Page 1311 – RTO Insider

November 6, 2018

GreenHat: (Some of) the Rest of the Story

By Steve Huntoon

If you’re as old as me you may remember the movie “Body Heat” from 1981. That last scene with Kathleen Turner on an exotic island beach somewhere.^[1] Yeah, you know what I’m talking about.^[2]

That brings us to the GreenHat Energy debacle, with the stakeholder tab running around $185 million.^[3]

Folks seem to think the GreenHat principals lost everything as their PJM financial transmission rights portfolio deteriorated in value. Bloomberg’s headline: “Ex-JPMorgan Traders Lost Millions on Bad Bets in Power Market.”^[4]

I don’t think so. I suspect the GreenHat principals, Andrew Kittell, John Bartholomew and Kevin Ziegenhorn, are sipping blender drinks on island beaches just like Kathleen Turner.^[5]

Kathleen Turner in the movie “Body Heat”

The Stage

But first let’s set the stage. Two of the GreenHat principals, Kittell and Bartholomew,^[6] are fresh off the JPMorgan market manipulation in California from 2010 to 2012 for which JPMorgan “agrees to pay a civil penalty of $285,000,000 [and] agrees to disgorge alleged unjust profits of $125,000,000.”^[7] Kittell and Bartholomew themselves paid nothing.

As recounted in a detailed RTO Insider story, they set up shop in 2014 as GreenHat Energy.^[8]

“Green hat” in Chinese basically means someone is getting screwed. So at least they had a sense of humor.

Over several years, they accumulate the largest FTR portfolio in PJM history — 890 million MWh — backed by only $600,000 in collateral.

It isn’t clear that PJM connected the dots of Kittell and Bartholomew to the JPMorgan market manipulation, though the connection was hiding in plain sight in FERC’s eLibrary via a word search on “Andrew Kittell” or “John Bartholomew.”

How the Scheme Works

The scheme here relied on the minimal collateral requirement to hold hundreds of millions of dollars in FTR positions. All that has to happen for GreenHat to make money is for positions to change in value over time — as of course they will — and for GreenHat to sell “in the money” positions to third parties. GreenHat would prefer that the overall value of its portfolio increase over time, but that isn’t necessary for GreenHat to make money because GreenHat can sell positions with value, and default on the rest. Indeed, GreenHat would want to buy every possible FTR with zero incremental collateral requirement, regardless of whether it expected those FTRs to make money.

Let me give you an example that is so simple even I can understand it. Let’s say PurpleHat Energy joins PJM and puts up $600,000 credit. PurpleHat buys long-term FTRs with no additional credit requirement: let’s say FTR 1 from source A to sink B for $10, and say FTR 2 from source C to sink D for $6.

As time goes on, FTR 1 decreases in value from $10 to $7, and FTR 2 increases in value from $6 to $8. PurpleHat bundles up FTR 2 and thousands of other FTRs that have increased in value (i.e., “in the money”) and goes looking for a buyer of these “winners.” Now the buyer looks at FTR 2, for example, and is thinking that if the current $8 value is maintained to settlement, PJM will pay me $8. Of course the buyer has to discount that $8 for the time value of money, risk of value change (could be up, down), etc. So the buyer agrees to pay PurpleHat, say, $7. Notice that PurpleHat has made $1 on FTR 2 ($7 revenue minus $6 cost). Multiply that by thousands of other FTRs and their megawatt-hour quantities and you get to real money real fast.

Now remember PurpleHat is selling winners for cash to third parties and will default on the losers. So PurpleHat can make wads of money even if its overall portfolio of winners and losers goes down in value. Got it?

The Collateral That Wasn’t

Beyond this big picture, here’s a remarkable part of the story: As the GreenHat portfolio deteriorated in value, and some FTR participants raised red flags with PJM,^[9] PJM asked GreenHat for more collateral.

GreenHat purported to provide that, in June 2017, in the form of pledging $62 million in future revenue from FTR sales agreements that GreenHat had with a third party, which we now know is Shell Energy North America^[10] (“Pledge Agreement”). Here is how PJM described it: “Mr. Kittell worked with PJM to establish a dedicated depository account and represented that GreenHat would request the third party to deposit the revenues from the bilateral contracts into a bank account that PJM had access to and from which PJM would execute automated clearing house withdrawals to cover net losses that accumulated in GreenHat’s PJM account.”^[11]

Now, one might think, wouldn’t PJM verify with Shell that Shell hadn’t already given GreenHat some or all of that $62 million (assuming that $62 million is a real number)? Well, PJM did ask GreenHat for permission to check with Shell about that $62 million, and GreenHat said … no.^[12]

Now, one might think, that’s that: PJM would tell GreenHat to come up with something better than a Nigerian prince story for $62 million. Instead, PJM went ahead with the Pledge Agreement,^[13] saying it had no choice,^[14] and GreenHat went on to more than double the size of its FTR position.^[15]

And, as fate would have it, GreenHat had already pocketed whatever was owed by Shell (not $62 million, but perhaps $7 million — more on that next).^[16] Uh oh.

The $62 Million That Wasn’t

There’s one more part of the story to tell here. You’ve probably assumed, like I did, that there had to be something to the $62 million claim that GreenHat made to PJM. But maybe that ain’t so. Maybe there never was any $62 million — not at the time of the FTR sale to Shell, or ever.

Analysis of the GreenHat positions suggests they were purchased at a cost of approximately $19 million when GreenHat acquired them (with minimal collateral) and valued in the range of $25 million when GreenHat sold them to Shell. It seems what GreenHat entered into the PJM eFTR system was just made up.^[17]

Per Queen in “Bohemian Rhapsody”: “Is this just fantasy?” And here the answer seems “yes.”

What Now?

What’s to be done now? FERC Enforcement should be all over this if it isn’t already. The penalties for market manipulation can be substantial as the JPMorgan order shows.^[18] And PJM should vigorously pursue civil action, such as the one initiated in Texas.

Lesson for the Future

Lesson for the future: All RTOs should carefully review all their credit requirements for everything — with experts in credit — just in case Kittell and Bartholomew, or others like them, are coming their way.

P.S.: The GreenHat experience is not an indictment of energy markets in general, or FTRs in particular. It is a cautionary tale of faulty credit policy and oversight.

