In what may be one of its last earnings reports as an independent company, Westar Energy said it improved its third-quarter earnings over 2015 while falling two pennies short of Zacks Investment Research’s consensus forecasts at $1.09/share.
The Topeka, Kan.-based company reported net income of $155 million in the quarter, besting last year’s showing of $138 million ($0.97/share).
Westar Energy’s Jeffrey Energy Center | Westar
Westar said the rise was due to rate increases granted by the Kansas Corporation Commission this spring and an increase in corporate-owned life insurance income. (According to its 10-K filing for 2015, Westar reports as income increases in the cash surrender value and death benefits of its policies.)
Year-to-date earnings are $40 million above the $253 million earned through the same period third quarter of 2015. But the company said the higher revenue was “partially offset by a Southwest Power Pool assessment and higher expenses due to improving long-term grid reliability.”
Westar did not host a quarterly conference call because of its pending sale to Great Plains Energy. The company said it would not hold any future earnings conferences before the deal closes. (See Great Plains Energy, Westar Shareholders OK $12.2B Deal.)
The earnings announcement comes two weeks after Kansas regulators warned that they might block the merger because of staff’s conclusion that the companies’ filing lacked information on costs savings and what operations would continue in Westar’s Topeka headquarters (Docket No. 16-KCPE-593-ACQ).
A spokesperson for the two utilities said they did not expect the commission’s concerns to alter the merger’s spring completion target. The companies filed for joint application reconsideration Nov. 2, adding testimony from two Great Plains employees attesting to future customer savings and the reasonableness of the purchase price. However, Great Plains staff said the allocation of savings as a result of the merger is unknown and no final determinations have been made on what departments will remain in the Topeka office.
Great Plains recently struck a compromise with the Missouri Public Service Commission that requires the company to keep its capital structure and credit ratings isolated from Westar’s. The agreement also bans Great Plains from seeking increases in retail rates or capital spending because of the purchase. Great Plains initially maintained that the Missouri PSC had no jurisdiction over the sale.
CARMEL, Ind. — MISO will continue its current treatment of the sub-regional transfer limit in the Planning Resource Auction, both in deciding the initial limit and subtracting firm transmission reservations, RTO officials told the Nov. 2 Resource Adequacy Subcommittee meeting.
Under that same approach, the preliminary limits for the 2017/18 PRA are 984 MW for South to North and 3,000 MW for North to South, MISO Director of Forward Operations Planning Kevin Sherd said.
The RTO said it believes its approach — which deducts firm reservations from 2,500 MW for flows South to North and 3,000 MW for North to South — curbs the curtailment risk that use of non-firm contract paths could introduce.
Some stakeholders had argued for changing the value used in the initial limit and possibly reassessing the deduction of firm flows from the limit, saying the current approach was overly conservative as not all firm reservations are used.
MISO is also at the center of a FERC complaint filed by its transmission customers, which argue the limit is too strict and traps capacity in MISO South, driving up clearing prices. (See MISO Recommends No Change to Transfer Limits.)
The RTO is expected to publish the final sub-regional import and export limits before March 1. Sherd said MISO plans to continue to evaluate the sub-regional limit methodology for future auctions.
WPPI Energy engineer Steve Leovy said MISO should still consider alternatives to the calculation of the limit.
RASC liaison Renuka Chatterjee said subtracting firm reservations in the sub-regional limit is consistent with the treatment of other capacity import and export limits. Leovy said the treatment was not equitable since the RTO considers pseudo-ties in capacity import and export limits and does not model pseudo-ties in the sub regional limit.
No Change to External Resource Treatment, Either
MISO also is electing not to change the PRA’s treatment of external resources any earlier than other auction changes set for the 2018/19 planning year.
MISO Manager of Resource Adequacy John Harmon said after careful consideration, the RTO will not introduce a locational construct in the 2017/18 PRA. Instead, MISO is seeking a permanent solution as part of a larger bundle of auction changes, including a seasonal construct and separate forward auction, in time for the 2018/19 planning year. The RTO had suggested that it could roll out six new external zones in the capacity auction next year. (See “MISO to Move Ahead with Brattle Demand Curve for Forward Auction,” MISO Resource Adequacy Subcommittee Briefs.)
“We feel strongly that changes regarding a locational construct should be part of a larger reform and not a one-off change,” Harmon said. He added that MISO is looking to do its due diligence on a more comprehensive solution and avoid the “whiplash” of adopting one interim solution then distancing itself from the temporary solution by the time it formulates permanent rules.
Dynegy’s Mark Volpe said that while he appreciated the RTO’s desire to develop a permanent solution, external resources should not be on equal footing with resources in zones inside the RTO’s footprint.
