FirstEnergy supports the U.S. Department of Energy’s call to financially support nuclear and coal-fired units, but that won’t stop the company from selling off its merchant generation fleet and retreating to the predictable returns of regulated assets.
FirstEnergy’s Akron, Ohio headquarters
CEO Chuck Jones last week said he is also “pleased” with signs of state-level support, including a resolution from the Pennsylvania legislature supporting the department’s proposal and the introduction of the Ohio Clean Energy Jobs bill to support nuclear units with zero-emissions credits (ZECs). But “whether these state or federal activities result in meaningful and timely support remains to be seen,” he said.
“We have no interest in maintaining generating assets that have commodity exposure, and we’re moving forward with exiting the commodity-exposed generation business,” Jones said during a call to discuss third-quarter earnings.
FirstEnergy reported earnings of $396 million ($0.89/share) on $3.7 billion in revenue, missing guidance by $80 million. However, operating earnings of 97 cents/share beat guidance by 10 cents. The results exceeded performance from the same quarter a year ago, when the company reported earnings of $380 million ($0.89/share) on revenue of $3.9 billion and non-GAAP earnings of 90 cents.
Company executives credited the success to “stronger-than-expected results” in its competitive and corporate segments, along with solid regulated performance that included distribution deliveries that were better than forecasted and higher transmission revenues.
The company increased its GAAP forecast for 2017 to a range of $2.02 to $2.42/share and non-GAAP to $3 to $3.10/share, which had been targeted at $2.70 to $3/share.
Jones said Ohio’s House Bill 381 was introduced earlier this month with terms that were “reduced” from FirstEnergy’s previous requests for nuclear price supports. But they’re “likely” enough to make plants “economically viable” when combined with the planned restructuring of First Energy Solutions (FES), the company’s competitive generation arm. He expects a final vote on the measure around the middle of the first quarter next year.
“We believe this effort is imperative for Ohio’s energy security,” he said.
Despite the price support discussions, the company remains focused on shedding FES, Jones said.
“A preferred outcome” would include agreement from FES’ creditors, he said, but Chapter 11 bankruptcy remains an option that hinges on several variables, including DOE’s proposal, FERC’s actions and discussions with creditors’ advisers.
“We recognize the varied interests of our stakeholders, but we’re also aware that some have an interest in floating rumors about our company,” he said in warning that he would not discuss the progress of negotiations.
The company is moving quickly to disgorge the assets. LS Power has agreed to pay $825 million in cash for 1,615 MW of capacity that includes four Pennsylvania gas-fired plants and interests in the Bath County Hydro and Buchanan gas-fired facilities in Virginia, which are owned by FirstEnergy’s Allegheny Energy Supply subsidiary. The transaction involving the four Pennsylvania gas plants is expected to close this year, while the sale of the interest in the Virginia facilities is expected to close in the first quarter of 2018.
Jones said the full deal, which added some assets but was still reduced by $100 million since it was announced earlier this year, was priced on “the existing market conditions.”
The company’s regulated Monongahela Power subsidiary in West Virginia “continues to work through the regulatory process” to take ownership of the 1,300-MW Pleasants plant and expects approval from the West Virginia Public Service Commission and FERC by early 2018, Jones said. Allegheny expects to receive $350 million in net proceeds after paying off all its remaining long-term debt.
FERC last week approved a MISO proposal to charge interconnection customers subject to quarterly operating limit studies $10,000 as a deposit (ER17-568).
MISO had estimated that its annual cost of quarterly operating limit studies for an interconnection customer was about $2,500, which it had been collecting yearly. The change allows the RTO to charge a single $10,000 fee to cover four years and refund any remaining amount when the customer is no longer subject to quarterly operating limits. MISO said the new collection schedule will be more efficient for interconnection administrators.
FERC accepted the Tariff revisions effective Feb. 15, 2017, on the condition that MISO clarify that the $10,000 study deposit is a one-time fee and not due every quarter.
MISO created quarterly operating limits almost a decade ago to allow for the limited operation of some generators based on seasonal studies.
CHICAGO — State regulators, their staff and utility executives proved reluctant to be pinned down on predictions about the future of the grid during a spirited question-and-answer session at the annual meeting of the Organization of MISO States (OMS) last week.
Tanuj Deora, chief content officer of clean energy facilitator Smart Electric Power Alliance, posed a series of questions to scrutinize attendees’ core assumptions about the power grid during the Oct. 27 meeting.
“We have an agreement that the power grid is the foundation of our modern civilization, yes?” he asked the audience rhetorically. “Well, there are a number of folks pushing back at that.”
Deora said he’s encountered people who are convinced that the power grid will become a stranded asset. Just a smattering of hands went up in the audience when he asked if any of them believed that people would altogether defect from the grid in the future.
A Future of Low Load Growth
Deora pointed out that recent trends demonstrate that economic growth no longer drives power consumption. “I think most people are planning on a world where we don’t have a lot of load growth,” he said.