It was filmed on Tunnels Beach, Hawaii. ↑
And if you’re a youngster, might I recommend that movie? Warning: You’ll never look at your significant other the same. ↑
https://pjm.com/-/media/committees-groups/committees/mrc/20180918-special-ftr/20180913-default-reference-points.ashx (slide 6). ↑
https://www.bloomberg.com/news/articles/2018-09-25/a-power-grid-and-its-customers-could-get-stuck-paying-for-a-failed-wall-street-bet. ↑
At least Andrew Kittell seems to be. On Feb. 1, 2017, Kittell purchased a $3.4 million home on Coronado Island, Calif. https://blockshopper.com/ca/sandiego/coronado/property/5364111600/640-coronado-avenue; https://www.zillow.com/homes/for_sale/17071030_zpid/32.697143,-117.187762,32.694768,-117.191425_rect/17_zm/1_fr/?view=public.TripAdvisor tells us: “Developed in 1888 as a beach resort town, and home to the famous Hotel del Coronado, the island is blessed with one of the finest beaches in the world and bathed in endless sunshine.” Must be nice. ↑
A touch of irony: Bartholomew’s career includes a stint at FERC’s Office of Enforcement investigating Energy Transfer Partners and Amaranth market manipulation. http://www.gpo.gov/fdsys/pkg/CHRG-113shrg91522/pdf/CHRG-113shrg91522.pdf (pdf pages 1617-1618). ↑
https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=13317770. ↑
https://rtoinsider.com/pjm-greenhat-energy-market-manipulation-jp-morgan-ftr-100407/. According to corporate documents on file with the Texas secretary of state, Bartholomew formed GreenHat on June 25, 2014. Ziegenhorn was added as a manager on Aug. 7, 2014, and Kittell was added as a manager on Feb. 26, 2015. ↑
As early as April 2016, at least one FTR market participant was warning PJM about a 100 million MWh FTR position with minimal collateral, what DC Energy called the “Illustrative Portfolio” (yes, GreenHat’s). https://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=1493734. ↑
“PJM Interconnection, L.L.C. … Verified Rule 202 Petition,” District Court of Harris County, Texas, Cause No. 201869829-7, filed Oct. 1, 2018. ↑
https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14970001 (pdf page 13). ↑
“PJM asked Mr. Kittell for permission to contact the counterparty to the bilateral trades regarding the contractual arrangement with GreenHat, and Mr. Kittell denied PJM’s request and specifically asked PJM not to contact the counterparty.” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (page 4). ↑
The email trail we have in the FERC filings has PJM asking for more support from GreenHat and ultimately sending an email on April 19, 2017, requesting a log of every payment GreenHat had received from Shell. But from there the paper trail goes cold: PJM doesn’t provide any response from GreenHat. https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (Appendix B, second page).Nor does it appear PJM questioned why Shell would pay GreenHat $62 million for positions actually worth a fraction of that amount (as discussed later). ↑
“To avoid a claim of interference with GreenHat’s contractual counterparty and to allow GreenHat the ability to sell down its portfolio, PJM had no choice but to comply with this request [that PJM not contact Shell].” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (page 4).This is puzzling. PJM had at least colorable Tariff authority to require meaningful collateral or other protection (if not as a condition to maintain existing positions, surely as a condition to expand those positions): “PJMSettlement may select participants for review on a random basis and/or based on identified risk factors such as, but not limited to, the PJM markets in which the participant is transacting, the magnitude of the participant’s transactions in the PJM markets or the volume of the participant’s open positions in the PJM markets. Those participants notified by PJMSettlement that they have been selected for review shall, upon 14 calendar days’ notice, provide a copy of their current governing risk control policies, procedures and controls applicable to their PJM market activities and shall also provide such further information or documentation pertaining to the participants’ activities in the PJM markets as PJMSettlement may reasonably request. … Each selected participant’s continued eligibility to participate in the PJM markets is conditioned upon PJMSettlement notifying the participant of successful completion of PJMSettlement’s verification of the participant’s risk management policies, practices and procedures, as discussed herein.” PJM Tariff Attachment Q, Section I.B (emphasis added).PJM seemed to rely on Attachment Q, Section II.D.2 (PJM has the right to “require additional collateral as may be deemed reasonably necessary to support current market activity.”), but this section appears applicable only to an “unsecured credit allowance,” which is not what GreenHat apparently had. ↑
GreenHat had a portfolio position of about 375 million MWh in mid-June 2017. The Pledge Agreement was entered into late June 2017. GreenHat went on to increase its position to 890 million MWh. https://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=14937343 (Figure 1, page 9).It is not clear how this more than doubling of the GreenHat position comports with PJM’s statement, quoted in the preceding footnote, that PJM was motivated to go forward with the Pledge Agreement to “allow GreenHat the ability to sell down its portfolio” (emphasis added). ↑
“PJM specifically asked Mr. Kittell if the counterparty had paid GreenHat any of the money due to GreenHat under their bilateral trade agreements. GreenHat never informed PJM that the counterparty had paid any money on that contract. Instead, Mr. Kittell forwarded PJM documents indicating money that it claimed the counterparty owed to GreenHat under their contract that would flow to PJM under the Pledge Agreement. It wasn’t until June 2018 that PJM learned from Mr. Kittell that GreenHat sent two invoices with a “Final Purchase Price” due from the counterparty to GreenHat under two separate FTR bilateral agreements between the two parties — well before GreenHat commenced discussions with PJM regarding the Pledge Agreement, and that the counterparty paid GreenHat all of the money the counterparty believes was due to GreenHat under those bilateral agreements.” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (pages 4-5, emphasis added). ↑
How is such a thing possible? GreenHat could have used the PJM eFTR system so as to make it appear as if Shell owed GreenHat an amount that far exceeded the actual value of the positions. There is a field in the eFTR system, which PJM does not use in settlement, that purports to offer market participants the ability to enter bilateral contract transaction prices. The GreenHat/Shell transacted FTRs had entered prices in this field that did in fact add up to at least $62 million, which GreenHat apparently offered to PJM as proof that it had receivables to pledge to PJM. But use of this field is not customary for bilateral transactions in the eFTR system (most market participants leave this field blank or enter 0). In other words, GreenHat could have entered 62 cents or $620 trillion with no economic significance (which may explain why Shell would not have cared what GreenHat entered). The actual transaction prices between GreenHat and Shell would be governed by the contracts entered into by the parties, not by what was entered into eFTR. The GreenHat invoices in 2016-2017 for “Final Purchase Prices” of $5.2 million and $1.5 million appear to reflect the economic substance of the FTR sales. ↑
PJM is trying to keep $550,000 in collateral of a GreenHat affiliate in PJM Interconnection, L.L.C., Docket No. ER18-1972-000. $550,000 is peanuts. PJM’s efforts should be on civil action and on FERC Enforcement. ↑

November 6, 2018February 12, 2025

Canada, New England Talk Trade, Politics and Clean Energy

By Michael Kuser

BOSTON — Energy made up $130 billion of the $750 billion that changed hands last year between Canada and the U.S., the largest bilateral trading relationship in the world. Industry participants on both sides of the border question why the Trump administration would risk that relationship with protectionist tariffs.

The New England-Canada Business Council (NECBC) 26th Annual Energy Trade & Technology Conference took place Nov. 1-2 in Boston. | © RTO Insider

Sergio Marchi | © RTO Insider

“We believe in building bridges, not walls,” said Canadian Electricity Association head Sergio Marchi, speaking at the New England-Canada Business Council’s (NECBC) 26th annual energy conference Thursday, where attendees also discussed the changing resource mix, investment prospects and siting challenges.

Canadians were disappointed that the energy chapter in the original North American Free Trade Agreement was not preserved in the proposed United States-Mexico-Canada Agreement, and surprised the updated energy provisions were bilateral, not trilateral, Marchi said.

