安特吉 (ETR) 2011 Q2 法說會逐字稿

Good day everyone and welcome to the Entergy Corporation Second Quarter 2011 release conference call. Today's call is being recorded.

At this time for introductions and opening comment I would like turn the call over to the Vice President of Investor Relations, Miss Paula Waters. Please go ahead, ma'am.

Good morning and thank you for joining us.

We begin this morning with comments from Entergy's Chairman and CEO Wayne Leonard and Leo Denault, our CFO will review results. In an effort to accommodate everyone with questions this morning we request that each person ask no more than 2 questions.

After the Q&A session, I will close with the applicable legal statement. Wayne?

Good morning, everyone. I'm pleased to report another quarter of solid financial performance which Leo will review with you in a moment.

Quarterly operational earnings per share top the second quarter record, set just 1 year ago, despite the effect of the [Paris] depressed power pricing on wholesale business as higher price contracts roll off. We continue to pursue a full agenda of strategic initiatives that will take some time to fully play out. In the meantime, commodity markets which are showing some signs of long-term recovery will continue to be a drag on earnings for at least the next couple of years.

I'll begin today by providing an update on the progress that we've made on some of those key initiatives. Starting at the utility. Our utility companies that work hard for a long time to secure regulatory structures and mechanisms to allow a real opportunity to earn returns commensurate with investment alternative of comparable risks. You'll see that these efforts are coming to fruition as you review the financial results.

For example, since the end of 2001, average residential rates have increased a little over 0.5% per year over the near 10 year period, or almost flat for 10 years. While utility operational earnings per share at the midpoint of the 2011 guidance is nearly double the operational results 10 years ago. At the same time, our operational and our safety performance and environmental record continues to set new company standards.

Our voluntary CO2 emissions reductions put us over 20% below the year 2000 level.

Formula rate plan filings for 2010 reflect earnings consistent with each company's bandwidth ranges in Louisiana and Mississippi and we are above the range in New Orleans.

Unseasonable weather in 2010 both a warm summer and cold winter contributed to these results with industries gulf states in Louisiana, [Entergy] Louisiana and New Orleans near the top end or above the range. In total, the New Orleans 2010 FRP filing reflected a $7.6 million decrease in electric and gas rates.

Also, included in the Entergy New Orleans May filing was a request to increase storm funding by about $20 million. To replace the cash storm reserve after expenditures for hurricanes Gustav and Ike, allowing the cash storm reserves to reach the approved $75 million level on schedule by 2017. The electric and gas rate changes are expected to be effected in October.

Turning to Texas, legislation was enacted in May, allowing for a special rider periodically adjust rates for changes in distribution investment. The public utility commission of Texas is now in the process of repairing the rule-making and rate filing package to be completed by late September.

Entergy Tech is also in continued efforts to achieve a purchase power capacity rider after the PUCT reopened the rule-making earlier this year. The introduction of a distribution rider and a purchase power capacity rider, coupled with the transmission rider already authorized, would provide industry tech these additional tools similar to those in place in other jurisdictions that efficiently and effectively promote the public interest and align shareholder and customer economic interests. If final rules are adopted, ETI has the opportunity to file for one or more of 3 riders in 2012, depending on circumstances related to a more complete review of overall costs.

The utility also continued to execute its capital investment commitment related to last year's resource selections in the summer 2009 long-term request for proposal.

In June Entergy Louisiana filed a request the seeking Louisiana public service commission approval to construct the 550 Megawatt 9 mile 6 to the [mine cycle] plant. The total project cost is estimated at $721 million excluding interconnection and transmission upgrades.

Under the current proposed structure, Entergy Louisiana would own plant, retain 55% of the energy and capacity, and sell the balance under a life of unit power purchase agreement to Entergy Gulf State Louisiana and Entergy New Orleans. The June LPSC filing also requested approval for Entergy Gulf states Louisiana to enter into the PPA for which 25% share of the output 9 mile 6

Entergy New Orleans also filed with the City Council seeking authorization to purchase 20% under its life of unit PPA with Entergy Louisiana.

LPSC approval was requested by January 2012 in order to issue full notice to proceed and maintain the construction schedule for a targeted commercial operations date by the summer of 2015.

Regulatory filings were also submitted seeking acquisition approval and rider recovery upon transaction closing for the 620 megawatt Hot Spring power plants in Arkansas and the 450 megawatt [Hinds] power plant in Mississippi. Posing on both acquisitions is target for mid-2012, subject to receipt of federal and state approvals and other closing conditions.

In transmission. On May 12, utility operating companies each file reports detailing the rationale for joining the Midwest ISO. Total net production cost savings range from $1.1 billion to $1.4 billion compared to $0.8 billion to $1.1 billion by joining the Southwest Power pool over the 10-year period from 2013 to 2022 compared to the status quo. Production cost savings are projected to be realized for customers in all operating companies. The report emphasized the known benefit to our customers of a mature functioning large day to market.

