Force, providing a forum for stakeholders and staff to develop market rules related to DER. The DREAM team has submitted a final report for the Technical Advisory Committee’s consideration at its April 28 meeting. (See “DREAM Task Force Submits Final Report,” ERCOT Technical Advisory Committee Briefs.)
ISO-NE has two large-scale pumped hydro storage facilities that can provide nearly 2,000 MW. The RTO developed a paper in January explaining how storage resources of at least 1 MW can participate in the energy and capacity markets. An updated white paper incorporating stakeholder feedback was released on March 31.
NYISO says it was the first grid operator, in 2009, to establish FERC-approved market rules for limited energy storage resources. Its energy limited resources classification allows a capacity provider to sell a minimum of 1 MW for at least four hours. Several other products participate in the ancillary market. The ISO’s Market Issues Working Group has begun a process to expand storage’s presence. In November, FERC accepted NYISO’s method for compensating Beacon Power’s 20-MW flywheel storage facility for frequency regulation (ER12-1653).
MISO is engaged in stakeholder discussions on incorporating storage into its markets. (See MISO Stakeholders Provide Ideas on Incorporating Storage.)
PJM is studying a way to remove barriers that distributed battery storage systems face when entering the markets. Currently, such resources have two options: interconnect as a generation source through the queue process or register as demand response. The review, prompted by a problem statement approved by stakeholders in February, will be limited to behind-the-meter generation of 20 MW or less. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM MRC & Members Committee Briefs.)
SPP members are considering a staff proposal to create a technology steering committee as a forum for discussions on incorporating storage and other technologies. (See “More Detail Requested on Technology Committee,” Strategic Planning Committee Briefs.)

At the Gulf Coast Power Association’s spring meeting last week, Allan Stewart, executive director of North American power for PIRA Energy Group, predicted innovations in battery technology will start changing electric market fundamentals as soon as 2020 in California and Hawaii. (See “Energy Storage Ready to Disrupt Industry?”, Overheard at GCPA Annual Meeting.)

Robert Mullin, Suzanne Herel, Tom Kleckner and William Opalka contributed to this article.

April 18, 2016

PSEG Defends Artificial Island Cost Increase

By Suzanne Herel

Public Service Electric & Gas (PSE&G) on Thursday submitted a letter to the PJM Board of Managers defending the cost estimate for its share of the Artificial Island project, which has nearly doubled to $272 million.

pseg pjm Salem-Nuclear-Generating-Station-on-Artificial-Island-(Wikimedia)-for-slider — Salem Nuclear Generating Station on Artificial Island *Source: Wikimedia*

PJM planners, who say the increase could lead to a rebid of the project, expect to update the board on the project when it meets this week. (See Artificial Island Cost Increase Could Lead to Rebid.)

PSE&G told the board it was not involved in determining PJM’s initial cost estimate of $125.9 million, which later grew to $137 million.

‘Unusual’ Project

At the March meeting of the Transmission Expansion Advisory Committee, Vice President of Planning Steve Herling said PJM stood behind its choice of project for a stability fix at the New Jersey complex housing the Hope Creek and Salem nuclear reactors. The work is unusual, so PJM had little to compare it to, and the estimate didn’t reflect a design-level study, he said.

LS Power was chosen for the bulk of the project, which involves building a new 230-kV transmission line from the nuclear complex, under the river and into Delaware. PSE&G and Pepco Holdings Inc. were assigned upgrades necessary for the interconnection. LS Power says it is standing by its $146 million cost cap.

PSE&G said it didn’t begin preparing a detailed cost estimate for the 230-kV line terminating at the Salem substation until July, as its own proposals had the line ending at Hope Creek.

“PSE&G has clearly stated throughout this process that any work required to be done in Salem would be expensive and complicated,” the company said, citing a handful of communications supporting the assertion.

“Any proposal with work at Salem will be very challenging; the location of the switchyard controls and protection are located inside of the nuclear generating station,” it had told the board in July 2014.