“The provisions of energy in the new NAFTA are scattered across a multiplicity of different sections, and so we’re puzzled as to why you would not want to consolidate all of these provisions in one coherent place,” he said.

David Alward | © RTO Insider

David Alward, consul general of Canada to New England and a former premier of New Brunswick, said Canada did not believe the premise of the original NAFTA was unfavorable to the U.S. and noted that negotiations over the new agreement led to a pessimistic cloud of uncertainty.

“But we achieved a good agreement and brought a certain level of predictability to the relationship,” Alward said.

Paul Hibbard | © RTO Insider

The Analysis Group’s Paul Hibbard, former chairman of the Massachusetts Department of Public Utilities, said, “It’s difficult to overstate the importance of Canada in meeting energy needs and renewables. … Looking forward, the potential growth in cross-border energy trade is staggering.”

Renewable, with Gas and a Little Oil

Massachusetts Energy and Environmental Affairs Secretary Matthew Beaton said his state is “continuing to make sure that we take a combo platter approach” to include all technologies in achieving a renewable energy future.

Matthew Beaton | © RTO Insider

“The existing markets are becoming more aligned on natural gas, which will continue to play a very important role in the market price of energy here in New England,” Beaton said.

Carol Grant | © RTO Insider

Carol Grant, commissioner of the Rhode Island Office of Energy Resources, said she is optimistic that people want to contribute to a cleaner world, “but I don’t think New England or anyone is saying at any price.”

ISO-NE Vice President of Market Operations Robert Ethier said the two most important issues for the RTO are winter fuel security and “addressing the states’ desire to bring in more carbon-free resources.”

Integrating those new resources is not now a problem for the RTO and likely won’t be for the next decade, Ethier said. It’s a two-fold economic challenge involving the energy and capacity markets.

“One is, bring in these zero-marginal-cost resources and insert them into our real-time supply stack, and it lowers energy prices for everyone,” Ethier said.

Robert Ethier | © RTO Insider

Second, “when the states contract for these resources, they don’t just affect the energy market, they also affect our capacity market,” Ethier said. So the RTO developed Competitive Auctions with Sponsored Policy Resources “to insulate the capacity market outcomes from having these resources, which are by most estimates uneconomic to enter into our capacity market, but enter anyway because they have long-term state contracts.”

Having new state-sponsored resources buy out old resources in the market will help manage and ration the entry of these resources into the market and prevent price suppression, he said.

“If we want to have long-term competitive markets in New England, and we want to have the prospect of merchant investment five, 10 or 15 years from now … they need to have confidence that there are going to be market opportunities for them into the future that make it worth their while to invest their money,” Ethier said.

Dan Dolan, president of the New England Power Generators Association, said 60% of the region’s electricity will soon come from state-sponsored resources not dependent on the wholesale market, “but the market is not structured to protect the 40% of generators who will remain dependent on the market.”

One of the panels at NECBC (left to right): Robert Ethier, ISO-NE; Dena Wiggins, NGSA; Paul Hubbard, Analysis Group; Sergio Marchi, CEA; and Seth Jaffe, Foley Hoag. | © RTO Insider

On fuel security, Ethier said the market needs to incent gas-burning generators to fully utilize LNG facilities and also ensure the region continues to maintain its existing fleet of oil-burning resources, at least in the near term.

“Those resources have remarkably low capacity factors for resources that were built as baseload … in the 1 to 2% range, so they hardly ever run,” Ethier said. “The thing is, when they do run, we really need them.”

Dena Wiggins | © RTO Insider

Dena Wiggins, president of the Natural Gas Supply Association, said that ample and diverse natural gas supplies balance the current weak U.S. gas storage picture of about 3 Tcf, so that a disruption to production in one place no longer spikes prices.

“It’s a little bit different here in New England, but those are spot prices,” Wiggins said in reference to potential spikes. “Our consultant tells us that during the winter peaks, only about 1% of the gas traded at those high prices.”

Siting Concerns

Attorney John Gulliver of Pierce Atwood compared 2000 with 2017, with New England nuclear remaining steady over that period, producing 31% of power, while oil moved from 22% to 0.7%, coal declined from 18% to 2% and natural gas grew from 15% to 48% — “with the balance made up by healthy growth in hydro and renewables.”

Seth Jaffe | © RTO Insider

Attorney Seth Jaffe of Foley Hoag said policymakers may be willing to pay the price for pursuing their political goals of a carbon-free economy, but both gas pipelines and hydropower transmission from Canada have had problems getting sited, even when hydro nominally supplants the need to burn natural gas. “You have to wonder, how are we going to get these projects done?”

Avangrid CEO James P. Torgerson said the difficulty in siting onshore wind in New York and New England is just one reason why offshore is more appealing.

James P. Torgerson | © RTO Insider

“You still have to deal with the intermittency, but the good thing about offshore wind [is] the capacity factors we’re seeing for that should be in the 50% range,” compared with 33% for existing onshore wind and 40% for new onshore projects, Torgerson said.

Speaking about Avangrid’s New England Clean Energy Connect (NECEC), a project of subsidiary Central Maine Power to bring 1,200 MW of Canadian hydropower to Massachusetts, Torgerson said, “We expect to get all the approvals in 2019,” despite Maine regulators in October having suspended hearings on the project. (See Maine PUC Move Poses Hurdle for NECEC.)

The Maine Public Utilities Commission on Nov. 2 scheduled several technical conferences in the case (Docket No. 2017-00232) ahead of resuming hearings January.

“Some communities are not as supportive as they initially were … but things evolve,” Torgerson said.

NECEC faces some of the same issues as Northern Pass did in New Hampshire, so when Maine environmentalists protested plans to string high-voltage lines across the Kennebec Gorge, for example, Avangrid agreed to tunnel under the river, he said.

The project to deliver Quebec’s hydropower will reduce electricity prices in Maine by about $40 million a year, provide communities $18 million a year in tax benefits and add more than $500 million to Maine’s GDP, Torgerson said.

Ian Robertson | © RTO Insider

Algonquin Power & Utilities CEO Ian Robertson noted how the intermittency of renewables is declining and the potential for storage to assist the trend.

“We’re all trying to understand how battery storage fits into that equation. Part of what we’re doing is working with regulators to put 500 of the Tesla Powerwalls in,” Robertson said. “But I’m not sure anybody in a utility really understands how storage can be most effectively introduced into an electric grid to create value for customers.”

November 6, 2018

FERC OKs Adjusted Rate for Disputed Transource Line

By Rory D. Sweeney

FERC on Thursday approved the designated entity agreement (DEA) for Transource Energy’s Independence Energy Connection, PJM’s largest-ever congestion-reducing transmission project, with one condition: that Transource stick to its original commitment for how long it can use an increased amount of equity in its rates (ER17-349).

The commission ordered that PJM submit a compliance filing within 30 days on the project that aligns the return on equity allowed for Transource in the DEA with the amount agreed to in a settlement agreement in the case. The current DEA limits Transource’s formula rates to 50% equity “once permanent financing is in place” and as long as capital market conditions “remain normal.”

