CenterPoint Energy on Friday reported a second-quarter loss of $75 million ($0.17/share), compared to a profit of $135 million ($0.31/share) a year earlier. The company’s adjusted earnings of 30 cents/share fell short of Zacks Investment Research expectations of 32 cents.
The quarter’s loss included a pre-tax write down of $242 million to reflect the Houston-based company’s investment in Time Warner. AT&T acquired Time Warner in June, with CenterPoint receiving $53.75 and 1.437 shares of AT&T common stock for each share of Time Warner common stock it held.
CenterPoint endured a morning roller coaster ride Friday on Wall Street before its stock plunged in after-hours trading. After opening at $28.10/share, the stock closed at $27.96 before losing 12 more cents after the closing bell.
CEO Scott Prochazka said during a conference call with financial analysis that the company’s electric, gas and Enable Midstream joint venture businesses performed well, accounting for a 25% increase in revenue to $2.8 billion from 2017’s second quarter.
Prochazka said the company’s $6 billion acquisition of Indiana electric and gas utility Vectren is progressing well. The company expects to close the deal in the first quarter of 2019. (See CenterPoint Energy to Acquire Vectren in $6B Deal.)
Port of Freeport | Port of Freeport
However, Prochazka also said the cost of CenterPoint’s Freeport Master Plan project has more than doubled, from $250 million to $650 million, as a result of “more defined analysis” of infrastructure and environmental-related routing issues. ERCOT approved the project last year to solve reliability issues near the Freeport area south of Houston. (See ERCOT Stakeholders OK $246.7M in Freeport Reliability Projects.)
CenterPoint plans to file a certificate of convenience and necessity with the Texas Public Utility Commission in September.
OMAHA, Neb. — State regulators from the SPP and MISO footprints are banding together to take on seams issues created by what one industry expert calls “RTO gerrymandering.”
Commissioners sitting on SPP’s Regional State Committee and MISO’s Organization of MISO States (OMS) met Monday to begin developing a joint RSC-OMS working group to improve market coordination and tackle problems the grid operators and their stakeholders haven’t been able to resolve.
“It’s a conversation we’ve been having off and on since May,” said RSC Chair Shari Feist Albrecht, who also chairs the Kansas Corporation Commission. “We want to contribute a state regulator’s point of view to the discussion here, and to provide advice and guidance.”
OMS Chair Ted Thomas, who chairs the Arkansas Public Service Commission, and Minnesota Public Utilities Commissioner Matt Schuerger met with RSC regulators before the committee’s regular quarterly meeting. Albrecht said the commissioners discussed defining the problems and establishing goals going forward.
“It made sense to work together,” she said. “State commissions have regulatory and cost-allocation authorities. We should have a responsibility in this area.”
“We need to work together… and not bang heads,” Thomas said during an OMS Executive Committee conference call in June.
SPP and MISO have been unable to agree to any interregional projects since FERC issued Order 1000 in 2011. The grid operators have said the cost of building joint models and financial and voltage thresholds inhibit their ability to come together on projects across the seams.
The RTOs agreed last month to work on improving their interregional process. They will study potential joint projects within their own regional models and have also added new benefit metrics, such as the avoided cost of other projects. (See MISO, SPP Loosen Interregional Project Requirements.)
“If there are problems, what are they? You can’t solve problems if you don’t try,” said Albrecht, noting that MISO and PJM work well across their seam. “We don’t have a sense of history or the background behind [seams issues]. Whatever they are, they’re not unsolvable.”
Stakeholders on both sides of the seam have expressed their frustration over the RTOs’ inability to get interregional projects approved. The Wind Coalition’s Steve Gaw, one of the more outspoken critics of the process, said he is pleased by the RSC and OMS efforts.
“RTOs were formed in part because of the savings that result from reducing the costs of seams between utilities,” Gaw said. “Today we have a seam between MISO and SPP that stretches across multiple states. The states, through the regional committees, are well positioned to examine whether significant cost savings for consumers and reliability improvements could be made between RTOs.”
Ironically, it’s the shape of the SPP-MISO seam itself that has contributed to the problem. Economist Rob Gramlich, president of Grid Strategies, said without “rationally configured RTOs,” seams issues have become larger than they should be.
“FERC has allowed oddly shaped RTOs — and the states and utilities have played a part in that — but they won’t work without effective seams management,” Gramlich said, referring to the shapes as “RTO gerrymandering.”