In one of its proposals, it had said, “Due to experience with multiple historical baseline projects at Artificial Island, PSE&G can state that [Nuclear Regulatory Commission] governing requirements, critical site power maintenance and outage complexities, as well as known controls expansion limitations, will all contribute to design constraints potentially limiting a Salem expansion. PJM should carefully consider the implications of allowing such risks or costs to be understated or excluded from a total project cost comparison.”

At April’s TEAC meeting, planners said they are now considering alternate configurations, including terminating the new line at Hope Creek instead of Salem — a change in scope that could lead to rebidding for the project.

Tortured History

It was just the latest twist in the tortured history of the project, PJM’s first competitive solicitation under FERC Order 1000.

PJM planners originally recommended awarding the stability fix to PSE&G, but the board reopened bidding to finalists following protests from spurned bidders, state officials and others, leading to awards for LS Power, PSE&G and Pepco.

In November, FERC ruled that PJM’s proposed allocation of virtually all the project’s costs to ratepayers in Delaware and Maryland might not be just and reasonable (EL15-95). At a technical conference in January, commenters said PJM’s solution-based distribution factor cost allocation method was not appropriate for projects such as Artificial Island and the Bergen-Linden Corridor upgrade. (See Commenters: DFAX Cost Allocation Inappropriate.)

April 18, 2016

MISO Fields More Capacity Auction Questions

By Amanda Durish Cook

MISO continues to move forward with modifications to its capacity market even as some stakeholders question the need for the proposed changes and others seek more time to consider their implications.

RTO staff are aiming to file Tariff changes with FERC next month to implement seasonal and locational capacity constructs. MISO also proposed filing in July for the creation of a separate Forward Local Requirements Auction for deregulated regions in 2018.

That timeline sparked concerns for many market participants still skeptical of the proposed auction.

During an April 14 Resource Adequacy Subcommittee meeting, multiple stakeholders urged the RTO to postpone a filing for the FLRA based on the volume of questions regarding its design.

“There were a lot of good questions today, but MISO has essentially said, ‘We’ll consider them,’” said Marka Shaw, Exelon regulatory affairs manager. “I think there’s a lot of work to be done, especially [before] a July filing.”

MISO concedes that several design details for the FLRA have yet to be clarified. RTO staff have asked stakeholders for feedback about how congestion costs from the current Planning Resource Auction should be allocated to the FLRA, what the proposed auction’s demand curve should look like and what resource adequacy plan rules should be implemented. MISO is also seeking reactions to the idea of bifurcated capacity procurement — separate auctions covering regulated and deregulated areas.

Price Risks in Bifurcation

Skeptical of bifurcation, independent power producers are instead pushing for a single three-year forward auction for all of MISO.

Consumer advocates urged the RTO to delay auction changes until results from the MISO-Organization of MISO States survey on available capacity are released in July — or until a capacity shortage becomes imminent.

Jim Dauphinais of Illinois Industrial Energy Consumers is among the opponents to the FLRA proposal. During last week’s meeting, he contended that capacity price volatility can be best addressed by self-supply and bilateral contracts, pointing out that more than 65% of capacity in southern Illinois for the 2015/16 was procured by those means.

Dauphinais cautioned that the FLRA’s proposed downward-sloping demand curve could act as a “wedge” to inflate prices before MISO’s predicted capacity shortage in the 2021/22 planning year.

“There’s volatility even if it’s done three years in advance with a sloping demand curve,” Dauphinais said.

Kevin Murray, representing the Coalition of Midwest Transmission Customers, sought clarification on whether load-serving entities in deregulated areas could develop a forwardixed resource adequacy plan and make bilateral agreements to circumvent a forward auction altogether, something MISO says will be possible.

AARP’s Bill Malcolm questioned the need for what he called a PJM-style forward auction.

“We urge more study on the matter,” Malcolm said. “The rate impact on consumers should be fully vetted and be part of the discussion.”

Mark Volpe, Dynegy senior director of regulatory affairs, focused on price volatility risks to the downside. He pointed to what he considered a “fundamental flaw” in the forward capacity auction design: The value of capacity in MISO’s Zone 4 could approach zero as more generation projects come online in southern Illinois.

Jeff Bladen, MISO’s executive director of market design, said Volpe’s comment illustrated why the RTO is seeking feedback on bifurcated procurement.

