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April 26, 2018June 17, 2024

NYISO Board Rejects Appeals on Capacity Votes

By Rich Heidorn Jr.

The NYISO Board of Directors has rejected two appeals of Management Committee votes on capacity zones and locational capacity requirements.

The board decli n ed to override the committee’s Feb. 28 vote that fell short of the threshold for authorizing a Tariff change to create rules for establishing and eliminating capacity zones. The committee had voted 54.1% in favor, short of the 58% required. (See “MC Rejects On Ramp/Off Ramp Changes” in NYISO Management Co m mittee Briefs: Feb. 28, 2018.)

The issue arose from Tariff revisions approved by FERC in 2012, setting rules for creating new capacity zones in the New York Control Area. The changes led the ISO to create a new capacity zone for the G, H, I and J load zones in the Lower Hudson Valley and New York City.

In denying an appeal by Central Hudson Gas & Electric and the New York Power Authority, the board said although some stakeholders called for developing rules for eliminating zones, FERC has not required them. The Independent Power Producers of New York (IPPNY), Cricket Valley Energy Center, Castleton Commodities Merchant Trading, Roseton Generating and the Long Island Power Authority (LIPA) opposed the appeal.

In 2017, ISO staff launched the “On Ramps and Off Ramps” project to consider rules for eliminating zones and concluded the deliverability-based approach used for creating zones was inappropriate for cancelling them. Staff said a reliability-based transmission security approach would be better for both creating and eliminating zones.

IPPNY said the change would distort market price signals and create uncertainty. Although it opposed the appeal, LIPA said it favors changes to the capacity zone rules.

“While we acknowledge the considerable time and effort NYISO staff and stakeholders spent developing the proposal, we deny appellants’ request that the NYISO take the extraordinary measure of filing the proposal pursuant to [Federal Power Act] Section 206,” the board said, calling “unpersuasive” the appellants’ contention that current rules are unjust and unreasonable.

“The NYISO has filed Tariff amendments pursuant to Section 206 only a few times in its history. The facts and circumstances presented here do not warrant that approach. Even if the board were so inclined, we do not believe the NYISO could satisfy the significant burden of proof required to implement the proposal pursuant to a Section 206 filing.”

The appellants’ arguments regarding price impacts on customers were not persuasive, the board said.

“Appellants assert that retaining a locality longer than needed causes undue price separation and would result in ‘excess costs’ for Zone J and Zones G-I customers. However, they calculate potential excess costs to consumers based on current system conditions in which there exists a continued reliability need for the G-J Locality to remain in place. Under system conditions that might support elimination of the zone, the cost impact of retaining the zone — if any — would be much lower,” the board continued. “We note that NYISO staff performed an analysis that illustrated, among other scenarios, the potential for adverse consumer impacts of prematurely eliminating a capacity zone. Appellants’ papers are silent on the NYISO’s consumer impact analysis, offering instead a conclusory economic assessment that is based upon incorrect assumptions.”

The board declined to remand the issue for further work but said stakeholders could consider it during the annual issue prioritization process.

Locational Capacity Requirements

In a related matter, the board also reje c ted an appeal from LIPA, NRG Energy and Helix Ravenswood, which asked the board to override the Management Committee’s Feb. 28 vote approving a change in how the ISO calculates locational capacity requirements (LCRs). The measure passed with a 77.55% vote. (See “Alternative Methods for Determining LCRs” in NYI S O Management Committee Briefs: Feb. 28, 2018.)

NYISO calculates the LCRs to maintain the statewide installed reserve margin (IRM) set by the New York State Reliability Council (NYSRC) based on the one-day-in-10 years loss-of-load expectation (LOLE).

The LCR rule change replaces the “TAN 45” methodology adopted for the 2006/07 capacity year, before the creation of zones G-J. Loads in the Lower Hudson Valley complained that TAN 45 increases their local requirement while reducing requirements for New York City and Long Island.

The new rules, originating from an economic approach recommended by Independent Market Monitor David Patton, are based on the lowest cost-to-supply capacity.

Opponents of the change called for more study of the issue. LIPA contends that the new method underestimates the capacity costs for a new unit in its zone and that it is being forced it to subsidize New York City, noting that its LCR is expected to increase to more than 100% of peak load, while the city is expected at less than 80%.

New York City and 60 large industrial, commercial and institutional energy consumers opposed the appeal of the rule change.

In rejecting the appeal, the board said the rule change was a “significant improvement” that had been “carefully developed, thoroughly vetted and received widespread support from market participants.”

