A special inspector for the Nuclear Regulatory Commission is expected to arrive at the Indian Point station Thursday to conduct an inquiry into why elevated levels of tritium were found in groundwater under the plant.
Indian Point Nuclear Power Plant (Source: Wikipedia)
Plant owner Entergy reported the finding to New York state officials after routine monitoring found elevated levels in three out of 40 wells at the site in the Hudson Valley, about 40 miles north of New York City.
“Although we don’t have an exact cause, we believe its likely cause is activities done in preparation for an upcoming refueling operation,” Entergy spokesman Jerry Nappi said Monday.
Early indications point to a sump pump failure that allowed contaminated water to leach into the holding wells, according to an NRC spokesman.
The latest incident provides more ammunition for Gov. Andrew Cuomo, who has sought the plant’s shutdown and who ordered state regulators to investigate its operations after two unplanned outages in December. (See NYPSC Denies Entergy Arbiter in Indian Point Investigation.)
Cuomo ordered the state departments of Health and Environmental Conservation to begin investigations of the incident.
“This latest failure at Indian Point is unacceptable,” Cuomo said in a statement on Saturday.
“This failure continues to demonstrate that Indian Point cannot continue to operate in a manner that is protective of public health and the environment,” the governor said in the letter he wrote to the state commissioners.
Entergy said there is no danger to the public or its workers.
“While elevated tritium in the ground on-site is not in accordance with our standards, there is no health or safety consequence to the public, and releases are more than a thousand times below federal permissible limits,” the company said in a statement.
NRC spokesman Neil Sheehan repeated that ground water contamination offers no threat to the public or workers on the site.
The groundwater will eventually leach into the Hudson “where it will barely be detectable and will pose no threat to the public water supply,” Sheehan said.
Three permanent inspectors are stationed at the plant and they will offer support to the special investigation. If additional action is warranted, NRC will expand the investigation.
“I am urging NRC to fully investigate all the wells surrounding Indian Point and determine why the pump was not working, how far the contamination spread, how to prevent future spills and more importantly determine if local residents’ health and safety are at risk.” U.S. Sen. Charles Schumer (N.Y.) said in a statement.
Foes of a natural gas pipeline that would connect Pennsylvania natural gas fields to New York and New England power markets went to federal court on Friday to stop the project.
Crew installing silt fence (Source: Cardno)
Environmental groups asked the 2nd Circuit Court of Appeals to set aside the three FERC orders that approved the $700 million, 650,000-dekatherm Constitution Pipeline.
FERC in late 2014 approved the 124-mile pipeline, granted rehearing in January 2015 and denied rehearing of its order on Jan. 28. (See FERC Upholds Constitution Pipeline OK.)
The group Stop the Pipeline notified the company of its intention to sue in the FERC docket (CP13-499).
Separately, Catskill Mountainkeeper, the Clean Air Council, Delaware-Otsego Audubon Society, Riverkeeper and the Sierra Club asked for review of the original approval and denial of rehearing (16-345).
FERC said the pipeline’s benefits would exceed its impacts on the environment and would supply gas to constrained energy markets in eastern New York and New England.
The commission granted partial permission to Constitution to proceed with limited tree felling along the pipeline route in Pennsylvania but not in New York, where state officials are still conducting environmental reviews. (See New York AG: No Tree Cutting for Pipeline Without Water Quality Permits.)
SPP staff called FERC’s acceptance last week of SPP’s regional cost allocation methodology for Order 1000 interregional projects a “fantastic order” that sets the stage for a redrafting of its previously rejected non-Order 1000 proposal.
In separate orders, the commission on Feb. 2 approved SPP’s use of its highway/byway methodology in allocating Order 1000 interregional costs with MISO and the Southeastern Regional Transmission Planning (SERTP) process. The orders accepted compliance filings revising the RTO’s joint operating agreement with MISO (ER13-1937) and its processes with SERTP (ER13-1939).
“The good thing is, it gives us a little clarity,” SPP attorney Erin Cullum told the Seams Steering Committee Feb. 3. “It does at least let us know this type of cost allocation is just and reasonable for interregional projects.”
Brett Hooton, SPP’s senior interregional coordinator, said the rulings mean Order 1000 interregional projects will be regionally allocated using the highway methodology process for any voltage level greater than 100 kV.