Then on July 1st, Perk issued order on the joint operating agreement between SPP and MISO that confirmed additional power flow between MISO and Entergy would be available over and above the 1000 megawatt interconnection assumed the cost benefit analysis as the [amering] tide that you often hear about.

At issue was whether the joint operating agreement allowed sharing of available transition capacity often called loop lowes, between MISO, SPP and Entergy Arkansas and the events that Entergy Arkansas joins MISO.

Perk found, consistent with past Perk policy as a Entergy Arkansas joins MISO, the joint operating agreement will allow market flows between MISO and the Entergy system across the interconnected SPP members facilities for the shared flow gates.

While additional details need to be resolved between MISO and SPP on compensation matters, perk decision on the JOA and the ability to utilize surrounding transition lines above the 1000 MW interconnection, previously assumed, for purposes of a conservative analysis, while only serve to increase the potential benefits of joining MISO.

Beyond the clear economic benefits of MISO, other factors favored MISO over the alternatives. It's mature operating day to market, larger geography, load and generation resources scaled in the diversity and transition cost allocation policies that are better aligned with our principle (inaudible) cost-causation.

For years we have advocated the efficiency of a cost causation principal. Despite what we often call participant funding, despite pressures to move to a more cost allocation base tariff or what others call rolled-in rates.

Speaking about per quarter 1000, after July 1 issuance, first chairman William Hall stated that a fundamental principle of the new rule is that if there are no benefits, there will be no costs allocated. Perk's policy, requiring cost allocation to be roughly commensurate with the benefit is more aligned with the efficiency and equity of cost causation principles and should provide the protection for our customers similar to those that we have long fought for. However the effectiveness of the new rule will depend on how it is implemented in various regions.

Since the May 12 filling, the utility continues to participate in technical conferences and meetings and have provided additional details on the analysis as requested by regulators. The Arkansas public service commission has a hearing scheduled for September and the docket addressing the system agreement and MISO.

Joining MISO marks a significant transformation of the Entergy system, providing greater independence, transparency, efficiency, addressing the exit of Entergy Arkansas and Entergy Mississippi from the system agreement as well as providing substantial benefits for our customers contributing to the ability to maintain affordable rates for Entergy's utility customers. Utility continues to target a system-wide cut over to MISO by December 2013.

Moving on to Entergy wholesale commodities. Starting with Vermont Yankee. Last Monday we announced that Entergy's Board of Directors voted to proceed with the October refueling outage. This decision followed the Board's careful deliberation on the merits of the case we filed and the arguments put forth by all parties at the preliminary injunction hearing conducted in June. The court has put this case in accelerated schedule for mid-summer trial on the merits of the case. Given that we are in litigation, that's about all we can say about that for the time being. However, even with this expedited trial schedule this litigation could will continue for an extended period of time given the potential for appeals to the second circuit and a writ to the US Supreme Court as many have speculated where this will ultimately end.

Turning the matters in New York. Progress continues on a regulatory front related to license renewal, Economic Safety and Licensing Board issued rulings in July continuing its work to determine issues that will be the subject of hearings and NRC staff determined the supplement the safety evaluation report is warranted to document their updated safety reviews. As a result, hearings at the ASLB likely will not occur earlier than mid-2012 with further delays possible given the complexity of the issues and the number of parties involved.

In June, we filed notice with the NRC that New York State Department of Environmental Conservation had not issued a final decision on our water quality certificate applications within the 1-year time frame required by law. The significance of this is simply if the NRC agrees that a waiver has occurred, that a new water quality certification is not a requirement of the NRC's issuance of (inaudible) points license. But it does not change the need to comply with the New York state water quality standards, which are the subject of the preceding of the state pollution discharge elimination system permit for speedy. For the cooling tower versus wastewater issues being addressed.

Although the speedy process protects water quality is not linked to the NRC license renewal process like the water quality certificate process is. The ALG has finally moved forward with a joint proceeding for both the water quality certificate and speedy's pending a waiver by the NRC. Hearings on several issues are now expected to begin in the fourth quarter of 2011. Written testimony on the first round of issuance was filed July 22 so that process is underway.

Final decisions by the DEC on this trial matters, representing a subset of issues in the speedy preceding are estimated up 2 years away and it could go beyond that. Despite a likely extended time frame to resolve issues on any point license renewal effort, yesterday, we signed a contract extension with CON ED for 500 MW of capacity and energy out of Indian Point units 2 and 3. The terms of the PPA prevent us from sharing all the detail.

However, we can tell you that this content contract is unit contingent and continues on license renewal for a 5-year term extending through 2017 and contains market-based pricing mechanisms within a predetermined range committing low-cost energy to Westchester and New York City while allowing Entergy to meet its goals on hedging energy volumes and periods after license -- current license expiration.