Transource Energy’s Independence Energy Connection will be PJM’s largest-ever congestion-reducing transmission project. | *Transource*

The settlement requires Transource to reduce its equity mix from 60% to 50% by June 1, 2020. The reduction would be triggered earlier if the project goes into service or permanent financing is obtained.

The $366.2 million 230-kV project is being opposed by some residents along its path between Washington County, Md., and Franklin County, Pa. (See PJM Redirects Residents’ Protests of Tx Project to States.)

The compliance filing is the third in the project’s approval path. The DEA was conditionally accepted on Jan. 12, 2017, and PJM submitted its compliance filing on March 2. That filing is now accepted with the required changes.

Transource’s Independence Energy Connection project consists of two separate lines that run north-south across the Pennsylvania-Maryland border. | *Transource*

The DEA approval was also conditional on the outcome of the project’s formula rate proceeding. The formula rate was conditionally approved on Jan. 31, 2017, and PJM submitted its compliance filing on March 2, 2017.

Transource requested rehearing of the formula rate but joined PJM in submitting a settlement offer on Oct. 2, 2017. FERC conditionally accepted the settlement on Jan. 18, 2018. PJM submitted its compliance filing on Feb. 16, which the commission approved on Sept. 21. The rehearing request was denied on July 6.

November 6, 2018

SPP Board of Directors/Member Committee Briefs: Oct. 30, 2018

By Tom Kleckner

The SPP Board of Directors and Members Committee met Oct. 30. | © *RTO Insider*

Stakeholders Honor Eckelberger, Skilton’s Service

LITTLE ROCK, Ark. — SPP directors, members, staff and other stakeholders took time out last week from the normal board week activities to honor two directors who predate the organization’s RTO status.

The RTO treated Jim Eckelberger, who stepped down in April after 14 years as the Board of Directors’ chairman, and Harry Skilton, vice chair for 14 years, to a catered farm-to-table dinner the night before the Oct. 30 board meeting.

The SPP board and members give Skilton (foreground) and Eckelberger a standing ovation. | © *RTO Insider*

Staff shared a video of family, friends and stakeholders sharing their favorite anecdotes about the two men. Both were presented with plaques topped by — what else? — replicas of transmission towers.

Eckelberger and Skilton are the last remaining members of SPP’s original board, which was created in 2000. FERC didn’t recognize SPP as an RTO until 2004.

Since then, SPP has expanded its footprint with the addition of Nebraska utilities and the Integrated System, and by offering reliability coordination (RC) services to Western Interconnection entities. The RTO has also become one of the lowest-cost grid operators by creating day-ahead and financial transmission rights markets and investing billions in transmission infrastructure.

Eckelberger, who takes great pride in SPP’s cost of service, pointed to an LMP contour map of the footprint, dominated by the cool blue denoting prices in the $20 to 30/MWh range, as an example of the RTO’s effectiveness.

“SPP greatly appreciates the 18 years Jim and Harry dedicated to SPP,” CEO Nick Brown said. “They have made extraordinary contributions to our company and were instrumental in transforming SPP into the regional transmission organization we are today.”

“Both should be proud of the legacy they have created here for SPP,” said Larry Altenbaumer, who replaced Eckelberger as chairman in April.

“I’m very fortunate to have 18 years at SPP be the capstone of my career,” Skilton said.

Both men are transitioning into emeritus status, effective Jan. 1.

“We’re fortunate they’ll be staying on in this emeritus role, because they have a wealth of experience,” said the Members Committee’s Tom Kent, COO for Nebraska Public Power District.

Awards of recognition for Skilton and Eckelberger | © *RTO Insider*

Members Elect 2 New Directors

The Members Committee replaced Eckelberger and Skilton on the board by electing newcomers Susan Certoma and Darcy Ortiz during its annual meeting. The appointments are effective Jan. 1.

Bruce Scherr, who joined the board in January 2016, was also re-elected.

Newly elected Director Susan Certoma | © *RTO Insider*

Certoma is president of Enterprise Engineering, which provides software and consulting to financial firms. She previously held technology-related positions at Wachovia Bank, Goldman Sachs, Merrill Lynch and Lehman Brothers during 30 years in the finance field. Certoma holds a bachelor’s degree in management and economics and an MBA from St. John’s University.

Ortiz is Intel’s vice president and general manager of corporate services. She previously led the global team responsible for Intel’s IT operations and services and served in several CIO positions. She has a bachelor’s degree in business administration from the University of New Mexico and an MBA from the University of California, Berkeley.

Brown said the new members’ technology backgrounds will be invaluable to SPP.

“Much of our continued success now hinges on effective management of data and technology infrastructure and our approach to cybersecurity,” he said in a statement.

The committee also elected seven representatives to three-year terms on the committee, with “the narrowest of unanimous margins,” Altenbaumer joked.

Members Committee ballot | © *RTO Insider*

The representatives are Kent for State Power Agencies; Blake Mertens (Empire District) and Kevin Noblet (Evergy) for Investor-Owned Utilities; Jason Atwood (Northeast Texas Electric Cooperative) and Mike Wise (Golden Spread Electric Cooperative) for Cooperatives; Kevin Smith (Tenaska Power Services) for Independent Power Producers/Marketers; and Jody Sundsted (Western Area Power Administration – Upper Great Plains) for Federal Power Marketing Agencies.

Mertens is the only newcomer; everyone else was re-elected.

Altenbaumer Tweaks New Governance Schedule

Altenbaumer continues to tinker with the board’s meeting schedule as he enters his first full year as chairman, saying he wants to “elevate the work of the board and members to focus on those things that are strategically important.” (See SPP Strategic Planning Committee Briefs: Oct. 18, 2018.)

Board Chair Larry Altenbaumer explains changes in 2019 as CEO Nick Brown (left) and Director Graham Edwards listen. | © *RTO Insider*

Following feedback from members and the Regional State Committee, Altenbaumer has scheduled a joint session between the board and RSC on the day the state regulators normally meet (the day before the board’s quarterly meeting). That time will be used for joint informational and background presentations to the directors, members and RSC.

“It’s an opportunity to become more efficient,” Altenbaumer said. “Many presentations given to the RSC turn out to be warmups for the same presentations to the board the next day.”

Altenbaumer has left slots in the RSC and board meetings for executive sessions, but he promised “anything that relates to decisions will be addressed during the typical [open] board meeting.”

Addressing stakeholder concerns that the changes could reduce transparency, Altenbaumer said keeping discussions from public view is “by far the last thing intended from this.”

“If any of you ever feel these things are trending in the wrong direction, as far as engagement and transparency, bring it to my attention,” he said.

Given a chance to respond publicly to Altenbaumer’s comments, no one did.

As proof of how governance will be handled in the future, Altenbaumer noted the board’s only approval item was the consent agenda.

“That speaks to the collaborative process,” he said. “This is a desire to try and improve the overall governance.”