The RTO’s rules for projects within SPP designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a region-wide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.
Staff’s Tariff revisions defined a non-Order 1000 seams project as one operating at 100 kV or above and costing at least $5 million. They proposed a default regional cost allocation for such projects.
“We had many questions when we got that order,” Cullum said, referencing the non-Order 1000 seams projects. “This lets us know what is just and reasonable as we go forward with non-order 1000 seams projects filing. It puts us in position to have a better conversation with FERC.”
“Having the order … helps us out quite a bit. We will have a frank discussion with FERC staff,” said SPP’s Sam Loudenslager, who is managing the non-Order 1000 seams docket.
SPP has to make an additional compliance filing on each order within 30 days. “They will both be fairly minimal and for the most part have been prescribed in detail by FERC,” Hooton said.
SPP Nears JOA with SaskPower
SPP is close to formalizing a JOA with Saskatchewan Power, the principal electric utility in Saskatchewan, Canada, months after the two completed the RTO’s first international transaction.
Hooton said the RTO hopes to have a completed JOA “in a week or so.” He said SPP’s agreement with SaskPower will be different than its JOAs with other seams neighbors, primarily because SaskPower is a planning region and a vertically integrated utility.
Once the JOA is filed, both parties will have to obtain certificates from their respective national energy departments in order to export power to each other.
In mid-December, SaskPower was able to “facilitate power” during an emergency situation in North Dakota, using its existing interconnections in the state. (See SPP, SaskPower Make First International Trade.)
The JOA will coordinate data exchange, planning, scheduling and “other aspects of transmission operations and planning in accordance with applicable NERC reliability standards, industry standards and good utility practices.” SPP and SaskPower will establish operating and planning committees to administer the agreement’s actions.
SPP, MISO Planning for Joint Stakeholder Meetings
SPP, MISO and their stakeholders will gather at SPP’s Little Rock, Ark., headquarters for a pair of meetings March 8-9 on seams issues and potential interregional projects.
The two RTOs will first conduct a JOA joint stakeholder meeting to discuss market-to-market and other issues. The RTOs are drafting a memorandum of understanding describing “guiding principles” to improve the M2M process and reduce congestion costs along their seams. (See SPP, MISO Working on M2M Improvements.)
Hooton told the committee the meeting “is the only opportunity we have to gain input from our stakeholders on the principles.”
The RTOs’ Interregional Planning Stakeholder Advisory Committee will then gather March 9, giving stakeholders an opportunity to provide their input on whether a joint study is needed over the next 18 months and to suggest issues to study. Members are welcome to submit “anything that doesn’t have a potential solution” already identified, Hooton said.
The SPP-MISO JOA calls for an “issues” meeting in those years when a joint study is not being undertaken. A planning committee comprising SPP’s David Kelley and MISO’s Eric Thomas will then decide whether an interregional study is needed. The 2015 joint study failed to reach agreement on interregional projects.
SPP staff said a joint study will be conducted this year with Associated Electric Cooperative Inc., a group of six regional generation and transmission cooperatives based in Springfield, Mo.
SPP Says Better Seams Metrics Coming
SPP staff promised the seams committee “better metrics” on seams flow data during its monthly review of seams congestion and M2M issues.
“We’re not comfortable that [the metrics] tell the whole story,” Kelley said. “The data comes from a lot of different places, and they’re not synched up.”
M2M settlements between SPP and MISO have become less volatile since the process started last March, when MISO compensated SPP $4.34 million for the latter having to re-dispatch generation to lessen congestion on flowgates. SPP has netted $8.75 million from the M2M process through Jan. 18.
MISO is drafting Tariff language to address under what conditions it can reopen or extend its day-ahead market when necessary to address technical problems.
The RTO occasionally delays the close of the market, but rules for doing so are implied and have never been spelled out in the Tariff.
MISO is looking to clarify Tariff section 39.1.1, which governs the day-ahead energy and operating reserve market trading deadline. The RTO said it’s in need of language that “clearly establishes MISO’s ability to reopen/extend the market [or] the conditions under which MISO would do so.”
“Currently the Tariff language doesn’t really address this,” MISO’s David Savageau told the Market Subcommittee last week.