The vital role of Indian Point in the region was clear and a draft report prepared by the Charles River's associates for the New York City Department of Environmental Protection. Key findings of scenarios without the Indian Point included higher wholesale electric cost to consumers, beginning at $1.5 billion each year, and after consideration of subsidies, for economic replacement and likely higher -- lower carbon levels, higher costs quickly rise to over $2 billion per year.

The loss of 1100 direct jobs and associated ancillary jobs supporting the plant, substantial grid reliability issues and increased air pollution estimated at 15% more carbon emissions and 7 percent to 8 percent more NOx. Underscoring these results was released by the EPA in early July of its final rule on cross state air pollution.

While we cannot say that we completely understand how the EPA did it smartly and believe me, we've tried, or that we agree with the results, or the challenges are not likely by a number of parties, this rule is now final. However, based upon where we stand today in our reading of the rules, New York will need to reduce its summer season NOx emissions by at least 44% some purchased of emission offsets from other states and by 54% without those offset purchases.

This summer ozone season of 2010 Indian point provided over 7 million MW hours of NOx free generation. New York will also have to reduce its annual NOx SO2 emissions. Any emissions in the excess of the allowed amount in the state could exposed to generators to maximum penalties of $37,500 per ton per day, and I would emphasize that per ton per day and that's a big number. And requirements to submit extra penalty additional allowances under the clean air act. We expect the generators will reflect the cost of NOx and an SO2 emissions in their bids and also market prices will increase as a result.

Now, summing it up for New York. I know that Indian point license renewal is a significant interest to everybody, it is certainly to us. We believe the arguments for license renewal are very strong and they're supported by the facts as evidenced by the water quality certificate filing at New York State, DEC, and NRC filing for license renewal. The NRC process also requires that Indian point obtains the consistency determination from the New York department of state under the federal Coastal Zone Management Act. Indian point will filed its application in due course, and we believe the factual case supports obtaining the cesium consistency determination especially since Indian point is an existing facility, not a new one, and since the plant is not seeking permission to change its operations in the Coastal zone.

Now, perhaps because of significance of Indian point or maybe because of the proximity of the plant to many of you that conduct business reside in New York, there have already been considerable rumors, speculations, questions that we typically refer to as kind of --inside baseball stuff. --

There is an unusual amount of digging on questions that typically don't come up until the much further into the regulatory process when a public record is starting to emerge. Specifically, speculations on the probability of some sort of settlement of the issues that would provide needed direction to both Entergy and operating the plant and the state for long-term energy planning. We agree that would make a lot of sense for everyone given the importance of the Indian point and the energy environmental needs of New York and the surrounding areas.

As a point of view company, we always have a position on the various issues individually or in total and an economic evaluation of what makes sense for our stakeholders at any point in time. Protracted litigation is always an option, but due to the inherent uncertainty and the cost, the certainty equivalent between a settlement and protracted litigation produce different results in our analysis, utilizing sophisticated decision risk analysis and statistical techniques and the best judgment of experts in each area. In other words, some sort of commercial agreements among all the parties is always the preferred option. On the other hand, when the parties cannot find common ground and we're always prepares to not only rely on the regulatory review process to make our case, but exhaust court appeals if necessary to secure a fair or reasonable outcome.

In Vermont, we went down various paths to achieve a fair and reasonable outcome but the nonnegotiable demand from the state to shut down the plant in March 2012 despite the NRC license renewal until 2032 gave us no choice but to seek relief in federal court.

In New York, it is well-known that we disclosed the fact that the spin off process that we offered a number of options to the state in order to meet their objectives and still achieve our business objectives, including a more efficient structured owned non-utility nuclear asset. In the end, these states demand on Entergy would've been a step backward in terms of our economic efficiency goals compared to the structure we already had in place. We relied on the regulatory process and as you know, we did not succeed. And we chose not to appeal to the courts in that instance.

In other words, our record supports the fact we practice what we preach. We are a dynamic -- emphasis on dynamic-- point of view company, and essentially everything has a price. That is, everything except our ethics and played in gray areas of the law like disclosure issues. Having said that, it is neither appropriate nor advisable to discuss any issue related to any dialogue or any --what if-- that is not part of the public record in the various regulatory processes. We will not answer questions on things like -- whether we have talked to certain parties--

The positions of the Company on various issues of whether they are negotiable, or speculate on other positions or disclose those positions if we think we might become aware of them. Or any other question that could fuel speculation or create mistrust or otherwise interfere with the regulatory process.

Like I said, there have already been a lot of questions or observations that start to feel like almost reverse psychology in order to solicit responses in areas where we have had a long held policy of not speculating on. I know there will be a lot more misinformation rumors since the renewal process duration but to selectively respond to any one in particular despite how much we might want to, given the nature of the rumor, is a slippery slope that we are determined to stay off. So you're going to get a lot of no comments on questions in that area.

Our no comment will not stop others from speculating, but it will not fuel those rumors. I just ask that you trust that we always have your best interest clearly in focus and we have an open mind on how to best protect and promote that.