Two days later, SPP moved its December board meeting, which has traditionally been used to approve the budget, from Little Rock to the more accessible Dallas/Fort Worth International Airport. The meeting has also been shortened by two hours; next year, it will likely become a conference call.

MMU Clarifies its Role in Generator Retirements

MMU Executive Director Keith Collins addresses the board and members. | © *RTO Insider*

Keith Collins, executive director of SPP’s Market Monitoring Unit, clarified comments he made during recent governance meetings that raised stakeholder concerns about the MMU’s involvement in generator retirement decisions. (See Stakeholders Push Back Against SPP Retirement Changes.)

At October’s Markets and Operations Policy Committee and Strategic Planning Committee meetings, some stakeholders pushed back against the possibility of the MMU intervening in regulatory proceedings. Collins said the MMU would only raise concerns in instances of physical withholding or other market power issues.

“The SPP Tariff is very clear,” he said. “Physical withholding and market power are under the MMU’s purview.”

“The MMU has an obligation to investigate and review those issues,” said Director Joshua W. Martin III, who chairs the Oversight Committee. The MMU reports to Martin’s committee.

Collins said the MMU has always used available data when it reviews generator retirement requests, and that the MOPC discussion was an attempt to collect data from market participants to improve its analysis.

He noted the Tariff is unclear as what the MMU should do if it identifies physical withholding or market power.

“Our responsibility rests with FERC,” Collins said. “To the extent we identify market power of physical withholding, we would have to raise that issue with FERC, unless the protocols or the Tariff [are] clarified as to what steps should be taken.”

“The Oversight Committee has reviewed this issue, and we’re comfortable with where it is right now,” Martin said.

SPP staff have said they will provide the MOPC and the board draft Tariff revisions for generator retirement procedures in January.

SPP-MISO Operating Procedures not yet Documented

Brown said during his president’s report that it is “untenable” that SPP and MISO “end up in situations where our operators are confused,” as happened in January’s “Big Chill” event.

The two RTOs have increased their coordination across their seam since the Jan. 17 event, when severe cold weather and generation shortfalls in MISO South led MISO to exceed its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. MISO made emergency energy purchases from Southern Co. before operations returned to normal.

Brown recalled that shortly after the event, he had told the board that one of his top priorities for the year was to reach an agreement with MISO on “exact operating procedures.”

“I was hoping to report we have signed documents for this meeting, but we don’t,” Brown said.

He was able to share with directors and members a pamphlet that says SPP members receive $1.7 billion in annual benefits, an 11-1 benefit-cost ratio. The document notes the Integrated Marketplace has produced more than $2 billion in savings since going online in 2014 and references a study that indicates every dollar SPP spends on transmission investment returns $3.50 in benefits.

“I would have no problem standing before any regulatory committee and defending these numbers,” Brown said.

Western RC Services to Net $3.4M

Operations Vice President Bruce Rew said SPP’s RC contracts with Western Interconnection entities will result in $3.4 million in net income through 2024. (See CAISO RC Wins Most of the West.)

SPP expects to earn $28.4 million in revenue over the life of the five-year contracts, which are effective in January 2020. However, adding up to 20 staffers in Little Rock to handle the new responsibilities will eat into much of that revenue.

Under the contract’s terms, the Western entities will pay an initial 5.5 cents/MWh. Annual extensions will begin in 2025, and mutual withdrawal provisions are included.

Smaller entities may yet participate in SPP’s RC services, Rew said. Later entities would be evaluated on a case-by-case basis.

Consent Agenda’s Approval Adds, Deletes Members

The board’s consent agenda included changes to the membership agreement that would clear the way for Mor-Gran-Sou Electric Cooperative to become the newest SPP member.

The Corporate Governance Committee approved membership agreement amendments for the North Dakota co-op similar to changes that facilitated the membership of Basin Electric Power Cooperative and its members as part of the Integrated System’s integration. Mor-Gran-Sou, which is embedded within the Integrated System, intends to join SPP as a transmission owner.

The CGC also recommended Cielo Wind Power’s membership be terminated immediately for failing to keep up with its membership dues and repayment agreements. SPP said Cielo in January stopped responding to the RTO’s outreach efforts and ignored a March demand letter.

The Austin, Texas-based company’s delinquency dates back to 2016. It owes $18,000 and interest.

The consent agenda also included staff’s recommendation to revise the SPP-MISO Coordinated System Plan. (See “MOPC Approves Changes to Joint Model with MISO,” SPP MOPC Briefs: Oct. 16-17, 2018). Also on the agenda were the Finance Committee’s 2019 operating plan, updates to the 2019 Integrated Transmission Planning assessment’s scope, the Market Working Group’s annual violation relaxation limits analysis, and nine revision requests:

MWG RR266: Substitutes “interest” for “ownership” in language modeling joint-owned units as single resources, recognizing that “ownership” doesn’t capture stakeholder intent that power purchase agreements and other non-ownership interests be included.
MWG RR288: Allows non-dispatchable variable energy resources converting to dispatchable status to use control statuses not originally available to them. SPP’s control statuses are: offline (the resource is not operating); non-regulating (online and capable of following a dispatch instruction or contingency reserve deployment but not eligible to clear regulation service); regulating (online and capable of following dispatch or contingency reserve instruction, and regulation deployment); and manual (online but not able to follow dispatch; e.g., start-up, shutdown, testing, etc.).
MWG RR316: Updates the multi-configuration (combined cycle) resource market design by adding two additional commitment parameters: group minimum down time and plant minimum down time. Also removes sync-to-min and min-to-off times from the submitted minimum down time or group minimum down time when the resource transitions between operational configurations. The current design only allows individual registered configurations to submit a minimum down time.
MWG RR323: Defines batteries as electric storage resources (ESRs), capable of being dispatched and participating in price formation. Excluded as ESRs are those resources that are either contractually barred or physically incapable of injecting energy back onto the grid because of their design or configuration. Also creates a new registration type, “market storage resource,” to be used only by ESRs.
MWG RR332: Corrects protocol calculations from designs implemented in RR200 (design change for bilateral settlement schedules (BSS) and over-collected losses (OCL) distribution) and RR235 (correction to RR200) necessary to accurately distribute OCLs and ensure BSS are receiving their correct OCL. The change ensures corrected resettlements back to the original May 1, 2018, release date.
ORWG RR318: Changes the contingency reserve requirement calculation to allow the use of the “most severe single contingency” as the basis of the minimum contingency reserve requirement on an hourly basis. SPP said the revision allows it to more accurately and reliably set the reserve requirement.
RTWG RR305: Updates Tariff language following modifications to the aggregate facilities study process by removing the requirement to file a service agreement before modeling new transmission service in the ITP models. Also removes the requirement that SPP issue notifications to construct (NTC) and notifications to construct with conditions (NTC-C) before filing a service agreement. Adds a financial commitment date of four years to the issuance of an NTC or NTC-C.
RTWG RR322: Changes the Tariff and other documents to reflect that the RTO is no longer using U.S. Energy Information Administration data in monthly load forecasts. SPP said the data in the EIA report are not granular enough because they are at the balancing authority level, rather than the local balancing authority level required. In January, the RTO began using forecast data that are available through the NERC system data exchange (SDX) and historical data where forecasts are not available.
RTWG RR325: Revises SPP’s pro forma language for large generator interconnection procedures and large generator interconnection agreements to comply with FERC Order 845.