“It’s helpful for state regulators in both regions to help resolve seams problems for their mutual benefit,” he said. “Clearly, SPP and MISO are talking to each other and trying to work things out. They’ve made a number of improvements, but somebody needs to be holding them accountable and moving the process forward.”
SPP General Counsel Paul Suskie, staff secretary for the RSC, said the grid operator is “encouraged” by the commissioners’ engagement and greater understanding of seams issues.
“It’s especially valuable when it comes to building seams projects, considering commissioners’ critical roles in cost allocation and siting authority,” he said.
Ag Study Safe Harbor Limit Stays Unchanged
The RSC unanimously accepted the Cost Allocation Working Group’s recommendation to not conduct a larger study on the aggregate study’s safe-harbor waiver criteria, following the CAWG’s first limited review. The committee also agreed that the CAWG should conduct a second limited annual review in 2019.
The committee agreed last year to conduct a limited study of the aggregate study, which assesses the projects necessary to satisfy transmission service requests to move energy around the SPP system, as well as who pays for those projects. Transmission upgrades under the safe harbor limit are base-plan funded through the RTO’s highway/byway approach. (See “RSC Leaves Safe Harbor Limit Unchanged,” SPP Regional State Committee Briefs: July 24, 2017.)
The safe harbor cost limit will remain unchanged at $180,000/MW.
Eversource Energy said Wednesday that it is increasing its capital spending over the next three years by $600 million, bringing the total to $7.1 billion through 2021.
“This incremental capital will be split between $300 million for electric transmission, $200 million for electric distribution and $100 million for natural gas distribution infrastructure investments,” Eversource CFO Phil Lembo said in an analyst call. “To be more specific, on the electric transmission system, we now plan to accelerate the upgrades of aging wooden transmission structures and expect to replace thousands of them with new steel poles over the next several years.
“The primary driver of this increased level of expenditure will be investments in resiliency and reliability,” Lembo said. He added that the figures do “not include any potential initiatives that may emerge from the grid [modernization] reviews in Connecticut or Massachusetts.”
Eversource, New England’s largest utility, offers retail electricity, natural gas service and water service to approximately 3.6 million customers in Connecticut, Massachusetts and New Hampshire.
Q2 Earnings Increase 5%
The company reported second-quarter earnings of $242.8 million ($0.76/share), up slightly more than 5% compared with $230.7 million ($0.72/share) in the same period a year ago.
Eversource’s transmission unit earned $112.7 million in the quarter, up nearly 17% from a year earlier, primarily because of higher investment in its electric transmission system.
The company’s electric distribution business earned $101.3 million in the second quarter, down more than 20% from last year primarily because of the sale of New Hampshire generation assets, higher property tax expenses and revenue decoupling for eastern Massachusetts customers. Distribution rate increases partially offset the decline.
Eversource earned $5 million from natural gas in the quarter, up 11% from the same period a year ago. Colder weather in 2018 increased natural gas sales in Connecticut, where sales are not currently decoupled. The company’s Aquarion Water unit, acquired in December 2017, earned $7.2 million in the second quarter.
Regulators’ Support
Harsh storms this spring underscored the need to accelerate resilience investments, spending supported by state regulators, the company said.
The Massachusetts Department of Public Utilities this spring approved $133 million of additional grid modernization investments for NSTAR Electric over the next three years, in addition to $100 million authorized in 2017 for two battery storage initiatives and initial electric vehicle infrastructure.
Eversource’s NSTAR Electric expects to begin construction on the nine-mile 115-kV line from Sudbury to Hudson, Mass. in 2019, with an in service date of 2020. | Eversource
The DPU also instructed NSTAR to file a three-year rate plan for continued grid modernization efforts beginning in 2021, which the company expects to submit sometime in 2020.
Growing demand in the Boston and Cambridge area prompted the company to upgrade several key substations.
On May 1, subsidiary Connecticut Light & Power’s new three-year rate plan took effect with an initial distribution rate increase of about $64 million. Two smaller increases will follow in 2019 and 2020.
Connecticut regulators also approved a base amount of $270 million per year in investments “aimed at making the grid more resilient, such as smart switches, enhanced tree trimming, upgrades to our poles and their integrity, and substation security,” Lembo said.
Eversource expects to file a separate grid modernization plan in Connecticut before the end of this year, he said.