MISO will continue discussion of external zone creation in 2017.
DALLAS — Having finally chased down Oncor, a quarry it has been after for two years, NextEra Energy has embarked on a charm offensive to ensure it successfully completes its acquisition.
The Florida-based company sent Senior Vice President Mark Hickson barnstorming across Texas last week to spread the message that Oncor is a perfect fit for NextEra’s focus on regulated investments and long-term power contracts. (See NextEra, EFH Seek to Reassure Texas PUC on Merger Deal.)
Speaking at the first of three Gulf Coast Power Association luncheons 48 stories up the Dallas skyline Wednesday, Hickson said Oncor has a lot in common with NextEra’s Florida Power & Light subsidiary.
“FP&L is part of the reason we’re one of the most admired companies for nine of the last 10 years,” Hickson said, pointing to the utility’s repeated listing among Fortune’s “Most Admired Companies.”
“We have the highest reliability [measures] and our bills are lower. Oncor shares those same commitments. The two of us coming together and sharing best practices is going to further our ability to provide that kind of service.”
Hickson also spoke before GCPA gatherings in Houston and Austin last week. Hickson’s tour followed the company’s Oct. 31 earnings announcement, in which it reported a 14% drop in third-quarter earnings.
Reducing Debt
Hickson said NextEra’s financial strength and access to Oncor’s cash flows will allow it to “reduce to zero” the utility’s nearly $11 billion debt and improve its credit ratings, thereby decreasing the cost of borrowing money, said Hickson, who heads the company’s corporate development and strategy functions.
FP&L already enjoys credit ratings of A or above from the three major ratings agencies. Oncor, which has been enmeshed in parent Energy Future Holdings’ bankruptcy since 2014, saw Moody’s bump its senior secured credit rating from Baa1 to A3 on the news of NextEra’s proposed acquisition. (See NextEra Reaches Deal for Oncor.)
Moody’s, Standard & Poor’s and Fitch Ratings have all since issued positive outlooks for Oncor.
“As our operations get less risky, the rating agencies aren’t so fussy about how much debt we have,” Hickson said.
NextEra announced in late July it had reached an agreement to acquire EFH’s 80.03% interest in Oncor for $18.4 billion. On Oct. 31, it announced an affiliate — created through a web of holding companies — would acquire the other 19.75% from Texas Transmission Holdings Corp. (TTHC), composed of a pair of private-venture funds, for an additional $2.4 billion. It has also acquired the remaining 0.22% interest owned by Oncor Management Investment.
That same day, NextEra and Oncor filed an application with the Public Utility Commission of Texas seeking its approval of the merger (Docket No. 46238). The companies expect the deal to close in the second quarter of 2017.
The application quickly drew intervention filings from an organization of Oncor cities and the Office of Public Utility Counsel. The PUC has placed the application on its Nov. 10 open meeting agenda.
Texas Investments
Hickson emphasized NextEra’s substantial investment — $8 billion over 15 years — in Texas through NextEra Energy Resources (NEER), its competitive energy subsidiary. The company’s Texas holdings include 26 wind farms (3,000 MW), 569 miles of natural gas pipelines in South Texas and 330 miles of transmission in western North Texas through subsidiary Lone Star Transmission.
Among the commitments NextEra has made, Hickson said, is to consolidate Lone Star with Oncor’s assets once the transaction is completed. Oncor, which already owns 119,000 miles of transmission and distribution lines and has more than 3 million meters, will keep its name and brand.
Oncor’s current ownership structure (L) and the organization chart under NextEra Energy’s proposed acquisition (R). | NextEra
“Oncor is a very sizeable company, but it will end up being 20% of” NextEra, Hickson said. The Texas utility’s addition will increase NextEra’s customer connections to 8.6 million and its regulated assets from $82 billion to $102 billion, he said.
“The trick in bankruptcy is to try and get as many creditors as you possibly can onboard with the transaction,” he said. “The easiest way to do that is to come as close as you possibly can to providing $11 billion of value.”
Under the merger agreement’s terms with TTHC, NextEra will pay 100% of the consideration in cash, leaving no debt at TTHC upon the merger’s close.
NextEra has been interested in acquiring Oncor since 2014, when EFH announced its bankruptcy. EFH and its creditors first supported Texas-based Hunt Consolidated’s bid for the utility in 2015, but that deal fell apart earlier this year when the PUC required conditions that changed the economics for investors.
NextEra says it will continue to maintain a ring fence around Oncor, not allowing it to incur additional debt and setting up a separate board that includes seven independent directors. Oncor CEO Bob Shapard will become the board’s chair, and E. Allen Nye Jr., the utility’s general counsel, will become CEO. Nye is the son of Erle Nye, the long-time CEO of TXU Corp. before EFH’s leveraged buyout.