November 6, 2018

Microgrids Seek Path out of Regulatory Limbo

By Michael Brooks

BALTIMORE — The drafters of the 1935 Federal Power Act could not have imagined modern distributed energy resources, let alone a small network of them that can operate independently of the grid.

“The phenomenon that I think FERC confronts and other agencies in Washington confront is that there’s been a lot more technological change than there’s been legislative change for a whole bunch of reasons that are above my pay grade to diagnose,” Commissioner Cheryl LaFleur told attendees of Microgrid 2.0 at the Hyatt Regency Baltimore Inner Harbor last week.

FERC Commissioner Cheryl LaFleur | *International District Energy Association*

“We’re trying to solve 21st century problems using … a 1930s law.”

How microgrids should be regulated was a central topic at the third annual conference held by the International District Energy Association (IDEA), which advocates for distributed generation, district heating and cooling, and combined heat and power.

Christopher Berendt, Drinker Biddle & Reath | *International District Energy Association*

“The reason we’re here talking about this today, probably more than anything else, is that consumer demand is driving us, and that we’re seeing more and more people say, ‘We want to see mixed-use, multi-customer microgrids because we want the variety of benefits that can come out of them,’” Christopher Berendt, counsel to IDEA’s Microgrid Resources Coalition, said during a panel on market design and policies.

Regulatory risk, he said, “acts kind of like repellant to private capital.”

“There is more capital waiting to flow into microgrid investment right now [that] you would not believe,” said Berendt, a partner with Drinker Biddle & Reath. “There is more capital chasing fewer good projects, and what is really needed to unlock those loads of capital and get more good steel in the ground is not the desire to deploy it, but the regulatory frameworks that support project financing.”

Without any direction from Congress, however, regulators must work with what they have. During her luncheon keynote speech, LaFleur pointed to the complications of DER aggregation, which the commission has been working on for nearly two years. (See FERC Rule Would Boost Energy Storage, DER.)

“It seems quite clear that distributed resources can be aggregated and bid into the market and contribute great value. But since they’re, in many cases, behind the meter, what do the states figure out? Who gets the first bite of the value?” LaFleur asked. “How are we going to figure out who pays what to whom in a sensible way? I think our staff has made a lot of progress in thinking about it. I think it can be worked through, but it’s a little more complicated than some of the … issues we usually deal with because of the number of different uses, and because although it acts wholesale when we see it in the markets, it’s actually at the distribution level.”

Commissioner Richard Glick told the Energy Bar Association last week he hopes the commission will act soon to encourage aggregation of DERs in wholesale markets. (See related story, Nearing 1-Year Mark, Glick Rejects ‘National Security’ Grid Risk.)

Dan Dobbs, Anbaric Development Partners | *International District Energy Association*

The industry also faces challenges at the state and local levels over siting rights of way and whether microgrids are defined as public utilities. “One thing all jurisdictions in this country have in common is that they’re not set up for microgrids,” Berendt said

Dan Dobbs, vice president of distributed energy for Anbaric Development Partners, pointed to New York’s Value of Distributed Energy Resources tariff as “a start.” (See NYPSC Takes Subway into Value Stack.)

“It’s not perfect, but it’s a good attempt at getting that value,” he said. But “you really need to be able to value power that comes in and goes out equally. That’s at the retail level, and you need to be able to do that similarly at the wholesale level when you are aggregating resources.”

November 6, 2018

FERC Sets GridLiance’s Zonal Placement for Hearing

By Tom Kleckner

FERC last week allowed GridLiance High Plains to begin rate recovery Nov. 1 for its facilities in the Oklahoma Panhandle but set the company’s proposed annual transmission revenue requirement subject to refund and settlement judge procedures (ER18-2358).

The Oct. 31 order rejected requests from SPP transmission owners to reject the filing or suspend rate recovery.

GridLiance’s assets, 410 miles of 69- and 115-kV lines and related substation infrastructure, were acquired in 2016 from Tri-County Elec. Co-op. (See GridLiance Closes Deal for Tri-County Co-Op’s Tx Assets.)

SPP placed the facilities in Southwestern Public Service’s transmission pricing zone, Zone 11. The RTO said in its August filing that GridLiance’s ATRR and facilities were not large enough to warrant their own pricing zone, and that they were also interconnected solely with Zone 11 facilities.

Tri-County service territory | *Tri-County Elec. Co-op*

It said the addition of the GridLiance assets will increase Zone 11’s ATRR of $112 million by 6.9%. Network integration transmission service charges will rise 2.8% if the ATRR of transmission facilities whose costs are recovered under Schedule 11 (Wholesale Distribution Service) is included, the RTO said.

More than a dozen SPP TOs and cooperatives and the Texas Public Utility Commission protested SPP’s filing, arguing that the RTO did not explain how upgrades GridLiance made to the Tri-County assets benefit existing Zone 11 customers and questioning how FERC could determine the additional costs were fair without analyzing the benefits.

Xcel Energy complained that GridLiance constructed more than $50 million of facilities outside the SPP regional transmission planning process even though the Tri-County load has decreased by at least 23 MW since 2016.

GridLiance said its planned and constructed upgrades address outages from ice and wind storms that resulted from a non-networked system.

Brett Hooton, president of GridLiance High Plains, said he was pleased FERC denied requests to reject the filing or suspend rate recovery.

“We look forward to demonstrating why wholesale loads are entitled to enjoy comparable reliability as the load served by the dominate transmission owners within SPP and how our reliability improvement upgrades meet that goal,” he told RTO Insider.

Commission OKs Revised ‘Financial Interest’ Definition

The commission also accepted revisions to SPP’s bylaws that clarify the concept of a financial interest. With the Nov. 1 order, SPP employees, directors and their spouses, minor children, and any person for whom they have power of attorney or guardianship rights will be allowed to invest in companies that have a de minimis relationship with the RTO and the electric sector (ER18-2376).

FERC agreed that SPP’s rules, developed before the expansion of its membership and market participation, created barriers in recruiting and retaining directors and employees. The commission said the bylaw revisions should continue “to safeguard SPP’s independence” by prohibiting directors and employees from investing in market participants active in the Integrated Marketplace.

FERC Order 2000 bars grid operators, staff and non-stakeholder directors from holding financial interests in any market participant and require them to maintain independence from “any entity whose economic or commercial interests could be significantly affected by the RTO’s actions or decisions.”

November 6, 2018

FERC OKs MISO External Capacity Zones, Dispute Deadlines

By Amanda Durish Cook

MISO can create external zones for its annual capacity auction and place time limits on members’ settlement disputes, FERC ruled in a pair of Oct. 31 orders.

