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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, 2018October 21, 2025

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

CenterPoint Energy to Acquire Vectren in $6B Deal

By Amanda Durish Cook

Houston-based utility CenterPoint Energy announced Monday that it will acquire Vectren in an approximately $6 billion deal expected to close in the first quarter of 2019.

CenterPoint will pay Vectren shareholders $72 for each share of Vectren common stock — a $6.45 premium to Friday’s closing price — and assume all outstanding Vectren net debt. Hours after the announcement, Vectren closed Monday at $70.31 while CenterPoint ended the day at $25.94/share, down 31 cents.

FERC PJM Vectren Centerpoint Energy — Vectren headquarters in Evansville | *Hafer Design*

The merged company will retain the CenterPoint name and its Houston headquarters. CenterPoint will also maintain Vectren’s Evansville, Ind., headquarters for the company’s natural gas utilities and Indiana electric operation. The company will serve more than 7 million customers, operate electric and natural gas delivery operations in eight states and hold about $29 billion in assets.

The merger agreement has been approved unanimously by the boards of both companies, though the deal still requires approvals from Vectren shareholders, FERC, the Federal Communications Commission and regulators in Indiana and Ohio. CenterPoint said it expects to maintain a 5% to 7% annual earnings per share growth target in 2019 and 2020, excluding any one-time charges related to the merger. Both CEOs said the move will benefit their companies.

“By combining our two highly complementary companies, we are creating an energy delivery, infrastructure and services leader that will drive value for our shareholders and customers, while enhancing growth opportunities for our businesses,” CenterPoint CEO Scott Prochazka said in a statement.

“With CenterPoint Energy, we’ve found the right partner to begin the next chapter for Vectren and our family of companies. … Together, we will be a stronger, more competitive company that will be well-positioned to continue to provide value for our stakeholders in the years to come,” said Vectren CEO Carl Chapman.

Prochazka will remain CEO of the combined company. All other executive positions will be announced “prior to or in conjunction with the closing of the merger,” the companies said. CenterPoint said it will establish an executive position in Evansville, Ind., to handle natural gas utility operations and a chief business officer for Vectren’s electric business to directly report to the CenterPoint CEO and “spearhead southwestern Indiana’s electric grid modernization and generation transition initiatives recently underway.”

Earlier this year, Vectren announced it would build an 800- to 900-MW, $900 million natural gas plant in southwestern Indiana and a 50-MW, $75 million solar farm about 60 miles from the gas plant site. The new generation would replace three of Vectren’s coal-fired plants. The proposed gas plant still requires approval from the Indiana Utility Regulatory Commission. The company is also set to complete construction this year on two solar farms near Evansville that will produce 4 MW combined.

Prochazka and Chapman told the Evansville Courier & Press that they expect the merger will reduce Vectren’s 5,500-person staff but that it was too soon to say where, or how deep, the cuts will be.

The company provides electricity to about 145,000 customers in Indiana and natural gas to more than 1 million customers in Indiana and Ohio. Vectren also owns non-utility businesses Vectren Infrastructure Services Corp., which provides underground pipeline construction, repair and replacement services, and Vectren Energy Services Corp., which offers performance contracting services and renewable energy project development. CenterPoint said it intends to continue operating both companies.

CenterPoint currently delivers electricity to more than 2.4 million customers in the greater Houston area and serves another 3.4 million customers with natural gas operations in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The company employs nearly 8,000 people.

April 24, 2018

CAISO Says Changes Will Better Match Forecasting, Demand

By Jason Fordney

CAISO last week provided details on its plans for major changes to improve the alignment of its day-ahead market with real-time demand by introducing more scheduling granularity and other refinements.

Nearly 150 participants joined a conference call Wednesday at which the ISO discussed technical aspects of the revised straw proposal it issued April 13. CAISO has also proposed extending the proposed changes across the Western Energy Imbalance Market (EIM).

As currently proposed, the changes would address forecasting uncertainty in the day-ahead that is currently left to the real-time market to resolve, CAISO Senior Design Policy Developer Megan Poage said during a presentation.