MISO staff is proposing that it be allowed to reopen or extend the close of the market when “unanticipated events” occur. In a draft, MISO said the conditions would have to be such that they interfere with a transmission provider’s ability to receive or process bids, offers or interchange schedule data. The RTO said it would also consider delaying close of market when a transmission provider’s bid, offer or interchange schedule data is “plainly inaccurate” and likely to hinder their ability to deliver using the market.
MISO also inserted a provision allowing it to extend market hours when missed or incorrect bids, offers and interchange schedule data “are otherwise likely to have a widespread negative impact on the results of the day-ahead energy and operating reserve market, in a manner that adversely threatens or affects the reliability of market operations or of the transmission system.”
MISO said it would post a notice any time it extends the trading deadline. No expected date has been set for MISO to adopt the proposed Tariff additions.
Soon-to-be Eliminated Demand Response Working Group Works on New LMR Deployment Rules
The Demand Response Working Group has completed a review of remaining open issues ahead of its disbanding as part of the stakeholder redesign, said group chair DeWayne Todd. One of those open issues is a change to how load-modifying resources (LMR) will be deployed this summer.
Under emergency pricing beginning in July, market participants with multiple LMR assets will have to identify which asset will be deployed at least 10 minutes prior to an LMR event. Asset owners formerly were required to identify the asset within 24 hours after the event.
Michael Robinson, MISO’s principal adviser of market design, said the RTO is having its legal team look into whether the new rules would necessitate Tariff changes. “We just started the process of having legal look into it. Because the LMR language was written so long ago, there’s nothing in the Tariff to address deployment,” he said.
Last August, FERC accepted MISO’s Tariff revisions to institute emergency pricing (ER15-1776). A vendor working with MISO found that calculating emergency pricing requires information on LMR deployment at the resource pricing node and wouldn’t work with MISO’s current treatment of LMR resources.
MISO Works ‘Triple E Flags’ into Real-Time Offer Enhancements Project
MISO will be including excessive energy exemption (EEE) requests into its real-time offer enhancements project.
The EEE process replaced the uninstructed deviation calculations and penalties. MISO dispatchers can waive excessive or deficient energy deployment charges by setting the EEE “flag.”
“This is under construction, but the project is still scheduled to be implemented in July,” said MISO Senior Real Time Operations Engineer Steve Swan during a presentation. He said that MISO is primarily adding the exemptions so offer overrides get into the five-minute dispatch sooner and automatically, although the option for manual entry would still exist.
MISO plans to test the software in March through June and take the project live sometime in July. Meanwhile, real-time offer enhancements will be the subject of a technical workshop on Feb. 25.
MISO-PJM Interface Pricing Project Heads to Final Four
MISO has until March 1 to decide which option it wants to take concerning pricing enhancements and interchange modeling with PJM.
Dhiman Chatterjee, MISO’s senior manager of market analysis, outlined the next steps for MISO and PJM’s interface pricing project, which is intended to settle longstanding differences in the way the two RTOs price transactions at interface buses. The goal is to end the double-counting that leads to overcharging during congestion contributions and overcompensating when a constraint is relieved.
Chatterjee said four options exist:
The MISO Monitor’s original proposal that favors a centroid-to-centroid approach where the non-monitoring RTO excludes a transaction’s impact on the constraint;
PJM’s original proposal that makes use of a 10-bus common interface;
A MISO and PJM collaborative approach in which financial transmission rights and day-ahead limits are modified if needed to reflect a transaction’s impact; and
A MISO incremental proposal suggested by MISO’s Monitor in which the centroid-to-centroid method is used alongside MISO excluding a transaction’s impact on PJM constraints while PJM preserves its common interface definition.
“We have all these options on the table, so we need something to compare them against. We did work a lot on developing a baseline,” Chatterjee said.
Chatterjee said if the RTOs decide to go with the collaborative approach, no Tariff changes would be needed, but MISO’s commercial model would be adjusted. MISO Monitor David Patton said he preferred the incremental approach over the collaborative approach because it could solve the issue completely.
Although MISO has until March 1 to make a decision, the RTO said it would have the analysis finalized and be ready to provide a recommended option before a Feb. 18 joint and common market meeting of PJM and MISO stakeholders. MISO said it would follow that up with discussion on the topic at March meetings of the Seams Management Working Group and the Financial Transmission Rights Working Group.