Some in the audience noted that electricity demand could spike over the next five to 10 years as more consumers adopt electric vehicles, similar to past spikes when refrigerators and air conditioning started to become commonplace. Deora also pointed out that electricity could increasingly displace natural gas for water and space heating as gas suppliers realize that may be more feasible to meet state emission-reduction targets.
Other audience members noted that if President Trump succeeds in a reviving American manufacturing, companies won’t return to now-vacant energy-devouring factories, but instead design energy-efficient spaces.
Wisconsin Public Service Commission staffer Randy Pilo added that, after multiple years of growth, a recession will loom sooner or later.
A Gray Area
Deora was met with no audience agreement when asked if regulators should continue to plan the grid on the assumption that generation should follow load with no reserve inventory.
“That is a sea change, because, gosh, the [Department of Energy] believes this with their measure of resiliency,” Deora said. He added that he believes the U.S. is on the verge of a “demand response renaissance.”
At least half of the audience agreed that economies of scale still favor central station generation, but generally hesitated when Deora asked whether that supply is best provided through the usual baseload, mid-priced peaker model.
“Come on, this was the first thing I learned as an intern,” Deora said, lightheartedly goading the audience.
Multiple audience members called out: “You can’t choose!” and “It’s gray area!”
“That worked really well when you could build a baseload plant and get energy value. … It’s turned on its head,” said Bruce Campbell, director of regulatory affairs at CPower Energy Management. He said once natural gas prices eventually rise, developers will migrate to yet another fuel type.
Deora ventured that it may be time to reconsider the economic model for power. “Usually when I bring up at conferences that we might need a rethink of power economics, the audience shudders and tells me it’s not time,” he said.
‘Sleepy Backwater’
Deora said that while some utilities are still focused on being a strict wires-only owner or operator, more are exploring how to optimize a distribution system platform or interconnect distributed energy resources — and are even open to owning their own portfolio of distributed resources.
Charles Goldman, a strategic adviser with the Lawrence Berkeley National Laboratory, said past predictions of the adoption of photovoltaic DER have proven too conservative. He said in his state of California, distributed solar is in clustered hot valley areas, wealthy coastal communities and tech-friendly Silicon Valley. Rooftop solar has significantly shifted the noon to 6 p.m. load curve.
“It’s all happened in the last four to seven years,” Goldman said.
“I realize in the Midwest, this is not a topical, front burner issue,” he said, but he noted that Minnesota is considering requiring its utilities to file distribution system plans, including DER forecasting.
“Distribution planning has been the sleepy backwater,” Goldman said.
He admitted that RTOs will have more difficulties forecasting and modeling future distributed resources than single-state ISOs.
Outgoing OMS President and Indiana Utility Regulatory Commissioner Angela Weber said regulators and OMS are uniquely positioned to steer the industry in rules surrounding DER.
“It’s the first time in OMS that I see the states leading on an issue.”
AUSTIN, Texas — The Public Utility Commission of Texas on Thursday threw a bit of cold water on Sempra Energy’s proposed $9.45 billion acquisition of Oncor after issuing a preliminary order that calls for Sempra to prove it’s financially fit to own the state’s largest utility.
Whether that’s enough to short-circuit yet another bid — the third — for Oncor remains to be seen.
Commissioner Ken Anderson filed a memo last week asking for more information on Sempra’s debt, the transaction’s financing, Oncor’s governance structure, the effect of Sempra’s other projects on its credit rating and Sempra’s corporate relationship with Oncor (Docket 47675).
“These issues are important because Sempra creates uncertainty when it fails to produce details about how it will fund the transaction,” Anderson wrote. “The purchaser must be able to prove it has the financial strength and stability to complete the purchase on its own, without impairing itself or Oncor.”
Hunt Consolidated and NextEra Energy failed in previous acquisition attempts to meet the PUC’s ring-fencing measures. Sempra announced it would make a bid for Oncor in August. (See Sempra Outmuscles Berkshire for Oncor.)
Anderson said Sempra’s current application before the commission provides “very limited details” on how it will finance the transaction and manage “liabilities associated with its debt and far-flung operations.” He noted the company’s debt has risen from $5 billion in 2007 to about $18 billion, but that cash from operations increased slightly through 2009 and has remained relatively stable since.
“So far, it seems Sempra has not realized a proportional increase in cash flow from its projects,” Anderson wrote.
Anderson reminded Chair DeAnn Walker and fellow Commissioner Brandy Marty Marquez that the PUC’s goal is to “once and for all” help Oncor escape a “risky, debt-laden majority owner” and “move forward without the nagging specter of a financially troubled parent.”
Oncor parent Energy Future Holdings, which declared bankruptcy in 2014, has retained an 80% stake in the utility since going into Chapter 11.
“Our objective,” Anderson said, is to “ensure that Oncor is not being permitted to hop from one frying pan into another, or even just into a simmering pot.”