“Contrary to appellants’ assertions that the new approach would introduce volatility, analysis indicates that the alternative LCR methodology will provide results that are more stable than the current approach,” the board said.

The board also turned aside arguments that the new methodology is flawed because it does not optimize the IRM calculation along with the LCR calculations, saying it “ignores the fact that the IRM is set by the NYSRC — not the NYISO.” The board said the ISO will work with the Reliability Council to explore a co-optimized approach but the new rules should not be delayed by that effort.

The board said, “Concerns over ‘rate shock’ are unpersuasive.”

“The NYISO is open to further discussion on [subsidization concerns and] … alternative approaches to cost allocation,” it said. “Such discussion is outside the scope of the instant proposal, however, and should not delay [its] implementation.”

April 26, 2018

AEP: ‘Halfway There’ to Wind Catcher Approval

Buoyed by recent positive developments, American Electric Power (AEP) CEO Nick Akins had several reasons Thursday to proclaim the company “in better shape than in the first quarter of last year.”

Not even falling pennies short of the Zacks Consensus Estimate for first-quarter earnings could dampen his mood. AEP posted earnings of $473.2 million and $0.96/share, similar to 2017’s first quarter ($474.3 million, $0.96/share) but missing the Zacks estimate of $1.00/share.

Paraphrasing Jon Bon Jovi, one of the Rock and Roll Hall of Fame’s newest inductees, Akins, who sits on the Hall’s board of directors, told analysts during a conference call, “This phrase will stick with you the rest of the day: We’re halfway there, living on a prayer, take our hand and we’ll make it, we swear.

“So, enjoy the ride with American Electric Power.”

Just this week alone, AEP saw FERC approve a settlement reducing the base return on equity for its PJM transmission companies to 9.85% (See “AEP ROE Reduced to 9.85% in Settlement” in Com p any Briefs.) and its Public Service Company of Oklahoma (PSO) subsidiary reach a se t tlement with several consumer groups over its Wind Catcher pr o ject.

“Wind Catcher is finally feeling some tail winds,” Akins said, referring to the massive 2-GW, $4.5 billion wind farm in the Oklahoma Panhandle. “We have accomplished settlements in Arkansas, Louisiana and now Oklahoma … that provides the framework for the various commissions to bless this significant project and its benefits for our customers.”

Akins said AEP is working to add other parties in Oklahoma to the settlement, including Oklahoma Corporation Commission staff. The state’s attorney general, Michael Hunter, opposes the project, saying PSO did not follow a competitive bidding process and doesn’t need the generation.

Akins admitted AEP is not likely to get Hunter “on board” but said the outreach will continue. He said the company is also continuing efforts to reach a settlement in Texas and hopes to have regulatory approvals in May and June.

“I think [the project] is framed up pretty well because a lot of work’s been done in the background,” Akins said. “As far as I’m concerned, we’re in a very good place.”

During AEP’s annual stockholder meeting Tuesday, Akins sa i d the Columbus, Ohio-based company plans to invest $17.7 billion in capital ($12.8 billion in wires infrastructure, $1.7 billion in renewable energy) over the next three years. That capex does not include Wind Catcher.

AEP’s share price closed at $69.77/share Thursday, up 1.1% from its open.

Xcel Expects Approval of Texas Wind Farm

Xcel Energy CEO Ben Fowke said Thursday he expects the Texas Public Utility Commission to approve its Southwestern Public Service (SPS) subsidiary’s request to build a 478-MW wind farm in West Texas.

The commissioners appeared to be grappling with approving the company’s request during their April 13 open meeting. They questioned SPS and parties to a unanimous settlement on the proposal about the legal justification for a project when there is no apparent need for the capacity and asked for more information. (See Texas Regulators Seek More Details on SPS Wind Project.)

The commissioners asked for more information before Friday’s open meeting.

Asked by an analyst during Xcel’s quarterly earnings call what he expects from the PUC, Fowke said, “We’re expecting approval.

“We think the project’s driving tremendous benefits for consumers,” he said. “There were some questions asked [by the PUC], and they’ve been answered. You can always have more discussion, but our thought is it will be approved.”

The company’s proposal has been endorsed by PUC staff, who are also part of the settlement between the utility and various consumer groups.

SPS announced last year it intends to build 1.23 GW of wind generation through a pair of wind farms in Texas and New Mexico and a long-term contract from another facility as part of parent Xcel’s multistate inve s tment in wind. Xcel said the projects will save the region’s customers about $2.8 billion over a 30-year period.