NextEra also says there will be no “involuntary reductions” at Oncor, labor agreements will be honored and the utility’s operations will not conflict with NextEra’s other businesses.
Hawaii Setback
NextEra is hoping to burnish its image after failing to win Hawaii regulators’ approval in July for the acquisition of the state’s largest utility. The company also has come under criticism from clean energy advocates in its home state over a ballot initiative they say would block solar competition.
Hickson noted former Oncor sister companies Luminant and TXU Energy maintain larger shares of the ERCOT market than do NextEra’s other subsidiaries. He said Luminant accounts for 18% of ERCOT’s generation compared to NextEra Energy Resources’ less than 1%, and retailer TXU Energy has a 12% share of customers compared to NextEra’s 3%.
“Not only do we have a low market share of generation, we don’t have any generation currently interconnected to Oncor,” he said, going on to note the utility will seek the commission’s approval before connecting to any NextEra generation.
Hickson said Oncor and FP&L will operate independently of each other and there are no plans to grow Oncor outside of Texas.
“The thing we surprisingly found — the customer growth, the economic growth — was equal to, if not better than, that of Florida,” Hickson said. “We think there are a lot of opportunities for Oncor to grow within ERCOT.”
TCEH Rebrands Itself as Vistra Energy
On Friday, meanwhile, TCEH Corp., the parent of TXU Energy and Luminant, announced that it has rebranded itself as Vistra Energy. The company emerged from Chapter 11 bankruptcy as a tax-free spinoff from Energy Future Holdings. (See Luminant, TXU Energy Emerge from Bankruptcy.)
Vistra combines the vision of “an energy company preparing for the future” and the tradition of “an energy company whose lineage dates more than a century,” the company said.
“The Vistra Energy brand is intended to capture the full opportunity set before us, backed by a proud history, the industry’s best team of professionals, stellar operating assets and a strong balance sheet,” said Vistra’s recently installed CEO, Curt Morgan, a former operating partner at private equity firm Energy Capital Partners.
Long known as Texas Utilities and then TXU, the company was acquired in 2007 by EFH and its consortium of private-equity investors through a leveraged buyout. The deal went sour when energy prices collapsed, and EFH filed for bankruptcy in April 2014.
Vistra retains Luminant, the largest generator in the ERCOT market with 17,000 MW, and TXU Energy, the No. 1 retailer with about 1.7 million residential and business customers.
NextEra Shares Drop Following Q3 Earnings Release
NextEra announced Oct. 31 that profits fell 14% in the third quarter compared to last year amid higher overall expenses and declines at NEER.
The company reported net income of $753 million ($1.62/share) down from $879 million ($1.93/share) the year prior. Revenue decreased 3% for the quarter, down to $4.81 billion.
FP&L reported its earnings rose 5.3% to $515 million. However, earnings fell 19% to $307 million for NEER.
CEO Jim Robo said he was not concerned with NEER’s third-quarter decrease.
“There is no one in this industry that has the greenfield capabilities that we do,” he said. “Being in the wind business, 70% or 80% of the value creation is in the … greenfield development of those projects. No one in the industry has the pipeline that we do, that has the team that we do and the year in and year out track record. I worry about a lot of things, but [NextEra’s clean-energy development] is very low in my list of things that I worry about.”
NextEra shares, which have risen 22% in the past 12 months, closed Friday at $123.18, down $3.42/share after the earnings announcement.
VALLEY FORGE, Pa. — Members endorsed PJM’s 2016/17 winter weekly reserve targets, but not without first questioning if they could be reduced.
Part of PJM’s reserve requirement study, the winter targets are used by the Operations Department to coordinate generator maintenance outages in the cold months. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)
Stakeholders asked why the winter loss-of-load expectation needs to be near zero given that few zones within PJM are winter peaking. PJM’s Patricio Rocha-Garrido explained to the Operating Committee that the annual LOLE target of 0.1 — one day every 10 years — is cumulative throughout the year, so maintaining a near-zero level in the winter provides more leeway in the summer when load is higher.
“If we were to allow for a large risk in the winter, we would need a lower risk in the summer, which would require a larger reserve margin,” Rocha-Garrido said.
The targets will leave PJM with between 24 and 30% of its available reserves between December and February.
PJM Considering Changes to System Operations Report
After walking through the operations report for October, staff outlined ideas for redesigning the report to address additional topics. Among the subjects being considered for inclusion are topology changes, weather trends and seasonal comparisons.