He added a list of additional issues to be considered in the preliminary order, which Walker and Marquez approved.
Spokesperson Amber Albrecht took exception to Anderson’s comments, saying Sempra is a “very strong, growing and conservatively financed company.”
“We have investment-grade credit ratings at the holding company level, as well as at all of our operating subsidiaries, and our market capitalization over the past 10 years has grown to nearly $29 billion from about $15 billion,” she said.
Anderson allowed that while Sempra’s current credit ratings of Baa1 (Moody’s) and BBB+ (Standard & Poor’s) are investment grade, they are also “bottom tier.”
“The company is vulnerable to changing economic conditions and could face challenges if overall economic conditions decline or if Sempra continues to experience significant challenges,” Anderson said, pointing to the company’s $10 billion LNG export project in Louisiana and international holdings in South America.
Sempra has already revised its financing structure since its initial bid in an effort to appease intervenors in the previous attempts to acquire Oncor. (See Sempra Reworks Oncor Bid to Erase EFH Debt.)
The PUC has scheduled a Feb. 21-23, 2018, hearing on the proposed acquisition in Austin.
PUC Orders Refiling in NextEra Ownership Bid for Oncor
The commission also rejected NextEra’s bid to acquire a 19.75% interest in Oncor and directed the parties involved to refile an application that includes Oncor as an applicant.
Walker had suggested in a memo that the filing be dismissed, saying the state’s Public Utility Regulatory Act (PURA) requires the “statutorily specified entity” to submit the filing. Anderson and Marquez agreed.
NextEra and Texas Transmission Holdings Corp. (TTHC), which owns the 19.75%, filed a joint application with the PUC in July. However, staff in August ruled the application deficient, saying neither applicant is a public utility under state regulations and that the case should not proceed without Oncor’s involvement (Docket 47453).
Oncor intervened in the proceeding in September, telling the PUC that it was not “seeking commission approval of the proposed sale.”
In her memo, Walker referenced statutory language that “an electric utility or transmission and distribution utility must report to and obtain approval of the commission before closing any transaction in which … a controlling interest or operational control of the electric utility or transmission and distribution utility will be transferred.”
Noting that neither NextEra nor TTHC complies with the requirements, Walker wrote, “In this case, Oncor must file the relevant report regarding this proposed transaction.”
Walker said the refiling would allow the commission to determine whether the proposed transaction should close.
Vinson & Elkins’ Matt Henry, representing Oncor, promised action within a few weeks. He said the utility intended to consult with NextEra and TTHC to determine how to proceed with a final filing, and that it would have to talk with Oncor’s board as well.
Commission Rules Against SPS’ Right of First Refusal
The commission issued a final order that made official its earlier rejection of Southwestern Public Service’s exclusive right to build new regionally funded transmission facilities in its service territory (Docket 46901).
The PUC discussed the issue publicly in July, making it clear how it would rule. (See Texas Commission Rejects SPS ROFR Request.) SPS said at the time it would seek a rehearing and an appeal; spokesman Wes Reeves said Monday the company plans to file a motion for rehearing by Nov. 20.
The commission further concluded that transmission facilities serving the public cannot be constructed in Texas without first obtaining a certificate of convenience and necessity (CCN) from the commission.
“Such a right would be inconsistent with the commission’s authority to issue CCNs for transmission facilities, which is not limited to only utilities that have a certificated service area in which the facilities would be located,” the commission wrote.
Walker abstained from the order, as the proceeding occurred a month before she joined the commission.
SPP and SPS in February requested the PUC determine whether the utility has the exclusive right to construct and operate new, regionally funded transmission facilities in areas of Texas that lie within its certificated service area. (See SPS, SPP Ask Texas to Rule on Transmission Competition.)
SPS contended that as an incumbent utility operating outside ERCOT, PURA gave it a right of first refusal to build in the service area prescribed by the PUC. SPP claimed that no such right existed, giving the RTO the ability to solicit and designate transmission-only utilities to construct and operate new transmission facilities within SPS’ service area under FERC Order 1000.
The project in question, the 345-kV Potter-Tolk transmission line in the Texas Panhandle, was pulled from SPP’s 10-year planning assessment in April. SPP’s Board of Directors directed staff to conduct a congestion study in the area, due within a year. (See SPP Board Cancels Panhandle Line, Seeks New Congestion Study.)
ERCOT’s Budget, Admin Fee Approved
The commission formally approved ERCOT’s 2018/19 biennial budget, which will keep the ISO’s system administration fee flat at 55.5 cents/MWh for the next two years (Docket 38533). The fee was raised from 46.5 cents/MWh in 2015.
The ERCOT board approved the budget in June, setting operating expenses, projects and debt-service obligations at $222.3 million and $228.0 million for 2018 and 2019, respectively.
FERC last week denied CAISO’s request to waive Tariff requirements regarding “availability assessment hours” used to assess utilities’ compliance with resource adequacy requirements (ER17-2263).