New Mexico’s Public Regulation Commission has already approved the facility.

Minneapolis-based Xcel repor t ed first-quarter earnings of $291 million, or $0.57/share, up from $239 million and $0.47/share a year ago. That beat analysts’ projections of $0.51/share.

Fowke borrowed lyrics from Minnesota rockers Prince (“s ometimes i t snows in A p ril”) and Bob Dylan (“ … trees, be n t over backwards in a hurricane breeze”) to illustrate recent severe weather that drove up profits.

Xcel’s share price gained 71 cents Thursday, finishing at $46.53/share after opening at $45.67/share.

— Tom Kleckner

April 26, 2018

CPUC Approves $98M PG&E Ex Parte Settlement

By Jason Fordney

Pacific Gas and Electric (PG&E) will pay $98 million in penalties for past improper communications with the California Public Utilities Commission (CPUC), but the years-old proceeding related to the controversy will continue to drag on because of new emails that came to light last fall.

San Bruno Pipeline Explosion Ex Parte Proceeding — The CPUC approved the settlement Thursday at a meeting in San Francisco | © *RTO Insider*

The CPUC on Thursday approved the $98 million settlement with PG&E, but the ex parte proceeding remains open to consider emails divulged late last fall revealing additional improper communications between the utility and its regulators. (See CPUC to Vote on $98M PG&E Settlement; Probe Reveals More CPUC-PG&E C o ntacts on Pipeline Blast.) The penalties covered eight different CPUC proceedings, including one related to the 2010 San Bruno pipeline explosion that killed eight people.

The communications “have cast public suspicion on the integrity of the Commission’s regulatory process,” the CPUC decisi o n said. PG&E released 67,000 emails as part of the proceeding, including a new b atch supplied to the agency in September that revealed more back-channel discussions. The ex parte proceeding was spurred by a public records request by the City of San Bruno in the wake of the September 2010 explosion.

None of the five commissioners who voted on the settlement Thursday were involved with the improper communications. Parties to the settlement include PG&E, the City of San Bruno, The Utility Reform Network (TURN), the City of San Carlos and the CPUC’s Office of Ratepayer Advocates and Safety and Enforcement Division.

TURN Executive Director Mark Toney on Thursday issued a scathing rebuke of the utility, saying “customers are tired of all the corruption at criminal corporation PG&E. And they want assurances that they are not paying even a penny of the costs of that corruption in their monthly bills, which is what this settlement provides.” PG&E was convicted of a felony related to the 2010 San Bruno pipeline explosion and in April 2015 paid a separate $1.6 billion fine for safety violations.

The new fines approved Thursday will come from shareholders and not ratepayers and will pay $12 million into the state’s general fund, $6 million each to the cities of San Bruno and San Carlos, and reduce by $10 million the revenue requirement in PG&E’s next general rate case. The utility will also forgo collection of $64 million in revenue in 2018 and 2019.

“PG&E’s failure to report these communications is an unacceptable violation of the CPUC’s rules and justifies the remedy provided in this case,” the CPUC said in a blog post. “Although these violations occurred more than four years ago, today’s decision is an affirmation that all parties to the CPUC’s proceedings must comply with the ex parte rules.”

The settlement was originally crafted in March 2017, but a CPUC administrative law judge ruled that a proposed $1 million payment to the state’s general fund was too low, and PG&E agreed to pay another $11 million to the state. The settlement agreement approved Thursday is the largest financial remedy ever imposed by the commission over violations of its ex parte rules.

April 25, 2018

Counterflow: The Surreal, the Absurd and the Tragic

By Steve Huntoon

The Surreal

I’d like to apologize — on behalf of FirstEnergy — for dragging countless congressmen into the arcane world of the electric utility industry. You’ve had to listen to millionaire lobbyists — the quintessential swamp — talking about stuff so dry that we who toil in this world aren’t allowed to talk to our spouses about it.

And biggest apology to Sen. Manchin because you’re the biggest victim. Bailout for FirstEnergy via the Defense Production Act of 1950? OMG.

Do you think if there were a scintilla of national security threat we might have heard something from, hmm, let’s see, maybe the Defense Department?

But here we are.

If you’re just listening to FirstEnergy’s lobbyists, you’ve missed a few key facts. FirstEnergy’s plants are:^[1]

Not baseload.
Old — not retiring prematurely.
Inefficient.
Unreliable.
Not needed for a reliable and resilient grid.