The proposal would introduce 15-minute scheduling in the integrated forward market, which procures the generation needed to meet forecast demand. It would also create a day-ahead imbalance reserve market product and combine the integrated forward market and residual unit commitment. The third major prong in the initiative is to procure imbalance reserves with a must-offer obligation to submit economic bids in the real-time market.

“These three elements are dependent on each other. They must all be introduced at the same time,” Poage said, adding that “We’ll be moving toward a co-optimized day-ahead market run.”

The initiative, which was announced in December, is seen as a possible forerunner for a new Western RTO market structure by introducing a day-ahead market into the EIM, which is currently only a balancing market. (See CAISO Day-ahead Could be Tailored for West.)

“Grid infrastructure has advanced, the resource fleet has changed and the policies regulating operation of the grid have evolved (i.e. FERC-mandated 15-minute scheduling in real-time energy markets),” the ISO said in the straw proposal.

The proposal is intended to help manage excess solar generation in the middle of the day and make it possible to also reduce generation output. The current structure does not allow the ISO to decommit resources that were scheduled in the integrated forward market.

CAISO said the current hourly scheduling structure causes the day-ahead forecast to be higher than actual demand, resulting in “downward uncertainty,” in hours 1 to 12, and mismatches between day-ahead forecast and actual demand in hours 20 to 22.

caiso day-ahead market scheduling — CAISO says the current hourly scheduling structure causes “downward uncertainty” between day-ahead forecast and real-time demand in hours 1-12 and “granularity difference” in hours 20-22 | *CAISO*

Based on comments from market participants, CAISO changed the proposed 15-minute and five-minute imbalance reserves products in upward and downward directions into a single product for both directions. To address five-minute needs, CAISO would create sub-regions for the imbalance reserves product.

It also provided additional information explaining certain formulas it plans to use in the new day-ahead market, data analysis and proposed methodologies to determine imbalance reserves requirement, as well as a settlement and cost allocation worksheet for use by potential market players.

Overall, CAISO said, the changes will help decarbonize the electric grid, improve reliability as the system changes and create more market benefits across the region. The goal is to present the proposal to the EIM Governing Body in August and the ISO Board of Governors in September.

April 24, 2018

Resilience, Storms, Survival are Topics at New Mexico Forum

By Jason Fordney

SANTA FE, N.M. — In an American West city known for its artists, writers and the beauty of its barren desert environment, state regulators and others last week discussed difficult grid reliability issues and the more vicious side of nature.

Grid Resilience Hurricane Season Current Issues Conference — New Mexico State University’s Center for Public Utilities held the Current Issues Forum at the El Dorado Hotel | © *RTO Insider*

New Mexico State University’s annual Current Issues Conference has a reputation as a more informal gathering than other industry gatherings. A major topic at this year’s meeting was the severity of the 2017 hurricane season, in which grid resilience was tested in Texas, Florida and the Caribbean.

Industry consultant Alison Silverstein told the forum that the duration, magnitude and “customer survivability” of electricity outages are metrics that could be used to measure grid resilience. The grid is operated for the benefit of customers, she said, and resilience should be measured in “customer-based” terms.

Silverstein was an author of the Department of Energy grid study released last August but later criticized the department when Energy Secretary Rick Perry used its findings in his proposal that FERC order price supports for coal and nuclear generators with onsite fuel. (See Author of DOE Grid Study Disputes Recommendations.)

Perry’s Notice of Proposed Rulemaking was rejected in January by FERC, which instead opened a new resilience docket.

Silverstein told the forum that the technical conclusions she reached did not align with the department’s contention in the NOPR that coal and nuclear plant retirements were a reliability threat. “They apparently didn’t read the results of their own study,” she said.

Regulators shouldn’t overly focus on generation-based outages because 90% of outages occur in the distribution system, Silverstein said, and big weather events don’t usually affect power plants. Fewer than one in 10,000 customer outage minutes were caused by generation shortfalls.

Coal plants forced to retire since 2002 were old, inefficient and lacked the flexibility that today’s grid needs, Silverstein said. “Regulations were not the cause of the retirements,” she said, adding that fuel diversity has improved in areas where coal plants have retired.