The ISO uses availability assessment hours to measure the availability of generation during a predetermined time period of the day for each type of capacity. Resources that are available for 98.5% of the hours for a month are eligible for payments, while resources that are available for less than 94.5% for that month are subject to non-availability charges.
| City of Glendale, Calif.
CAISO wants to keep its 2017 availability assessment hours for 2018, but that violates a requirement that the hours vary by season. The ISO requested the waiver to provide relief to demand response companies that had offered to provide capacity based on qualifying capacity values calculated under California Public Utilities Commission rules, which are the same as 2017, creating a conflict with CAISO rules.
FERC’s Oct. 24 order said the waiver request affects the availability assessment hours applied to all nonexempt resource adequacy resources and not solely the DR providers that require relief.
“CAISO does not provide a precise accounting of the demand response resources that require relief through this waiver request,” FERC said. “However, the number appears to be relatively small compared with the total number of resource adequacy resources subject to the availability assessment hours. In sum, CAISO has not shown that the small amount of resources requiring relief justifies or requires the proposed scope of the waiver CAISO requests.”
The commission said CAISO could submit a limited waiver request that directly addresses the problem of DR participation without creating undesirable consequences for the resource adequacy program.
CHICAGO — The Organization of MISO States (OMS) last week failed to reach consensus on how to respond to MISO’s plans to allocate costs for smaller transmission projects that produce broader economic benefits for the grid.
OMS is slated to present its suggestions on cost allocation at a Nov. 16 Regional Expansion Criteria and Benefits Working Group (RECBWG) meeting, but members were still unable to develop a unified position during their annual meeting on Oct. 27. OMS set a priority to establish a group position on the subject late last year. (See No OMS Consensus on MISO Cost Allocation Changes.)
MISO currently has no mechanism in place for allocating costs for economic projects with voltage ratings below 345 kV.
OMS board members say they might ask MISO to require market efficiency projects to be at least 230 kV and have a cost threshold of either $1 million or $5 million to $20 million in order to be eligible for cost allocation. They could also request that the benefit-cost ratio be increased from 1.25:1 to 1.5:1 if benefits other than the adjusted production cost are factored in, a move MISO has promised to consider.
The RTO has meanwhile assembled a straw proposal that would lower the cost allocation eligibility threshold to 100 kV, replace the 20% footprint-wide allocation with a postage stamp rate and enact a still unspecified project cost threshold. The proposal would limit cost allocation to benefiting transmission pricing zones.
Missouri Public Service Commission economist Adam McKinnie said his state requires a voltage threshold below 230 kV. “The interconnections between my state are 161 kV [or] 169 kV. I’m very wary of any cost allocation that does not give lower-voltage projects between SPP and MISO a cost allocation,” he said.
North Dakota Public Service Commissioner Julie Fedorchak expressed discomfort with any proposal that would allocate 100% of costs to benefiting transmission pricing zones, pointing out that much of the transmission development occurring in her state will not necessarily benefit its ratepayers.
The OMS board has also contemplated a cost-sharing proposal that would designate one portion of costs to benefiting transmission pricing zones and another to the local resource zones that contain those pricing zones.
“I think this debate shows that regulators need time to go back to their states and digest this,” said OMS President Angela Weber.
“Every state might not get everything they want, but the question is, ‘Can we come up with something that is better than what MISO is proposing?’” said Public Utility Commission of Texas staffer Werner Roth.
GEORGETOWN, Texas — The Texas Renewable Energy Industries Alliance GridNEXT conference brought together more than 100 industry leaders, producers, developers, utilities, large consumers, entrepreneurs and policymakers to discuss the latest energy trends and developments. They attended workshops and participated in panel discussions on new technologies and the smart grid, integrating renewables and corporate energy management.
ERCOT Market Awaits Coal Retirements’ Effects in 2018
Cyrus Reed, conservation director for the Lone Star Chapter of the Sierra Club, moderated a panel discussing emerging issues in the ERCOT market. Reed has long led the fight against fossil-fueled generation in Texas, a fact NRG Energy’s Bill Barnes couldn’t help alluding to.
“Four thousand megawatts of coal retirements … I figured you’d be in a tuxedo,” Barnes deadpanned, referring to Luminant’s recent decision to close three coal plants. “This is what you’ve been waiting for.” (See Vistra Energy to Close 2 More Coal Plants.)
In a way, so are others involved in the market. Steve Reedy, deputy director of ERCOT’s Independent Market Monitor, noted that the ISO hasn’t seen a summer with tight reserve margins since 2007. He said the Monitor is anxiously waiting to see how the market performs in 2018.
“Will we see coal generators making profits that justify future investment?” Reedy asked. “We did see too much capacity on the system, more than justified for the load. If the load doesn’t rise fast enough to justify the generation, we expect to see retirements. So we will see if retirements in the market work.”