In the tough competition for weakest bailout argument, the winner is the argument that if we didn’t have all the coal plants we had last winter, there would have been an electricity problem, which is like saying if we didn’t have all the Fords we had last winter, there would be a car problem. Duh.

All the Fords aren’t disappearing overnight. And the Fords that do disappear are being replaced by better Fords.

A weaker argument for subsidizing old, inefficient and unreliable plants is hard to imagine. If it had prevailed 100 years ago, we’d still be driving Model T’s.

Quick Quiz

Let’s see if you’ve been conned with a quick quiz question: The Department of Energy projects in the year 2050, 32 years from now, there will be this much coal and nuclear generation in the United States:

0 gigawatts
10 gigawatts
100 gigawatts
274 gigawatts

The answer is (d) 274 gigawatts.^[2] Yes, Rick Perry’s own Department of Energy projects a huge amount of coal and nuclear generation to be around for the next 32 years.

It’s a con to pretend coal and nuclear plants will disappear quickly (or at all), causing any sort of reliability problem — and to premise a bailout on such fantasy.

The Absurd

The absurd is that all the responsible entities in the electric industry know there is no emergency. All the independent grid operators, the unanimous Federal Energy Regulatory Commission (where four of the five Commissioners are Trump appointees), former federal regulators, and all the independent analysts have repeatedly said that. These would be the first to warn of an emergency if one actually existed.

Compounding the absurdity, earlier this month FirstEnergy told the bankruptcy court that all its coal and nuclear plants would be operating throughout its bankruptcy proceeding.^[3] That proceeding will take at least five to six years.^[4]

That means all the FirstEnergy plants will be operating for at least the next five or six years.

On top of that, Robert Murray, coal CEO and FirstEnergy’s fellow traveler, told The Wall Street Journal earlier this month there was no longer any need for a bailout to save his company from bankruptcy because of increased exports to Asia.^[5] He now “expects his company to thrive whether or not the Trump administration intervenes,” the Journal reported.

There is no fire. Or even a puff of smoke.

The Tragic

FirstEnergy’s customers paid it $6.9 billion in return for the company’s transition from a regulated environment to a competitive environment. If that “bet” had turned out well, FirstEnergy would, of course, have kept the money. It hasn’t gone as well as FirstEnergy anticipated, and now FirstEnergy wants customers to bail them out all over again.

I didn’t realize just how outrageous that was until poring through the record of FirstEnergy’s stranded cost proceeding in Ohio from almost 20 years ago. FirstEnergy’s stranded costs were based on the difference between their regulated “net book value” and their net revenues in the future under market conditions.

Please bear with me. “Net book value” is the original cost of the plants reduced by the amount of capital that customers already have reimbursed the utility (a.k.a., depreciation). So, when FirstEnergy was paid net book value (less the future market revenues it would get to keep), it was paid the rest of the plant costs that customers hadn’t already paid for.

In other words, customers have already paid for 100% of FirstEnergy’s plants. FirstEnergy may retain legal title, but in equity the customers own the plants.

Can you imagine the tragedy of customers having to pay for those old, inefficient and unreliable plants all over again?

Let’s hope a surreal and absurd bailout and a tragic rate increase don’t come to pass. And if they do, let’s hope voters figure out who’s responsible.

All of this is common knowledge in the industry. For my own takes, the non-baseload, old and inefficient nature of these plants is discussed here: http://www.energy-counsel.com/docs/Clunker-Poster-Child.pdf. The unreliable nature of these plants is discussed here: http://www.energy-counsel.com/docs/Cash-for-Clunkers-Redux-RTO-Insider.pdf. The lack of need for these plants is discussed here: http://www.energy-counsel.com/docs/Counterflow_More-Smoking-Guns-for-the-Clunkers_RTO-Insider.pdf. ↑
https://www.eia.gov/todayinenergy/detail.php?id=35572 (for coal, 195 gigawatts); https://www.eia.gov/outlooks/aeo/pdf/AEO2018.pdf (page 43, for coal, 79 gigawatts) ↑
https://www.usnews.com/news/best-states/ohio/articles/2018-04-04/utility-says-power-plants-will-stay-open-during-bankruptcy ↑
https://www.ohio.com/akron/business/breaking-news-business/firstenergy-solutions-bankruptcy-could-take-years-consumer-impact-review-begins ↑
https://www.wsj.com/articles/robert-murray-says-trump-administrations-help-not-needed-to-save-his-coal-company-1523570164?mod=searchresults&page=1&pos=3 ↑

April 25, 2018

Still ‘Committed,’ SPP Halts Mountain West Integration Effort

By Tom Kleckner

KANSAS CITY, Mo. — SPP CEO Nick Brown said Tuesday the grid operator remains committed to making Mountain West Transmission Group’s membership proposal work, despite Xcel Energy’s surprise decision to pull out of the group and its pending integration into the RTO.