“This is something we’re acutely aware of, but I can’t predict what the forward zone will look like,” Bladen said, referring to how the auction might clear.

According to Bladen, MISO will not seek a specific price outcome for the forward auction, but it does want results to fall within a target reliability range.

Bladen also said MISO wants stakeholder feedback on the shape of the FLRA demand curve.

Meanwhile, draft Tariff changes for MISO’s proposed seasonal and locational capacity constructs are almost complete, according to Renuka Chatterjee, MISO executive director of resource adequacy and transmission access planning. Still, the RTO could delay an expected July filing with FERC, depending on feedback from the Independent Market Monitor — and an unnamed MISO customer — regarding the creation of external resource zones.

The seasonal construct proposal outlines a single auction with two seasonal offers, while the locational construct sets out external resource zones. (See MISO Delays Seasonal, Locational Capacity Constructs.)

April 18, 2016

Pilgrim to Refuel Next Year, Close in 2019

By William Opalka

Entergy said Thursday it intends to refuel the Pilgrim nuclear plant next year and then cease operations on May 31, 2019.

Pilgrim Entergy Nuclear Power Plant — Pilgrim Nuclear Power Plant *Source: Entergy*

The company announced last year that the plant would close between 2017 and 2019 but deferred a decision on whether to perform one last refueling. (See Entergy Closing Pilgrim Nuclear Power Station.)

“The issue is that we have an obligation to provide the ISO-NE with power until that May 31, 2019, date. After looking at different options to best fulfill that commitment, we determined refueling Pilgrim was the most appropriate way for the company to meet the obligation,” spokesman Patrick O’Brien said.

At the time of the closure announcement, company officials said the plant’s annual revenue was projected to drop by $40 million a year because of low energy prices.

With a poor ranking for operational performance, the plant was also under increased scrutiny from the Nuclear Regulatory Commission. Meeting NRC requirements to continue operating would have required $45 million to $60 million in capital expenditures, the company said.

Cheap natural gas has depressed power prices and stressed nuclear plants throughout the country. Entergy closed its Vermont Yankee plant at the end of 2014. (See New Lifeline for FitzPatrick Nuclear Plant.)

The final refueling will be a brief boon for the local economy. Entergy said Pilgrim’s 2015 refueling outage required a $70 million investment in the plant, including $25 million in new equipment, and employed nearly 2,000 employees, including 1,184 extra contract workers.

Entergy said a team with decommissioning and Pilgrim plant experience will plan for the shutdown.

The 680-MW plant began commercial operations in 1972.

April 18, 2016

FERC ALJ: Shell, Iberdrola Owe California $1.1B over Energy Crisis

By Robert Mullin

A FERC judge ruled last week that Shell Energy North America and Iberdrola Renewables saddled California consumers with $1.1 billion in excess energy costs at the height of the Western Energy Crisis.

The initial decision by Administrative Law Judge Steven Glazer said the Mobile-Sierra presumption of “justness and reasonableness” does not apply to overpriced long-term contracts the two companies signed with the California Department of Water Resources (CDWR) shortly before the crisis ended in 2001 (EL02-60-007, EL02-62-006).

By that time, CDWR 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, while the state’s other two investor-owned utilities teetered on the brink of insolvency.

Glazer’s ruling also reinstated Iberdrola as a party to the proceedings, reversing a previous dismissal from the case.

The California Public Utilities Commission initiated the case to recover costs from the crisis. Shell and Iberdrola are the only suppliers not to have settled or renegotiated the terms of their contracts with CDWR, which expired in 2011 and 2012.

While the initial decision is subject to further review and modification by the full commission, Glazer’s opinion increases the likelihood that the two companies will be forced to disgorge at least some of the profits from the contracts. According to the ruling, the Shell and Iberdrola contracts strapped California consumers with an “excess burden” of $779 million and $371 million, respectively. Both estimates include interest accrued through April 2015.

“I am gratified that the ALJ agreed that FERC has a duty to vindicate the public interest and protect consumers from exorbitant overcharges that Shell and Iberdrola pocketed due to the worst electricity crisis and market meltdown in modern history,” PUC Commissioner Mike Florio said in a statement.

