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.
Speaking during an earnings call, Crane said the company will abandon the merger and begin buying back the 57.5 million shares it issued for the $6.8 billion deal if regulators don’t act promptly.
“That’s our only commitment, to try this until March 4,” Crane said. “If we can’t get it by March 4, then we have to fold up and then start to execute on the debt reduction and the buyback of the equity issued.”
While the PSC indicated in its Oct. 28 order that it expected to rule by March 4, a PSC spokeswoman said the commission is not obligated to act by then (case 1119).
“There is no requirement, statutory or otherwise, that obligates the commission to issue a decision within a certain number of days from the date the record closes in a commission case,” said spokeswoman Kellie Didigu. “It is a commission policy to issues a decision within 90 days on major cases, such as rate cases and the current merger proceeding. However, if necessary, the commission can take more time.”
The commission closed the record Dec. 23, making the 90-day mark late March. The commission will post a notice and an agenda 48 hours before an open meeting at which the commissioners will announce their decision, Didigu said.
Valuing Nuclear
Crane said another focus of 2016 will be advocating for the company’s nuclear fleet to be “properly valued for their clean, safe and reliable attributes.”
To that end, the company is supporting FERC-ordered reforms to MISO’s capacity market, especially regarding Zone 4. There, April’s capacity auction saw prices clearing at $150/MW-day, up to 40 times more than elsewhere in the RTO. (See MISO Files Changes to Capacity Rules; Seeks Adjustment on Import Limit.)
“We were successful and PJM was successful in the capacity market redesign. That gave some upside to the fleet in NiHub [Northern Indiana],” Crane said. “It greatly helped Byron and added help to Quad Cities.”
Still, he said, Quad Cities is struggling, and Clinton is in the red, he said.
As for the MISO reforms, Crane said, “We would like the design to be more like the PJM capacity market design.” But, he said, “That in itself will not save Clinton.”
In New York, Exelon’s Nine Mile Point and Ginna plants might be helped by a zero-emission credit program being developed at the direction of Gov. Andrew Cuomo.
“We still have quite a ways to go, but as a threshold political matter, having a governor of the prominence of Gov. Cuomo step forward and propose to compensate nuclear fairly to keep it in business is important,” said Joseph Dominguez, executive vice president for government and regulatory affairs. “If we get the details right, I would go so far as to say it’s kind of a watershed event for the industry.” (See New York Would Require Nuclear Power Mandate, Subsidy.)
Added Crane: “We’ve got a very supportive administration that recognizes the clean benefits of nuclear, and that’s really appreciated.”
Crane also announced during the earnings call that Exelon will be increasing its dividend by 2.5% each year for the next three years beginning in June, regardless of whether the PHI deal goes through.
Earnings
Exelon reported fourth-quarter earnings of $309 million ($0.33/share), compared with $18 million ($0.02/share) for the same quarter in 2014. Its revenue for the quarter was $6.7 billion, compared with $7.26 billion in 2014.
“Despite a challenging year for the sector, strong operating performance at both our utilities and our generation business enabled us to deliver strong earnings,” Crane said.
Exelon said fourth-quarter earnings were impacted by warm weather in the ComEd and PECO zones, increased nuclear outages, higher depreciation and amortization expenses for its generation business and the cost of funding the PHI transaction.
That was partially offset by higher earnings at Commonwealth Edison, and lower uncollectible accounts at PECO and Baltimore Gas and Electric.
Crane said the utilities experienced a record earning year. Net income for the full year was $2.27 billion ($2.54/share), compared with $1.62 billion ($1.88/share) for 2014. CFO Jack Thayer said the company is poised to invest $3.95 billion in capital across three utilities and an additional $1.38 billion at PHI.
FERC Commissioner Tony Clark said last week that the Supreme Court’s ruling upholding FERC’s jurisdiction over wholesale demand response frees the commission to take another look at Order 745’s requirement that RTOs pay DR providers LMPs equal to generation.
“With the disposition of these matters, I would encourage the commission to turn its attention towards a thorough assessment of the underpinnings of a compensation regime that continues to be widely panned by market experts,” he said in a statement.
“That this case has garnered so much attention says much about how financially lucrative the current mechanism is to one particular type of market participant. Yet the commission’s job is not to support a particular technology, resource class or business model based on its subjective preferences; it is to dispassionately create mechanisms that find economically proper prices.”
Critics, including former Commissioner Philip Moeller, who dissented on the 2011 order, contend DR should be paid a price of LMP minus G, where “G” stands for the retail price of electricity.