SPP mountain west integration nick brown — Nick Brown updates SPP’s board | © *RTO Insider*

But integration work has been put on hold until the remaining Mountain West members decide what to do next.

“Obviously, the ball is in the court of the Mountain West participants,” Brown told SPP’s Board of Directors and Members Committee. “I’ve told them we remain committed to doing whatever it takes to come to a reasonable path forward, to create, again, the value that was expected from the previous agreement.”

Representing about 40% of Mountain West’s load and considered the group’s most influential member, Xcel announced Friday it was pulling its 1.4 million customers out of the agreement. That has left the Mountain West’s smaller entities reviewing their options. (See Xcel Pulls out of Mountain West, Endangering SPP Integration.)

“It would be a shame for an individual participant of the Mountain West to unilaterally destroy the value I think would be afforded to the new SPP members of Mountain West and also destroy the value on the table for our current members,” Brown said.

Board Chair Jim Eckelberger told directors and members the Mountain West entities had yet to sign a transition service agreement funding the integration work and approving a set of policy recommendations governing the terms of their RTO membership. In the absence of a signed agreement, Eckelberger said, the board’s March 13 approval of the integration’s funding and policy recommendations has been suspended.

SPP also announced on Tuesday that all Regional Tariff Working Group meetings previously scheduled to address the integration have been canceled through the end of May. The stakeholder group had scheduled 17 meetings before the July 31 board meeting to work on at least a dozen Mountain West-related revision requests.

On Monday, the Regional State Committee (RSC) approved the Cost Allocation Working Group’s request to suspend its work on the new member cost allocation review process. The RSC in January directed the group to draft a report on how new members affect existing cost allocations. (See Mountain West, Cost Allocation Top SPP RSC Concerns.)

The board and single representatives from each SPP member met in an executive session Tuesday afternoon to discuss next steps in the Mountain West integration. The group also discussed recent letters sent to SPP asking for more stakeholder involvement in new member negotiations. (See SPP Group Balks at Mountain West Concessions.)

SPP pointed to Brown’s earlier comments to the board when asked if any decision had been made on next steps.

Several members said their concerns were heard in the follow-up discussion, and the RTO said it would respond to each of the members’ letters.

April 25, 2018

FERC Orders Deadline on NYISO Market Power Reviews

By Rich Heidorn Jr.

NYISO must set a deadline for completing final market power reviews on retiring generators, FERC ruled.

The commission’s April 23 ruling came on a rehearing request by Entergy Nuclear Power Marketing but denied the company’s request that it set a 120-day deadline for the ISO’s review of its Indian Point nuclear plant (ER16-120-004, EL15-37-003).

NYISO FERC Market Power Reviews — Indian Point Nuclear Plant

The issue stems from the commission’s 2015 order that found the ISO’s Market Administration and Control Area Services Tariff wanting because it did not include rules on the retention and compensation of generators needed for reliability. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)

Entergy sought rehearing or clarification of the commission’s November 2017 ruling approving the ISO’s second compliance filing in the docket, in which the ISO added a 90-day deadline for completing reliability studies related to plant shutdowns. Entergy said the ISO’s lack of a deadline for the market power review left it without certainty about its authorization to exit the market.

The Services Tariff says the ISO can perform a market power review for capacity suppliers seeking to retire to determine whether the “decision has a legitimate economic justification” or is intended to withhold capacity to increase prices.

Entergy asked the commission to require NYISO to complete its final market power review of Indian Point by March 13, 2018, 120 days after receiving Entergy’s complete generator deactivation notice. The company contended FERC had previously approved the 120-day deadline, which it said reflected the ISO’s statements concerning when it plans to conduct the analysis and how long it takes to complete. (See Entergy Asks FERC to Clarify Indian Point Retirement Process.)

The commission said it had not approved the 120-day deadline but agreed with Entergy that the lack of a deadline “could impede the generator’s ability to make informed decisions about deactivating.” It gave the ISO 30 days to make a compliance filing proposing a “reasonable timeline” for completing the market power reviews.

“Although NYISO’s [Open Access Transmission Tariff] states that it will determine whether a generator is needed for reliability within the first 90 days after the generator gives notice of its intent to deactivate, neither NYISO’s OATT nor Services Tariff provide a timeline for NYISO to complete a final market power review (if needed), which impacts the ability of that generator to ‘be deactivated as planned,’” the commission said.

