Duke Energy Corp (DUK) 2011 Q1 法說會逐字稿

Good day, everyone. Welcome to the Duke Energy first-quarter earnings review and business update. Today's call is being recorded.

At this time, for opening remarks, I would like to turn the conference over to Mr. Stephen De May, Senior Vice President Investor Relations and Treasurer. Please go ahead, sir.

Thank you, Ann. Good morning, everyone, and welcome to Duke Energy's first-quarter 2011 earnings review and business update. Leading our discussion today are Jim Rogers, Chairman, President, and Chief Executive Officer, and Lynn Good, Group Executive and Chief Financial Officer.

Jim and Lynn will review our first-quarter results and provide an update on key issues. After these prepared remarks we will take your questions.

Today's discussion will include forward-looking information and the use of non-GAAP financial measures. You should refer to the information in our 2010 10-K and other SEC filings concerning factors that could cause future results to differ from this forward-looking information. A reconciliation of non-GAAP financial measures can be found on our website and in today's materials.

Note that the appendix to the presentation materials includes additional disclosures to help you analyze the Company's performance.

Now I will turn the call over to Jim Rogers.

Thank you, Stephen. Good morning, everyone, and thank you for joining us today. We appreciate your interest and investment in Duke Energy.

Today we reported first-quarter 2011 adjusted diluted earnings per share of $0.39. That compares to $0.36 in the first quarter of 2010, an approximate 8% increase. Earnings at the Company's regulated utilities were slightly lower for the quarter.

US Franchised Electric and Gas experienced higher earnings resulting from the Company's power plant investments and modernization program, but, as expected, this was offset by less favorable weather and higher operation and maintenance cost. Strong results from Duke Energy International and reduced corporate costs contributed to the increase in adjusted diluted earnings per share. These results for the quarter create a solid foundation for the remainder of 2011 as we continue to execute on our business plan.

During today's call Lynn will first review our quarterly earnings. Then I will give you updates on, first, the merger with Progress Energy and related filings; second, our major construction projects, including the Edwardsport IGCC project and the procedural schedules in Indiana; and, finally, our standard service offering in Ohio. I will also spend a few minutes discussing the latest proposed environmental regulations from the EPA and the outlook for nuclear generation in light of the events in Japan.

Now I will turn it over to Lynn for a more in-depth discussion of our financial performance for the quarter.

Thank you, Jim. Turning to slide 5 I will begin with an overview of our financial performance for the quarter.

As Jim mentioned, our adjusted diluted earnings per share increased from $0.36 in the prior-year quarter to $0.39 in this year's first quarter. A discussion of our GAAP reported results of $0.38 is included in our press release from earlier today. The increase in adjusted diluted EPS for the quarter was primarily due to higher results from Duke Energy International and reduced corporate costs, which are included in our Other segment.

Results at the regulated utilities were slightly down. The increased earnings from investments in our modernization program were offset by less favorable weather and expected higher operation and maintenance costs. Our Commercial Power segment performed better than expected, supported by a strong start for the Midwest gas fleet as well as our competitive retail arm in Ohio, Duke Energy Retail.

Slide 6 outlines the significant adjusted earnings drivers for each of our business segments for the quarter. First, US Franchised Electric and Gas.

Quarterly adjusted segment EBIT for FE&G decreased from the prior year even though we continue to experience favorable pricing from our modernization program, principally in the Carolinas and Indiana. We also had more normal weather and higher planned operation and maintenance costs.

As a reminder, during the first quarter of 2010 we experienced significant favorable weather. Heating degree days were 22% higher than normal in the Carolinas and 11% higher than normal in the Midwest. The winter impact to the current year quarter was much closer to normal.

We expected a quarter-over-quarter increase in our operation and maintenance costs, primarily due to inflationary increases and additional costs from planned nuclear outages and vegetation management.

Severe weather has also been a theme in 2011. A first-quarter ice storm in Indiana and second-quarter wind and thunderstorms in the Carolinas and the Midwest caused customer outages and damage to our system. As a result, we expect to see an increase in storm-related O&M costs for the full year, but we will work actively to maintain this increase within the 3% to 4% increase range that we shared with you in February.

I would like to recognize the dedication of our employees and neighboring utilities and also thank them for helping us quickly restore power to our customers who were affected by the storms.