The state has obtained $7.7 billion in settlements over other long-term contracts. It also has received about $4 billion in settlements over short-term contracts, with complaints pending against 13 companies involved in short-term deals, according to Florio.

The public interest consideration was pivotal — but not decisive — in Glazer’s complex, 219-page decision to nullify the legal presumption of validity accorded to bilateral energy contracts.

Mobile-Sierra Reinterpreted

Grounded in Supreme Court precedent, the Mobile-Sierra doctrine holds that bilateral energy contracts can be voided only when a contract rate is shown to adversely affect the public interest. The burden of proof rests with the party seeking to break the contract, who must clearly show harm to the public. In 2003, FERC ruled that it was not in the public interest under the Mobile-Sierra rule to break CDWR’s contracts with Shell and Iberdrola. California appealed the ruling to the 9th U.S. Circuit Court of Appeals.

A 2008 Supreme Court decision in Morgan Stanley Capital Group Inc. v. Public Utility District No. 1 of Snohomish County would introduce a new dimension to the California proceeding, which was eventually sent back to FERC on remand. Based on Morgan Stanley, FERC now had to add an additional test to the Mobile-Sierra rule: whether the terms of a contract were the result of market manipulation.

In his ruling, Glazer spelled out that the “questions to be decided here focus on the Mobile-Sierra rule as reinterpreted by Morgan Stanley.”

“Specifically, those questions first ask whether the Mobile-Sierra-Morgan Stanley presumption of the justness and reasonableness of each of the contracts at issue is ‘avoided’ by reason of unlawful activity on the part of each wholesale marketer in making its contract with CDWR,” Glazer wrote. “Alternatively, the next question asks whether the Mobile-Sierra-Morgan Stanley presumption is ‘overcome’ by reason of the contract’s burden on consumers or other harm to the public interest.”

The decision to overturn California’s contracts with Shell and Iberdrola provided a mix of answers to both questions.

‘Avoided’ and ‘Overcome’

Glazer’s ruling against Shell rests on evidence that the company manipulated electricity spot prices during the crisis, employing many of the same strategies as Enron. The most harmful of those practices included false exports, false load scheduling and “anomalous” bidding strategies designed to drive up market clearing prices. The decision notes that Shell’s head of electricity trading joined the company after working at Enron.

Expert witnesses in the proceeding disagreed about the impact of spot market manipulation on the forward power prices underlying the contracts. Glazer agreed with California’s experts, who he said demonstrated that short-term prices affected forward prices in “a statistically significant manner.”

Glazer also found that Shell’s own trading activities contributed to the price spikes.

“Shell’s behavior in short-term trading with CDWR affected forward prices,” Glazer wrote. “Forward prices reflect expectations about future spot prices. Shell’s manipulative activity and that of other suppliers in spot markets elevated spot market prices and made them much more volatile.”

Shell’s culpability did not end there. Glazer noted that the Shell team negotiating the long-term contract with CDWR was in close contact with the company’s traders during the crisis and knew about the manipulative trading strategies in the spot market. He cited internal Shell emails showing that company negotiators understood the long-term contract was a “big bet” that the energy prices would eventually “tank.”

And tank they did, leaving California holding long-term contracts priced far higher than markets in subsequent years.

“The continuing decline of forward prices after the deal was signed proved to be costly to CDWR,” Glazer wrote. “It signaled that paying the high locked-in power prices of the Shell contract over the next two to three years would be more expensive for CDWR than acquiring power in the forward market would have been.”

The demonstration of those excess costs for the public, coupled with the illegal market activity producing them, laid the legal groundwork for Glazer’s decision: that the Mobile-Sierra presumption of justness and reasonableness was both “avoided” and “overcome” in the case of the Shell contract with CDWR — failing both tests established by Morgan Stanley.

Iberdrola Contract ‘Overcome’

In his decision to overturn Iberdrola’s contract, Glazer determined that while Mobile-Sierra was not “avoided,” the doctrine was “overcome” because of the long-term costs carried by the state of California, which was forced to issue bonds to fund the electricity and capacity purchases.

