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.
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.
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).
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.
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.)
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.
“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.”
“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.”
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.
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.
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.”
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.
“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.”
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’sNick Brown. Joining the discussion this year was PJM’sAndy Ott, with a vacant chair left to recognize 2017 participant Steve Berberich of CAISO.
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!”
WILMINGTON, Del. — Has the door for revising PJM’s Capacity Performance calculations been opened too far? Some stakeholders fear so after members at last week’s Markets and Reliability Committee meeting endorsed revisions to an issue charge for an initiative examining the calculation of the balancing ratio used in setting capacity offer caps.
Originally, the market seller offer cap (MSOC) equation was out of scope in the inquiry being conducted by the Market Implementation Committee and members were only focused on how to determine the balancing ratio.
The balancing ratio needs to be addressed because it is currently based on the number of performance assessment intervals PJM experienced in the past three years, and it can’t be determined if there are no such events. That became a reality this year, requiring PJM to reuse last year’s as a stopgap until a new calculation is developed. (See “Stopgap Balancing Ratio OK’d Despite Questions,” PJM MRC/MC Briefs 10-26-17.)
Beyond the balancing ratio, the issue charge also allows for evaluating how many assessment intervals are assumed in calculating the nonperformance charge rate. The current assumption is 30 intervals per year, which some stakeholders have argued is too high.
But Joe Bowring, PJM’s Independent Market Monitor, pointed out that changes to the nonperformance charge can affect the MSOC, so the MIC needs the latitude to consider changes to it as well. It’s important to maintain the consistent relationship between the nonperformance charge rate and the MSOC, said PJM’s Pat Bruno, who was presenting the proposal.
“We can’t keep the equation ‘net [cost of new entry] times B’ as the default offer cap out of scope with this issue charge because any changes we make with the nonperformance charge rate may impact that default offer cap equation,” he said.
Exelon’s Jason Barker questioned that position, arguing that FERC approved the specific MSOC equation — the net CONE for a unit’s technology class multiplied by the balancing ratio. He said all the necessary assessment-interval changes can be made while keeping “the FERC-approved tether to net CONE” by ensuring the interval calculation remains consistent throughout the formulas, a point on which Bruno agreed.
Barker said that — and not a potential wholesale re-evaluation of the MSOC — is what he believed stakeholders were agreeing to when they approved the issue charge. Other stakeholders agreed.
“I don’t think there’s anything in the issue charge as it stands now that would prevent us from completely changing the nonperformance charge rate,” Bruno acknowledged.
But Bowring argued there’s nothing “magical” about the current MSOC and that FERC approved the logic through which the equation was developed.
“You have to address this additional question if all of these issues are at play, which they are at the moment,” he said.
Barker said he couldn’t endorse the widened scope and encouraged others to vote against it as well.
Other stakeholders voiced concerns about the potential effect on other market mechanics, but Barker’s lobbying fell short. The proposal was endorsed with five objections and one abstention.
Offer Cap Walk Back Stalled
PJM’s hope to return to previous language over energy market offer caps was dashed after stakeholders agreed with Bowring that the previous rules also weren’t correct.
Members approved the current Manual 11 language at the October 2017 MRC to comply with FERC Order 831. PJM staff subsequently discovered the revisions restrict market-based offers to $1,000/MWh, contradicting language in the Operating Agreement. The proposal would have reverted to previous rules that market-based incremental energy offers may not exceed $1,000/MWh unless the cost-based incremental energy offer is greater than that amount. In that case, the market-based incremental energy offer is capped at the lesser of the cost-based incremental energy offer or $2,000/MWh.
The current proposal was pushed through PJM’s stakeholder process unusually quickly, with a first reading at the Members Committee webinar just three days before the MRC meeting. PJM’s Rami Dirani said the quick turnaround was necessary to maintain consistency because the order became effective on April 12. He described the return to the prior language as “very straightforward,” but Bowring disagreed.
“It doesn’t strike me as being so straightforward,” he said, noting that the previous rules didn’t address PJM’s obligation to verify cost-based offers ex ante — based on forecasts — and ensure that price-based offers not exceed cost-based offers of more than $1,000.