Next, Commercial Power. Commercial Power's adjusted segment EBIT was fairly consistent with the prior-year quarter, primarily due to favorable results from the Midwest gas generation fleet which experienced higher volumes and capacity prices. These results offset the expected segment EBIT decline due to the annualized effects of 2010 customer switching in Ohio.

Our non-regulated Midwest gas fleet performed well during the quarter, supported by higher PGM capacity payments as well as higher energy margins. As a reminder, this fleet will receive capacity payments of $174 per megawatt day through the end of this month. Beginning in June the capacity payment will drop to $110 per megawatt day.

The Midwest gas fleet dispatched around 2,000 GW hours more than the prior-year quarter. This higher-than-expected increase was due to our reduction in natural gas prices which was more significant than the resulting decrease in power prices, and resulted in greater on- and off-peak generation.

Duke Energy Retail continues to successfully capture margin in Ohio. The level of customer switching has stabilized and the overall cost to serve our Duke Energy Retail customers was lower than expected. I will provide a more in-depth update of the competitive Ohio environment in a moment.

Our commercial renewable energy portfolio has grown to more than 1,000 MW and we continue to target annual growth of approximately 250 MW. Even though we have experienced a slowdown in 2010 for additional wind PPAs we are seeing enhanced opportunities for 2011 solar investments, as well as a strengthening in opportunities for wind and solar growth in 2012 and beyond.

Next, let me move on to Duke Energy International. This segment's adjusted EBIT increased principally due to higher average contract prices in Brazil and more favorable average foreign exchange rates. Results were also positively impacted by an arbitration award in Peru.

Finally, our other segment recognized a decrease in adjusted net expenses, primarily due to a prior-year donation to the Duke Energy Foundation and lower corporate overhead costs.

Before moving on to a few other topics, let me address our effective tax rate and provide an update on bonus depreciation. For the quarter, the effective tax rate was approximately 31% as compared to approximately 34% in the prior year's quarter. The higher effective tax rate in the first quarter of 2010 was principally due to a $17 million charge from a change in the tax treatment of the Medicare Part D subsidy. We continue to anticipate a 2011 effective tax rate of approximately 32%.

In February, I highlighted our preliminary estimates regarding the cumulative cash benefits expected from the extension of the bonus depreciation provisions. During that earnings call we estimated a range of $1.5 billion to $3 billion.

In late March the IRS issued clarifying guidance. Most of the expenditures for our major construction projects, including Cliffside, Edwardsport, and Buck, will qualify for 50% bonus depreciation. A significant portion of the Dan River project will qualify for 100%. As a result, we have refined our estimate to be approximately $2 billion.

Turning to slide 7, I will spend a few minutes on our volume trends for the quarter and the economic conditions within our service territories. As a reminder, our 2011 guidance assumes we will see weather-normalized volume increases of about 1% driven by growth of approximately 2% in the industrial class and less than 1% in the commercial and residential classes.

For the quarter, our total weather-normalized electric volumes in the regulated business were flat to the prior year. We experienced strength in the industrial sector offset by weakness in the commercial and residential sectors.

Let me first address our weather-normalized industrial volumes, which were about 4% higher than the prior-year quarter. As the economy and industrial activity continued to recover, growth persists across a broad range of our major industrial classes including steel, automotive, and textiles. We continue having discussions with our primary industrial customers to gain further insight into their expectations for future production levels. Most expect 2011 to be consistent with or slightly favorable to 2010 with that trend continuing into 2012.

For the quarter, our weather-normalized residential volumes were down about 2%, a trend that has been recognized by other utilities during this earnings season. Although we continue to see modest growth in the number of residential customers in both the Carolinas and Midwest, there is a small reduction in average kilowatt hour usage per residential customer. A sluggish recovery and high unemployment may be influencing their usage patterns.

Finally, our weather-normalized commercial volumes were also slightly down for the quarter. Despite this weakness, we are seeing positive economic signals. Office vacancy rates in our principal metropolitan areas are trending down, consumer retail sales continue to experience strength, and the employment picture has slowly improved. However, these trends have not yet translated into sustained levels of growth in the commercial and residential sectors.

For the balance of 2011 we expect to continue seeing growth in the industrial class. It is too early to determine if the recent weakness in residential and commercial usage is a continuing trend, but we will watch it closely as we progress through the year.