ERCOT FERC Hurricane Sandy MISO Informational Forum — Grid resilience and recovering from natural events were key themes at this year’s forum | © *RTO Insider*

Coal and nuclear subsidies are not the answer and would “cost a fortune,” she added.

There are many ways to improve resilience and reliability, she said, mentioning many of the topics discussed throughout the two days of the forum: distribution system improvements, situational awareness, emergency drills, system recovery and black start capabilities.

“Customer survivability” includes things like backup generators, rooftop solar and emergency supplies like flashlights. “You are already doing a lot of these measures,” Silverstein told the regulators.

Hurricane Response Ongoing, DOE Official Says

DOE Deputy Assistant Secretary Devon Streit discussed the department’s response to the hurricanes and natural disasters of 2017, an effort that is still ongoing. She said the department had response efforts in Texas, Florida, Puerto Rico and the U.S. Virgin Islands.

“We learned that island response is tough,” she said, mentioning not only the difficulties of restoring electric infrastructure in a remote environment but also the challenges of operating without facilities like radar, without which planes cannot land. Ships could not transport electrical equipment because they were carrying food, medicine and other critical supplies.

DOE’s Office of Infrastructure Security and Energy Restoration (ISDER) is responsible for energy sector preparedness and response, including electricity, oil and gas, and cybersecurity. It studies threats and examines hazards as well as holding exercises. It is responsible for communicating with federal and state agencies on what is happening on a near-hourly basis, she said in a presentation.

“We are still active for Hurricane Maria,” a response now in its 236th day, she said.

Streit discussed the value of situational awareness and mutual assistance projects, such as utilities sharing equipment. “What happened in Puerto Rico or Virgin Islands could happen in other places,” she said.

Texas Official Discusses Harvey Response

Public Utility Commission of Texas Chairman DeAnn Walker described how she went to her commission’s State Operations Center to conduct the response during Hurricane Harvey, which she said was “a very, very different storm than previous storms such as Ike and Rita.”

Walker said that in the first time in her experience, mobile substations were brought in because “we had substations flood that had never taken on water the whole time they were built.”

At the operations center, the PUCT worked on grid restoration with utilities and state and federal officials, including DOE, the U.S. Army Corps of Engineers, the Federal Emergency Management Agency and the Department of Homeland Security.

Harvey was the largest rain event in U.S. history, dumping an estimated 40 to 60 inches of water in southeast Texas and southwest Louisiana. ERCOT lost 12,000 MW of generation as gas-fired plants were evacuated or flooded, and coal plants and wind turbines were shut down. (See Weeks Later, Utility Officials Still Awed by Scale of Hurricane Harvey.)

April 24, 2018

RTOs Take to Catwalk for Western Commissioners

By Robert Mullin

VANCOUVER, Canada — The three RTOs vying to organize Western electricity markets on Thursday faced off before an audience of utility regulators in what one state commissioner billed a “beauty pageant.”

Peak Reliability PJM Connext Mountain West Western RTO — Kavulla | © *RTO Insider*

“Thank you for competing,” Montana Public Service Commission Vice Chairman Travis Kavulla jokingly told representatives of CAISO, SPP and PJM. Kavulla is co-chair of the Committee on Regional Electric Power Cooperation, which hosted the panel at its spring meeting in the Coast Coal Harbour Hotel.

The regulators were there to examine the possible benefits and drawbacks of the competing grid operators’ efforts to sign up utilities in a region that has been historically resistant to organized markets. (See CAISO Bid for Western RTO to Face Competition in 2018.) They, and other industry watchers, also learned what region PJM is focusing on in developing its Western market partnership with Peak Reliability.

Here’s some of what they heard.

Looking West

Little Rock, Ark.-based SPP has been running its Integrated Marketplace since 2014, after previously operating a balancing system like CAISO’s Western Energy Imbalance Market (EIM). The RTO last year entered membership negotiations with Mountain West Transmission Group, a partnership of seven transmission-owning entities within the Rocky Mountain region of the Western Interconnection. The effort hit a significant roadblock late Friday when Xcel Energy announced it was pulling out of the group and the negotiations with SPP because of the “limited benefits” for its customers in integrating into the RTO. (See Xcel Pulls out of Mountain West, Endangering SPP Integration.)