Glazer said Iberdrola’s power marketing unit engaged in manipulative practices during the crisis, including “parking” false exports of California power to be sold back into the state at elevated prices. And, as with Shell, Iberdrola employees negotiating with CDWR were shown to have coordinated their activities with the company’s electricity traders.

Still, Glazer found no evidence that CDWR actually relied on forward prices to evaluate the contracts, breaking a link in the chain tying the contracts to the spot markets. Iberdrola’s contract included a tolling arrangement by which CDWR controlled the dispatch of energy from its cogeneration facility in Klamath Falls, Ore.

“There are no records of CDWR modeling [Iberdrola’s] Klamath contract pricing against forward price curves and no testimony from any witness for the complainants that the evaluation was done,” Glazer said. “During the period it was negotiating long-term contracts, CDWR believed that forward price curves were an unreliable basis for setting prices for its long-term contract portfolio.”

Iberdrola and Shell could seek a settlement with California for a discount from the $1.1 billion rather than take their chances that the commission will reject the ALJ ruling.

“We take our business and compliance with regulations very seriously,” a Shell spokesman said in a statement. “As this is an ongoing legal matter, we will not be able to make any further comment at this time.”

Iberdrola expressed confidence it would prevail.

“We are currently reviewing the ALJ’s recommendation but continue to believe that the full commission will accept our arguments and those of FERC staff presented at the hearing,” an Iberdrola spokesperson told RTO Insider.

While the company declined to elaborate on that point, Glazer’s ruling does note that FERC staff believe Iberdrola’s contract did not pose a “down the line” burden on California consumers relative to the rates they could have obtained after elimination of the dysfunctional market, contrary to the ALJ’s own conclusions.

April 18, 2016

Committee Recommends 2 Industry Vets for PJM Board

By Suzanne Herel

The PJM Nominating Committee is recommending Dean Oskvig, retired CEO of Black & Veatch, and Mark Takahashi, CFO of Ascendant Group, for election to the Board of Managers.

Dean-Oskvig pjm nominating committee — Dean Oskvig *Source: Black & Veatch*

They would fill the spots left vacant by Richard Lahey and Jean Kinsey when they retire at this year’s annual meeting, to be held next month.

Oskvig spent his entire 40-year career with Black & Veatch, where he began as an engineer and went on to become project manager, partner-in-charge, COO and ultimately CEO for energy. Previously, he served in the U.S. Air Force.

Takahashi is an international finance executive with 30 years of experience in energy finance after starting out as an engineer. He has worked in the engineering, procurement and construction, and power and utility sectors.

The committee also is recommending that South Carolina technical engineer Terry Blackwell be re-elected to the 10-person board. He was chosen last year to serve out the remaining term of William Mayben, who retired after eight years. (See New PJM Board Member Elected, Re-election Eligibility Changed.)

Mark Takahashi (Linkedin) pjm nominating committee — Mark Takahashi *Source: Linkedin*

This will be the first board appointment under new terms adopted last year: Members will be ineligible for re-election once they turn 75 or have served five terms.

That precludes Lahey from seeking another term; he has served on the board since its inception in 1997.

PJM does not disclose the ages of its board members, so it’s unclear whether Kinsey, who joined in 2003, could have sought another term.

The Nominating Committee consists of eight members: five PJM stakeholders and three board members. This year’s sector representatives were Marji Phillips, Other Suppliers; Joe Kerecman, Generation Owners; Lisa McAlister, Electric Distribution; Ruth Ann Price, End Use Customers; and John Horstmann, Transmission Owners.

The board members were Howard Schneider, who served as the nonvoting chair, Ake Almgren and Kinsey.

April 18, 2016

Grid Execs Talk Cybersecurity, Renewables

By Rich Heidorn Jr.

HOUSTON — NYISO CEO Brad Jones got to wear his cowboy boots again last Tuesday, returning to Texas for a discussion with the CEOs of SPP, MISO and his former employer, ERCOT.

Though three of the four grid executives claim Lone Star roots, Jones was the only one wearing boots onstage at the Gulf Coast Power Association session.

Footwear aside, the four of them had much in common, including concerns over cybersecurity and their management of shifting generation resources. They also expressed sharply differing views on some subjects, such as the value of FERC Order 1000.