Carl Johnson, representing the PJM Public Power Coalition, noted that many Manual 11 changes were being discussed in October, “so maybe it just slipped our focus. But I thought we knew what we were doing then, and it’s clear from reading the manual language that we didn’t.”
The changes were originally made to reduce complexity, Dirani said.
“The inclination would be to spend a little more time on this rather than move another … rule that is not right,” Johnson said.
Other stakeholders agreed.
Calpine’s David “Scarp” Scarpignato asked that PJM return with some comparison of potential rule changes.
“I need to know more than just the mechanics,” he said.
“I’m sure it seems simple; you’re going back to previous language. So I’m sure it felt simple, but it has obviously led to further questions,” said Adrien Ford with Old Dominion Electric Cooperative.
Staff agreed to send the issue back to the MIC for discussion but said they aimed to get feedback in time to have a proposal prepared for a vote at next month’s MRC.
Price Formation Reshuffle
PJM’s Adam Keech outlined staff’s plan to address energy market price formation changes in accordance with the Board of Managers’ request that stakeholders break the issue into pieces so that less controversial changes can be implemented sooner. The board made its request in a letter April 11. (See PJM Board Seeks Reserve Pricing Changes for Winter.)
The plan breaks potential changes into short-, mid- and long-term goals that correspond with the board’s request that some reserve market changes be ready for implementation by next winter and that other energy market changes be prepared for next spring.y
In the short term, PJM plans to focus on the synchronized reserve market, dynamic reserve zone modeling, simplifying the operating reserve demand curve (ORDC) and fast-start pricing if FERC approves the proposal PJM has already filed.
The mid-term topics for the first quarter of 2019 would include developing a 30-minute reserve product, along with additional revisions to the ORDC and fast-start pricing.
The long-term plan would extend the implementation of integer relaxation and look to add shortage pricing to the day-ahead market.
“My interpretation of the discussions [at the most recent meeting of the Energy Price Formation Senior Task Force] was there were no objections to moving forward with that,” Keech said.
Greg Poulos, the executive director of the Consumer Advocates of the PJM States, said his members don’t necessarily see the need to make these changes, “but we are aligned with the goals” of analyzing the situation to see if any changes are warranted.
The consumer advocates are particularly interested in cost-impact analyses, he said.
Stakeholders OK Manual, Operating Agreement Changes
Members approved changes to Manual 12: Balancing Operations to incorporate rules approved by FERC in November regarding reviews required for approval of pseudo-tied generators. The changes were endorsed with two objections and three abstentions. (See “External Capacity,” PJM PC/TEAC Briefs: March 8, 2018.)
Stakeholders also endorsed unanimously several manual revisions and other operational changes:
Manual 14A: New Services Request Process. The revisions clarify language to match existing procedures and add language to describe in detail system impact study (SIS) and interconnection feasibility study analyses. In January, a FERC administrative law judge issued an initial decision finding that PJM’s process is unjust and unreasonable because of a lack of transparency (EL15-79). On Feb. 20, PJM filed a brief on exceptions challenging the ruling. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
Manual 14B: Regional Transmission Planning Process. The revisions are the result of a periodic review that identified several administrative changes, including a revision to the generator deliverability procedure and adding the Ohio Valley Electric Corp. to the western region study area definition. (See “Transformer Consideration Changed for Gen Deliverability,” PJM PC/TEAC Briefs: March 8, 2018.)
Manual 28: Operating Agreement Accounting. The revisions address changes to comply with FERC Order 825 implementing five-minute settlements. Also makes a technical correction for the revenue data used to calculate settlements for generation resources. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
Revisions to the Operating Committee charter to replace the term “spinning reserve” with “synchronized reserves” to match the language in PJM manuals.
FirstEnergy announced mixed first-quarter earnings Monday, along with a potential path to exit the bankruptcy of its merchant subsidiaries.
