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.
Salem Nuclear Generating Station on Artificial Island Source: Wikimedia
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.)
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.)
Entergy said Thursday it intends to refuel the Pilgrim nuclear plant next year and then cease operations on May 31, 2019.
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 Vermont Yankee Retirement Leaves ISO-NE More Dependent on Gas.) The company also said it will close its James A. Fitzpatrick plant in New York in about a year, although state officials are trying to create incentives to keep it operating. (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.
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.
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 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 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.
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.
“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 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.
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.
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 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.”
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.)
Massad
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.”
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.”
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.
“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.
Independent transmission company GridLiance continued to gather up industry expertise last week with the announcement that American Electric Power’s J. Calvin Crowder has joined the company as president of the South Central region, which includes the ERCOT, MISO South and New Mexico grids.
Calvin Crowder
Crowder will oversee business development activities with public-power agencies from his base in Austin, Texas. Crowder was most recently president of AEP’s Electric Transmission Texas (ETT), which he helped grow to $3 billion in assets.
“Calvin is a highly regarded electric utility industry executive who brings an in-depth understanding of the utility business, collaborative management style and excellent relationships with RTO officials as well as state and federal regulators,” GridLiance CEP Ed Rahill said in a statement.
Crowder has 25 years of experience in the industry, much of it with AEP and its Central and South West predecessor. He has focused his career on regulatory and legislative matters, securing a $1.5 billion investment for ETT in ERCOT’s Competitive Renewable Energy Zone.
Crowder earned his bachelor’s degree in economics and his master’s degree in regulatory economics from New Mexico State University.
The Z2 Payment Plan Task Force brought two payment plan options to the committee, recommending the level-payment plan over a staggered-payment option. The task force’s recommendation cleared the 66.7% threshold for acceptance at 77.4% after a voice vote was inconclusive.
Under the level-payment plan, each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months, beginning in November, with the final installment due in August 2017. FERC’s interest rate for refunds will apply to the outstanding balances. (See “Z2 Task Force to Present Final Recommendations,” SPP Briefs.)
The dollar amounts to be billed remain an unknown, which led to much of the members’ reluctance to approve the recommendation. Midwest Energy’s Bill Dowling called the schedule “problematic,” saying he has “zero” money in the budget to handle bills that may be coming his way.
“I’m still questioning why we have to decide now, without knowing how many zeros we’re talking about here, let alone how many commas,” he said. “It’s really tough to figure out where this money comes from, or how I get the money, until I get an invoice that says I have 30 days to pay.”
“If we wait until later to decide and some other action is needed, like going to FERC, that might prolong this process even further,” responded Oklahoma Gas and Electric’s David Kays, the task force’s chair.
“Ultimately, the amount you will pay or receive will be what it’s going to be,” said Aundrea Williams of NextEra Energy Resources. “Voting on the payment plan doesn’t really affect what you’re going to owe and receive.”
Kays said the software used to calculate the credits is scheduled to be in production by June 1. He said historical data will be available for stakeholder review in time for the MOPC’s October meeting.
SPP will review stakeholders’ data with them in late May. Kays said staff will walk through the calculations and demonstrate the software is performing correctly.
Stakeholders will be exposed to confidential data, which will require signing nondisclosure agreements. Staff assured members the NDAs would not preclude their ability to communicate with FERC.
Market Working Group Gives Updates on Revision Requests
The committee approved a Market Working Group revision request to clean up the Tariff’s out-of-merit-energy (OOME) language (RR 145) while remanding a second back to the working group for additional work (RR 154).
RR 145 is intended to correct dispatch and set point instructions for variable energy resources, clarify OOME treatment for qualifying facilities and make other minor changes to the Tariff’s OOME provisions.
The second change, RR 154, would make it clear when SPP should perform a repricing of the day-ahead and real-time balancing markets. Current protocols and the Tariff allow for the repricing in the day-ahead market “for any reason at any time,” said American Electric Power’s Richard Ross, the MWG’s chair.