The majority said full LMPs was appropriate because rates should reflect the service provided rather than the provider’s cost. It said its reasoning was consistent with the single-price clearing method used by RTOs: nuclear, coal, gas and wind generators are all paid LMPs regardless of their fuel costs or tax advantages.
The commission also said it would be difficult to establish “G” in the formula because retail rates vary within states and change over time.
It’s unclear whether the commission will take up the matter. In any event, Clark — who joined the commission after Order 745 — likely won’t be around to see it relitigated, having announced last month that he won’t seek reappointment when his term ends in June. (See Clark Won’t Seek New FERC Term.)
ISO-NE Resumes Work to Integrate DR into Energy Market
Two other cases dropped off FERC’s to-do list last week as a result of the Supreme Court ruling. On Friday, FirstEnergy (EL14-55) and the New England Power Generators Association (EL15-21) withdrew complaints they had filed seeking to bar DR from participating in the PJM and ISO-NE capacity markets, respectively.
ISO-NE spokeswoman Marcia Blomberg said Monday the ruling will allow the RTO to resume its work to “fully integrate” DR into all of the RTO’s markets, including the day-ahead and real-time energy and operating reserves. The RTO had suspended work on the project because of the legal challenge.
“We will work to accomplish this by June 1, 2018, on the schedule we worked out with our stakeholders to ensure a reliable transition through implementation of well-designed market rules and thoroughly tested modifications of energy management software.”
Once integration is complete, DR will offer into the day-ahead market alongside generators and be subject to the same Pay-for-Performance incentives.
Currently, small levels of DR participate in the RTO’s energy markets, but their offers are cleared administratively and not in the market, Blomberg said. DR and energy efficiency resources have been participating in the RTO’s capacity market since it began in 2010.
PJM, MISO: Business as Usual
For PJM and MISO, meanwhile, the ruling meant mostly business as usual.
PJM General Counsel Vince Duane started off last Thursday’s Markets and Reliability Committee meeting with some comments about what the ruling will change for PJM. In a word: “Nothing.”
“We have not done anything to change the status prior to this. The Tariff is as the Tariff has been,” he said. “DR has cleared, it has future obligations. It’s really business as usual.”
He told members not to be concerned over the fact that the ruling returns the matter to the D.C. Circuit, calling it a formality.
Duane’s counterpart at MISO, Senior Vice President of Legal and Compliance Service Steve Kozey, had the same message. Most of MISO’s DR assets are managed through state programs, and Kozey said state laws won’t have to be adjusted in the MISO footprint.
Kozey said he felt comfortable talking about the order in open session because MISO wasn’t a party to it and won’t be directly affected. “It was a big deal to PJM [and] New England … where a great deal of turmoil and uncertainty has been brought to an end,” he said.
Little Impact on PJM Capacity Market
Despite the ruling, DR participation is unlikely to increase in PJM’s capacity auctions, Morningstar analyst Jordan Grimes said in a Jan. 25 research report, noting that “almost all other PJM rule changes have been more restrictive to DR.” Under Capacity Performance rules, DR will be required to respond year-round and, like generation, will face high penalties for nonperformance. Lead times were cut to 30 minutes with an hour minimum dispatch.
“Ultimately DR market saturation will be the limiting factor. The more DR in PJM the more likely it is that the resource will be dispatched,” he wrote. “Because DR providers receive more than 90% of their revenues from the capacity market and the mainstream revenues from other economic activity (i.e. producing steel, cement), it is unlikely that DR providers will submit offers competitive with physical generation.”
The ruling is unlikely to have a significant impact on PJM energy and capacity prices, Grimes said. In contrast, capacity prices could have moved to the net cost of new entry price cap had the court vacated Order 745 and the market needed to replace DR, he said.
New York, ERCOT
ERCOT spokeswoman Robbie Searcy noted that the grid operator is not regulated by FERC and thus was not affected by the ruling. “Demand response continues to be an important tool in ERCOT, and our stakeholders continue to evaluate other opportunities for these resources to participate in the wholesale energy market.”
The order also had no evident impact in New York. As part of its Reforming the Energy Vision initiative, the New York Public Service Commission last June approved rules for utilities to offer customers financial payments for DR (14-E-0423, et al.). The retail programs, modeled after those in place at Consolidated Edison, will begin in some areas in July with a full rollout planned for summer 2017. (See Demand Response for All Coming to New York.)
“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 
Speaking during an earnings call, Crane said the company will abandon the merger and begin buying back the 57.5 million shares it issued for the $6.8 billion deal if regulators don’t act promptly.