“There are benefits from operating together” in an RTO, SPP Chief Operating Officer Carl Monroe told Western commissioners. “A natural inclination we would have is to look west.”

“We’ve got another unique situation in that we’re the only one connected to ERCOT,” he said.

Monroe touted the fact that SPP’s Board of Directors cannot express a decision without the consent of the RTO’s Members Committee, which provides each market participant a vote over market initiatives presented to the RTO board.

He also pointed out that SPP has functioned as a reliability coordinator (RC) for 20 years.

“And how that interfaces with the market … that was one of the key issues we dealt with in the market,” Monroe said. “These are hybrid markets. … They have to be designed to protect reliability itself.

“Our job one is to keep the lights on — reliability,” he added. “Even the economics don’t make sense if you’re not reliable.”

SPP’s market has been efficient for its members, he said.

“The capital costs of putting the market in — we recovered those within six months,” Monroe said, adding that the SPP footprint today carries 5 GW less generation than it would “if we weren’t running the market.”

He also pointed to SPP’s expertise in integrating large volumes of renewables.

“Of course we’re in a wind-rich area. We just set a record when 63% of the load was served by wind,” he said. “That could not have been done unless on a regional basis.”

“We actually do interregional coordination,” Monroe continued. “This is one of the things we’ll need to do within the West itself, is making sure we coordinate all the activities, whether it’s transmission planning, transmission operations, reliability coordination, market activity. All those things will have to be coordinated with the other parties that border whatever footprint we finally get around to.

“Part of the strategy going forward is being open to those parties who want us to do these services for them,” Monroe said.

Listening to the West

“As you all know, many states in the West are aggressively pursuing more renewables,” CAISO CEO Steve Berberich said.

With a fleet heavy in renewables, ramping and overgeneration become “a focal point” for the ISO, he said.

“Security-constrained economic dispatch — in other words, an optimized market — is the best way to run the grid as efficiently as possible, and the sharing of resources is the best way to solve our critical need collectively to support the variability of renewables and the induced ramps,” Berberich said. “Further, the zero-marginal-cost power is better shared at a lower cost for all of our customers. We share this view with our [SPP] friends from Little Rock. You’ll also hear that from our friends from PJM in Philadelphia.”

Berberich trumpeted the EIM’s $250 million in member net benefits since it was launched in 2014. CAISO last year proposed to expand the EIM to include day-ahead transactions without transitioning the market into a full RTO. The ISO has also announced it will withdraw from Peak Reliability as an RC and provide reliability services to other balancing authority areas in the West.

He acknowledged that the EIM’s implementation of a day-ahead market will require the ISO to resolve approaches to resource adequacy and transmission compensation.

“Those are solvable, and we’ll continue to give deference to state control over resource mix and capacity margins. We also expect the EIM Governing Body to morph into a broader governing body with at least some joint decisional authority with the current [CAISO] board of directors,” he said.

CAISO expects to offer the combined EIM and day-ahead market at a cost significantly below the ISO’s current grid management charge, Berberich said. It also intends to offer the same reliability services as Peak at a “significantly reduced” cost.

“When you cut through it all, the fundamental markets are all the same. … What is different in our market, however, is the sophistication of our optimization and how it supports renewables, steep ramps and distributed generation aggregations,” Berberich said.

He said the ISO doesn’t foresee the need for any new transmission to “support the transformation into a regional market.”

On the issue of governance of an expanded ISO, Berberich told the commissioners that the “main pathway” is to change the existing governance model through legislation at the state level in California.

“The alternate pathway is to continue to evolve our governance according to the Energy Imbalance Market’s governing model, and with a day-ahead market, that will necessarily involve decisions on transmission compensation and some form of resource adequacy, both potentially having input from the [EIM] Body of State Regulators,” he said.

“Some of the ISO brethren say the Peak/PJM market offering is a market by the West, for the West, which misses what has already occurred in the Energy Imbalance Market. Participants are certainly not guests of the ISO, rather, they help form the market,” Berberich said.