“We’re in Steve’s camp,” Barnes said. “We’ve made market improvements, but we still need to live through the events we’ve set up. We haven’t had a true scarcity event in years, but if we have severe weather, we could have one. That’s when we can all sit back and say, ‘Yes, that’s how it’s supposed to work.’ Or will there be temptation to intervene in the market?”
“The ERCOT market … is brutally competitive,” said The Wind Coalition’s Walter Reid. “You have true competitors, with a very low barrier to entry for new generators. You also have the wild west of open access to true transmission. Generators are able to interconnect with the lowest impediment anywhere in the country.”
Reid credited the state’s regulators and legislators with helping bring a sense of order to the market.
“They’ve adjusted the market, as opposed to making dramatic changes,” he said. “Any time you make a dramatic change, you’re disrupting entrepreneurial energy. Only entrepreneurial energy will help us when we have energy shortfalls.”
Asked by Reed why real-time co-optimization makes him “scream like a 13-year-old girl at a Justin Bieber concert,” Reedy acknowledged the Monitor is a “really big fan.” Of several market-design improvements the Public Utility Commission of Texas is considering, “our favorite idea is real-time co-optimization,” he said. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
“It’s effectively choosing on an every-five-minute basis where you get [the] spare reserve capacity you’re paying for. That’s your insurance policy,” Reedy said. “And you’re paying for it effectively and appropriately.”
The Monitor agrees with the proposals being offered by a report commissioned by NRG and Calpine, Reedy said, but not all the implementation details.
“We also like factoring marginal [line] losses into the price. Prices are important. They’re the signal to tell people where to invest and how to operate. If energy is less valuable — if all the wind farm is doing is heating up the lines — it’s not really as useful. To the extent it’s doing that, it should be factored into the price.”
“It’s easy to support an energy-only market when the prices are low … but logic can tell you that it can’t last forever,” Reid said. “It’s going to take some courage to stay the course and say this is how the market is designed to work. There’s periods of low prices, then high prices which incent new development and bring about a period of lower prices.”
Does Grid Resiliency Override Solar & Storage?
Speaking on a panel devoted to solar energy and storage, Judy McElroy, CEO for Fractal Energy Storage Consultants, surprised some in the audience when she focused her comments on grid resiliency and the importance of baseload generation.
“Don’t confuse [solar and storage] with resiliency. You still need to have conventional generation with solar and storage,” McElroy said. “While I’m at 50% renewable energy, I still need that conventional generation on standby and pay it to maintain the system. You’re never going to be free from that conventional generation.
“I know we want it so bad and we’re working so hard to make it happen, but we have to do it responsibly. If you’re a grid operator or someone who’s in the service utility industry, your job, first and foremost, is to keep the lights on, and we have to be responsible about that.”
As Tesla’s Topher Blunt said, “Solar doesn’t work if you don’t have grid power. When your challenge is to rebuild the grid, what do you do when your whole rooftop array is rolled up like a burrito?
“We’re finding storage is not necessarily the thing you have when power is out,” Blunt said. “Trying to plan for the absolute worst scenario, and have batteries at the ready, is not the best use of batteries.”
DERs Pose Big Changes for the Grid
The coming of distributed energy resources means big changes for the consumer, said Enbala Power Networks’ J.T. Thompson.
“The costs have gone down, and the grid is inverting. We’re moving from a centralized grid to one very much at the edge,” Thompson said. “We have to be ready for that, our utilities have to be ready for that, and we have to help our customers be ready for that. All of this is taking place at breakneck speed.”
Scott Hinson, director of engineering for Pecan Street — a research project at the University of Texas involving several Texas utilities, energy retailers and technology companies — related the story of one 12-year-old consumer who understood the future grid. Hinson was working on a residential microgrid controller in one participant’s garage, while the young man watched.
“He was dubious of the amount of space it took up in the garage,” Hinson said. “When I explained how it worked, he said, ‘So the power goes out, but I get to keep playing Xbox?’
“‘Yes, you do.’ He gave me a thumbs-up, and then he was out in the yard.”
Public Power Still Has Role in Texas’ Market
Panelists discussing public power issues agreed that the state’s municipalities and co-operatives, many of which have not opted into ERCOT’s competitive market, still have a role to play.
“When we talk retirements and reserve margins, it’s the munis and co-ops … that can provide the cash flow to help the market,” said the city of Georgetown’s Chris Foster. “We’re at that level that if the rest of the market goes belly up and prices are expected to rise, we expect the PUC to turn to us and say, ‘Can you help?’”
“As a rural cooperative, we’re not an early adopter by any means,” said Ingmar Sterzing, with Pedernales Electric Cooperative. “We appreciate CPS [Energy] and Austin [Energy] getting out in front so we can learn and grow from that. We also have a traditional mindset of lower-risk investments. We take things in a prudent, measured approach.”
Georgetown’s commitment to 100% renewable power presents another example of public power leadership.
