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.
SPP established a new high for wind penetration Jan. 31, with 39.1% of load being supplied by the resource.
Kansas Wind (Source: Kansas Energy)
The record was set at 5:29 a.m., when load was about 23,000 MW and energy from wind reached the 9,000-MW level for just the third time in the RTO’s history. The mark topped the previous record of 38.3%, set Nov. 4.
SPP’s record peak for wind remains 9,948 MW, set Dec. 19.
The RTO says it can handle wind penetration levels of up to 60% with additional transmission and monitoring tools, according to its first wind integration study since 2009. (See Study: 60% Wind Penetration Possible in SPP.)
SPP has scheduled a wind integration summit Feb. 17-18 in Little Rock, Ark., to provide its stakeholders with an open forum to ask questions, provide feedback and critique the study’s results.
The RTO says wind-powered generation accounted for about 13.5% of its fuel mix in 2015. It has 12,397 MW of installed wind capacity in its footprint, with another 33,819 MW in various forms of development.
CMS Energy boosted fourth-quarter earnings to $106 million ($0.38/share), outpacing the $96 million ($0.35/share) it earned in the last quarter of 2014. The Jackson, Mich., company’s earnings grew 9.6% year over year, even as operating revenue for the quarter dropped 14.2% to $1.51 billion.
Revenue for the entire year was also down, dropping to $6.46 billion from 2014’s $7.18 billion, while net income for 2015 grew to $523 million ($1.89/share) from $477 million ($1.74/share).
The improved earnings came as the company reduced expenses to $1.26 billion in the fourth quarter from $1.49 billion for the same period in 2014. For the year, expenses dropped to $5.29 billion compared to 2014’s $6.03 billion.
The company raised its guidance for 2016 to $1.99 to $2.02/share. CEO John Russell said the company has committed to expanding its 10-year capital expenditures plan from $15.5 billion to $17 billion.
“The future looks bright for CMS,” Russell said. “Our unique business model has worked well for more than a decade and we expect it will continue going forward.”
Russell said 2015’s year-end results marked the company’s “13th consecutive year of consistent financial performance.” He also pointed out a 29% reduction in employee injuries compared to 2014 and a record rating in reliability.
SERC Reliability Corp. named MISO the winner of its President’s Award, citing its management of a record summer load, compliance with CIP standards and resolution of seams issues.
The award is presented annually to companies recognized for electric reliability excellence.
“MISO’s mission is to ensure reliability at the lowest possible cost for the customers in our region,” said CEO John Bear, who accepted the award Feb. 2 at the SERC CEO Summit. “This award is a testament to the hard work and dedication of our employees to deliver on that mission.”
According to MISO, the award acknowledged the RTO’s “commitment to reliability and its willingness to share best practices and lessons learned with fellow SERC members.” MISO said the award is attributable to multiple achievements in the MISO South region, notably handling a record summer peak in 2015, compliance with CIP version 5 requirements and successful settlement of the SPP transmission flows dispute. (See FERC OKs MISO-SPP Transmission Settlement.)
One of NERC’s eight regional electric reliability councils, SERC oversees reliability, adequacy and critical infrastructure of the bulk power supply system in 16 Central and Southeastern states.
Virginia Electric and Power Co. won the award last year, following South Carolina Electric & Gas’ win in 2014.
Dominion Resources blamed December’s “extremely mild weather” for a drop in its fourth-quarter earnings, reporting earnings of $416 million ($0.70/share) compared to last year’s $490 million ($0.84/share) for the same period, a decline of about 15%. The weather reduced earnings by about 8 cents/share, the company said.
“While we have discussed our sensitivity to weather in prior calls, never [has weather had] the kind of impact that we saw in December,” said CFO Mark F. McGettrick in a conference call with analysts.
Dominion projected earnings per share for the year of $3.50 to $3.85/share, but the company came in at $3.20/share on revenue of $1.9 billion. This was compared to earnings of $1.3 billion, or $2.24/share, for 2014.
The company noted that it is nearly done building the 1,358-MW natural gas combined cycle plant in Brunswick County, Va., and that it has obtained nearly all necessary approvals to build a 1,588-MW combined cycle plant in Greensville County, Va.
Most of the call was taken up, though, with news that it is buying the Utah-based natural gas distributor Questar for $4.4 billion in cash in a deal aimed at expanding its gas business into the West.
Dominion said it expects to complete the acquisition by the end of the year. The company also said it would be assuming Questar’s approximately $1.31 billion in long- and short-term debt.
Like Duke Energy, which announced in October it would purchase Piedmont Natural Gas, Dominion expects the value of natural gas to increase as more and more states switch to the fuel for electric generation in order to meet state and federal emissions mandates.
CEO Thomas Farrell II said the Questar acquisition “provides enhanced geographic diversity to Dominion’s natural gas operations.”
“While our Dominion transmission system is known as the Hub of the Mid-Atlantic, the Questar system is called the Hub of the Rockies, and a principal source of gas supply to the Western states. We believe the value of the system will increase over time,” Farrell said. “As Utah and the surrounding Western states seek to comply with the requirements of the EPA’s Clean Power Plan … compliance is highly likely to result in an increased reliance on low-emission, gas-fired generation.”
It is Dominion’s latest big natural gas play. The company is one of the majority owners of the Atlantic Coast Pipeline project, a $5 billion, 550-mile pipeline that would bring natural gas from the shale fields in Pennsylvania, West Virginia and Ohio to markets and terminals in Virginia and North Carolina. Farrell said construction is expected to start by the end of the year.
Dominion also has invested $3.8 billion to convert its LNG import terminal at Cove Point, Md., on the western shore of the Chesapeake Bay, into an export facility.
The New York Public Service Commission on Tuesday denied Entergy’s request for an administrative law judge to handle the company’s objections to the state’s investigation of the Indian Point nuclear power plant (15-02730).
Gov. Andrew Cuomo ordered the PSC to investigate plant operations and finances after two unplanned outages in December. Entergy has called the investigation “political” and objected to turning over documents that it says are outside the scope of any state investigation. (See Entergy Disputes Investigation of Indian Point, Calls it Political.)
“The appointment of an ALJ is neither appropriate nor needed. This matter is a special investigation ‘directed by the governor and performed by PSC staff, into specific problems or events at a facility,’ with which Entergy is required to cooperate,” the commission said. An ALJ acting as a referee “would not expedite resolution of disputes” as contested rulings would lead to more administrative appeals, it said.
The NYPSC has made five requests for “batches” of documents related to plant operations from Dec. 28 to Jan. 22. Cuomo wants the initial findings of the investigation reported by Feb. 15.
Entergy said it has complied to the vast majority of the document requests. PSC staff so far has not countered its objections, according to Michael Twomey, Entergy vice president of external affairs.
“We have provided over 300,000 pages of documents, but there are some, for example, related to nuclear safety, that are solely under Nuclear Regulatory Commission jurisdiction,” Twomey said.
State officials have also asked for financial documents from the plant, which the company has also contested.
“While we have discussed our sensitivity to weather in prior calls, never [has weather had] the kind of impact that we saw in December,” said CFO Mark F. McGettrick in a conference call with analysts.
Gov. Andrew Cuomo ordered the PSC to investigate plant operations and finances after two unplanned outages in December. Entergy has called the investigation “political” and objected to turning over documents that it says are outside the scope of any state investigation. (See