MISO Seeks Leaders for New Resource Adequacy Subcommittee
MISO continues its march toward a revamped stakeholder process. A system-wide note went out requesting leaders for MISO’s newly created Resource Adequacy Subcommittee. Stakeholders and MSC leadership said the portion of the MSC’s charter dealing with capacity needs to be revised so it doesn’t intersect with the RASC’s charter, a point that was raised at January’s Steering Committee meeting.
“There was a pretty robust discussion at the Steering Committee. I imagine that will continue throughout the new stakeholder process,” said Kent Feliks, chair of the MSC.
Feliks said there has also been discussion among the MSC on whether the Steering Committee should absorb the responsibilities of the Data Transparency Working Group and the Stakeholder Governance Working Group.
He also said the topics dissected in the Data Transparency Working Group could be a little dense for the Steering Committee to come in cold. “We don’t want to lose the work that we’ve done in that group, but there’s concern that the Steering Committee isn’t the appropriate place to hold those discussions,” Feliks said.
Jeff Bladen, MISO’s executive director of market design, said the RTO is still working on common issues that may be recurrent in separate meetings. He said the informational forum may be a good outlet for topics that can be examined in multiple groups and committees. “There’s also been the discussion that the Steering Committee will help guide issues to the appropriate venue,” he said.
Meanwhile, Bladen is calling for stakeholders to offer their input on next steps on energy storage issues.
Bladen also said MISO may have to accelerate its timeline for addressing energy offer caps in light of FERC’s Jan. 21 order proposing a $1,000 “soft” offer cap for all RTOs’ day-ahead and real-time markets. (See FERC Proposes Uniform Offer Cap Across RTOs.)
Comments on the Notice of Proposed Rulemaking are due 60 days after its publication in the Federal Register. MISO was expecting to begin conversation on energy offer caps in May.
Despite mild temperatures that dampened its fourth-quarter performance, Eversource Energy posted 2015 results that easily bested its previous year’s earnings.
The company also increased its quarterly dividend 6.6% to $0.445/share.
Eversource reported 2015 earnings of $878.5 million ($2.76/share), compared with 2014 earnings of $819.5 million ($2.58/share). Full-year results included after-tax integration costs of $15.8 million in 2015 and $22.1 million in 2014 from the 2012 merger of NSTAR and Northeast Utilities. Excluding those costs, Eversource earned $894.3 million ($2.81/share) in 2015 and $841.6 million ($2.65/share) in 2014.
In the fourth quarter, the company reported earnings of $181.8 million ($0.57/share), compared with $221.6 million ($0.69/share) in 2014.
Eversource projected 2016 earnings per share of between $2.90 and $3.05 and long-term EPS growth through 2019 of between 5 and 7%. The company reduced its long-term EPS growth rate from the previous 6 to 8% primarily because of the impact of the extension of bonus income tax depreciation through 2019.
“We invested the most dollars ever in New England’s energy delivery systems, achieved our best ever level of electric service reliability, connected record numbers of new natural gas heating customers, posted very strong financial results and made significant progress in addressing the region’s energy infrastructure challenges,” CEO Thomas J. May said.
The company is an investor in the Northern Pass transmission project to bring Canadian hydropower into New England and Spectra Energy’s Access Northeast natural gas pipeline. Both projects are undergoing regulatory review.
FERC turned aside attempts to block Spectra Energy’s Algonquin pipeline expansion, allowing construction to continue on the 37-mile span, which is expected to be completed in November.
The commission rejected requests for a rehearing and a stay by eight parties, primarily impacted landowners, municipalities and environmental interests (CP14-96).
The ruling reiterated the commission’s order last March granting Algonquin Gas Transmission a certificate of public convenience and necessity for the Algonquin Incremental Market (AIM) project in New York, Connecticut, Rhode Island and Massachusetts.
The challengers complained that FERC erred in not ordering an evidentiary hearing and said it violated the Clean Water Act. They also raised questions over the staff’s National Environmental Policy Act analysis and whether the project was required “by the public convenience and necessity.” (See related story, Dueling Studies Dispute Need for More Pipelines in New England.)