“We went 100% renewable in our contracts because they were price competitive,” Foster said. “It was a pretty easy adoption for us. It speaks to the competitiveness of those resources. Why aren’t more utilities adopting that strong of a stance?”
“You can’t just spin around and diversify [your] assets,” said Austin Energy’s Khalil Shalabi, referring to the utility’s nuclear and coal generation. “If we sign a bunch of renewables contracts, we have to keep rates affordable. But to go to a net-zero utility — with nuclear and 65% renewables — we’ll almost be there by 2027.”
Jan Vrins, Navigant’s global energy practice leader, said there’s no doubt the economy will decarbonize. When, he would not say.
“The pace by which and how is up to debate,” Vrins said during a “fireside chat.” “We’re going through a huge transformation … and the energy markets are not working anymore. We have to fix them. DERs will be 10 times more disruptive to our markets than renewables have been. There will be a complete value shift away from generation to transmission, distribution and beyond. Smart cities will create more value to customers and citizens. That’s where the investment will go, not to generation.”
Vistra Energy will acquire Dynegy in a $1.7 billion all-stock deal that will create a power generation and retail giant owning 40 GW of capacity and serving nearly 3 million customers, mainly in ERCOT, PJM and ISO-NE, the companies announced Monday.
In a conference call, Vistra CEO Curt Morgan said the companies planned to close the deal by April 30, 2018, allowing six months for regulatory approvals from FERC, the New York Public Service Commission and the Public Utility Commission of Texas.
Dynegy’s combined cycle gas turbine fleet and geographically diverse portfolio were a big attraction for Vistra.
Morgan said the deal “should create a more stable earnings profile and offers some downside earnings protection, especially when combined with our retail operations.”
The CEO had previously indicated Vistra would consider a large-scale acquisition outside ERCOT “if it was all stock, there were substantial value levers, quality assets in PJM and ISO-NE, and also a large natural gas fleet to move us to a gassier portfolio and preserve balance sheet flexibility. In short, this deal does that.”
It will be structured as a tax-free reorganization and will not trigger change-in-control provisions in either entity’s credit or bond agreements. The combined company will have a market cap around $10 billion.
Vistra’s executive team, including Morgan, Chief Operating Officer Jim Burke and Chief Financial Officer Bill Holden, will lead the combined company, based at Vistra’s headquarters in Irving, Texas. Morgan said he will announce his full team within a few weeks.
The new board is expected to have 11 directors: the current eight members of the Vistra board and three members from Dynegy’s board. Dynegy CEO Bob Flexon will continue to serve until April 30, 2019, or the date the transaction closes, whichever comes first.
Flexon said the deal was “an incredibly compelling opportunity” for Dynegy and its shareholders.
The combined company projects streamlining to achieve approximately $350 million in annual savings before interest, taxes, depreciation and amortization (EBITDA) within a year. Morgan said it will maintain Vistra’s “balance sheet strength and discipline. … Vistra would not be entering into this transaction if that were not the case.”
De-Levering
Morgan said the deal provides Dynegy “instant de-levering.” The combined company will have a net debt-to-EBITDA ratio of about 3.2 by the end of 2018, which is projected to decline to 2.6 by the end of 2019 and 2.4 by the end of 2020. It will have $3.9 billion in liquidity as of April 2018.
“Three times gross debt-to-EBITDA is the right long-term leverage target in this industry given the high degree of commodity price exposure and the necessity to maintain dry powder on the balance sheet in order to be able to transact at opportunistic times in market cycles,” Holden said.
Analyst Neel Mitra of Tudor, Pickering, Holt & Co., said it is a good deal for both companies, saying the $350 million in synergies, tax savings and the addition of PJM assets benefit Vistra. “At the same time, Dynegy’s EBITDA contribution should trade at a higher multiple given that its over-leverage issue is corrected by Vistra’s pristine balance sheet,” he said by email.
ERCOT Market Power
Morgan said the company will need to shed about 900 MW in ERCOT to remain under the 20% market share limit. “We’ve got two paths that we can go down. We will be kicking off a divestiture process that we’ve already started and will be going out in the market,” Morgan said. “But there’s also another avenue that I won’t get into in too much detail here … where we wouldn’t have to do any divestiture at all. You guys will see that in the marketplace. We can execute that in the six-month period that we’re talking about getting [regulatory] approval. And we will have a mitigation plan in place when we file with the [Texas] PUC for approval.”
PJM Outlook
Morgan said the company was assuming no improvements to capacity or energy prices in PJM, but it also did not expect prices to fall further.
“It takes a substantial amount of net megawatts — meaning net between new additions and retirements — to actually move the capacity curve. It’s such a flat curve. It takes on a net basis about 6,000 MW of additional [capacity]. I don’t think 6,000 MW on a net basis is going to come into this market. That’s why we are looking at capacity being relatively flat.”
He said the projections do assume some new generation in the RTO “because for some reason people are still investing. But I think this last [capacity auction] clear put a chilling effect. … And also, capital going into PJM projects is beginning to dry up. I’ve heard that from a number of people. So, I think the market there is beginning to discipline itself.”