You all love certainty. Who doesn't? With the exception of some options traders out there, but unfortunately we cannot provide that to you today. But we are very early in the process and as these things typically unfold, sometimes things get better.

At Pilgrim, we are pleased to report the completion of 2 open items requiring resolution before the renewal process in renewed license can be issued. First, on June 30, the NRC staff issued the supplement to safety evaluation report completing the additional safety review of the license renewal application. Than 2 weeks ago the ASLB issued a decision rejecting on remained from the NRC last year, the only admitted contention remaining before them. And appeal of this rejection by the ASLB is possible, and other late option contentions remain outstanding. However, the NRC regulations allow for the issuance of Pilgrims 20 year license renewal while any appeals for late file contentions are pending.

Before closing, I would remind you of utilities extraordinary efforts to respond to winter storms, tornadoes and floods affecting all aspects of operations this year. Efforts include to protecting the generating units along the Mississippi river from potential flooding.

Post monitoring and transmission facilities to keep targeted lines and operations and restoring approximately 216,000 customer outages from multiple storms, primarily on Arkansas and Mississippi. Not only are our employees the best to responding to these challenges, but they do so more safely than ever. With the fewest number of recordable accidents over any 6-month period in the company's entire history. The utility is well-prepared and battle tested as we face the peak of the hurricane season ahead.

Lastly, nuclear operations, in May, Nuclear Energy Institute announced the top -- 2 of the top industry practice awards recognizing safety innovations for 2 of Entergy's nuclear plants. Scrutiny of the safety of the nuclear industry has never been greater, and our employees throughout the Company continued to show that they are committed and up to the task.

And now I will turn the call over to

Thank you, Wayne and good morning everyone.

In my remarks today I will cover quarterly financial results and cash performance and update of our share repurchase program, our 2011 earnings guidance, then I'll share a few closing thoughts on our long-term financial outlook.

Starting with our financial results, on slide 2. Second quarter 2011 earnings were higher than 2 year ago at both the utility and parent and other while they were lowered at EWC.

Second-quarter earnings included accretion from share repurchases. The lower share count is due to the effect of repurchases completed in both 2010 and 2011 including initiation of repurchases against $500 million program during the quarter.

Higher utility results were driven by sales growth across all customer classes, including the effect of warmer than normal weather. Overall retail sales growth on whether adjusted basis was also higher than last year driven by continued strength in the industrial sector.

Turning to other results were higher on reversal of the tax reserve, and at EWC lower power pricing continued to affect results.

Turning now to the details driving quarter over quarter results. At the utility, slide 3 shows higher net revenue as one factor driving the quarterly earnings increase. Overall retail sales grew by 2.9%. For the second year in a row weather was a significant factor. In Entergy's service territory, cooling degree days were 38% above normal for the second quarter. The regions temperatures rank second hottest in 117 years of available data for the second quarter. Texas and Louisiana temperatures were especially warm rankings first and second respectively. June was particularly warm across the service territory with stations averaging at least 4F above the monthly norm.

Residential sales grew 3.7% but decreased slightly on a weather adjusted basis. While the number of residential customers increased 0.7%, the usage per customer on a weather adjusted basis declined.

The trend of increasing industrial sales continued with 2.8% growth this quarter. Industrial expenses in Texas and Louisiana contributed to about 40% of the total industrial increase. Texas is showing the strongest growth of all jurisdictions especially in the industrial sector.

Recent reports from the Dallas Federal Reserve Bank noted the positive outlook for refiners and petrochemical companies along the Gulf coast. Also on a positive note, consumer confidence on the West South Central region which includes Texas, Louisiana and Arkansas ranked first in overall confidence among the 9 regions of the United States.

These bright spots were partially offset by weakening in small industrials as well as paper and wood products segments. These trends have affected Entergy Arkansas and Entergy Mississippi which saw a decrease in the industrial sales compared to strong results in 2010.

Regulatory actions in 2010 also contributed to this quarter's net revenue increase, including rate adjustments in Entergy Arkansas and Entergy Texas, partially offset by a formula rate plan decrease at Entergy New Orleans. Also contributing to the utilities earnings increase was lower interest expense. More than $1.3 billion of refinancing have been executed at an average coupon of 4.6%, a decline of over 100 basis points.

As of June 30 the weighted average coupon rate for the utility debt portfolio was 5.6% with 30 basis points lower than last year.

Moving on to EWC, the quarter over quarter decrease in operational earnings was due primarily to lower net revenue and to higher effective income tax rate. Net revenue for EWC's portfolio declined as a result of lower energy and capacity pricing.

For the EWC nuclear fleet, the average realized price for the second quarter of this year was $52.38 per megawatt hour, or 9% lower than last year.

Capacity pricing has also declined over the last several years due to low demand conditions driven by recession, coupled with a degree of energy efficiency programs success and high levels of demand response. The collapse has been most severe over the last 12 months in New York.