The commission found the written record was sufficient for it to act and said a “trial-type hearing” was unnecessary. It said its March order complied with the CWA, despite objections from several applicants that the “conditioned certificate order” came before state agencies in Connecticut, Massachusetts and New York had issued their water-quality certifications.
“The commission routinely issues certificates for natural gas pipeline projects subject to the federal permitting requirements of the CWA,” FERC said. “The practical reason is that, in spite of the best efforts of those involved, it may be impossible for an applicant to obtain all approvals necessary to construct and operate a project in advance of the commission’s issuance of its certificate without unduly delaying the project.”
The commission affirmed its original finding that Algonquin demonstrated a need for the AIM project, pointing to “executed long-term firm transportation agreements” with its 10 project shippers for the expansion’s full capacity.
The AIM project will include six new compressor units and have an expected capacity of 342,000 dekatherms/day.
Spectra Energy said the Algonquin and a related Maritimes expansion were a response to the New England governors’ initiative on new energy infrastructure. It said the AIM project will provide the Northeast “with a unique opportunity to secure a cost effective, domestically produced source of energy to support its current demand, as well as its future growth.”
WASHINGTON — All of the speakers at a FERC technical conference on Thursday agreed that PJM’s allocation method for financial transmission rights and auction revenue rights could be improved. They just couldn’t agree on what changes would make it better.
The commission called the information-gathering session after the Financial Marketers Coalition and others protested PJM’s proposal to eliminate the netting of negatively valued FTRs against positively valued FTRs within portfolios and to increase ARR results by 1.5% annually (EL16-6-001, ER16-121). (See FERC Orders Tech Conference on PJM FTR Rule Changes.)
Patton
David Patton of Potomac Economics, which serves as the market monitor for MISO, NYISO, ISO-NE and ERCOT, told FERC staff that the commission should broaden the inquiry and “adopt some principles instead of just looking at incremental rule changes.”
In particular, he said, the settlement obligation should be well defined, the settlement of FTRs should be non-discriminatory and FTR shortfall costs should be allocated as consistently as possible with cost causation.
“I would recommend you issue a [Notice of Proposed Rulemaking] that all RTOs’ [methods] are unjust and unreasonable and issue some principles,” he said.
PJM’s Tim Horger asked the commission to render a decision by April 5 to provide adequate notice to participants before the 2016 annual ARR allocation and FTR auction.
An FTR entitles its holder to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.
Stakeholders and PJM had been wrangling with the issue of FTR underfunding for more than a year when Steve Lieberman of Old Dominion Electric Cooperative offered the current proposal, which fell short of reaching the consensus necessary to make a Section 205 filing. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)
The Financial Marketers Coalition — representing DC Energy, Inertia Power, Saracen Energy East and Vitol — objected to the elimination of netting, saying PJM hadn’t proven that current market rules were unjust and unreasonable, nor that the proposed changes would fix underfunding.
Bresler
The conference consisted of four panels: ARR and FTR modeling, sources and apportionment of underfunding, PJM’s proposed modifications and alternative solutions.
PJM Market Monitor Joe Bowring took issue with the notion of underfunding.
“I don’t think there’s any such thing as underfunding,” he said, noting that there is no guarantee of full funding for FTRs in the day-ahead market. “There is revenue inadequacy.”
PJM’s netting provision, he said, provides a subsidy to those with more negatively valued FTRs in their portfolio, creating a larger payout to some holders of the same product. Removing netting would ensure that all negatively valued FTRs are treated the same and all positively valued FTRs are treated equally.
While Patton said FTRs are primarily a financial instrument whose integrity needs to be preserved, Bowring said that the product was created in order for load to be reimbursed fairly.
“FTRs were about replacing firm transmission rights, ensuring that load that paid more than generators received got that money back,” he said.
FTRs were created when PJM operated only a real-time market. When the day-ahead market was formed, FTRs became a day-ahead product.
“There was a very good reason behind that change, to solidify the incentive to participate in the day-ahead market,” because that’s the best place to manage risk, said Stu Bresler, PJM’s senior vice president for market operations. “I think it’s critical and it needs to be preserved. It was created to be a fungible product around firm transmission service, to allow it to be traded, if you will, with the idea of getting the value back to the load. I think the theory has worked.”
