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.)
Having survived a legal challenge that could have crimped its development for years, demand response now has an opportunity to take a central role in combating climate change and reducing energy bills by taking advantage of the growing spread of advanced metering technology.
But the industry still faces formidable challenges due to varying state regulations and consumer resistance to time-of-use pricing, hurdles the Supreme Court’s Jan. 25 ruling upholding FERC’s authority to regulate wholesale DR did nothing to eliminate. (See Supreme Court Upholds FERC Jurisdiction over DR.)
“While the Supreme Court ruling puts federal regulators at the helm of modernizing the electric grid — at least for the 70% of the country operating in deregulated electric markets — individual states can still restrict or set strict criteria for participation in those DR markets, which in some cases are increasingly restrictive,” said EnerKnol policy analyst Erin Carson in a research report released Monday.
Reflecting that sober assessment, shares of DR provider EnerNOC, which jumped 70% on the day of the ruling, retreated soon after, ending the week up 26%.
“Without establishment of price signals to customers, DR cannot fulfill its potential,” concluded a report released a week before the Supreme Court ruling by the Evolution of DR Project (EDP).
“The vast majority of residential customers are not exposed to price signals,” said the report, the result of a “multi-party dialogue” that included utilities, RTOs, state and federal policymakers, DR providers and other stakeholders.
Impact of Supreme Court Ruling
Although the Supreme Court case dealt explicitly with DR in wholesale energy markets, many observers predicted a rejection by the court would also jeopardize the resource’s participation in the capacity markets, where DR earns most of its revenue. (See related story, Clark Calls for New Look at Order 745.)
Kevin Lucas, director of research for the Alliance to Save Energy, noted that DR revenue is essential to justifying investments in data analytics and building controls. “Fair, market-based compensation in competitive wholesale energy markets is a critical step toward increasing the deployment of energy-saving technologies such as whole-building controls and smart-grid-enabled analytics,” he said in a press release. “With major legal questions now resolved, the direct benefits to consumers of these products and services are sure to follow.”
“Business uncertainty about the outcome of the Supreme Court case has held innovators and implementers in limbo for months,” wrote Denis Du Bois, a clean technology consultant and host of the Energy Priorities radio program. “Not only was the future of demand response in question, but similar ideas for energy efficiency markets also had a foggy outlook. By upholding the order, the court has removed that uncertainty for demand response and clarified the future of energy efficiency as well.”
Smart Meter Deployment
If maximizing DR requires exposing consumers to price signals, it also requires smart meters, devices capable of two-way communication and capturing real-time usage.
The Obama administration spent more than $3 billion in stimulus funds on smart meters and other smart grid investments. And while the spread of the technology has been unmistakable, there is disagreement over the current penetration of smart meters.
Source: American Public Power Association
FERC’s ninth annual Assessment of Demand Response and Advanced Metering report, released in December, cited Energy Information Administration data that put penetration at 30% through 2012. The Edison Foundation’s Institute for Electric Innovation reported that more than 50 million smart meters were deployed as of July 2014, representing more than 43% of U.S. homes.
The EDP report estimates that about 70% of meters have been upgraded to smart meters or are planned for replacement in the near future, in line with projections by research group NPD, which predicted 75% by 2016.
FERC found the Texas Regional Entity leading with penetration of 70%, followed by the Western Electric Coordinating Council at 51%. Bringing up the rear were ReliabilityFirst Corp., which includes portions of PJM and MISO, at 17%, and the Northeast Power Coordinating Council at 12%.
Real-time Pricing
Despite the growing availability of smart meters, EDP noted that “at the residential level, nearly all customers are on retail rates that are fixed and do not vary with time or location.”
“Efficiently integrating new technologies such as storage and electric vehicles may require exposure to time-varying rates/prices to reflect the true marginal cost of power in each interval of time,” it said. “Without such time-varying rates/prices, the customer cannot know when inexpensive electricity should be bought and stored, and when the stored electricity should be utilized to avoid buying expensive electricity.”
But political aversion to price spikes and human nature has made it a challenge to make that vision a reality. Indeed, the FERC report found that enrollment in time-based DR programs dropped by 6.1% between 2011 and 2012.
A Department of Energy report last June looked at customer response to time-based rates based on studies of 10 utilities.
The utilities in the study ran at least one of four types of time-based rate programs: critical peak pricing (CPP), critical peak rebates (CPR), time-of-use (TOU) pricing and variable peak pricing (VPP).
The report concluded that opt-out enrollment rates were about 3.5 times higher than they were for opt-in programs (93% vs. 24%), but there was no significant difference in retention rates (91% for opt-out, 92% for opt-in).
The department report attributed the results to what social scientists call the “default bias.”
“When facing choices that include default options, people are predisposed to accept the default over the other options offered,” the Energy Department report said. The department said the findings indicate cost-benefit advantages to using opt-out approaches.