I will now discuss more details on the competitive environment in Ohio, including the level of customer switching. A chart showing the trend in customer switching since December of 2009 is on the right-hand side of slide 8. As displayed by the light blue and red bars on the graph, the level of customer switching in Ohio began to stabilize in the third and fourth quarters of last year.

This stabilization has continued into 2011. As of March 31, approximately 67% of our native load customers have switched to other generation providers as compared to approximately 65% at December 31. Our competitive retail arm in Ohio, Duke Energy Retail, continues to serve approximately 60% of our Ohio customers who switched helping to preserve margin. As a result, Duke Energy is providing generation services to approximately 73% of the customers in our Ohio service territory.

We do not expect a significant change in customer switching levels for the remainder of the year. As a result of annualizing the effect of switching which occurred in 2010, we continue to expect a $0.05 to $0.06 negative earnings impact for net switching in 2011. We expect the majority of this negative impact to be recognized in the first half of this year.

In summary, our financial performance through the first quarter keeps us on track to achieve the $1.35 to $1.40 adjusted diluted earnings range for 2011 that we have forecasted earlier this year. For the remainder of the year, we will continue to focus on effective cost control and operational performance.

The strength of our balance sheet supports our ability to continue growing our dividend, targeting a long-term payout ratio of 65% to 70% based upon adjusted diluted earnings per share. Additionally, we are well-positioned to achieve our targeted 4% to 6% long-term growth in adjusted diluted earnings per share.

Now I will turn it back over to Jim.

Thank you, Lynn. Let's take a look at slide 9 which contains a merger scorecard to update you on our various filings and approval status related to the merger with Progress Energy.

We filed our initial S-4 on March 17. We made amended filings on April 8 and April 25 in response to comments from the SEC. We are currently targeting shareholder meetings late in this quarter or early in the third quarter.

In April, the companies made merger-related filings with the North Carolina, Kentucky, and South Carolina state regulatory commissions. Hearings have been scheduled to begin in North Carolina on September 20. Hearing dates in Kentucky and South Carolina are pending.

We have also made filings with the Federal Energy Regulatory Commission, the Department of Justice, and the Nuclear Regulatory Commission. Our initial Hart-Scott-Rodino Act filing with the DOJ was made in late March and the required 30-day waiting period has expired. Requests for additional information have not been received; therefore, our obligations under the Hart-Scott-Rodino Act have been satisfied.

We will continue to provide merger updates to the commissions in Indiana, Ohio, and Florida as requested. Additionally, several existing affiliate agreements are required to be modified and will be filed for approval as applicable.

Currently, integration planning teams consisting of Duke and Progress employees are on track and preparing comprehensive analysis of both companies. They will identify best practices and processes, and determine the most optimal ways to operate our combined organization. We continue to target a closing date by the end of the year.

The status of our fleet modernization projects is outlined on slide 10. We continue progressing with our Cliffside, Buck, and Dan River projects in North Carolina as well as our Edwardsport project in Indiana. In total, these 4 projects represent investments of approximately $7 billion and about 2,700 MW of capacity.

Buck is scheduled to be in service later this year and Edwardsport, Cliffside, and Dan River are expected to be in service in 2012. We currently have a request pending with the Indiana Commission for an increase in the estimated cost of Edwardsport from $2.35 billion to approximately $2.88 billion including financing costs.

This project continues to make sense for the following reason. Our updated IRP analysis continued to confirm that we need additional capacity in the state and completing the plant is the least costly option for that additional capacity. The project will help meet the long-term growth needs of our customers in Indiana with less impact to the environment. And finally, the plant will use coal, an abundant Indiana resource, which supports local jobs in the state.

In March, we filed testimony with the Indiana commission related to the cost increase proceeding. In this testimony we have made a proposal to the commission which is structured to mitigate the near-term customer rate impact of the cost increase above $2.35 billion.

Turning to slide 11, you will see that our proposal consists of three components. First, we proposed to cap our recoverable construction costs at $2.72 billion excluding financing costs related to the project's construction. Costs above this hard cap would not be recovered in customer rates.

Second, we propose to waive the incentive approved by the Indiana commission in 2007 related to how deferred income taxes are treated in the cap structure, an estimated annual pretax earnings and cash flow impact of approximately $25 million. Finally, we proposed a reduction in depreciation expense that would result in an estimated annual pretax cash flow reduction of approximately $35 million.