The “agreement in principle” with two groups of “key” creditors that represent most of the outstanding debts for FirstEnergy Solutions (FES) includes $225 million in cash and a tax note of $628 million due before 2020, according to a company financial disclosure filed with the U.S. Securities and Exchange Commission.
Additionally, a $787 million unsecured claim would be allowed for creditors of the company’s Bruce Mansfield coal-fired plant in Pennsylvania, where a fire damaged two of the facility’s three coal-fired units earlier this year and two workers died from exposure to hydrogen sulfide gas in August, according to company filings. Four other employees were injured. The claim would be allowed against FES and its subsidiaries, FirstEnergy Generation and FirstEnergy Nuclear Generation.
Although FirstEnergy’s Allegheny Energy Supply (AE Supply) subsidiary hasn’t filed for bankruptcy, the agreement would also transfer to creditors its ownership of the Pleasants coal-fired plant, for which it hasn’t found a buyer. (See FirstEnergy Shutting down Unsold Coal Plant.) AE Supply sold off its natural gas and pumped hydro generation assets last year. (See FirstEnergy Selling Merchant Fleet Despite NOPR.)
Earnings
The agreement came as the company also reported unadjusted first-quarter earnings of $1.2 billion ($2.54/diluted share), which improved from $205 million ($0.46/share) during the first quarter last year. Operating earnings of 67 cents/share improved from 52 cents during the same period in 2017 but missed expectations by 1 cent. Revenue increased to approximately $3 billion compared with $2.9 billion a year ago but remained several hundred million dollars below analysts’ expectations.
The company attributed the improved performance to shedding its beleaguered merchant generation fleet.
FirstEnergy’s coal-fired Pleasants Power Station in West Virginia would be signed over to creditors as part of an agreement announced Monday that would allow the company to exit the bankruptcy proceedings of its merchant-generation subsidiaries
“Today, we are pleased to report strong earnings that represent FirstEnergy as a fully regulated company,” CEO Charles E. Jones said.
The company raised its forecast range for unadjusted earnings for the year to $3.61 to $3.91/share, but it announced a gloomier forecast for next quarter. Unadjusted earnings are expected to drop to no more than 4 cents/share and could fall to a loss of 6 cents. Operating earnings are expected in the range of 47 to 57 cents/share.
Agreement Conditions
Company executives clarified several of the agreement’s points during a conference call on Monday to discuss the quarterly earnings with financial analysts.
One of the agreement’s conditions allows that if more than 60% of unsecured claims are recovered, FirstEnergy would receive 50% of any additional recovery. Jones acknowledged that such a situation would include any federal bailouts, such as those the company has requested through the Department of Energy, but emphasized that his interest is in keeping the plants open for the well-being of the communities in which they’re operating.
“We’re highly motivated to get support for those generating assets because it would be a mistake for our country for them to close,” he said. “I’m going to keep fighting for support for those plants, because it’s the right thing to do. If it gets to the point where it exceeds the threshold that we’ve got in this agreement with creditors, then, yes, we would share some of that, but that’s not why we’re doing it.”
In exchange for assistance from FirstEnergy during restructuring, the settlement would release the parent company from all claims, including decommissioning obligations for any of the nuclear plants if they are closed as the company has announced, Jones confirmed. (See FES Seeks Bankruptcy, DOE Emergency Order.)
FirstEnergy would waive some intercompany claims and maintain all previously announced guarantees, including pension obligations for FES employees. Creditors agreed to “use their best efforts” to get remaining creditors to join the settlement by June 15.
The agreement must receive sign-off from a federal bankruptcy court in Ohio, along with the boards of directors for FirstEnergy and its subsidiaries, including FirstEnergy Nuclear Operating Co. (FENOC).
FES and FENOC voluntarily filed for Chapter 11 bankruptcy on March 31. FES is FirstEnergy’s merchant generation and retail marketing subsidiary, while FENOC operates FES’ three nuclear plants. The decision, while expected for some time, is nonetheless creating ripples of uncertainty throughout the industry. (See FES Bankruptcy Creating Additional Uncertainty.)
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.
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.
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.”
“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 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.