“NYISO should set a deadline for completing final market power reviews (if needed) working back from the proposed deactivation date rather than starting from the submission of a complete generator deactivation notice,” it continued. “This is because the final market power review may be less effective with data and assumptions too far removed from a generator’s actual deactivation date.”

Entergy plans to shutter Indian Point Unit 2 by April 30, 2020, and Unit 3 within a year after that. In December, the ISO reported that new gas-fired and dual-fuel generation coming online in the next few years will provide sufficient capacity to maintain reliability after Indian Point’s closure.

April 24, 2018

Overheard at the GCPA Spring Conference

By Tom Kleckner

HOUSTON — The Gulf Coast Power Association’s annual spring conference drew almost 400 attendees to the so-called Energy Capital of the World to participate in discussions on retail markets, distributed generation, competitive transmission and separate roundtables featuring RTO CEOs and market monitors. (See related stories, RTO CEOs Trade Quips, Thoughts on Future at GCPA and Market Monitors Debate Their Roles, Effectiveness of Programs.)

SPP GCPA PJM 2015 Annual Meeting Silver Spring Networks — GCPA’s Spring Conference in Houston | © *RTO Insider*

‘New-day Democrat’ Houston Mayor Recalls Legislative Career

Houston Mayor Sylvester Turner, a Democrat, broke character as he reprised his role in Texas Senate Bill 7, which deregulated the state’s electric industry in 1999 and set up a fund to help low-income consumers.

“I remember my sparring partner [Dallas Republican Steve Wolens] asking me whether Democrats would support deregulation. We’ll deregulate anything,” he said, as the ballroom erupted in laughter.

Smiling sheepishly, Turner regained his poise. “We are new-day Democrats!”

It turns out that Turner, a 27-year member of the Texas House of Representatives, was a new-day Democrat back in the 1990s. “I said, ‘I’m not opposed to deregulation, especially if it will spur technology and innovation and new ways of doing things.’”

Turner’s only request was the creation of the System Benefit Fund, which collected about $800 million in fees from customer bills. While the Legislature did use the fund to help the state’s budgets meet the legal definition of balanced, Turner was able to ensure the fund disbursed the remainder to low-income customers in its final three years of existence, he said. The fund was wound down in 2017.

GCPA President Mark Walker welcomes attendees | © *RTO Insider*

“This doesn’t mean elderly, low-income consumers don’t exist,” Turner said. “They’re still there, and the need is still there. I hope we will always be sensitive to those that are vulnerable.”

Industry Analysts: Expect Low Prices in SPP

GCPA DG Distributed Generation — Marcie Zlotnik, managing partner in BZMZ Interests, accepts the Pat Wood Power Star Award | © *RTO Insider*

A pair of industry analysts agreed that SPP will “by far” be offering lower wholesale prices than any other RTO over the next five years.

GCPA DG Distributed Generation SPP — McIntosh | © *RTO Insider*

“There are a couple of things in SPP that will be coming down the pipeline in the next couple of years,” said Brian McIntosh, product director at Genscape. “With Mountain West [Transmission Group]’s integration, you will have a ton of hydro and baseload generation that would be added into SPP with a limited load. You’ll be adding more supply to the system with more wind growth.”

Bojana Popovic, vice president of strategy and product development for EDF Energy Services, agreed, suggesting attendees look at the power purchase agreement prices for wind in SPP. “They still have four years of [production tax credits] … just look at where it’s cheapest to contract renewables,” she said. “It’s SPP.

“I do have a question about how long SPP can sustain low prices and maintain that level of investment.”

McIntosh cautioned against placing too much stock on future predictions.

“It looks like a future with super low natural gas prices, but if you think that’s the future we’ll end up with, you can shoot yourself in the foot.”

DG Panelist: You Can’t Stop the Technology

Patrick Reinhart, El Paso Electric’s assistant vice president of Texas external affairs, told his fellow DG panelists that, “I think a lot more customers are going to want DG on the system. They want storage on system. They want the grid to back them up,” he said. “It goes back to who pays for it. For 100-plus years, energy flowed in one direction. Now, it’s flowing back the other direction. I’m an opponent of toll roads. We can argue about whether to go in that direction.”

Meghan Nutting, vice president of policy and government affairs for solar developer Sunnova, agreed DG is coming. Just don’t listen to the naysayers, she said.