Topology changes considered in the Operations Assessment Task Force’s winter 2016/17 preparedness study. | PJM
Stakeholders requested PJM increase its focus on reducing load-forecasting errors by providing more granularity about what factors are driving errors, such as how many and how often generating units are brought online in response to specific reliability contingencies. Staff said their ability to release information on specific units is limited because of the need to protect market-sensitive data.
“We’re talking about that internally,” PJM’s Joe Ciabattoni said.
Committee Endorsements and Recommendations
The OC made the following endorsements without objections or abstentions:
The 2017 day-ahead scheduling reserve requirement, which will be incorporated into Manual 13.
Updates to the TO/TOP matrix, an index between the PJM manuals and NERC reliability standards that specifies assigned and shared tasks for PJM and transmission owners. The changes, which the OC recommended be approved by the Transmission Owners Agreement-Administrative Committee, add new standards and delete inactive ones.
‘Cover to Cover’ Manual 13 Changes Better Reflect Reserve Requirements
PJM’s Chris Pilong presented a first read of extensive changes to Manual 13: Emergency Operations, on which the RTO will seek endorsement at the December committee meeting. Many of the changes are to clean up and streamline language regarding capacity and transmission emergency procedures.
“There are a lot of changes in here,” he said, but he acknowledged that many aren’t substantive. The biggest changes were the inclusion of more accurate Mid-Atlantic Dominion (MAD) reserve requirements. “The obligation can be met with non-MAD resources … if they’re deliverable,” he said.
Manual 14D Changes to Facilitate Periodic Surveys
PJM will be seeking endorsement at the December committee meeting on changes to Manual 14D: Generator Operational Requirements. The changes include the renaming of the section on fuel limitation reporting — now fuel and emissions reporting — a new section on periodic reporting and updates to the provisions on seasonal reporting. PJM’s Augustine Caven said the intention is to begin doing generating-unit surveys more often. “We definitely utilize [the survey] pretty heavily for operations purposes as we head into the winter,” he said.
Audit Goes Well
NERC and ReliabilityFirst Corp.’s planning and operations audit, which reviewed PJM’s compliance with 21 reliability standards and 48 requirements, concluded with no violations, two areas of concern and nine recommendations. There also were two open enforcement actions, PJM’s Srinivas Kappagantula said.
PJM is awaiting a draft audit report and will let stakeholders know about any changes it decides to make.
Kappagantula commended the transmission owners for their assistance in the process. “I wanted to think the TOs because we’ve reached out to you … for some of the data-sampling evidence that we requested,” he said. “That kind of reduced the onsite burden for us and the audit team … because they didn’t have to go through a bunch of documents onsite.”
OATF Study Finds No Major Concerns
While several major generation additions are coming online this winter, the Operations Assessment Task Force’s preparedness study found no significant concerns from its base case and N-1 analyses.
It found that off-cost generation redispatch and switching will be required to control local thermal or voltage violations in some areas. Networked transmission voltage violations were controlled by capacitors and all other voltage violations were caused by radial load, PJM officials said.
Stakeholders were concerned, however, that the study used hypothetical values in its calculations rather than real-world results.
Calpine’s David “Scarp” Scarpignato noted that units with dual-fuel capabilities weren’t differentiated from those without for pipeline failure contingencies. “This thing has a point to it, and I think you [should] set up the base case as accurate as possible,” he said.
PPL improved its third-quarter performance by 20%, reporting $473 million($0.69/share) in earnings, compared to $393 million ($0.58/share) for the same period last year. The company attributed the increase to higher rates for its Pennsylvania and U.K. operations and warm weather, which boosted demand.
PPL raised the bottom end of its 2016 earnings guidance by 5 cents to $2.30-$2.45/share based on slightly stronger-than-expected performance at its Pennsylvania and Kentucky utilities. The company, whose Pennsylvania utility benefited from a rate increase in January, intends to file rate hike requests in November for Kentucky Utilities and Louisville Gas and Electric.
With the exchange rate for the British pound falling in the wake of the U.K.’s decision to leave the European Union, PPL mitigated the financial impact on its U.K. operations by restriking its currency hedges.
“We remain confident in our ability to deliver on our long-term growth projections,” PPL CEO Bill Spence said during a conference call. “We expect to achieve 5% to 6% compound annual earnings growth from 2017 to 2020 and are targeting annual dividend growth of about 4% over the same period.”
Lagging Coal Units Drag down PSEG
Public Service Enterprise Group’s third-quarter earnings of $327 million ($0.64/share) were down 26% compared to the same period last year, when it reported $439 million ($0.87/share) in 2015. However, the company’s adjusted operating earnings of $444 million ($0.88/share) were up 10% year-over-year from $403 million ($0.80/share) in 2015.