This proposal strikes a balance between several important objectives -- the continuing need for new and modernized power generation, minimizing the rate impact to customers, and providing shareholders a reasonable return on their investment. The hearing to review the estimated cost increase, including our proposal to cap recoverable costs, is scheduled to begin October 26.

Additionally, certain interveners asked the Indiana commission to examine whether Duke exercised undue influence over the commission related to Edwardsport. The commission denied this request on February 25 citing lack of statutory jurisdiction. However, they ordered that the Edwardsport case be expanded to review interveners' allegations of fraud, concealment, and/or gross mismanagement with the burden of proof resting with the interveners.

The interveners will file testimony on July 14 and the hearing is scheduled to begin on November 3, after the hearing on the estimated cost increase.

Next, turning to slide 12, I will update you on our progress in Ohio. In November of last year we filed a request for the Public Utilities Commission of Ohio to transition to market-based generation beginning in 2012. Our current electric security plan expires at the end of 2011. This market rate offer, or MRO, was designed to deliver competitive and fair rates to our customers and create mechanisms that provide opportunities to earn adequate returns on our Ohio generation investments.

In February, the Ohio commission issued an order denying our MRO filing on the grounds that it did not meet statutory requirements. We filed an application asking the commission to reconsider its decision and they have agreed to do so. We await their pending decision.

Our objectives in Ohio remain the same. First, ensuring stable prices and reliable service for our customers and, finally, obtaining mechanisms allowing us to earn reasonable returns on our investments in Ohio.

It is critical that the state implement policies giving utilities the appropriate level of financial protection, allowing them to make capital investments in Ohio. Such investments benefit Ohio in terms of job creation and economic development.

We continue evaluating several options for our next SSO filing, including the possibility of filing an ESP proposal in the second quarter. Last week we filed a stipulation and recommendation with the Ohio commission. It addresses how costs related to Duke Energy Ohio's proposed move from MISO to PJM, effective January 1, 2012, will be treated in the customer rates.

The stipulation was also signed by the commission staff, the office the Ohio Consumers Council, and the Ohio Energy Group. The stipulation proposes that Duke Energy Ohio will be able to recover all MISO transmission costs. Also, we will be able to recover all PJM transmission expansion costs above $121 million over time.

MISO exit fees, which are estimated at approximately $20 million, will not be recovered from customers. This stipulation, if approved by the commission, represents a major milestone with our proposed transfer to PJM.

Let me spend a few minutes with an update of recent developments related to environmental regulations. In March, the proposed air toxic rule was issued by the EPA, a rule that is expected to be finalized in November of this year. And the EPA also proposed rules on cooling water intake structures at facilities such as our power plants, and these are expected to be finalized by July of 2012. Slide 13 illustrates our generation profile in relation to these rules.

I want to highlight a few points related to our potential exposure under these proposed rules. First, the anticipation of more stringent environmental rules has long been part of our business plan. Over the past 10 years we have spent $5 billion retrofitting existing units with updated emissions controls. These investments have helped us to reduce sulfur dioxide emissions by 73% and nitrogen oxide emissions by 52% over the past five years.

Additionally, we are currently spending approximately $7 billion on our fleet modernization projects, which will give us the ability to retire a significant amount of our older, less-efficient coal generation which has not been remediated with modern emissions control devices. Today approximately 75% of our current coal generation capacity has scrubbers in operation. This will increase to approximately 90% once our fleet modernization program and related retirements are completed.

Next, let me give you a few thoughts on the proposed cooling water intake rules. We could have some exposure for additional capital requirements at our once-through cooling steam generating units. However, any exposure will be dependent on the final form of the rules, including whether there are requirements for closed-loop cooling systems as well as how stringent the entrainment provisions are.

Finally, it is important to highlight that rather than looking at each of the proposed rules individually, we evaluate all of the pending environmental requirements together. Any economic decision to spend additional capital or retire units are based on the totality of all proposed environmental rules and expected future regulations taken together. Such decisions will be dependent upon finalization of the rules as well as reasonable timeframe for compliance.

We are currently modeling several potential scenarios which could result in additional capital expenditures of approximately $5 billion for compliance over the next 10 years. In the short term, our current 3-year CapEx plan assumes environmental capital of approximately $800 million through 2013, mostly for updating some of our current emission controls in the Carolinas and Indiana.