Maintaining Margins
Eversource and its partner Orsted formed Bay State Wind for offshore wind solicitations but lost out this spring as Vineyard Wind won the 800-MW award for Massachusetts and Deepwater Wind picked up orders in Rhode Island and Connecticut. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)
Lee Olivier, Eversource executive vice president for business development, said the company did not want to dilute its earnings for the sake of winning.
“We put in a compelling bid with returns that were consistent with the current returns we have in transmission, and that was risk-adjusted,” Olivier said. “Now clearly others took a different view of that, perhaps took more risk and lower returns, but we’re not in this thing to win for the sake of winning.”
Eversource sees potential for up to 7,000 MW of additional offshore wind in the Northeast by the middle of the coming decade.
“We see the long-term offshore wind becoming a major component of the bulk power system in New England,” Olivier said. “In Massachusetts, you have an additional 800 MW of authorization; that will likely come in our opinion early next year. We will participate in that. You’ve got a bill in the Massachusetts legislature that would authorize another 1,600 MW of offshore wind.”
Connecticut on July 31 issued a request for proposals seeking 12 TW of clean energy, he said.
“It could be Class 1 energy [wind and solar] but also could be existing nuclear and hydro, so we see that as a potential opportunity for offshore,” Olivier said. “They have authorized essentially 2,400 MW of offshore wind that’s kind of a specific RFP to offshore wind and probably the first 800 MW will come up in late this year or early 2019.”
A forecasting error is prompting CAISO to procure a large volume of out-of-market resources for September under a special measure not invoked since the emergency shutdown of the San Onofre Nuclear Generating Station in 2012.
CAISO will solicit up to 1,434 MW of resources under its Capacity Procurement Mechanism, stakeholders learned during a call Thursday.
The procurement was prompted by the California Energy Commission’s July 10 publication of a revised load forecast showing the ISO’s balancing area will next month need 1,247 MW more in systemwide resource adequacy (RA) resources than originally projected, plus a 15% planning reserve margin.
Under CAISO’s Tariff, the ISO can invoke CPM in response to a “significant event,” defined as any “substantial event” or “combination of events” that “causes, or threatens to cause, a failure to meet reliability criteria absent the recurring use of a non-resource adequacy resource on a prospective basis.” A load forecasting error qualifies as such an event, Delphine Hou, the ISO’s manager of state regulatory affairs, said during the Aug. 2 call.
The CEC attributed the RA forecast error to its reliance on 2016 — rather than 2017 — energy demand data in its original 2018 monthly forecast. The forecast is provided to both CAISO and the California Public Utilities Commission for RA planning, which is managed by the commission.
| CEC
The error was discovered because of discrepancies between the CEC forecast and the monthly peak forecast CAISO produces for Western Electricity Coordinating Council planning, which the ISO used this year for its flexible capacity needs assessment. The revised CEC forecast aligns with CAISO’s projections, which had been benchmarked to 2017 load figures.
October a ‘Concern’
While this month’s CPM solicitation will focus only on procuring resources for September, Hou said the ISO will continue to evaluate the need to procure resources for October, which the revised forecast indicates has an even bigger RA need: 5,103 MW. Under CAISO rules, a CPM procurement has an initial term of 30 days, which can be extended by another 60 days if the “significant event” is likely to persist.
Pointing to the much larger October deficiency, NRG Energy Director of Market Affairs Brian Theaker asked, “Can you elaborate on what the ISO will be looking for and what conditions it will impose before making a decision as to whether to CPM for October?”
While October load will be lower, the ISO is “sensitive” to the possible continuation of Santa Ana winds during the month, fire concerns in Southern California and the impact of drought, she said. She also pointed out that some generators may begin entering maintenance outages during that month.
“So we want to at least see how September goes. … It is likely we will extend the significant event through October, but we wanted at minimum to get the word out for September,” Hou said.
“Why are we hearing about [the error] now? It seems like we would’ve had this information back in January,” said Nuo Tang, principal energy policy strategist at San Diego Gas & Electric.
Hou was diplomatic in her response.
“It took some time because we were having a lot of discussions with the CEC and the CPUC about how to think about the difference between the forecasts, and it was eventually recognized that because the original RA forecast seemed somewhat low for September. … Out of an abundance of caution, we really should sunshine this other forecast for CAISO to use under significant events,” she said.
| CAISO
“I think what you’re highlighting is that we don’t vet the system RA forecasts,” leaving CAISO stakeholders unable to compare the forecasts used for system RA and flexible capacity, Tang said. “Would that be a fair characterization?”