The retirement of two coal-fired plants in New Jersey, a reduction in the value of its lease of two coal-fired plants in Illinois and lower hedges accounted for the difference, the company said.
“Net income was impacted by our decision to retire the Hudson and Mercer coal-fired generating stations in 2017,” said PSEG CEO Ralph Izzo.
Mercer Generating Station | PSEG
Warm summer weather staved off an even greater drop in the company’s performance, but it wasn’t enough to offset poor performance year-to-date thanks to unfavorably warm conditions during the winter. Izzo announced the company was shaving the top end of its 2016 guidance by 5 cents to $2.80-$2.95/share.
Its Public Service Electric and Gas subsidiary has reached a settlement with key parties for an extension of its existing landfill/brownfield solar program. The settlement provides for an investment of approximately $80 million to construct 33 MW of grid-connected solar generation over three years.
The PSEG Power generation subsidiary incurred $67 million ($0.13/share) in one-time charges related to the early retirement of the Hudson and Mercer generators.
Reduced energy hedges caused by lower fuel prices were partially offset by lower load-serving costs, but they still reduced net income by $0.02/share, the company reported.
The PSEG Enterprise/Other business group reported a net loss of $67 million ($0.13/share) after recalculating the residual values of its leases of two coal-fired plants in Illinois. The company recorded an after-tax impairment of $86 million on the leases “as a result of current and expected future market conditions.”
Unit Retirements, Tax Ruling Dampen Exelon’s Performance
Exelon’s third-quarter earnings fell 22% to $490 million ($0.53/share), down from $629 million ($0.69/share) in 2015. Adjusted earnings were up 11% year-over-year to $841 million ($0.91/share) from $757 million ($0.83/share).
While the company benefited from substantially better hedging and reduced nuclear decommissioning trust fund payments, those positives were outweighed by an unfavorable tax ruling, costs from the Pepco Holdings Inc. merger and plant retirements.
In September, the U.S. Tax Court ruled against the company in a $1.45 billion tax-shielding dispute with the Internal Revenue Service that stemmed from Exelon’s $4.8 billion sale in 1999 of six coal-fired plants in Illinois. The buyer, Edison Mission Energy, eventually sold four of the plants out of bankruptcy to NRG Energy, which leases two of them to PSEG.
While Exelon hasn’t decided whether to appeal the ruling, it is required to post a bond for the payment anyway. The company accounted for $199 million of the bill in the third quarter.
The quarter saw a shuffling of Exelon’s nuclear fleet as well, with the company announcing the early retirement of the Clinton and Quad Cities facilities and the purchase — pending regulatory approval — of Entergy’s James A. FitzPatrick station in New York.
Overall, earnings were bolstered by regulatory rate increases and favorable weather but partially offset by decreased capacity revenue, increased income taxes from a decrease in the domestic production activities deduction and increased nuclear decommissioning amortization, the company said.
Even with the write-downs, CEO Christopher Crane was bullish, announcing that the company was raising its 2016 guidance from $2.55/share to $2.75/share. The revision was based on improved performance of its Commonwealth Edison and recently acquired PHI utility subsidiaries.
Dominion Improves Finances
Dominion Resources had a good Monday last week, announcing both strong third-quarter results and the redistribution of its Questar acquisition that allowed the parent company to retire debt.
The company earned $690 million ($1.10/share) for the third quarter, compared with $593 million ($1/share) for the same period in 2015. It amounted to a 16% increase that the company partially attributed to favorable weather, lower capacity expenses, revenues from regulated growth projects and a lower tax rate. The performance was offset by share dilution and the absence of a farmout transaction, the assignment of part or all of a natural gas interest to a third party, which contributed $27 million to earnings a year earlier, the company said.
Dominion reported an operating earnings increase of 17% to $716 million ($1.14/share), compared to $611 million ($1.03/share) last year. The principal difference in the adjusted earnings was related to transaction costs associated with its acquisition in February of the pipeline company Questar.
The deal expanded Dominion’s service territory to Utah, where the natural gas deliverer has about 1 million customers. The sale closed in September, and by the end of October, Dominion had “dropped down” Questar to Dominion Midstream Partners, its master limited partnership, in a $1.7 billion deal that will allow the company to retire debt.
A federal appeals court has halted the award of clean energy contracts sought by three New England states while it considers an appeal filed by a New York-based clean energy developer (16-2946).
The 2nd U.S. Circuit Court of Appeals issued a temporary injunction on Nov. 2 in response to Allco Renewable Finance’s emergency petition.
Connecticut, Massachusetts and Rhode Island last month announced they would commence negotiations with developers of solar and wind projects totaling 460 MW. (See New England States Move Toward Renewables Contracts.)