Klein
Speakers who opposed the Tariff changes said it’s not fair for FTR holders to pay for balancing congestion — reflecting the differences between day-ahead and real-time load and generation.
“FTR holders are not the cause of congestion imbalances and shouldn’t be allocated them,” said Abram Klein of Appian Way Energy Partners. “The congestion belongs to load.”
Bowring rejected Klein’s argument.
“The idea that balancing congestion should be separated out … that’s just wrong,” he said. “We’re going to force load to guarantee the value of FTRs in the day-ahead market? That’s standing logic on its head.”
David Mabry of the PJM Industrial Customer Coalition pointed out that participants choose to be involved in the FTR market. “The part of the market where people are coming in voluntarily is where underfunding is happening. From that perspective, the process is working correctly,” he said. “Where it may not be working, it’s where folks are going into the process hoping to get some money out of it. But it is not a guarantee.”
Said Bowring: “Even in the darkest days of the lowest levels of revenue inadequacy, FTRs were still highly profitable.”
During the panel discussing alternative solutions, Harry Singh of J. Aron & Co. said a better market design would include separating out balancing congestion.
“When PJM started out, it was a real-time market,” Singh said. “Day-ahead congestion plus real-time congestion does not equal what you would have in a single settlement system.”
“PJM does agree that the allocation and balancing of congestion is something that we should look at,” Bresler said. “I don’t think the PJM ARR and FTR construct is in need of complete overhaul. I do, however, think there are areas for further investigation and adjustment.”
Mabry
One idea would involve updating the set of source points, which date to 1998, involved in ARR allocations, he said.
Joe Wadsworth of Vitol agreed with Singh and recommended redefining the FTR product to be settled with only day-ahead congestion funds.
In addition, he said, fully funding FTRs would make them more valuable. “Increased confidence in FTRs would lead to a reduction of risk premiums and stronger values for ARRs than what otherwise might have occurred,” he said. “You’re going to generate more funding that will benefit transmission customers.”
Wadsworth also suggested allocating shortfalls due to outages to the transmission owners responsible for them — an incentive to reduce outages and schedule them when they cause the least congestion.
Bresler said he did not think the FTRs should be guaranteed full funding, or that underfunding should be allocated all to load.
“Commission guidance would be extremely helpful at this stage,” he said.
[Editor’s Note: An earlier version of this article mistakenly reported that J. Aron & Co. is a member of the Financial Marketers Coalition.]
ISO-NE will hold its 10th Forward Capacity Auction on Monday with expectations that prices will continue to rise as more generation resources leave the market.
Capacity prices have more than quadrupled over the past two auctions, with total costs reaching about $4 billion in FCA 9. Last year’s auction set prices at $9.55/kW-month throughout most of New England, with administrative prices set in the constrained zone of Southeastern Massachusetts/Rhode Island.
Some 24,447 MW of capacity resources cleared FCA 9 at $9.55/kW-month, an increase of more than one-third over the $7.025/kW-month clearing price for most resources in FCA 8 in 2014.
The upcoming auction, for the capacity commitment period of 2019/20, will not have Entergy’s 680-MW Pilgrim nuclear station in Massachusetts, which the company said last year will close by early 2019. (See Entergy Closing Pilgrim Nuclear Power Station.) Auction results are expected on Wednesday.
Pilgrim Nuclear Plant (Source: Entergy)
A Dec. 31 research report by UBS Securities predicted higher prices with the loss of Pilgrim, “which we assume will be replaced with a new asset requiring $11/kW-month to be economic; without any new entry, we foresee an even higher outcome of $13/kW-month.”
A year ago, UBS thought the market had reached its high-water mark in FCA 9 as more than 1,000 MW of new resources were procured. Entergy announced its intention to close Pilgrim a few months later, just before the deadline for qualified resources to apply for inclusion in FCA 10.
One difference this year is ISO-NE’s inclusion of 390 MW of behind-the-meter solar resources. FERC approved the inclusion of the resources over the objections of power generators, saying they were properly accounted for in the installed capacity requirement calculation.