“Yes, that is fair, and in fact you pre-empted my very [next] line … which is [that] for future coordination, we’re definitely working very closely with the CEC and CPUC to review the RA forecast for next year,” Hou said.
Credit Where it is Due
Tang also asked why CAISO chose to invoke a CPM significant event instead of relying on exceptional dispatch, a shorter-term out-of-market procurement mechanism.
Hou said that CAISO officials were concerned that if they delayed procuring resources, generators without RA designations could end up selling to other buyers, including those outside the ISO, or go out on maintenance outages.
“What we landed on was that we would prefer to notify the market earlier to get more bids into the competitive solicitation process [in order] to have a deeper pool for the operators to be able to pull from, because this is a system issue. It’s not going to be as a restrictive as a local issue,” she said.
Eric Little, manager of wholesale and GHG market design at Southern California Edison, asked if the ISO would reduce the 1,434-MW procurement if any LSEs show above their minimum RA requirements for the month.
Hou said the ISO had not yet performed that analysis, but that it would credit the system for any LSE overages.
“And then once you do that, when you start to cost allocate, will there be any reduction in bills for those LSEs that showed over, so they’re only getting allocated for their portion of the additional CPM procurement performed by the ISO?” Little asked.
“It would credit against the total required amounts … but it would not be a credit against the cost allocation,” Hou said.
“So all other LSEs get the benefit that the one LSE showed long?” Little asked.
“Yes,” Hou replied.
Resources owners have until Aug. 25 to submit their offers to the ISO. Bidding is open to any RA eligible resources internal to the ISO balancing authority area. External, or “intertie,” resources are excluded from participation.
FERC has allowed MISO and PJM to implement the first of a two-phase fix to remedy the RTOs’ double-charging of congestion fees on pseudo-tied generation.
The commission on Tuesday approved amendments to the RTOs’ joint operating agreement addressing market-to-market (M2M) settlement and day-ahead coordination of pseudo-tie transactions (ER18-136-003, ER18-137-003).
Effective Aug. 1, the RTOs will calculate day-ahead LMPs “that reflect the real-time usage of the pseudo-tied resource,” FERC said. To model generator pseudo-tie impacts, the RTOs will calculate flowgate impacts based on amounts offered in the day-ahead market. The two will also modify settlement procedures to account for market flows and associated M2M congestion payments.
Until now, the RTOs have reflected the costs of relieving a binding flowgate in both their LMPs.
FERC agreed with the RTOs that the proposal “represent[s] an improvement over current practices” and will eliminate most of the overlapping congestion charges.
Separately, the commission also approved PJM’s Phase 2 revisions, which will modify its Tariff to provide for rebates for deviations from day-ahead commitments and remove the remaining overlapping congestion charges not addressed by Phase 1 (ER18-1730).
FERC required MISO to make periodic informational filings on the status of its Phase 2 efforts.
MISO and PJM worked throughout 2017 to remove the overlapping congestion charges soon after the first of several complaints about the issue were filed with FERC. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)
MISO reports 754 MW pseudo-tying into the footprint and about 2,142 MW pseudo-tying out.
Possible Interregional Projects
Meanwhile, the RTOs are working on two studies that could identify both small-scale and large-scale interregional transmission projects.
MISO and PJM are conducting a two-year coordinated system plan study to identify more expensive seams projects called interregional market efficiency projects (IMEPs) and a shorter-term study to identify smaller targeted market efficiency projects (TMEPs). (See MISO, PJM Plan 2 Studies for Seams Projects.)
The windows for submitting interregional project ideas opens Nov. 1 for PJM and Jan. 1 for MISO. Analysis on the project proposals will take place next year. MISO and PJM have yet to approve an IMEP.
At an Aug. 1 Interregional Planning Stakeholder Advisory Committee conference call, MISO and PJM staff said they would be ready to share this year’s TMEP study results during the October IPSAC. PJM interregional engineer Alex Worcester said the two are investigating 19 facilities — down from an original 61 — that have each amassed more than $1 million in congestion charges in 2016 and 2017 combined.