As the EPA further defines these proposed rules it is important for them to consider the following. First, there must be a reasonable transition period in order to allow utilities to comply with the new rules. The rules proposed have compliance periods that are too aggressive and do not give us adequate time to permit and install new pollution control devices.

Second, this could result in more plant closures than would otherwise be necessary, causing a strain on our ability to continue providing reliable power. And finally, we must also ensure that the EPA maintains flexibility in how we can comply with the rules, helping to keep the cost of compliance to a reasonable level.

We will continue to evaluate these rules and refine our assumptions as appropriate. Additional information on our environmental initiatives and sustainability plans are contained in the recently released Duke Energy Sustainability Report now available on our website.

Moving on to a nuclear update, the recent devastating earthquake and tsunami in Japan will result in increased scrutiny on nuclear operators throughout the world. The NRC announced a review of nuclear risk in the United States, a process that will, in our judgment, likely stretch into 2012. We support this review and will be active participants in the process.

As you recall, we operate 7 nuclear units and the map on slide 14 shows you their locations. Since March 11 when the earthquake and tsunami hit Japan, we have been actively working through multiple industry organizations, including the Institute of Nuclear Power Operations and the Nuclear Energy Institute, to offer assistance to the people of Japan.

It is too early to speculate on any outcomes of the NRC's review process. However, it is important to understand that safety and continuous improvement are deeply embedded in the culture of our company and they are especially strong within our nuclear organization. We have been safely operating our Duke Energy nuclear plants for almost 40 years and last year marked the 11th year we have had capacity factor above 90%.

We routinely incorporate lessons learned from worldwide experiences, as we did after Three Mile Island and after the events of 9/11. Likewise, we will incorporate the lessons we learn from our own analysis and the NRC's review of the events in Japan.

As you know, we are in the early stages of developing our proposed Lee Nuclear Station in South Carolina. We expect it to be operational in the early 2020s, which gives us plenty of time to carefully analyze and incorporate the knowledge we will gain from Japan's experience.

In order to continue maintaining new nuclear as an option we have filed amended project development applications to the Lee Project with both the North Carolina and South Carolina commissions. These applications request approval of our decisions to continue incurring project development related costs for Lee Nuclear. We anticipate receipt of our combined construction and operating license in 2013, and we will continue pursuing additional nuclear partners.

Finally, we must obtain the appropriate legislative framework in North Carolina that will allow us to invest in new nuclear development.

Although we are experiencing continued support for nuclear generation, the events in Japan have affected views of the appropriate timing for legislation related to the annual recovery of financing costs for new projects. The legislative filing deadlines in the General Assembly passed without the introduction of desired legislation. We believe this legislation is critical to keeping nuclear power an option for North Carolina and we continue to work with policy makers on this issue.

On slide 15, you will see the key priorities that we presented in February. In 2011 our focus remains on successful completion of the merger, excellent operating performance, efficient cost management, a strong balance sheet, and continuing to deliver a competitive total shareholder return to our investors.

2011 will be an important year for regulatory activity as we will be making filings for updated rates in the Carolinas and working on our next steps in Ohio. Additionally, we continue to work toward a constructive outcome in Indiana on our Edwardsport cost increase proceeding.

I am pleased with where we are through the first quarter and with our employees' continued focus on our day-to-day operations. This supports our mission to deliver affordable, reliable, and clean energy benefiting our customers, investors, and the communities in which we serve.

Now let's open up the phone lines for your questions.

(Operator Instructions) Angie Storozynski, Macquarie Capital.

You mentioned that you expect your customer switching to stabilize and you actually do not expect change in the current level of switching going forward, and yet we have two big companies in your region both with very aggressive retail plans. How can you reconcile those two?

Thanks for your question. I think, if you look at the slide that we shared on slide 9, we have been at the switching experience for some time. Early on we saw rapid switching of the industrial and commercial base and now we are kind of into residential. And you will notice that we have seen stabilization really going back into the third quarter of 2010, so I think we are into an area with a customer base that is, frankly, stickier than what we experienced early on.

The other thing I would say is in addition to switching, perhaps stabilizing, we have also been very aggressive with our own retail offering and been successful in retaining customers in that way.

And do you expect that trend to continue past 2011?

You know, Angie, I think 2012 is difficult predict because we don't yet have a price for 2012, that is the importance of the SSO negotiation that is ongoing. So think it's premature to talk about 2012 at this point.

Okay, thank you.