Impact of Low Gas Prices, Renewables

ERCOT CEO Bill Magness, who moderated, began the discussion by asking his colleagues whether natural gas or renewables were causing bigger changes in their operations.

Jones © RTO Insider (gcpa, cybersecurity, order 1000, renewables) — Jones © *RTO Insider*

“Both,” responded MISO CEO John Bear, a Texas native. “Five years ago, we were about 85 to 90% provided by coal. It’s about half that right now. So we’ve really made a significant shift because of the wind generation and obviously the gas coming online.”

Bear said he didn’t share the fears of some that the Clean Power Plan and other environmental rules will “rob of us our fuel diversity.”

“In fact it’s giving us fuel diversity,” he said. “We’re losing our storage, because that coal pile is largely going away for us. But we are adding a lot more flexibility because of those gas plants.”

SPP CEO Nick Brown took note of his RTO’s growing wind generation — 12.5 GW installed and another 4 GW in the transmission queue. The RTO set a new record at 2 a.m. April 5, with wind representing 48.32% of generation. (See related story, Wind Energy’s Growth Causes Second Look at 2 Tx Projects.)

“If you had asked me five years ago if we would ever see 48% of the generation online at a given point in time being from … wind, I would have laughed at you,” Brown said. “And yet it is a reality. And I’m sure before the end of this year we’ll see 50%.”

In five years, Brown said, “we’ll be predominantly a renewable generation fleet with some thermal. We’re going to have to learn to operate differently.”

Magness © RTO Insider (gcpa, cybersecurity, order 1000, renewables) — Magness © *RTO Insider*

Magness said ERCOT is, like MISO, affected equally by renewables and low gas prices. It has been trading wind records with SPP and also expects to exceed 50% penetration this year. “We’re seeing hours of negative pricing across the system in a way that’s relatively new,” Magness said. “It used to be more isolated in the west zone.”

By contrast, New York gets only 4% of its power from variable renewables, said Jones, who joined the ISO in October. Controllable hydroelectric facilities provide another 20%. (See New NYISO Head: New York a ‘Fantastic Opportunity’.)

Unlike Texas, which is fighting the CPP in court, New York “wants to take leadership on low-carbon issues,” Jones said.

Thanks to its participation in the Regional Greenhouse Gas Initiative, the state doesn’t need to make any changes to comply with the CPP. But meeting Gov. Andrew Cuomo’s Clean Energy Standard, which calls for renewables providing half the state’s power by 2030, is another matter.

“To give you a sense of scale, [that would require] 25,000 MW of solar, if solar is the only technology we use. It’s 15,000 MW of wind if that’s the only technology, and we today have about 1,700” MW, he said.

Jones called out former ERCOT colleagues, joking, “I had to go to New York to get a capacity market.” With low energy market prices and a demand for increasing renewables, he said, “it is very valuable to have.”

Demand-Side Management

Because of the growth in intermittent resources, Brown said grid operators “need to pay more attention to the demand side of the equation.”

“Historically, as balancing authorities, we assume load is just this random event and then we chase it, most typically with these huge thermal machines,” Brown said. “The engineer in me has always hated that.”

He predicted policymakers will “allow wholesale market operators to send price signals to the end-use load and use that load as a controlling mechanism to help us balance.”

Bear agreed on the need. “At some point, loads are going to start growing again,” he said.

Is Order 1000 Worth the Trouble?

Left to right: Bill Magness, ERCOT; Brad Jones, NYISO; Nick Brown, SPP; John Bear, MISO © RTO Insider (gcpa, cybersecurity, order 1000, renewables) — Left to right: Bill Magness, ERCOT; Brad Jones, NYISO; Nick Brown, SPP; John Bear, MISO © *RTO Insider*

Bear and Brown also questioned the value of Order 1000 and its competition requirements.

Bear said MISO has already committed to building $6 billion in transmission to eliminate congestion in its footprint.
“Because we did that, when you combine that with … $2 gas, there’s not a lot of congestion on the footprint, so finding those economic opportunities [to justify new transmission projects] is really hard,” he said.