“Very soon here, we’ll be reaching out to the equipment owners of the 19 facilities flagged for further study to identify the limiting equipment and what the potential solutions might be,” Worcester said.
In September, MISO and PJM will begin testing the potential upgrades to see if they solve congestion.
The D.C. Circuit Court of Appeals on Tuesday upheld a 2016 FERC order that reallocated most costs for the Presque Isle system support resource agreements to consumers in Michigan’s Upper Peninsula.
The court denied in full petitions from a group of Michigan officials and load-serving entities, which included the state’s Public Service Commission and attorney general (15-1098). They argued that FERC’s reallocation of the SSR costs amounted to retroactive ratemaking. (See Michigan Groups Contest Presque Isle Cost Allocation.)
But the court said FERC was within its authority to order refunds to customers “who paid too much, funded by surcharges on customers who paid too little.”
“The reallocation at issue here does not constitute an impermissible retroactive rate increase,” the court said. “FERC reasonably determined that the prior rate methodology was unjust and unreasonable, and its reliance on certain evidence in reaching this conclusion was appropriate. Having … determined that a different methodology would comply with cost-causation principles, FERC had authority to order refunds and corresponding surcharges.”
The court added that while FERC is limited in power over the filed rate doctrine, its “remedial authority is otherwise expansive.”
The decision means Upper Peninsula ratepayers will bear nearly all SSR costs for the coal-fired plant. Under the original 2014 agreement, those costs were allocated across the American Transmission Co. zone on the Michigan-Wisconsin border, with Upper Peninsula ratepayers paying 8% and Wisconsin ratepayers responsible for the rest.
Following a complaint by Wisconsin’s Public Service Commission that the state was paying for most of the SSR but not receiving the majority of the benefits, FERC allowed MISO to shift 98% of the costs to LSEs in the sparsely populated Upper Peninsula. That change in part stemmed from NERC’s 2014 decision to separate the Upper Peninsula from Wisconsin into its own local balancing authority.
FERC at the time said it was unjust to allocate SSR costs on a pro rata basis to all LSEs in the ATC zone, despite historical practice. It said the costs must instead be allocated to LSEs that require the operation of the plant for reliability purposes. The Michigan LSEs and regulators countered that there was no new evidence or change in circumstances to justify changing ATC zone allocations.
The court was not persuaded by the Michigan argument. It pointed out that ATC was the only MISO zone subject to such a pricing zone methodology, with LSEs in other zones paying for reliability resources in proportion to their reliability needs: “For the rest of the MISO area, the Tariff provided only that reliability costs were allocated to the LSEs ‘which require the operation’ of reliability resources. In other words, SSR costs for all non-ATC service areas were allocated to the LSEs that actually benefited from the reliability resources.”
The court was also not swayed by the argument that FERC improperly relied on a preliminary MISO load-shed study in its reallocation decision.
“FERC’s recognition that more accurate data was necessary does not undermine its reliance on the preliminary study at the time of the complaint, or on the final data once the study was complete,” the court said. At any rate, the court said, the Michigan groups did not demonstrate that the old pro rata calculation was superior.
Cloverland Electric Cooperative, one of the Michigan petitioners affected by the surcharges, said through its attorney that it was disappointed with the decision.
“We … believe it expands FERC’s authority to assess retroactive surcharges beyond anything we have seen before. It also undermines the court’s rule about accepting post hoc rationalization of earlier FERC orders,” attorney Christine Ryan said in an email to RTO Insider.
The Western Energy Imbalance Market saw financial benefits soar to a record $71.2 million in the second quarter on surging exports of low-priced solar generation from California and the addition of new members Idaho Power and Powerex, according to a report from market operator CAISO.
CAISO earned the largest share of the EIM’s Q2 benefits on surging solar exports. | CAISO
Quarterly benefits were up more than 69% from the first quarter and 75% from the same period a year earlier. (See CAISO, PacifiCorp Gain Most EIM Q1 Benefits.) The EIM has yielded $401.7 million in gross benefits for its members since it began operation with PacifiCorp in November 2014, the ISO estimates.
The CAISO balancing area reaped $27.9 million in EIM benefits last quarter, with net exports exceeding 1.9 million MWh, nearly 10 times the volume of the next biggest exporters, NV Energy and Arizona Public Service.
“The second quarter of 2018 saw an uptick in energy moving out of California through the EIM, as the system experienced high levels of renewable production at a time in the season when temperatures are still cool and electric demand is moderate,” the ISO said in a statement.