For example monthly spot prices in New York's rest of safe zone range from $0.15 to $0.65 per kilowatt month in the second quarter of this year compared to $0.64 to $3.52 a year ago. The August spot auction for New York rest of state came out a few days ago at just about $ 0.05 per kilowatt month.

A major driver that has affected New York capacity markets over the last 2 months and which will continue to affect in city and rest of state prices unless otherwise resolved has been the addition of roughly 550 MW from the story of 2, but has not been litigated as expected.

There has been some discussion about creating a new capacity zone in New York for the lower Hudson Valley area, potentially by the summer of 2014, such a development could improve capacity pricing for Indian point units longer-term.

Other help in the capacity markets will likely come over several years from retirement of certain generators that currently rely heavily on capacity revenue and we are facing increased environments compliance costs going forward. Also, these little capacity values may drive a retrenchment of low response programs or at least slow their growth.

System load growth remains a wild card but there's some possible upside to compared to New York's current load forecast which are projected to remain below 2010 levels until 2014.

Operationally, the nuclear fleet produced a 91% capacity factor slightly higher than the second quarter last year. This capacity factor improvement is due to 8 fewer refueling outage days this year. Non-refueling outage days were comparable quarter over quarter.

The higher effective income tax rate at EWC also contributed to the lower earnings. In May, the state of Michigan enacted legislation that repealed its business tax replacing it with a corporate income tax. The new tax law which will be effective January 1, 2012 eliminates a future deduction which was available for certain book and tax differences. Given that this deduction is no longer available, EWC wrote off the related deferred tax asset.

Finally, parent and other results were higher this quarter due primarily to lower income tax expense on current and other activities. The lower tax expense is attributed to a reversal of the tax reserve, which results from the settlement of an uncertain tax position. A 2011 guidance assumes a 35% effective income tax rate and a tax which reserves adjustment recorded this quarter is consistent with that guidance assumption.

Moving on to slide 4. Entergy's operating cash flow performance for second quarter this year recorded a decrease are proximally $140 million compared to the second quarter of 2010. This decrease in OCF was driven mainly by 2 factors, lower deferred fuel cost collections and the previously discussed decrease in the Entergy wholesale commodities net revenue.

I'll now turn to an update on our share repurchase program as reflected on slide 5. During the second quarter we completed roughly $105 million of shares repurchases. We purchased a total of 1.4 million shares at an average prices $68 per share. About 75% of the repurchases were made through the existing $500 million Board authorized program. The balance was repurchased offset the diluted effects of grant exercises.

At the end of last quarter, $425 million remained on the existing $500 million program. Consistent with past practice, decisions on whether to buy back stock will be based on a number of factors including current business conditions and investment needs, our liquidity and financial flexibility to quickly respond to changing conditions or opportunities, particularly since we are approaching the peak of hurricane season, and our point of view on the value of our stock.

Slide 6 details our current 2011 earnings guidance which ranges from $6.35 to $6.85 per share on both and as reported an operational basis. The guidance range remains unchanged from the numbers we initiated last October.

As we assess earnings performance to date, we believe we have made good progress through the first half of 2011, and earnings have benefited from favorable weather. Consequently, we are well positioned relative to our full-year guidance range. For the rest of the year, efforts will focus on continuing to produce positive financial results through strong operational performance.

Consistent with our past practice, we normally will affirm or revise guidance on a quarterly basis and we'll revise guidance only when we see factors that move our expectations outside of the overall range we have previously provided.

In closing, I'd like to touch on 2 topics. First I'll make a few comments about our EWC sold forward table in the release, then I'll touch on our long-term financial outlook looking ahead to next year and beyond.

On slide 7, we summarize information from our EWC nuclear sold forward table on page 5 of the release. This quarter we've included a range for the average energy contract revenue per megawatt hour rather than a specific price point. The range takes into account contracts with a collar like the recent extension of the power purchase agreement with CON ED that Wayne mentioned earlier. The lower end of the range reflects contract floors and the upper end contract ceilings.

At the bottom of table 6 the average contract revenue per megawatt hour which includes both capacity and energy revenues reflects the price that the contracts would settle assuming current forward market prices.

Slide 8 outlines key aspects of Entergy's long-term financial outlook. Starting with the utility, we continue to see the long-term growth outlook consistent with the 6% to 8% compound average growth rate through 2014, off the 2009 base year net income. One thing to note is the changes in utility net income can be lumpy, due to several factors, including weather in sales growth, timing of capital investments, and regulatory actions. All of these items do not occur evenly from year to year.

For EWC we expect declining revenues as price trends for energy and capacity play it out over the next few years and both sold and unsold volumes. As we outlined in table 6 in the release, assuming current contracts and forward markets for EWC nuclear output, average prices decrease in 2012 and again in 2013, before recovery starts in 2014. Long-term EWC offers a valuable option on positive effects of ongoing economic growth and environmental regulation.