He noted that transmission projects typically take eight to 10 years to complete. “Add an extra year to the process to bid those things out, pick amongst [the responses], work through the litigation process — I’m wondering if that’s really necessary,” he said.

Nick-Brown,-SPP-web (gcpa, cybersecurity, order 1000, renewables) — Brown © *RTO Insider*

Brown said SPP’s board will soon make a decision on whether to authorize its first competitive transmission project. The RTO received 11 responses to its solicitation to build a 115-kV line between North Liberal and Walkemeyer in southwestern Kansas. (See SPP Issues RFP for 115-kV Transmission Project.)

“We now call into question the need for this line just because of changes in the load forecast,” he said. “So we may have gone through all that [competitive solicitation] for nothing.

“I’ve always characterized the [Order 1000] process as very cumbersome, very costly, very time consuming. And it’s going to be interesting to see if the benefit of the competitive process justifies the extremely complex process.”

In contrast, Jones said he has a “positive perspective” on Order 1000, although he agreed on the need to “streamline” the competitive process.

Jones said the FERC order has helped New York break a “logjam” to initiate its first major transmission projects in 30 years.

One project, the Western Energy Connection, will add 1,000 MW of transmission capacity for hydro, gas and renewable generation, including the dam at Niagara Falls. “We can’t get all of that hydro resource into the state. It’s bottled up. And we’re having to spill some of that water down the river,” he said. (See NYPSC Directs NYISO to Seek Tx Bids.)

Cybersecurity Fears

The executives also shared their concerns over cybersecurity.

Bear © RTO Insider (gcpa, cybersecurity, order 1000, renewables) — Bear © *RTO Insider*

Bear said the issue was a minor concern for MISO five years ago. “The amount of time we spend on it now is unbelievable,” he said. “It’s that big black unknown. We’re doing everything we can to make sure we’re as prepared as we can be, but if anyone looks at you and says, ‘Are you sure that we’re never going to have an event?’, you can’t say ‘I’m sure.’”

Brown called the issue “the most frustrating” part of his job and said SPP is no longer solely focusing on keeping hackers out of the system.

“What keeps me up at night is, are they already in and we don’t know it? And the challenge is, I don’t know how much to spend. What’s the right amount? What’s the right amount of risk mitigation for this type of event? I don’t know the answer to that.

“How much protection do we have from our insurance carrier for a cyber penetration event? I still can’t get straight answers,” he added. “Even the coverage we have has certain exclusions in there that the underwriters are just adamant have to be there and I’m adamant that they can’t be there. We just don’t see eye to eye.”

April 18, 2016

Congress May Order CFTC to Back Down on Private Rights

By Rich Heidorn Jr.

WASHINGTON — U.S. Sen. John Boozman (R-Ark.) last week introduced legislation that would force the Commodity Futures Trading Commission to grant SPP the same broad regulatory exemptions the commission granted other grid operators in 2013.

The commission’s 2013 order exempted electricity transactions subject to FERC-approved tariffs from most provisions of the Commodity Exchange Act (CEA). SPP was not party to the order because its day-ahead market was not fully implemented at the time.

Unlike the 2013 order, the draft order CFTC is considering for SPP includes a preamble stating the commission’s intent to preserve “private rights of action” under Section 22 of the CEA. (See Witnesses Ask CFTC to Drop ‘Private Rights’ Clause.)

CFTC Chairman Timothy Massad testified Thursday at a hearing of the Senate Appropriations Committee’s Subcommittee on Financial Services and General Government, which is chaired by Boozman. The Arkansas senator did not raise the issue.

However, a Boozman spokeswoman said the senator introduced an amendment that was included in the manager’s package at the Senate Agriculture Committee’s markup on the CFTC’s reauthorization Thursday.

“The amendment would ensure the current regulatory framework remains in place and prevent inconsistent regulations between FERC and CFTC,” said spokeswoman Sara Lasure. She said Sen. Joe Donnelly (D-Ind.) co-sponsored the amendment.

Speaking at the Gulf Coast Power Association’s annual meeting in Houston last week, SPP CEO Nick Brown said the RTO was working with Boozman to bar the commission from allowing private rights of action for wholesale electric markets.