Ross also:
Updated the committee on its work regarding the SPP Market Monitoring Unit’s nine suggested improvements to the market design. (See “Market Working Group Addressing Monitor’s Recommendations,” SPP Board of Directors/Members Committee Briefs.) Two of the nine recommendations — minimizing the over-allocation of transmission congestion rights and auction revenue rights in the day-ahead market, and improved reporting on planned outages — are complete, Ross said. A final report is expected to be presented at the July MOPC and board meetings.
Briefed the committee on the MWG’s Price Formation Task Force, which was created to “identify concerns with current pricing methodologies” and propose solutions. The task force is currently analyzing feedback gathered from the MOPC and the MWG.
Told the committee that estimated costs for Integrated Marketplace RRs since September 2013 have surpassed $11 million. He said nine of the 10 RRs will be implemented this year and next.
SPP Pondering ‘One-Offs’ as Potential Seams Projects
SPP Principal Regulatory Analyst Sam Loudenslager brought the committee up to date on the RTO’s effort to create a new class of seams transmission projects, which was rejected by FERC in November.
SPP had proposed a new transmission category to identify projects that fall outside the Order 1000 interregional planning process or may not be eligible for cost allocation. FERC rejected it, saying the plan was too broadly drawn (ER15-2705). (See FERC Rejects SPP Proposal for Seams Transmission Projects.)
The RTO’s staff has been seeking further direction from FERC to determine whether to make another filing. Loudenslager said his recent conversations with FERC staff indicated “they didn’t think we could present a filing that would pass their legal concerns.”
He said FERC staff focused on SPP’s criteria for seams and interregional projects. “They didn’t think we had been through the process enough.
“They suggested we might need to differentiate between [seams and interregional] projects,” Loudenslager added. He said staff encouraged SPP to bring them potential projects that “didn’t pass muster with MISO” as potential “one-offs.”
SPP’s current rules designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a regionwide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.
“We need a more convincing argument with FERC about why this needs to be a standard one-off,” said Carl Monroe, SPP’s chief operating officer. “We do have special circumstances where these one-offs have to be done outside the Order 1000 process, especially if they don’t fall into the stipulation of shared costs. That way, parties outside MISO could agree to a process where we might be able to find agreement with MISO members that fall outside the Order 1000 process.”
Loudenslager said FERC staff suggested SPP work with Associated Electric Cooperative Inc., a member of the Southeastern Regional Transmission Planning process based in Missouri. “To the extent we came up with something on AECI that didn’t pass muster with MISO,” he said, “they encouraged us to bring it to them as a one-off.”
MOPC Chair Noman Williams, chief operating officer for SouthCentral MCN, suggested staff continue to develop a business practice to add some structure to the one-off process.
“Have it at least all laid out so we don’t have to recreate the process [each time],” he said.
Staff Says No Further HPILS Construction Needed
Staff told the MOPC no additional construction is needed for the 2014 High Priority Incremental Load Study (HPILS) because of slumping oil prices and dropping rig counts.
The HPILS study, commissioned to address unexpected load growth resulting from oil and gas shale production, recommended $439 million in transmission upgrades to serve needs through 2013.
In approving the HPILS report in 2014, SPP’s board directed members affected by HPILS loads and assumed generation additions to provide updated forecasts of those loads and generators before the quarterly MOPC and board meetings. The board also directed members to notify staff should additional notices-to-construct be required.
Jay Caspary, SPP director of research, development and special studies, said 110 MW of load remains unserved in North Dakota’s Bakken Shale play through 2017 and 200-300 MW is unserved in New Mexico’s Permian Basin oil fields in Eddy and Lea counties near the Texas Panhandle. He said the loads are “consistent with previous projections” and recommended no change in HPILS project construction.
Basin Electric Power Cooperative completed a 75-mile, 345-kV line in North Dakota in December, while Southwestern Public Service has energized three projects in the Permian Basin, adding 40 miles of 345-kV lines (which operate at 230 kV) and 19 miles of 115-kV lines. SPS is working on another project between Lubbock, Texas, and Hobbs, N.M., which is scheduled to be in service by 2020.
Some stakeholders questioned the accuracy of the load forecasts, given the low price of oil and dropping rig counts.