The first order allows MISO to create external resource zones and modify capacity import and export limits to align with them. Excess auction revenues will be divided among load-serving entities with historic supply arrangements that may be affected by the new zones (ER18-2363).

FERC said distinguishing external capacity suppliers from internal ones would preserve the intent of the RTO’s local clearing requirement. “We find it just and reasonable … for MISO to no longer count all external resources, regardless of electrical distance and dispatch control, towards satisfying the local clearing requirements for MISO’s local zones. Continuing to do so would undermine the purpose of the local clearing requirement, which is to ensure that a sufficient amount of unforced capacity is located within each local zone so that each local zone can meet its [loss-of-load expectation] during its local zone peak demand when it is import-constrained,” the commission said.

FERC also brushed aside stakeholder protests that the RTO’s plan was hasty because its current treatment of external resources was not causing reliability issues. “A transmission operator need not wait until there is a reliability event before proposing tariff revisions to prevent one,” the commission said.

It also rebutted municipal agencies’ argument that WPPI Energy’s Nelson Energy Center in Illinois should be considered a border external resource because Exelon’s Quad Cities nuclear plant is considered one. The commission said that while Quad Cities is directly connected to the MISO system, the Nelson plant “requires intervening transmission to reach the MISO transmission system” and doesn’t follow a predictable path. FERC also declined to speculate on municipal agencies’ concerns over how the RTO might treat future external generation using the proposed Grain Belt Express HVDC line, saying such discussion was “premature.”

FERC had rejected MISO’s plan for external capacity zones in August, taking issue with a proposal allowing an external resource bordering more than one local resource zone to choose which zone to participate in during the auction. The commission also rejected a provision that would have allowed holders of evergreen supply contracts written prior to the RTO’s capacity construct to receive historical supply arrangement credits in perpetuity.

MISO responded with edits that made evergreen contract extensions eligible for excess auction revenues for the original term of the contract or two years, whichever is longer, and a new electrical connectivity analysis that ensures external resources bordering more than one local resource zone participate in only one zone. (See MISO Adds Study to 2nd External Zone Filing.)

FERC accepted both changes and said the two-year limit would ensure that resources won’t be able to “permanently avoid the locational price signal that MISO’s resource adequacy construct was designed to provide.” But the commission said that the RTO should notify owners of external resources bordering multiple zones which zone they’ll be assigned to in the upcoming auction. MISO agreed to provide the notice.

Limits on Settlement Dispute Resolution

FERC’s other order allows MISO to bar settlement disputes that are not initiated within approximately four months (ER18-1648-001).

Effective Nov. 1, members have a 120-day time limit for initiating transmission or market settlement disputes and another 90 days to request either an informal or formal alternative dispute resolution if the member doesn’t like MISO’s response. The RTO has two years from the operating day in question to make resettlement corrections. Resettlement outside the two-year cutoff would require MISO and the participant to seek a Tariff waiver with FERC. The commission’s order permits MISO to create a “Limitations on Claims and Adjustments” section of its Tariff.

The 120 days will be counted from the operating day of the market settlement in question or the date of the first transmission settlement invoice. The 90 days are counted from the day the settlement dispute was “resolved or determined” by MISO.

The RTO said the two years would also apply to settlement errors that it “unilaterally discovers without a related dispute submission by a market participant.”

Until now, MISO’s Tariff did not prohibit settlement disputes that are not submitted within specified time periods.

MISO’s first attempt at the dispute resolution filing was met with a FERC deficiency letter, questioning the two-year requirement. (See FERC Seeks Details on MISO Dispute Resolution Plan.) The RTO argued “that the need for market certainty and promptness of claims supports a two-year resettlement period.” It added the definition of “continuing error” to the two-year provision, which covers “continuing, system, software or other execution that is inconsistent with the Tariff.” The term replaces the undefined terms “system error” and “software error,” which MISO used in its first filing.

MISO said it only foresees two kinds of transmission and market settlement errors: those in system procedures or software that take longer to identify or “execution errors,” including human errors, that are more easily identifiable.

FERC said the RTO’s proposal strikes an “appropriate balance between requiring market participants to promptly initiate claims involving readily discoverable one-time MISO errors and the correction of more long-lasting MISO errors that may not be readily discoverable.”

November 4, 2018

Nearing 1-Year Mark, Glick Rejects ‘National Security’ Grid Risk

By Rich Heidorn Jr.

WASHINGTON — Nearing the end of his rookie year, FERC Commissioner Richard Glick last week reiterated his opposition to the Trump administration’s efforts to protect coal and nuclear generation, rejecting the notion that national security is at stake.

The luncheon speaker for the second day of the Energy Bar Association’s Mid-Year Energy Forum, Glick opened his address with wishes for a “speedy recovery” for Commissioner Kevin McIntyre, who stepped down from the chairmanship Oct. 24 after disclosing a “serious setback” in his battle with a brain tumor. McIntyre last appeared in public at the commission’s July meeting. “We hope he’s back at 888 First St. [FERC headquarters] as soon as possible,” Glick said.

After that, Glick reflected on his first 11 months in office and the “resilience” debate sparked by the Department of Energy’s proposals to deliver on Trump’s campaign promise to save the coal industry. Last month, the administration reportedly dropped DOE’s proposal to invoke emergency powers to provide price supports for “fuel secure” generation following opposition from the National Security Council and National Economic Council. (See Chatterjee Dodges as DOE Spins on Coal Bailout.)

“Fortunately, at least according to press reports, that particular approach may be waning,” Glick said. “It’s hard to tell … we still hear from the secretary of energy … and others in the Department of Energy — suggesting that we have a national security emergency. The concern I have — and both parties do this — people overuse the term ‘national security.’”

Glick, a Democrat, agreed that policymakers “should be prepared for low-frequency, high-impact events” such as extreme storms and cyberattacks. “This isn’t a new issue … [NERC has] been looking at this issue for a number of years. They haven’t always been calling it ‘resilience.’”

If gas pipelines are at risk from cyberattacks, “let’s try to figure out how to solve the cybersecurity problem,” he said. “We should figure that out, not try to figure out some other solution that seems to be aimed elsewhere. And I think everyone recognizes if we do have issues with blackouts … the issues are mostly going to be in transmission and distribution, not necessarily generation.”

The commissioner rejected the argument that the Supreme Court’s 1944 Federal Power Commission v. Hope Natural Gas Co. ruling ensures generation owners will not lose money on their investments. “I don’t think that’s what Hope said, especially in a competitive market. … Not everyone can make money. There’s going to be some companies that do well, and some aren’t.”

Glick also noted the commission’s April order making it easier for renewables to interconnect with the grid (RM17-8) and said he hoped it will act soon on an order to encourage aggregation of distributed energy resources in wholesale markets. “I think that has the potential to be a big boon, both for reliability but also for those technologies and certainly for green energy,” he said. (See Ready to Act on DERs, FERC Tells Congress.)

November 4, 2018

PSEG, GridLiance Spar over Order 1000

By Rich Heidorn Jr.

WASHINGTON — Public Service Electric and Gas has never been a fan of FERC Order 1000. No wonder.