Solar Energy Project Schematic | Allco
“Defendants-appellees are enjoined from awarding, entering into, executing or approving any wholesale electricity contracts in connection with the current energy solicitation during the pendency of this appeal,” the court said.
The three-judge panel expedited the appeal, set up a briefing schedule and ordered oral arguments in New York City as soon as the week of Dec. 5.
In its motion for the injunction, Allco tried to establish parallels with the U.S. Supreme Court ruling earlier this year in Hughes v. Talen, in which the court invalidated a contract between Maryland and a natural gas generator. Allco said the Maryland contract was “just like what Connecticut plans to do here.” (See Supreme Court Rejects MD Subsidy for CPV Plant.)
In the schedule set up by the states, negotiations are supposed to be completed by mid-January. The solicitation imposed a 20-MW minimum on the contracts that could be considered.
Allco said the 20-MW minimum is arbitrary and violates the Public Utility Regulatory Policies Act and the Federal Power Act. The company develops small solar qualifying facilities under PURPA.
The company filed a lawsuit against Connecticut officials after the multistate solicitation was announced last year. (See Allco Challenges New England’s Renewable Procurement Plan.) A U.S. District Court dismissed Allco’s challenge over the summer, saying the company lacked standing. The company appealed to the 2nd Circuit and then filed its emergency motion last month as the states’ solicitation process was ending.
Edison International will continue upgrading its transmission and distribution networks to take advantage of recently enacted legislation requiring California to reduce greenhouse gas emissions to 40% below 1990 levels by 2030, company officials said during their third-quarter earnings call with analysts last week.
Through its primary utility subsidiary Southern California Edison, the company is seeking to become a “key enabler” of California’s goals by facilitating the adoption of rooftop solar, energy storage and electric vehicle charging, CEO Pedro Pizarro said.
| Edison International
“Grid modernization, which, by the [California Public Utilities Commission’s] estimate, will be an ongoing effort into the middle part of the next decade, is a very significant part of the needed solution” for reducing emissions, Pizarro said. Edison’s quarterly profit increased by 11.1% to $419 million partly on higher revenues stemming from a revenue escalation mechanism included in a rate case approved late last year.
Pizarro noted that state officials are turning their GHG reduction efforts from the power industry — accounting for about 20% of current emissions — to the transportation sector, which is responsible for more than a third.
“We believe the significant new efforts across all sectors of the economy will be needed and many of these efforts will require significant electrification of sectors that today rely on fossil fuels,” Pizarro said.
Edison anticipates about $4 billion in yearly capital spending and $2 billion in annual rate base growth next year and into “the foreseeable future,” with nearly all of the investment on the “wire side” of the business, according to CFO Maria Rigatti.
“We believe it has lower investment opportunity risk as compared to utilities with a high percentage of growth tied to generation investment,” Rigatti said.
Edison is seeking regulatory approval to roll $200 million of “early-stage” grid modernization into its 2016-2017 rates, but the company might have to delay that investment until 2018 if it does not receive a timely decision from the CPUC. The spending would focus on replacing aging infrastructure, adding new customer connections, upgrading information technology, maintaining SoCalEd’s generators and modernizing the utility’s distribution system to accommodate the growth of distributed energy resources.
The company’s $1.1 billion West of Devers transmission project — which will upgrade existing 220-kV lines to double-circuit lines — was approved by the CPUC in August but has been challenged on environmental grounds.
Edison has also proposed alternative designs — which require “significant re-engineering” — in the CPUC’s review of the company’s $600 million Mesa substation project, which would upgrade the existing facility in the western Los Angeles Basin from 220 kV to 500 kV.
“These permitting and approval challenges are increasingly typical of transmission planning and part of the process, although the need for these projects is not affected by the regulatory delays that impact initial timing,” Rigatti said.
Edison continues to engage with Mitsubishi Heavy Industries in arbitration over steam generator design flaws that forced the permanent closure of San Onofre nuclear generating station in 2013. Edison shares ownership of the plant with San Diego Gas and Electric.
In the event of a favorable outcome for the plant’s owners, SoCalEd will refund to its ratepayers 50% of any proceeds that exceed legal expenses, Pizarro said. The rest of the money would be used to pay down or reduce the short-term debt associated with the utility’s capital spending program.
Edison anticipates receiving a decision on the matter later this year or early next year.
ERCOT’s latest seasonal forecasts indicate the ISO will continue to have more than enough generation capacity to meet demand into next summer, continuing a recent pattern of rosy forecasts.
ERCOT Control Room | ERCOT
According to the winter Seasonal Assessment of Resource Adequacy (SARA), ERCOT expects to have almost 82,000 MW available December to February, more than enough to meet an anticipated winter peak of 58,000 MW. That would exceed the ISO’s winter peak record of 57,265 MW, set in February 2011.