“It’s interesting to me to see all these discussions happening for a technology with a penetration of 1 to 3%. They say it’s a very small part of the system right now,” Nutting said. “I think before we try to limit this technology, let’s give it a chance for success. And not just solar, but energy efficiency, [electric vehicles], microgrids … rather than limit or stop these things now, let’s see what we can do with these technologies.”

As an example, she pointed to California, where she said CAISO recently canceled $2.6 billion in transmission projects no longer needed because of the state’s abundance of rooftop solar.

“It’s important to keep that in mind when talking costs and benefits,” Nutting said.

April 24, 2018

Baker’s Carbon Dividends Plan Reaches Across Aisle

By Tom Kleckner

HOUSTON — Approaching his 89th birthday, James A. Baker III last week revealed the enduring sharpness of his political mind with a keynote address that delved into personal history, decried the “bankruptcy of our national public debate” and offered a middle ground to address climate change.

James Baker GCPA carbon tax — Baker | © *RTO Insider*

Baker made his name in Republican politics, running campaigns for Gerald Ford and George H.W. Bush. He ran the White House staffs for both Ronald Reagan and Bush and served as their secretary of the treasury and state, respectively.

Last year, Baker partnered with George Schultz, Hank Paulson and several other luminaries in promoting the “Carbon Dividends” plan, a “new climate strategy” that purports to strengthen the American economy, reduce regulation, help working-class Americans, shrink government and promote national security.

“At the risk of tooting my own horn, I do know a little bit about politics,” Baker said. “It’s obvious to me this solution should be able to attract support from those on both sides of our political debate.”

The plan rests on four pillars: a gradually increasing carbon tax; carbon dividends for all Americans; border carbon adjustments; and significant regulatory rollback.

Baker and his coauthors propose to begin with a “sensible” $40/ton carbon tax that would steadily increase over time. “Every dime” of the proceeds would be returned to citizens, giving the theoretical family of four $2,000 in carbon dividend payments in the first year.

“In my view, that would not be a true tax,” Baker said. “The plan speaks to the frequent frustration about economic insecurity expressed by most Americans. These measures, to be viable, have to take into account the impact of economic growth to human welfare.

“They must be politically sustainable,” he said, emphasizing the importance of that point. “Make no mistake, politics is about gaining and exercising power. That’s why political parties exist. That’s why we have campaigns and elections. Power should be a means to implement policies that advance freedom, security and the well-being of our citizens.”

Baker said he recently took a call from former Secretary of State John Kerry, “who said he might be able to sign on to [the plan] too.”

“The moment may never be more right,” Baker said. “If we spend too much time debating the role of climate change, we may find ourselves rehashing the same political arguments that have poisoned our debate. Our plan can be seen as a really good mainstream policy, just in case the Al Gores of the world happen to be right.”

April 24, 2018

Market Monitors Debate Roles, Effectiveness of Programs

By Tom Kleckner

HOUSTON — Market monitors from the Eastern Interconnection and ERCOT last week debated their roles in the RTOs they oversee and the need for effective monitoring programs at the Gulf Coast Power Association’s annual spring conference.

Market Monitor Gulf Coast Power Association GCPA ERCOT — Collins | © *RTO Insider*

“Part of our role is to dig into the garbage and the bad side of things,” Keith Collins, executive director of the SPP Market Monitoring Unit, said at the Gulf Coast Power Association’s annual spring conference. “Most people would be surprised at what other people are attempting to do. Unfortunately, that gives us the job security that we have.”

“We maintain credibility by being credible,” said Potomac Economics’ Pallas LeeVanSchaick, director of NYISO’s MMU. “We’ve established our reputation by providing information and transparency into the market. When we have opinions, and we have a lot of market suggestions, we back that up with rationale. We’re not promoting one set of participants over another.”

Potomac’s Steve Reedy, deputy director of ERCOT’s Independent Market Monitor, said his group considers its role to be that of an educator.

“Certainly, we advocate certain positions, but we look to make sure an honest discussion is held on all important issues,” Reedy said. “We don’t win every battle, and not every issue we advocate passes. But as long as we feel the issue is properly understood by all sides and by the [Public Utility Commission] in its votes — we feel that is our most important role.”

“Our primary function is to help support and maintain competitive prices,” said Monitoring Analytics President Joe Bowring, whose firm serves as PJM’s IMM. “We have three sub tasks: looking for instances of market power and reporting on them; making proposals that improve market design; and continuing to support market design changes that support competition.”