PacifiCorp was the biggest beneficiary of CAISO’s renewable surpluses, importing nearly 1.1 million MWh of low-cost power over the quarter and earning $11.67 million in EIM benefits, the second-largest share among market members.
Trailing the two biggest earners were APS ($8.6 million), wind- and hydro-heavy Idaho Power ($7.8 million), NV Energy and Portland General Electric ($5.4 million each), Puget Sound Energy ($2.3 million) and Powerex ($2.3 million).
The report once again shows CAISO as a significant exporter of power during spring. The ISO said the EIM’s transfer capability allowed it to avoid curtailing 129,128 MWh of surplus renewable energy among its members during the quarter, up 93% from a year earlier. The avoided curtailments resulted in displacement of 55,267 metric tons of CO2 emissions and increased the volume of renewable energy credits, although the benefits calculation does not include the value of RECs, the ISO said.
The report also illustrated the extent to which certain EIM areas function as paths for wheel-through transfers, meaning the BA area is neither the source nor sink for large volumes of power. During the second quarter, the NV Energy and APS systems handled 828,282 MWh and 321,667 MWh of transfers between CAISO and the PacifiCorp-East (PACE) area, respectively, while the relatively small PacifiCorp-West system facilitated 386,788 MWh of north-south transfers among California, the Pacific Northwest and PACE. By comparison, just 127,205 MWh of energy were wheeled through CAISO over the period.
“As part of the EIM Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel-through volumes to assess whether, after the addition of new EIM entities, there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits,” the report notes.
A CAISO proposal to compensate EIM participants for wheel-through transfers last summer drew strong opposition from stakeholders concerned about the impact on the economic dispatch of generating resources. (See EIM Members Wary of Need for Wheeling Charge.)
The EIM’s gross benefits represent either cost savings for serving load or increased profits from merchant operations within the participating BAAs. The benefits calculation nets out inter-BAA transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
Idaho Power and Powerex began transacting in the EIM on April 5, days after the beginning of the second quarter. Sacramento Municipal Utilities District is slated to join the market in April 2019, followed by the Los Angeles Department of Water and Power, Salt River Project and Seattle City Light in April 2020.
FirstEnergy has reached what CEO Charles Jones called a “big milestone” in its process of unwinding from FirstEnergy Solutions, the bankrupt merchant generator that was until recently a subsidiary.
FirstEnergy’s Akron, Ohio headquarters
The FES bankruptcy settlement is now “definitive, comprehensive” and includes FES, its subsidiaries, FirstEnergy Nuclear Operating Co. and a committee for unsecured creditors, Jones said Wednesday. It builds on agreements FirstEnergy announced in April while reporting its performance for the first quarter. (See FirstEnergy Announces Mixed Earnings, Plan for FES Bankruptcy.)
“This definitive, comprehensive settlement defines and quantifies all of FirstEnergy’s obligations with respect to FES and FENOC,” Jones said.
The Aug. 1 announcement came as part of FirstEnergy’s review of its second-quarter performance, which exceeded both revenue and earnings expectations. The company reported quarterly adjusted earnings of 62 cents/share, which beat expectations by 9 cents, and revenue of $2.7 billion, which was $130 million over projections. Revenue increased $100 million compared to the same quarter last year, while earnings were up 18 cents/share year over year.
The settlement credits FES for nine months of its shared services costs with FirstEnergy and entitles the former subsidiary to continue purchasing the services through June 2020. FirstEnergy also agreed to increase its cash payment and cover costs for some FES employee benefits, which represent $218.5 million in additional costs incurred by FirstEnergy. FES is expected to file the agreement by the end of August as part of its bankruptcy case and to receive approval in September.
While FirstEnergy no longer has any merchant generation assets, Jones maintained his strong advocacy for financial supports for nuclear and coal units, saying that “the market policies in our country have severe flaws” and that he will “continue to be a loud advocate” for changes. Shuttering large-scale plants “is not going to be a good thing for the 6 million customers that I look out for,” he said. Jones said he remains “hopeful” that the U.S. Department of Energy “will eventually step forward to do something to stabilize” those plants.
Entergy accelerated its march towards becoming a “pure play” utility Wednesday, announcing the sale of its Pilgrim and Palisades nuclear power facilities for their accelerated decommissioning.