Parent and other can vary from year to year. Parent interest expense depends on the level of borrowing as well as the cost of debt given the range of possible private and public financing options and the timing of their execution. And income tax expense can fluctuate with resolution of unresolved income tax issues.

Our capital deployment philosophy focuses on maintaining a balanced investment in capital return program. Our capital plan includes expenditures to support continued safe and reliable operations as well as value added productive investments. We also plan to maintain a capital return program which includes common stock dividends and share repurchases. Our current long-term outlook remains to return up to $4 billion to $5 billion to shareholders from 2012 through 2014.

As we move into the next quarter we recognize that many of you will continue to fine-tune your estimates for the coming year and beyond. In that regard we have provided additional details on key business drivers in the appendix of this webcast presentation.

Our over-arching aspiration remains top quartile total shareholder return. Conditions in the commodity markets in the interim uncertainties for the full agenda of strategic initiatives that Wayne reviewed earlier have left us well short of this aspiration in recent years. Nevertheless, the management team continues to focus on delivering results that will create tangible long-term value we can return to you, the financial yardstick of our success. To that end we will continue to focus on safety, operational excellence, risk management, and disciplined capital deployment to maximize the value of our Company.

And now the Entergy team is available for your questions.

Thank you, sir. The question and answer session will be conducted electronically. (Operator Instructions) If you'd like to ask question please do so by pressing the star key followed by the digit one on your touch tone telephone. If you're using a speakerphone please make sure your mute function is turned off to allow your signal to reach our equipment. Once again please press star one and will pause for a moment to assemble the queue.

Thank you, sir. The question-and-answer session will be conducted electronically.

(Operator Instructions)

We'll go first to Paul Patterson from Glenrock Associates.

Good morning.

Good morning, Paul.

Good morning, Paul

On the water permit, if the NRC doesn't agree to the waiver, and if the water permit actually is denied, what would be the next steps?

If the water permit is denied by the state of New York, the remedy available to the company would be to appeal it.

Okay. And can the plant operate, I guess, while that's going on? I guess that's the case with Vermont Yankee. If you guys -- if the case doesn't go your way in Vermont or New York, while it's under appeal, these plants can still operate. Is that right?

Right. A particulate note -- l will make note of the term the timely filed doctrine that allows the plants to continue to operate, assuming that the facility has sought the licensing for NRC, at least 5 years prior to plant expiration. And in the case of New York, our point of view is that the timely found doctrine would apply that would allow the plants to continue operating while we will were resolving issues you just raised.

Great. And just on the capacity markets in the Northeast, we've seen a story in Ravenswood file for emergency -- I don't know -- petition deferred to basically have markets mitigation buyer side market power mitigation. And we're seeing efforts in New England by generators to do the same. Do you guys see the potential for, I guess, ISO activity to potentially raise the capacity market by going after these out of market revenue generators?

Yes, Paul. I mean, we're part of any of those proceedings, both as a member of the ISOs, but also at PERK. I think it's going to play out over the next year or so, both within the ISOs and then also eventually at PERK. So, in fact you've seen preliminary rulings coming out on PGM on the same issue.

Right. So what kind of -- can you give us an idea about what you think might happen in terms of capacity pricing in the Northeast as a result of this? Any sense? I mean, I know, it's kind of foggy right now, but --

If mitigation takes place, I mean, as Leo went through the details what's going on in the quarter, and both those markets, I mean, the prices are depressed. So, with the market mitigation, they fit in anywhere from 75% to 80% of what their new build cost is, what they have to do, fit in to. So, logically, that's going to increase those capacity prices.

Right. And any sense as to how much maybe or is that too preliminary?

I think it's too preliminary.

Okay. Thanks a lot.

And we'll move next to Daniel Eggers from Credit Suisse.

Hey, good morning, guys. Without trying to pin you down on kind of questions you won't answer, are there some external data points we should be following as far as New York's concerned? Maybe to monitor discussions you're having or the process outside of the kind of more obvious New York decisions on the water permit?

Well, I mean, there will be, but I think the water quality permit is, you know, the as we stand today is probably about as front and center as far as what options we would offer or direction that we may have going forward. You know, there is -- again, to get into it, there's already a process. And for reasons I just outlined, and again, apologize I can't at this point, but it just wouldn't be advisable.

But I'd say on large quality permit, and in particular, the issue there which we discussed, what is not approved. The question there in the monitor, is it headed for conditional approval? Or rather than rejection, including towers, flat rejection, or conditions upon something else. I think following those hearings, versus making the assumption that it's up or down rejection or proceed. Other than that, I'm not sure I can help at this point.

Okay --

As time passes, we'll keep you updated in those things that we feel comfortable commenting on our part of the public record, but today there's a bunch.

Okay. That's fair.

And then on -- just on the hedging philosophy right now, there's a big step up in percentage of generation that was sold for 2013 with the contracting. How should we think about kind of the strategy on filling out 2013 or maybe about 2014 to 2015? What you guys would expect as far as selling more that power output?