Solar is only a small piece of the 35,126 MW of ICR resources in FCA 10, but the reduction was enough to displace the need for one small generating plant. (See FERC Accepts ISO-NE’s Solar Count over Protests.)
FERC last month also reaffirmed the zero-price offer requirement in ISO-NE’s new entrant pricing rule, rejecting complaints that it unreasonably suppresses capacity prices and discriminates against existing resources.
ISO-NE’s rule allows new resources to lock in their first-year clearing price for up to six subsequent delivery years by offering as a price-taker with a price of zero.
The New England Power Generators Association, which had previously sought to disqualify DR from participation, last week withdrew its petition as moot.
WEC Energy Group reported net income of $179.3 million for the fourth quarter of 2015, up 48% over 2014’s pre-Integrys merger earnings of $121.4 million.
The boost to earnings per share were less dramatic, increasing to $0.57/share from $0.53/share.
The Milwaukee-based company announced Wednesday that total earnings for 2015 were $638.5 million, compared to 2014’s net of $588.3 million. However, earnings per share for the year were $2.34, down from 2014’s $2.59.
WEC reported fourth-quarter revenue of $1.85 billion. When adjusted to exclude the $780 million of revenue from Integrys operations, Wisconsin Energy revenues were $1.07 billion in the fourth quarter, in comparison to 2014’s last three months, which brought in $1.23 billion.
Dividends per share, on the other hand, increased to $0.46/share in 2015 surpassing 2014’s $0.39/share for the fourth quarter. Total dividends for 2015 were $1.74/share outstripping 2014’s $1.56/share.
The company said daily average temperatures in the fourth quarter of 2015 were 26% warmer than in 2014. We Energies, the company’s utility subsidiary, experienced a 7.5% decline in residential electricity use from 2014’s fourth quarter, and total gas sales were down 13.9% for the quarter.
“We delivered solid results in the final quarter of 2015 despite record warmth that limited customer demand for heating throughout December,” said CEO Gale Klappa, who announced last month that he would retire in May. He called 2015 a “year of achievement” for WEC, noting the June 29 completion of the Integrys Energy Group acquisition. He also cited the company’s recognition by PA Consulting as the most reliable utility in the Midwest for the fifth year in a row.
The acquisition was “a major step that created the leading utility system in the Midwest, serving more than 4 million customers,” Klappa said. “Since the close of the acquisition, we’ve made significant progress in focusing our six operating utilities on world-class reliability, customer satisfaction and financial discipline.”
PPL increased earnings from ongoing operations in the fourth quarter although overall results declined because of the spinoff of its generation assets into Talen Energy.
PPL reported 2015 earnings of $682 million ($1.01/share) compared with $1.74 billion ($2.61/share) in 2014. The results reflect the loss from discontinued operations of $921 million, or $1.36 per share, from its June 1 spinoff of its competitive supply business.
Earnings from ongoing operations, however, were $1.49 billion ($2.21/share), compared with adjusted earnings from ongoing operations of $1.35 billion ($2.03/share) in 2014. That represents a 9% increase on a per-share basis.
“I think it’s incredible if you look at where we are since the spin. We’ve received two favorable rate outcomes in Pennsylvania and Kentucky, we’ve raised our guidance on our U.K. incentive revenue, we’ve lowered our exposure to the pound and we’ve moved toward increases in our dividend growth,” CEO William Spence told analysts on an earnings call Thursday.
Earnings from PPL’s U.S. operations are expected to grow 11 to 13% through 2018, with 1 to 3% growth expected in the U.K.
PPL announced that it is increasing its common stock dividend to $1.52 annually from $1.51/share, marking its 14th increase in 15 years.
The company reported fourth-quarter earnings of $399 million ($0.59/share), compared with $695 million ($1.04/share) for the same period in 2014. Adjusting for the Talen spinoff, fourth-quarter earnings from ongoing operations were $294 million ($0.43/share), compared with $330 million ($0.49/share) in 2014.
PPL’s reported earnings for 2015 included net special item after-tax charges of $807 million ($1.20/share).
Special items for the fourth quarter of 2015 included reductions to net deferred income tax liabilities resulting from a reduction in the U.K. corporate income tax rate and unrealized gains on foreign currency-related economic hedges.
More than half of PPL’s revenue comes from its U.K utility, Western Power Distribution.