Morgan said the company will be “opportunistic” in seeking additional generation, predicting “there’s going to be just a ton of assets that come into the market.”
“But that’s not going to be a primary [focus]. … What we would like to do, we think we have this tremendous platform to grow our retail business.” The company will begin with 240,000 commercial and industrial customers and 2.7 million residential customers.
Generation Mix
Morgan said the move to a “gassier portfolio” would give the combined company the lowest-cost structure in the industry, with wholesale costs as low as $9/MWh and retail costs as low as $45 per residential customer equivalent.
| Vistra Energy Investor Presentation, October 2017
The combined company will have more coal — 32% — than Vistra’s current 28% share. But the deal will boost its natural gas share to 61% from 54% while reducing nuclear from 17% to 6%. It will also provide more geographic diversification, reducing Dynegy’s PJM exposure (45%) to 29% in the new company. Of the combined company’s 40 GW of installed capacity, 84% is in Texas, PJM and New England.
Terms
Under the terms of the agreement, Dynegy shareholders will receive 0.652 shares of Vistra common stock for each share of Dynegy common stock they own, resulting in Vistra and Dynegy shareholders owning approximately 79% and 21%, respectively, of the combined company. Based on Vistra’s closing share price of $20.30 on Friday and the agreed exchange ratio, Dynegy shareholders would receive $13.24 per Dynegy share.
| Vistra Energy Investor Presentation, October 2017
Price Formation
Morgan said he is hopeful that the Department of Energy’s Notice of Proposed Rulemaking will result in FERC actions boosting the company’s generation and noted that Vistra has introduced a price formation proposal in ERCOT as an alternative to the Calpine-NRG Energy whitepaper. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
“With the DOE action taken I do think there is some pressure for PJM and ISO-NE and others to come forward with something around price formation because that was very prominent in the DOE [proposal],” he said. “I don’t think DOE will get implemented, obviously, the way that it was put in.
“But more importantly I think that FERC will be inclined to act on whatever the ISOs bring forward. You hate to handicap things, but it sure seems like there’s a good chance — a better chance than not — that if there is something brought forward, which I expect there will be around price formation, that it will ultimately be approved by FERC.”
RENSSELAER, N.Y. — The NYISO Management Committee was briefed Wednesday on the ISO’s strategic planning process, which broadly examines issues the grid operator expects to face over the next five years.
“A lot of the issues concern public policy,” Rich Dewey, NYISO executive vice president, said in reviewing the ISO’s draft plan. They include carbon pricing, locational capacity requirements, better integration between the distributed system platform and wholesale markets, and planning for transmission to support offshore wind.
| NYISO
On integrating public policy with the market, the report asked, “How will the wholesale markets adapt to provide the necessary services (i.e., ramping, transmission security, inertia, frequency regulation) to balance the intermittent renewable generation?”
Howard Fromer of PSEG Power New York asked, “What sense of urgency did the board have, looking ahead five years, about a sense of fear in the market — whether we will even have this market in five years? The market design did not contemplate today’s reality of zero and negative prices.”
Dewey said there was no fear at the board, but members did feel a sense of urgency and “have been spending a lot of time on figuring out how to use a very powerful tool, the markets, to achieve our goal of a sustainable energy market and grid.”
2018 Budget Recommended to Board
The committee voted to recommend that the board approve the ISO’s proposed Rate Schedule 1 revenue requirement of $155.7 million for the 2018 budget year, which translates into spending of $0.987/MWh.
Alan Ackerman, chair of the Budget and Priorities Working Group, presented the budget, the key priorities of which include physical and cybersecurity enhancements to secure operations and meet audit and compliance needs. (See “2018 Budget Up 5% on Security Enhancements,” NYISO Management Committee Briefs: Sept. 27, 2017.)
Tariff Changes for Inverter-Based Storage Approved
The committee approved proposed Tariff and Ancillary Services Manual changes to define the role of inverter-based energy storage in providing synchronized reserves.
Daniel F. Noriega, NYISO associate market design specialist, presented the changes — already approved by the Business Issues Committee on Oct. 11 — that would allow generators and demand-side resources that use inverter-based storage technology to provide spinning reserves. (See “Proposed Tariff Changes for Energy Storage,” NYISO Business Issues Committee Briefs: Oct. 11, 2017.)
The committee also approved a proposal, approved earlier this month by the BIC, to more closely align the real-time and day-ahead impact tests and penalty calculations used to identify generator misuse of fuel cost adjustments (FCA). The current day-ahead process is considered more precise than the real-time because it also tests the impact on real-time prices based on market reruns.
The Management Committee elected Chris LaRoe of Brookfield Renewable as vice chair for 2018. Scott Butler of Consolidated Edison also stood for the position.