Dan, this is Leo. We're pretty comfortable with the levels we are right now. We're going to continue to execute on the hedging strategy based on the limits we put in place and our point of view about around the market.

Obviously, we have limits that are based on things like financial policy, liquidity, and credit ratings and the like. We're in pretty good shape where we stand right now for where we want to be. We've had to spend a lot of time figuring out the right way to hedge going forward as Wayne mentioned.

The idea of hedging out beyond the current licenses is one that we have to make sure that we put additional risk management structures around and we do that first before make any transaction decisions. But for right now, we'll really be just basing it on what our point of view is going forward in the markets and where we think things are going to go.

And just to make sure, so the numbers, the 14, 15, those pieces are effective in the Midwest plants plus kind of the end point contract with CON ED, is that a fair representation of mix of what's catching so far?

Majority, yes.

One last question, just on the Cooper plant, is there any exposure to guys given the flooding issues there? As far as maybe additional spending or impact on payments they make you as for running the plant?

Yes, Dan. There's no impact. The plant did very well during the flooding issue. And, you know, we're continuing to watch actually the rivers is already declining and the plant did actually did very well so we don't see any impact there.

Okay. Thank you, guys.

And will take the next question from Ashar Khan from Visium.

Good morning. Leo, if I want to go back to the slides, that was in your guidance for this year, there was a $0.62 negative variance for the weather and -- So based on what you provided in the release, you're up like $0.02 if I'm right on a year-over-year. So am I correct, we are running ordinarily like based on what you provided last year for this year, we're running like $0.64 ahead as we stand on weather for 2011, versus 2010 as a positive thing?

We haven't done third quarter yet, Ashar. So third quarter is really -- as you know for us, given the location of the service territory, third quarter is a big quarter for us -- make or break us either way. We could have weather that's below normal, cooling degree days were above normal cooling degree days.

So yes, we're running pretty comparable to where we were last year which is a pretty big year, both in the winter and the summer. But until we get through the third quarter, I wouldn't declare weather closed in the books yet, one way or the other. And obviously we always go back at the end of the year and when we do next year guidance and we'll adjust back to normal weather for next year as well.

Okay. And the second question if I can ask, what was the average purchase price for the shares that were purchased in the second quarter?

About $68.

$68? Thank you very much.

Our next question comes from Steven Fleishman from Bank of America.

Yes, hi, good morning. Couple questions. Is there any sense of timing or schedule on the NRC ruling on your water permit -- Filing?

Hey, Steve. This is Chuck Barlow. No, there's really -- there's not any pressure on the NRC to make a ruling on that ruling until they get much closer to the actual ruling on our license renewal application.

Okay. This is the waiver issue, correct?

The waiver issue for Indian Point.

Will they take comments on other stuff as part of that so we'll know there's a process, or will just suddenly come out one day?

I don't know the answer to that. We've made our filing, there have been responses filed with the NRC by the DEC and by Riverkeeper, but what their process going forward will be, we really have not been informed.

Okay. And then Wayne I will do my best and try to interpret on what you are trying to say. Maybe I read it as we're just going to hear a lot of things over this period and hearing a lot of things early on. And I guess one thing you're trying to say, look, if in the end it makes sense for shareholders to settle on issues just to let us know that you are going to be looking to what's the best risk return option, I guess?

That's right. That's right. I mean, you are very plugged in as you always are to a lot of these rumors.

I think what's kind of precipitate a lot of this is -- it would make a lot of sense. I mean, for both parties to come together give directions and state directions. Obviously that makes sense.

In the process of posturing, sometimes things get into the press that are just not true or whatever and we can't comment on those kind of things. And then in the process of the trade presses and others, trying to get more information, as you've seen, there are rumors, speculation that have been leaked as fact -- or postured or we've been positioned that's not willing to consider certain things, and that's just not true. I mean, as you've known over the years, we've spent -- some people in this room have spent careers at negotiating table. Sometimes it turned out well and sometimes we have deadlocked, but that is our preferred position, and in this case, it would be a preferred outcome. But it has to make commercial sense.

And I guess the point that we're trying to make is just not a warning -- not to warn you all, but just there will be a lot of things out there that just aren't true. And we would like to respond to them, but we would only get, like I said, create distrust among a lot of parties. And we don't have the best record in New York already coming out of the spin is terms of trust and that nature. And we're trying to rebuild that and commenting on these rumors, it always gets -- words get turned around and things and we're going to stay away from that.

But we are, you know, like you kind of described, we do continue to develop scenarios that would be in the best interest for litigation. And we're open to ideas in any of these processes, and hopefully they won't have to go the whole 9 innings here.

Okay. One last quick thing I guess for Leo. Just on these new data on Hedges with the collars, you might have said this and I missed it. At current forwards would you be at the lower end of the collar on these?

They'd be probably in the middle end of them at the moment.

Okay. So probably the best thing is to assume middle and then if things get a lot better, it's higher and if things get worse, it's lower?