Asked how to keep monitors from being seen as just another stakeholder in the market, Bowring said, “I’ve been accused of many things. I’ve been accused of being pro-load, I’ve been accused of being pro-generation. I’ve never been accused of being just another stakeholder. We’re used to losses in the stakeholder process.”

Reedy also addressed the coming summer in Texas, saying he has seen August forward prices of $200/MWh. ERCOT is expecting record peak demand that month, but it only has a 9.3% reserve margin after a wave of coal-fired retirements last fall.

“It’s been quite a while since things have been this tight in ERCOT,” Reedy said. “It will test the political resolve of certain entities and whether they want to commit to an energy-only market. All indications so far are they want to continue, but that could change with multiple hours of $9,000 prices [per megawatt-hour for scarcity pricing]. From an IMM perspective, it’s very interesting to us.”

April 24, 2018

RTO CEOs Trade Quips, Thoughts on Future at GCPA

By Tom Kleckner

HOUSTON — At the Gulf Coast Power Association’s annual spring conference last week, ERCOT CEO Bill Magness once again moderated a panel of his counterparts from around the country, welcoming back MISO’s John Bear and SPP’s Nick Brown. Joining the discussion this year was PJM’s Andy Ott, with a vacant chair left to recognize 2017 participant Steve Berberich of CAISO.

Bill Magness GCPA ERCOT SPP — RTO CEOs left to right: Bear, Brown, Ott and Magness | © *RTO Insider*

Magness asked Brown and Ott to explain their participation in the Western markets. SPP has been working to integrate the Mountain West Transmission Group since January 2017, while PJM has partnered with Peak Reliability to offer market services in the Western Interconnection through its PJM Connext subsidiary.

Brown pointed out that SPP is not a greenhorn when it comes to being active in the region. “We’ve worked with participants in the West the last 10 years, helping them to understand our markets,” he said. “The efficiencies, the increasing of reliable operations across larger areas, the integration of renewables … those are all things people are wanting.”

“It’s really education, trying to fill a void,” Ott said. “We’re fostering a discussion of competitive markets. Even if we’re not successful, we’ve had a positive influence. When we first got out there, we saw cultural differences, but we very quickly talked about a market for the West, by the West. We let them realize, ‘Wait a minute, I’ve got control,’ because it’s their assets, their region.”

In describing the value of RTOs to their members, Brown shared a story about a conversation he had with a current SPP participant, who had previously formed another organization consisting of member utilities.

The member asked Brown, “‘What are you going to say to convince me to turn over management of my assets?’

“‘Well, how did you do it within your organization?’” Brown said he responded.

“‘I pried it out of their cold, dead fingers.’

“I said, ‘OK, we can’t do that. We’re not going to do that. We’ve got to show the value proposition [of an RTO]. Quite frankly, that’s why you don’t have value in doing this by yourself anymore.’ That’s what the folks in all our footprints saw: the benefits.”

Asked what he was watching in the other RTOs, Bear pointed first to their response to FERC’s resilience initiative, saying “there are ways we could be more resilient.”

“The FirstEnergy situation in PJM … we’re interested to see how that gets dealt with,” Bear said, referring to FirstEnergy Solutions’ recent bankruptcy filing and plea for governmental protection of its nuclear and coal plants. (See FES Seeks Bankruptcy, DOE Emergency Order.)

“We’re also watching Andy’s guys to see how they do scarcity pricing. For SPP, we’re watching how they deal with all that wind, and how they do so well with 50%, 60% [wind penetration] levels. We can only simulate that.”

“My neighbors matter a lot to me. John and I are intertwined, and we have great working relationships between the two of us,” Ott said, noting his organization also learns from SPP. “A developing story is in New England, where they worry about fuel security. They only have a couple of interstate pipelines, and we have 25. How they deal with that fuel-security problem will affect us.”

Like SPP, MISO is also working to accommodate a large influx of wind energy and other renewables. Bear said the ISO had 100 MW of renewable energy in the mid-2000s, but that has now grown to 18.5 MW.

“We had people telling us that with up to 5 GW [of renewables], we would crash the system,” he said. “We’ve done a lot of transmission build to disperse that [energy] and pass the benefits around. We’ve also had to design products to handle the wind. We had a lot of wind turbines that wouldn’t turn down, but now, we incentivize them to do the right things.”

Magness did not let the round table end without uttering a word he said is heard these days at every self-respecting conference: blockchain.

“There, I said it!” he said, peering at his audience.

Later, upon begin congratulated for mentioning “blockchain,” Magness brought up another futuristic word from a bygone era: “Plastics!”