As homes become smarter and electric vehicles increasingly become the norm, there will be money to be made in managing how and when people use power. But investors are still in the early stages of figuring out how to make returns on the rapid changes overtaking the power sector, according to energy finance professionals.
Nalin Kulatilaka, BU; Michael Lapides, Goldman Sachs; Sheldon Simon, Adage Capital Management; and Stephen Byrd, Morgan Stanley.
Investment experts discussed new energy technologies, regulatory trends and the evolving business model for utilities at an Oct. 19 “fireside” chat hosted by Boston University’s Institute for Sustainable Energy.
Kulatilaka
Panel moderator Nalin Kulatilaka, of the university’s Questrom School of Business, asked how capital will be drawn to new energy technologies, whether for generation or energy storage — or the software that can manage energy better.
“Historically, energy investment has been with big instruments and now it’s going to be much more a mix of large and small, centralized and distributed,” said Michael Lapides of Goldman Sachs. “It’s going to have much more of a technology overlay to it. From a software perspective, we’re barely at the surface of what’s likely to happen in the broader electricity industry. What is the real customer usage level? What’s the normal?”
Utility or Tech Firm?
Byrd
Stephen Byrd, who heads Morgan Stanley’s North American power research group, said that while traditional utilities appreciate new opportunities conceptually and are making efforts to adapt, he questioned whether they’ll become the agents or interfaces that enable customers to benefit from the advances in technology.
Such a company — he said he could think of several already operating in California — analyzes “the data within your house or business and says ‘here are all the ways we can change the pattern of your usage,’ and then links that up with the utility bill structure,” Byrd said. “I can see the day when one of those companies goes to a utility and says, ‘I’ve got a million of your customers and they’re all on an app on their phones, and we can press a button and shift your peak usage by around X%.’ What is that worth? We don’t know, but it’s worth a lot. That’s not the death of the utility, but there’s a lot of value there that I think the utility may not capture. Maybe a technology company captures that.”
Simon
Sheldon Simon, an equity analyst with Adage Capital Management, said a system built to move megawatts from central stations was not designed to accommodate the changing case of distributed — and variable — power generation.
“If you think about significant lumpiness in the U.S. electricity industry’s [capital expenditure] cycles, it’s almost always been very generation-friendly,” Simon said. “The grid is not built to have every house be a power plant, or to have so much intermittent generation as we’re going to have. We’re going to see some markets, far more than planned, where the intermittency creates problems for the grid operator.”
Barbarians at the Wall
It’s currently harder to create true value in power generation than in distribution and energy management, Byrd said.
“Truly new generation technologies are pretty rare to actually have an impact, though we’re watching some areas. There are a lot of very smart people focused on that,” he said. “It’s just very hard to beat the low-cost nature of larger, more centralized power plants. But I wouldn’t rule that out.”
| Goldman Sachs
On the disruptive power of wind, Byrd likened wind to a barbarian horde: “They’re going to spread everywhere. I can think of some nuclear plants that are castles along the wall that are being attacked by the barbarian horde. That’s an opportunity for some, and it’s a serious threat to others.”
Simon said “that in a very different way, utility-scale and distributed solar will have a very similar impact. It will be more localized, it will be closer to the customer, if not owned by the customer.”
Lapides
Utilities now face the question of how to grow, which will partly be through fleet transformation, according to Lapides.
“A few years ago there were some very large utilities that owned almost no renewables, and now they’re major top-10 players in the industry because they have huge economies of scale and balance sheets,” Lapides said. “And they serve a lot of customers. Is that what happens with storage? Maybe. Is that what happens with software that deals with grid management? Maybe.”
Regulatory Trends
As technologies evolve and customers use less electricity or go elsewhere for power, utilities have to reallocate their fixed costs to a smaller base, which means that rates could go up for remaining customers. Kulatilaka asked how regulators would likely deal with that new situation facing utilities.
“If we’re entering a period where interest rates go up — they’ve been going down for 30 years — the regulatory models’ gist is that utilities will seek higher returns, forcing rates higher,” Simon said. “So there are limits to how high customer rates can go up when you have less utilization and fewer customers. That could be the real conflict that causes real stress on the industry, because at the end of the day, it is about the money, about what people can pay and what’s politically palatable.”
Speaking about the impact on the regulatory paradigm, Lapides said: “The answer’s out there staring us in the face. … The states that were early movers in decoupling, basically, whether they realized it or not, got their utilities out of the business of caring a lot about demand growth. Think about the implications. From an earnings power perspective, from an environmental perspective, from a planning perspective, it hits all of those three. It’s not rocket science.”
Simon expressed little confidence in the responsiveness of utility commissions.
“Regulators, with few exceptions, will not be forward-thinking,” he said. “They’ll swing the bat when the ball’s in the catcher’s mitt. They’re risk-averse, so they’ll step in when things get to be dire, and what they’ll do is unclear. … [Regulators] are not necessarily friends of the utilities; they just want to make sure that when people turn the switch on, the lights come on.”