The Sacramento Municipal Utility District found, conversely, that peak period demand reductions for opt-in TOU customers were about twice (12%) as large as they were for opt-out customers (6%). Peak period demand reductions for SMUD’s opt-in CPP customers were about 50% higher (24%) than they were for opt-out customers (14%).
The study also found that retention rates were higher for critical peak rebates than for critical peak pricing.
This, the researchers said, was consistent with the theory of loss aversion, which holds that, given a choice, people are more likely to seek to avoid a loss rather than acquire a gain. “The risk from nonperformance during critical events under CPP is greater than under CPR, and this could be a motivating factor that decreases enrollment and retention,” the report said.
State Policies
Some states are attempting to overcome behavioral obstacles.
The California Public Utilities Commission is requiring the three investor-owned utilities in the state to establish default TOU rates for residential customers starting in 2019. The Massachusetts Department of Public Utilities is requiring that load-serving entities implement time-varying rates as smart meters are deployed.
Last June, the Michigan Public Service Commission ordered DTE Electric and Consumers Energy to offer opt-in TOU and dynamic pricing rate structures over the next two years.
The EDP report cited complaints of DR providers and multi-state utilities over inconsistencies in DR rules from state to state and the complications of wholesale market programs that “can underlay or overlay” state DR programs.
It recommended that state-level policies on distribution platforms consider how distribution-level DR will be coordinated with regional wholesale DR. It also called for RTOs to participate in the proceedings that develop distribution-based market systems.
Some others say more action is needed to clarify federal and state jurisdiction. “My take is that [the Supreme Court] decision can guide the development of demand response, but we still need congressional action (and perhaps a broader Supreme Court decision) to update a U.S. electricity market framework that is over 80 years old,” wrote Varun Sivaram, an advisor to New York’s REV initiative.
The Evolution of DR Project report provides a succinct history of demand response, beginning in the 1950s and 60s, when utilities began offering incentive-based “interruptible” programs to large commercial and industrial customers.
Between 1980 and 2000, direct load control programs offered savings to smaller customers through radio controls allowing utilities to turn off hot water heaters and air conditioning during peak demand.
The term “demand response” came into use after 2000, when the creation of ISOs and RTOs created “a new platform” for the resource, including market-based DR.
Using new technology and directed by FERC policies, the RTOs “moved beyond emergency programs and began to incorporate DR as a market resource that could compete with supply resources. DR began to be viewed as a dynamic, controllable and dispatchable resource that could help balance supply and demand in a wholesale market.”
DR began providing ancillary services, including operating reserves and regulation.
At the same time, utilities began installing advanced metering infrastructure — smart meters — that provided both more precise time-based measurement and two-way communications.
In contrast with traditional energy efficiency — making devices and equipment use less power — DR was “dynamic, controllable and dispatchable.”
A new term emerged — intelligent efficiency — to describe building technology that can respond to price or other inputs automatically.
In the last five years, DR backers have sought to ensure the resource has a role alongside rooftop solar and microgrids in the move to distributed energy resources.
An August 2015 report by the Rocky Mountain Institute said that although the Supreme Court ruling would be “immensely important” for demand response, the industry was limited by “traditional, top-down grid paradigms.”
“By focusing on DR’s revenue potential in wholesale markets, a huge part of the core value proposition of demand flexibility is lost — namely, the economic benefits of flexible, controllable demand to individual customers,” it said.
The institute’s co-founder, Amory Lovins, is credited with inventing the term “negawatt” — power saved through conservation or efficiency.
The institute’s new report, The Economics of Demand Flexibility, coins a new term, “flexiwatts” — demand that can be moved across the hours of a day or night based on economic or other signals.
The report concludes that residential demand flexibility can save $9 billion per year in spending on transmission investments — a cut of more than 10% of forecast spending — and $4 billion annually in energy production and ancillary services. That could reduce consumers’ electric bills by 10% to 40%.
Flexiwatts can reduce capacity spending by reducing peak loads and flattening aggregate demand profiles of customers. In the energy market it can shift load from high-price to low-price times. They can also reshape load profiles to complement the increasing intermittent generation expected in response to EPA’s Clean Power Plan.
While DR is deployed infrequently and often used only as a last resort during peak demand, demand flexibility can be used continuously and proactively to reduce costs year-round, resulting in direct bill reductions instead of infrequent incentive payments.
Demand flexibility can use automatic controls to reshape a customer’s demand profile in ways that either are invisible to the customer (for example, using storage to decouple the timing of consumption from the grid impact) or minimally affect the customer (shifting the timing of non-critical loads within customer-set thresholds).
It also takes advantage of time-of-use or real-time pricing, demand charges and distributed solar PV export pricing to provide retail price signals directly to customers or through third-party aggregators.
“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.