“To open this to 100 [U.S.] district courts is just insane in my mind,” Brown said. “I don’t know a better word for it. … This would just be a field day for the legal community.”

Other grid operators have expressed concern that the commission’s reference to private rights in the SPP order could undermine their 2013 waiver.

“The real risk is for market participants who are in the [congestion revenue rights and financial transmission rights] markets,” ERCOT CEO Bill Magness said. “When I had to come back to meetings at ERCOT and talk about CFTC again, it was a very unhappy day. We thought we were done with these discussions for a while.”

April 18, 2016

MISO Reliability Subcommittee Briefs

MISO met NERC’s frequency response requirement for 2015, although performance was not as good as a year earlier, adviser Terry Bilke told an April 13 Reliability Subcommittee meeting.

The RTO’s estimated annual frequency response was -475 MW/0.1 Hz in 2015, complying with its obligation of -211 MW/0.1 Hz under NERC’s frequency response standard (BAL-003-1).

Still, results from local balancing authorities were not as good as in 2014. “I was kind of hoping we’d see incremental improvement year-over-year,” Bilke said, adding that the decline was small enough to be attributed to sampling error.

“We’re still okay,” RSC chair Tony Jankowski said. “But there’s nothing that says we’re going to be OK except for past performance. And obviously, that’s [no] guarantee.”

Data for the first quarter of this year showed that more than 400 generators provided no frequency response in the first quarter, while about 100 plants were determined to be harming MISO performance. Fewer than 200 generators rated an “OK” response, with a small number classified with “theoretical perfect performance.”

Monthly Real Time Unit Commitment Performance (MISO) reliability subcommittee briefs — Daily real-time unit commitment rating at peak hour for March (top) and monthly performance (bottom).

“Interestingly, one of the best performers was a wind farm,” Bilke said.

That assessment comes as MISO stakeholders are being asked to respond to FERC’s Feb. 18 Notice of Inquiry, which seeks comment on whether RTO pro forma interconnection agreements should be changed to require all new generation be capable of providing frequency response (RM16-6).

Jankowski said the language in the notice indicates that FERC does not recognize all the factors at play.

“From the market’s perspective, I don’t think we have any indication that a generator is a frequency response generator or not, or a good performing generator or not,” he said. “So to have any sort of expectation that we don’t have enough [frequency response] because the market clears wrong, I don’t buy that. There isn’t a constraint for frequency response.”

MISO thinks frequency response should be compulsory for new generation and voluntary for all existing generation, Bilke said. He added that if reliability declines in light of a changing resource mix, FERC should revisit the issue.

Comments on FERC’s notice are due April 25. Jankowski urged the RSC to be “proactive” in making suggestions on frequency response incentives and penalties through local balancing authorities.

“Nothing precludes us from doing this today,” he said.

March Incident Breaks 3-Month Perfect Score on Commitment Performance

Last month’s sole “unacceptable” rating for real-time unit commitment performance — occurring March 22 — was attributed to an operator’s mistake.

“We had a unit that was left on in an operator error,” Steve Swan, MISO senior manager of dispatch and balance, said during a monthly operations update. “They misread the runtime. It’s been addressed.”

March otherwise contained all “excellent” daily performance ratings, receiving an overall score of 2.9 — just shy of “perfect,” but breaking a trend of perfect 3 rankings in peak hour unit commitment since December.

The month had no minimum or maximum generation alerts or warnings nor any tie-line errors lasting longer than 15 minutes.

Swan also reported that -45,308 MW was added to MISO’s inadvertent interchange balance in January, bringing the running total of imbalances since 2009 to -749,641 MW.

By the end of this month, MISO expects to complete two bilateral inadvertent interchange paybacks, where two balancing authorities swap under-generation for over-generation. Swan said MISO is also performing “internal data mining” to investigate why the footprintwide balance continues to be negative.

Seams Quarterly Report Released

MISO has released its latest quarterly report on seams issues.

“We historically haven’t gotten a lot of review on [the report],” said Ron Arness, Seams Management Working Group liaison. He noted that, although feedback is light, stakeholders continue to request the report every year.

— Amanda Durish Cook