Right. If you look in the table where we get down to the bottom of that table where we put in the percent sold on a revenue basis it's got capacity and energy unit. The energy portion of that is at what we would settle at today if it was the forward curve.

Okay.

In that bottom section of that table, where we present percent sold on a revenue basis, that includes all revenue including capacity, that estimate as a single point and that single point is using today's forward curve as a subtle point.

Okay. Great. Thank you.

Thanks, Steve.

And we'll move next to Julien Demoulin Smith from UBS.

Good morning.

Good morning.

Good morning.

Good morning.

Can you hear me?

Yes.

Great. Firstly, to follow-up on the questions on the nuclear side, the ASLB had previously issued a release suggesting it anticipated resulting the Pilgrim renewal by the end of July 2011. Is there any new comparable date we should be looking out for? Is there any kind of defined or prescribed timeline at this point in the process?

We run currently end of year 2011.

Great. And then secondly, could you comment briefly on your efforts to renew the FRPs in Louisiana -- changes that you have suggested that could be a potential new case filing in the state quick?

We made our last filings for this year term of FRP in May and those rates are going to effect in September. So at this point we will continue to work with the staff, we would intend to work to continue those FRPs and renew those for another term. They've been very efficient -- they worked well for our customers and for our owners.

So you would anticipate resolving the FRP renewal by September or in the next couple of months?

Really, they're two different issues. If you look at the filing that the rates went in they will go into effect in September so we will need to obviously have that approved by the LPSC. And our intent is to resolve the FRP as far as renewals, hopefully by the time we would refile in May of next year.

Great. And thirdly can you just quickly discuss the potential for a Texas rate case in light of these latest register legislation et cetera?

Yes. If you look at Texas and all other jurisdictions one of the fundamentals in our plan is that each of our businesses are under authorized return. The efforts in Texas, as Wayne talked about, if come to fruition, especially the capacity rider would help us do to a lot of that.

The capacity rider may require us to file a base rate case just is to set the baseline. We've already done that for transmission and we proactively already did that for distribution in our last rate case. But we look significantly at, where that is, that's the biggest pressure on it and depending on where they are with relation to ROEs and whether we get these riders done, will require whether or not we will file a rate case which we can do each year in Texas.

Great. Thank you.

We'll take the next question from Michael Lapides from Goldman Sachs.

Hi. You talked at length about process dates rule and the impact on the non-regulated side. Just curious, how are you thinking about what it means for the regulated side of the business in terms of potential rate base growth opportunities in terms of your Arkansas coal plant that may need scrubbing, et cetera?

Okay. This is a complicated question. I'm going to start with like Rob talked about on kind of how it effects that side and I'll let Gary follow up specifically on how their thinking about how it affects the business plan.

Good. The first part of the tag team is we're assessing the impact on the rule. Obviously, the issues for us stem around timing.

Where the EPA prior to what we knew as the transport rule before this finding by the EPA had a -- we were assuming a 2014 effective date. We've now moved up under the rules to 2012. That certainly has an impact.

And when you combine the notion of allowances, all of those affect the perspective cost of compliance and certainly, the fines. On the regulated side of the fence, which Gary can talk to, obviously, there are assumptions made by the EPA regarding the retirement of a plants in our regular did space quite candidly, that are needed. Whether it's reliability purposes, transmission base load, load following, read [mush] run designation, and there's a lot of that we have to do to try and assess where that is, and it's a dynamic process for us.

We're just not at a point right now where taking a firm company point of view because we ultimately have to determine what this means for our customers, and that's an iterative conversation with the regulators. Gary?

Actually, cover probably into 2 parts. The first, is really there is mechanisms for environmental cost recovery for COx and NOx and in each of our jurisdictions in case of EGSL and ELL and NEOI. There are environmental adjusted riders that are available to cover those costs.

As well as through Arkansas post services and APSA and NPSC and the public utility commission Texas which is recover through fuel. The rule is new which we heard from Rob and change significantly from what we saw and expected in 2014. So we are in the process of actually evaluating what would have to be done to each of those plans. In each case there are technological solution that would require some capital investment. We have not that far down the rule -- this road to really say what those are.

We knew what they were going to be, we did not think they would be significant as it existed under 2014 and what was the propose rule. We believe though our initial that as we look forward to it that we would still be able to make those investments, as Rob said those plants they are reliability much run and I believe we will be able to do that in a cost effective way.

But I think that going to be more evolved as we are studying it right now this is relatively new.

Thank guys. I will follow it up offline.

We have no further questions at this time. I would like to turn the conference back to Miss Paul Waters for any additional or closing remarks.

Thank you and thanks to all for participating this morning. Before we close we remind you to refer to our release and website for Safe Harbour and Regulation G compliance statements. Our call is recorded and can be accessed for the next 7 days by dialing 719-457-0820, replay code 8424061. This concludes our call. Thank you

And again that does conclude today's presentation. Thank you for your participation