The ISO’s job is to “listen to whatever the West wants and do our best to provide the value inherent in our interconnected systems.”

“When do we need to move to this new market? Soon, we think. We believe it will provide the most efficient way to streamline new transmission planning and upgrades, reduce the need for more capacity and reduce the need to curtail valuable clean resources. It provides the greatest value with the geographical and resource diversity that the West is blessed to have.”

For the West, by the West

“We believe there’s a very real opportunity for the utilities in the West to pursue the potential for the creation of a separate market,” said Stu Bresler, PJM senior vice president of markets and operations.

Bresler was speaking on behalf of the joint proposal between Peak Reliability and PJM Connext (a PJM subsidiary) to develop new wholesale market structures for the West. Like the CAISO EIM day-ahead expansion, it would fall short of creating a full RTO in the near term, while creating a foundation for one in the future.

Kavulla asked: “What area are you focusing on? Is it an area with lots of trees and hydro, or lots of sun?”

“We’re focusing primarily in the Southwest,” Bresler replied.

“The value proposition — and Steve has already said it before I had a chance to get up here — is a market for the West and by the West,” Bresler said. “What we are really leveraging here is the combined knowledge of our expertise of both of our organizations.

“PJM has proven its ability to promptly deliver on its commitments,” he said, citing PJM’s pledge to complete a business plan with Peak by March 30. (See Peak/PJM Enter Western Market Commitment Phase.)

“We have also been sharing the full plan with a set of key entities in the Western Interconnection that could potentially form the basis for a separate market out here in the West, should they decide to pursue that,” he said.

Striking a similar note to SPP’s Malone, Bresler said that wholesale electricity markets exist for the sole purpose of reinforcing grid reliability.

“That’s why we develop them; that’s why we operate them.”

Bresler said markets are intended “to ensure that physical asset owners have the financial incentive to act in a manner as to reinforce grid reliability.” Key to that is ensuring that market prices reflect actual operating conditions, and that “those prices are transparent to market participants in real time.”

“And that transparency and that reflection of actual operating conditions is what builds the confidence of the physical asset owners that the dispatch instructions delivered by the system operator are in their financial best interests. That financial best interest is a powerful motivator that supports reliable grid operations,” he said.

“We believe that the bulk of trading activity actually occurs in the bilateral markets,” Bresler said. “That is really an appropriate way for things to occur because it is what allows market participants to best manage and therefore minimize their risk.”

Bresler said the Peak/PJM business plan — which has not been made fully available to the public — shows that “with a large amount of participation in a market in the West, the production cost savings become very substantial.”

Lauding Peak’s RC capabilities, Bresler said that much of the hard work of starting up a regional market is already complete based on Peak’s West-wide model and the processes and mechanisms in place to support reliability.

“Really, the smaller part is layering [the market] on top of those reliable grid operations,” he said.

PJM’s “Day 1” market offering would consist of a day-ahead and real-time market.

“Some options that could be included as well, should participants want it, we could operate ancillary services. We could also add [financial transmission rights], but that’s not a requirement for Day 1,” Bresler said.

Based on feedback from potential participants, Bresler said Day 1 won’t include a resource adequacy construct or capacity market; consolidation of transmission tariffs; provision of transmission service; and regional or sub-regional transmission planning.

On one key issue, Bresler sought to score points from commissioners overseeing utilities already participating in the Western EIM.

“I don’t think of the establishment of the market as being exclusive of participation in the EIM,” he said.

Bresler noted that Peak and PJM had envisioned getting a “critical mass” of commitments from market participants by May or June, but they have extended that timeline to determine a “go or no go” decision on the market by the fall.

Kavulla asked Bresler when Peak/PJM anticipated releasing its full business plan for public review.

“We don’t really have any plan to do that. If members do decide to take the next step, we would take the decision with the members to do that,” Bresler said.

Bresler wrapped up his moment in the spotlight by echoing Berberich’s conclusion: “If utilities in the West want a full market … there’s not a better time to do it than now.”