The preliminary spring SARA (March-May) also projects nearly 82,000 MW of available capacity and a seasonal peak of 58,000 MW in May. The assessment takes into account the expected spring generation outages for routine maintenance; the final spring SARA report will be released in March.
Asked about the recent positive forecasts, ERCOT Senior Director of System Planning Warren Lasher said, “I believe we’re in a period right now where we have adequate resources. The emphasis here is proving that assessment back to consumers.”
“We’ve added resources, but we’ve also modified our load forecast methodology,” said Pete Warnken, ERCOT’s manager of resource adequacy. “I believe it’s a more accurate, more on-target forecast.”
Lasher and Warnken both cautioned that continued congestion in the Lower Rio Grande Valley, which resulted in conservation calls in early October, remains a subject of concern. The 524-MW Frontera combined cycle plant’s withdrawal from the ERCOT system Oct. 1 to dispatch into the Mexican market has complicated the task of meeting demand along the U.S.-Mexico border.
“Our current expectation is we won’t have a similar call for conservation,” Lasher said.
Weather is not expected to play a factor this winter. Senior Meteorologist Chris Coleman said Texas hasn’t seen an extremely cold day since Feb. 2, 2011, and its coldest month in recent history came in December 1989. Lasher warned a few very cold days could drive up demand during early morning and evening hours.
ERCOT serves about 24 million customers and 90% of Texas’ load. The ISO has added 600 MW of new capacity since the preliminary winter SARA was released Sept. 1, and an additional 800 MW are expected to be in operation by December. New natural gas, wind and solar resources are expected to provide another 1,700 MW of capacity for the spring.
VALLEY FORGE, Pa. — PJM has determined that it must keep a loop flow in place with NYISO when the Con Ed-PSEG “wheel” ends next year, but that by 2021 that “operational baseflow” will be reduced to zero.
Presenting at the Market Implementation, Operating and Planning committees last week, PJM staff explained that anything less than a 400-MW loop flow on the current system would “impact” system reliability and minimize transfer capability across the seam.
The baseflow is “allowing us the flexibility to operate the system until we get some experience operating without the wheel in place,” PJM’s Ken Seiler said.
Staff also said they don’t expect “widespread congestion impacts” outside of the northern New Jersey and southern New York area.
Dave Pratzon of GT Power Group asked that PJM provide an annual review to see if maintaining the 400-MW operational baseflow assumption was necessary for reliable, economic system operation.
At the Planning Committee meeting, Citigroup Energy’s Barry Trayers said NYISO has been explaining that the 400-MW loop is necessary to keep PSEG North’s territory from “voltage collapse” and asked if that was accurate.
“We’re going to have to circle back with New York,” PJM’s Paul McGlynn said. “We haven’t seen anything like that in our analyses.”
He said they would also check with PJM’s Operations Department to determine if they’re seeing “anything close to that.”
Manual Updates Endorsed
The Planning Committee endorsed updates to three manuals.
In Manual 21: Rules and Procedures for Determination of Generating Capability, an acceptance test is now required for newly constructed units for which a summer/winter verification test after the unit is in service previously was sufficient. “Not many people are doing this so what we have to do is go back and look at your verification tests,” PJM’s Jerry Bell said. “You have to do this before you can cap-mod your unit up,” he added, using the shorthand for a notice of a capacity modification.
In addition to an administrative cleanup, the changes add detail to the testing requirements, including an expanded section on capacity interconnection rights. It also adds rules for non-hydro storage and removes class average information for wind and solar resources that will instead be posted to the planning resource page on PJM’s website.
Manual 14B: PJM Region Transmission Planning Process is being amended to remove from the capacity import limit (CIL) procedure references to the Reliability Pricing Model, PJM’s capacity market design. Starting with the 2020/21 delivery year, the CIL will not be applied as part of the capacity process. Instead, the limits will be considered during interconnection studies for new transmission service requests, part of new study procedures approved in early 2016.
PJM’s Michael Herman explained how the CIL will be calculated and used to determine that the import capacity is sufficient to support PJM’s capacity benefit margin (CBM), the portion of the RTO’s emergency import capability that is deducted from total transfer capability to determine available transfer capability (ATC). CBM is reserved to import capacity assistance from external areas under emergency conditions.
Section G.11 states that the CIL “is used to confirm that import capability into the PJM system is sufficient to support the PJM [CBM] as well as confirmed long-term firm transmission service.”
American Municipal Power’s Ed Tatum questioned how “sufficient” is determined. McGlynn explained there is an annual study in accordance with NERC reliability standards. Stakeholders endorsed the intent of the manual changes but asked that that explanation be written into the revisions. Herman confirmed that they will be.