“These forecasts coming from folks who believe the price of oil will go back up to $50 or $60 a barrel kind of flies in the face of logic,” Empire District Electric’s Rick McCord said. “It doesn’t make sense to come in here and say [the recent slowdown] doesn’t have an impact. Could [SPP planners] give us some sort of an indication [of how much] load growth doesn’t show up to change what we’re doing?”
“We feel these [projections] are right for the system,” Caspary said. “The load growth is still there. It’s not what it was, but it’s still amazing compared to the rest of the SPP system.”
Ross asked whether staff could use its SCADA system to check “withdrawals off the transmission system.”
“I’m sure we can do that,” Caspary said, “but the directive we got was to look at the forecasts.”
Consent Agenda/RRs
The committee approved in a near-unanimous vote a revision request to SPP Business Practice 7650, which defines procedures for processing competitive transmission proposals as part of the RTO’s Integrating Planning Process.
The RR clarifies the steps taken to determine which detailed project proposals (DPPs) are equivalent to a transmission project in the Integrated Transmission Plan’s Transmission Owner Selection Process’ (TOSP) portfolio. The Business Practice Working Group (BPWG) said the criteria changes will further improve SPP’s ability to “efficiently and accurately” complete the DPP process within the ITP’s required timelines. DPP projects approved for construction as a competitive upgrade may be eligible for “incentive points” within the selection process.
A review of the first TOSP found a combined 1,672 DPPs were received for the 2015 ITP Near-Term and 10-Year assessments, and an additional 1,664 DPPs were submitted for the 2016 ITPNT. Stakeholders expressed their concerns that the drain on resources would affect the 2017 ITP10 schedule and lead to less-than-optimal solutions.
McCord, the working group’s chair, said submitting better DPPs would allow staff to spend more of the 30-day assessment window on needs and solutions, rather than ensuring incentive-point qualification, and lead to more innovative solutions. The language changes to the business practice would be effective with the 2017 ITP10.
ITC Holdings’ Marguerite Wagner cast the lone negative vote, following precedent set during the stakeholder process. The RR was approved by the BPWG and two other groups, with ITC Great Plains the sole dissenting vote each time.
“We don’t oppose the language,” Wagner said, “but we oppose the application of this language in the middle of the three-year cycle.” She said technology improvements could help reduce the number of DPPs, “so it’s unclear this is necessary at all.”
The committee also approved four other RRs from the BPWG and seven additional RRs from the MWG and two other working groups as part of the consent agenda:
BPWG-RR 147, clarifying the methodology to define a competitive upgrade’s 50% completion status;
BPWG-RR 148, updating BP 2150 to reference the current webRegistry;
BPWG-RR 149, updating BP 6150 to reference NERC reliability standards;
BPWG-RR 150, updating BP 4300 to reference a NERC reliability standard;
MWG-RR 25_MPRR 211, adding language to identify offer costs eligible for recovery with a “market” or “reliability” commitment;
MWG-RR 128, clarifying description of day-ahead start-up eligibility recovery rules;
MWG-RR 137, aligning enhanced combined cycle language with that for quick-start resources;
MWG-RR 142, preventing a resource from registering as a quick-start resource and a multiconfiguration combined cycle resource;
ORWG-RR 141, allowing use of updated ratings for facilities, elements and flowgates that reflect current ambient conditions or more relevant system conditions; and
ORWG-RR 146, removing the criteria revision process from the SPP operating criteria, as the process is now a MOPC process.
Criteria Review
SPP Director of Planning Antoine Lucas reviewed with the MOPC a planning criteria study of the Integrated System’s (IS) transmission grid that evaluates thermal and voltage limits and includes a stability assessment.
Lucas said a 2013 criteria study of the IS members — Basin, Western Area Power Administration-Upper Great Plains and Heartland Consumers Power District — identified four projects totaling $10.56 million to be completed before joining SPP in October 2015.
The study was updated when two additional IS members, Central Power Electric Cooperative and Tri-State Generation and Transmission, joined SPP in January. The 2016 integration study added two additional projects totaling more than $3 million.