Financial analysts congratulated Entergy executives on the news during the second-quarter earnings call, where the company announced adjusted earnings of $1.79/share, beating Zack’s consensus estimate of $1.26 by 42%.
Palisades Power Plant | Entergy
CEO Leo Denault said the plants’ sale “solidifies” Entergy’s plans to fully divest itself of three of the four nuclear plants in its Entergy Wholesale Commodities (EWC) business.
Entergy’s share price jumped Wednesday by almost $2 — from $81.03/share at the market’s open to a high of $82.99 — before falling back to close at $81.82.
“This gives us a lot of capital, both financially and operationally, to focus on the growth of the utility,” Denault said.
Earlier this year, Entergy reached an agreement with Vermont state officials to sell its Vermont Yankee plant to NorthStar Group Services, which will handle the decommissioning. The plant was shuttered in 2015. The company is waiting on regulatory approvals to sell the plant’s holding company.
The transaction includes the transfer of the plants’ operating licenses, spent fuel and nuclear decommissioning trusts, to Comprehensive Decommissioning International, a newly formed joint venture between Holtec International and SNC-Lavalin.
Entergy received a “nominal” cash consideration in the deal, which must clear the Nuclear Regulatory Commission and other regulators.
“You could afford it if you could demonstrate the ability to close a nuclear plant,” CFO Drew Marsh told analysts. “The main objective was to move the risk to a party capable of [decommissioning] and doing it much quicker than we can.”
Pilgrim Nuclear Power Station | Entergy
Pilgrim, located in Plymouth, Mass., is scheduled to end operations by June 2019, and Palisades, in Covert, Mich., is to close in early 2022. The two plants date back to the early 1970s. They generate almost 1.5 GW of power between them and employ 1,200 people.
Entergy’s Indian Point nuclear plant in New York will close by 2021, according to an agreement between the company and state officials. Denault said there was “nothing to read” into not including Indian Point in the deal.
The company reported earnings of $245 million ($1.34/share), excluding a one-time tax benefit of 31 cents/share for the settlement of a 2012-2013 IRS audit. That compared to $410 million and $2.27/share a year ago.
EWC reported a loss of $57 million in the quarter. Entergy affirmed its 2018 consolidated operational earnings guidance range of $6.25 to $6.85/share.
FERC on Tuesday rejected NorthWestern Energy’s attempt to limit its liability for service interruptions to an ExxonMobil oil refinery in Montana, saying the provision was discriminatory (ER18-1715).
The utility had attempted to include the limitation in an unexecuted network integration transmission service agreement for ExxonMobil’s Billings refinery, saying it was needed because of the facility’s size, its “sophisticated equipment” that is “particularly sensitive” to loss of power, and that its continuous 24/7 operation lacks a backup power source.
The liability provision stated that neither party would be liable for “consequential, special, indirect or incidental damages whether arising in tort or contract, including a breach or alleged breach” of the agreement.
In 2016, ExxonMobil sued NorthWestern in state court, seeking $92.4 million in damages and lost profits over two power outages at the refinery that the oil company said resulted from NorthWestern’s negligence. The case was settled in December 2017 but terms were not released.
Billings Refinery | ExxonMobil
NorthWestern said the service interruptions — a 96-minute outage in 2014 and a 53-minute outage in 2016 — were caused by faults on its 50-kV radial lines feeding the refinery. It said the outages were triggered by problems on the distribution system of the city of Billings’ sewer plant. ExxonMobil’s suit alleged the utility was negligent because protective relays on its 50-kV lines were not coordinated with the relay system at the sewer plant.
FERC agreed with ExxonMobil that the liability provision was unduly discriminatory because NorthWestern was not seeking to impose such limits on other transmission customers, including three other oil refineries it serves in Montana.
“A transmission provider seeking commission acceptance of a non-conforming agreement bears a high burden to justify and explain that the non-conforming aspects of the agreement are not merely ‘consistent with or superior to’ a pro forma agreement but are necessary,” FERC said.
The commission rejected NorthWestern’s argument that ExxonMobil expected perfect, uninterrupted service. “ExxonMobil’s lawsuit against NorthWestern was not based merely on service interruptions, but the allegation that NorthWestern had ‘negligently failed to exercise reasonable care in designing, constructing, installing, managing, maintaining, inspecting and operating its electrical facilities and equipment,’” the commission said.