In 2014, PJM staff selected PSE&G to construct a $300 million transmission upgrade for Artificial Island — the RTO’s first competitive project — only to have the RTO’s Board of Managers reopen the bidding following protests from spurned bidders and others. PJM later awarded most of the project to LS Power. (See PJM Board Puts the Brakes on Artificial Island Selection.)

“I’d like to see the whole thing repealed,” Larry Gasteiger, chief of federal regulatory policy for PSE&G’s parent, Public Service Enterprise Group, said during a panel discussion on the landmark order at the Energy Bar Association’s Mid-Year Energy Forum last week.

Gasteiger, a former FERC chief of staff, acknowledged that that outcome is unlikely. He noted that the commission has taken no action to change the rule in the two years since it convened a technical conference to review its performance. (See Five Years Later, FERC Takes Another Look at Order 1000.)

But he said it has not met the commission’s hopes for creating competition. “Outside of the organized markets there has not been any competitive transmission bidding opportunities. Within the organized markets, it’s been mixed … to say the least. SPP’s Walkemeyer project is almost a poster child: spending $5 million on the competitive process for an $8 million project … that got canceled.” (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

He said relying on least-cost transmission solutions is akin to buying a $3,990 Yugo, the boxy import car mocked in the 1980s for its low quality.

Justin M. Campbell, chief development officer for GridLiance, a transmission developer backed by the private equity firm Blackstone Group, conceded the order has resulted in cumbersome solicitation processes.

But he said competition is essential to keeping transmission costs — which have risen to 10% of customers’ bills, from 6% in 2006 — under control. He cited LS Power’s winning bid on MISO’s Duff-Coleman project, which came in at $50 million, well below the projected $58.6 million.

He said competition has been hamstrung by state policies driven by incumbent transmission owners and RTOs’ “categorical” exemptions from competition for certain types of projects, such as those for reliability, projects whose costs are allocated locally or solutions below 300 kV.

Campbell rejected Gasteiger’s Yugo comparison, saying the developers competing for projects are not “two-men-and-a-laptop type of outfits.”

“What you’re going to see is Duke [Energy,] Edison [International and] American Electric Power. You’re going to see companies that own tens of thousands of miles of transmission and are fully capable — just like the incumbents,” he said, adding that competitors use many of the same engineering procurement construction (EPC) contractors as incumbents.

“The way we’re able to save cost is in more efficient design. It’s in how we handle the risk allocation between the customer and developer and EPC contractor. So, it’s things like that that [allow savings], not lowballing construction or anything like that.”

He cited a study the Brattle Group did for GridLiance and LS Power that found competitive projects — which often include cost caps or other cost controls — have averaged 40% below initial project cost estimates and could ultimately produce savings of 55%. The report said ratepayers in the U.S. and Canada could save $8 billion over five years if ISOs and RTOs increased the share of transmission investments opened to competition to 33%, up from 2% currently.

Transmission Planning: How Low Can You Go?

Other panelists discussed transmission planning and rates.

Theodore Paradise, ISO-NE | © *RTO Insider*

Theodore Paradise, ISO-NE’s assistant general counsel for operations and planning, said the rise of behind-the-meter generation and distributed resources may require a rethinking of transmission planning and the distinction between federally regulated transmission and state-regulated distribution. “Maybe it’s time for all of us to figure out where the power system is going as we do system planning looking out 10 years. Do we need to plan down to 115 [kV] for transmission?”

Consultant Paul Dumais, a former Avangrid executive, praised FERC’s Oct. 16 order changing how the commission sets TOs’ return on equity rates, a change expected to increase the ROE cap for Avangrid and other New England Transmission Owners (NETOs). (See FERC Changing ROE Rules; Higher Rates Likely.)

Paul Dumais, Dumais Consulting | © *RTO Insider*

When FERC approved incentive ROE adders for a $1.5 billion Avangrid project about 10 years ago, he said, “it really changed things in the company. There was a focused effort to make sure that capital was appropriated. … And in large part I believe it was due to the fact that there were incentives given for the particular risks and challenges of that project.”

When FERC reduced the NETOs’ ROE cap, however, Avangrid could only collect half of the incentive, Dumais said.

“The Iberdrola folks in Spain [then Avangrid’s parent company] felt they had been bait-and-switched.”

Dumais said he was hopeful that the commission’s new policy will allow it to resolve ROE complaints within the 15- month limit on refunds. Maine regulators, he noted, complete full utility rate cases in 12 months.

November 4, 2018

FERC Again Denies MISO Wind Developers’ Queue Complaint

By Amanda Durish Cook

FERC last week again declined to modify MISO’s interconnection queue rules, rejecting rehearing requests from wind developers who say the RTO is moving too slowly for them to meet the federal production tax credit deadline.

The Oct. 31 order is the second time FERC has denied EDF Renewable Energy’s request that MISO be required to devise a fast-track option in its interconnection queue for projects that can demonstrate readiness for development (EL18-55-001). (See FERC Sides with MISO in Queue Design Dispute.)

FERC once again declined to modify MISO’s interconnection queue rules | *E.ON Climate and Renewables*

E.ON Climate and Renewables, Invenergy, Tenaska Wind Holdings and Project Resources Corp. had joined EDF in seeking rehearing. The companies argued that FERC rendered a decision without addressing the situation’s harm to consumers or analyzing the need for a one-time departure from queue rules considering the 2020 PTC deadline.

But FERC said EDF still has not met its burden of proof to show that that MISO’s queue design is unreasonable, unjust or discriminatory. The commission also said “some of EDF’s claims about queue delays were overstated,” as the RTO said that most interconnection customers would complete the queue in time to begin commercial operation before Dec. 31, 2020, the deadline for receiving the full PTC. In any case, FERC said queue delays that might preclude some interconnection customers from the full advantage of a tax credit “does not amount to MISO’s failure to make reasonable efforts under its Tariff.”

“Delays in the interconnection process can be due to actions outside of MISO’s control, such as customer withdrawals and actions of affected systems,” FERC pointed out.

But, as with the last order, the commission ended with a warning for the RTO to improve its queue practices: “We strongly urge MISO, along with its stakeholders, to make addressing MISO’s interconnection queue processing delays a priority. We urge MISO to look to the other RTOs for best practices, closely examine the resources it is dedicating to the interconnection study process and consider whether additional resources would alleviate queue delays, as well as fully consider other approaches for improvement.”

MISO’s queue contains about 490 projects totaling more than 80 GW, down from 90 GW earlier in the fall.

The RTO has been working to speed up the queue through more stringent site control requirements and increased milestone payments. Staff say the changes will encourage stalled projects to withdraw from the queue earlier in the process. (See “MISO to File Queue Changes,” MISO Queues up Interconnection Options.)

The RTO has also eliminated the dynamic stability, short-circuit and affected-system analyses from the first phase of the queue’s definitive planning phase. The studies are repeated in the queue’s later phases. (See MISO Plan to Reduce Queue Studies Gets FERC Nod.)