In Manual 14A: Generation and Transmission Interconnection Process, the word “interconnection” is being replaced with “new service” to ensure cost allocation will occur for all projects. The change addressed needs identified at special PC sessions regarding new service request cost allocation and study methods.
Too Soon to Include CO2 Pricing in Market Efficiency Analyses
PJM staff have decided not to incorporate CO2 prices into their analysis of market efficiency transmission projects, saying that accurately projecting the likely price depends heavily on how — or whether — states comply with EPA’s Clean Power Plan.
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“States have seven different compliance pathways and their choices will have very different impacts on resource entry and exit,” PJM said in a presentation.
“Right now, there’s not a clear driver that could be built into the market efficiency scenario,” PJM’s Muhsin Abdur-Rahman told the PC.
Load Voices Concern over Transmission Repair Costs
During a review of immediate-need projects, members of the Transmission Expansion Advisory Committee questioned the proposed solutions for the loss of the South Butler-Collingwood 345-kV line in American Electric Power’s transmission zone, which would result in a loss of more than 300 MW of load.
AEP Transmission Zone | PJM
The region, an industrial zone in which continued growth is expected, is partially served by local 69-kV lines built in the 1950s with wood poles and distribution-class cross arms. A wholesale distribution cooperative served by such 69-kV lines has experienced multiple forced and momentary outages recently, planners said.
One option, which was estimated to cost $76.5 million, would add a new 345-kV switching station near Steel Dynamics Inc. (SDI) in Butler, Ind., a tap of the Rob Park–Allen 345-kV line and the addition of about 17 miles of a double-circuit 345-kV line.
PJM recommended a second option, estimated to cost $108 million. It would add new 138-kV and 345/138-kV stations and reconstruct sections of the Butler-North Hicksville and Auburn-Butler 69-kV lines as 138-kV double-circuit lines. In addition, the 138-kV circuit between Dunton Lake and the SDI Wilmington substation would be reconductored.
When AMP’s Tatum asked why the project was needed immediately and could not be included in a competitive window, McGlynn explained that a data error had recently been found in the modeling, revealing that there is an overload on the line currently.
Tatum said AMP “has a problem moving forward with this.”
Carl Johnson of the PJM Public Power Coalition pointed out that this project is “exactly the kind of issue” that caused the formation of the Transmission Replacement Processes Senior Task Force. “You’re probably making the right choice, but … you couldn’t have handed us a better example,” he said.
Reimbursement through this process would distribute the costs throughout the RTO, despite the fact that part of project would replace aging infrastructure, which should stay with AEP, Johnson said.
“We’re seeing more and more examples of this,” he said.
Looking over all of the projects, Tatum commented that, “It looks like we have $520 million of projects that are immediate need. … I don’t know what we can do in the planning process to get out in front of that.”
“If we were all doing our jobs perfectly and properly, we wouldn’t have any immediate need projects,” McGlynn conceded.
Tatum then pointed out seven projects whose cost estimates had ballooned from $205 million originally to $372 million, about an 82% increase.
“We might need to do better than an 82% increase, and I’d like to see if PJM could help us with that,” he said. “I hope that as we move forward and continue enhancing our planning process and ability that our cost estimates might be a little bit more robust at the initiation of a project.”
SPP’s recent trend of sending market-to-market payments to MISO continued in September, but that trend figures to reverse itself in the months that follow.
SPP’s Gerardo Ugalde told the Seams Steering Committee on Wednesday that the RTO sent $1.66 million to MISO as a result of temporary and permanent flowgates with the ISO. It was the third straight month the M2M process has resulted in a payment from SPP to MISO.
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“We don’t foresee this showing up in November,” Ugalde said. “This seems to be a seasonal change, where the flows flip.”
Temporary flowgates resulted in 591 hours of binding M2M and $1.14 million in charges from SPP to MISO; permanent flowgates added another $517,000 in M2M charges to the RTO as a result of 441 hours binding.
SPP Interregional Coordinator Adam Bell reminded stakeholders of a Nov. 30 deadline to submit projects they would like to see included in a potential joint study with the ISO as part of the 2016 Coordinated System Plan. (See “SPP, MISO Shared Joint Study Needs List,” SPP Briefs.)
Bell said initial discussions have been held with MISO to use the targeted study as the “foundation” for a “much broader study” next year. He said progress has been slow in developing coordinated system plans with both the ISO and Missouri-based Associated Electric Cooperative Inc.
Vistra combines the vision of “an energy company preparing for the future” and the tradition of “an energy company whose lineage dates more than a century,” the company said.