Michael Lapides, Goldman Sachs.

Two questions; one related to the merger. How should we think about the risk or reward to the potential O&M synergies, the non-fuel O&M synergies level? Meaning your ability to far exceed the level of O&M synergies you have discussed and the challenges you will likely face to get to the levels you have discussed.

Michael, I will start and I am sure Jim will have something to add. We have been focused early on and describing quite clearly the fuel and joint dispatch savings on the merger, and so in our filings you will notice our reference to $700 million that our intent would be to flow to customers right away.

We are still in the midst of merger integration planning. We have not disclosed a specific target on non-fuel O&M. We do expect, because of the contiguous nature of the companies and certainly corporate costs, etc., that we will be able to achieve what would be a very significant amount in that area. But it will depend upon how the integration comes together and it will come together over time.

So as we get closer to closing and further into integration we will be in a position to talk more about it, but at this point nothing further.

Okay. Second, Jim, when you think about the environmental regulations, especially the HAP or the MACT rules, how much flexibility do you think the administration and the EPA has in terms of the timeline of implementation?

Michael, my judgment is they do have flexibility with respect to the timeline, although there is some that argue that they don't with respect to it. But I think it's up to them to make the decision, given the magnitude, the number of rules that are being proposed and subsequently implemented, to give us enough time to do this in a way to smooth out the cost impact on customers and do our best to limit the cost increases associated with meeting their targets.

Got it. So in your view, the Clean Air Act amendments of '90 and prior amendments gives the EPA flexibility on the timeline?

I think it does. I mean, think about it. In 1990, when the rule was past, they had five years before they started compliance which gave us plenty of time to get ready. They have proposed three years now on some of the rules and so I think they have flexibility to push those rules out.

Historically, it has been five years for compliance. Three is inconsistent with the way it has been in the past.

Got it, okay. Thank you, much appreciated.

Paul Patterson, Glenrock Associates.

Good morning. I wanted to follow up on I think you made the statement, Lynn, that the cost to serve in the Ohio territory was lower. Did I hear that correctly or --?

That is correct, for Duke Energy Retail.

And why was that?

You know, Paul, we haven't dissected it any further than the fact that we were able to achieve costs less than what we had planned. I think it's a combination of market conditions. It's also a combination of the hedging that we put into place relative to where we plan to be.

Okay. So you sourced it better maybe, is that one way to sort of think about the --?

I think that is one way to think about it, yes.

Okay. Then when you are looking outside the service territory, clearly you guys have a retail arm there that is working in the service territory. Are there any thoughts about expanding maybe a little bit more aggressively outside since there is some switching and you have got some extra power?

You know, Paul, we have been competing in Ohio. We have not moved outside of Ohio at this point, but we are trying to take advantage of opportunities we see outside of our service territory as well.

Okay. But any thoughts about anybody in particular you might be looking at?

Nothing in particular.

Had to ask, okay. And then with respect to the DEI Peru arbitration is there an ongoing effect from that?

You know, Paul, that is a settlement of a tax matter that originated in the earlier part of the decade that was resolved in our favor. So it's not ongoing; it's just an event that impacted this quarter.

Okay, great. Thanks a lot.

Nathan Judge, Atlantic Equities.

I wanted to follow up on page 13 of your presentation and thank you for this additional detail. There is a couple of questions here. One, could you just kind of reconcile what your outlook related to the three -- coal combustion residuals, transport rule and air toxics rule -- how that expectation stands relative to your expectations at your analyst day in early 2010?

Nathan, I will take a shot at it and, Jim -- Dhiaa Jamil is also here if they want to add to it. As we looked at proposed rules in all these areas, we have been running a variety of scenarios and -- as you would expect us to, just kind of using the intelligence of what has been developing in these regulations. So it was within a tolerance of what we were expecting and we are learning more as these rules are finalized.

I think it's also important, Nathan, to keep in mind that we are going to be retiring more than 1,000 MW of older high-emitting generation, and that was part of the modernization plan to get prepared to retire that. So at the end of the day that reduces the cost associated with addressing the emissions issues associated with those old plants, because the economics really drove us to say, at the end of the day, it's going to be better to retire than try to retrofit.

And actually -- which is a great jumping off point to the follow-on question to that. Your $5 billion has remained pretty constant and the EPA, especially on the air toxics rule, contends that dry sorbent injection or the dry scrubber is sufficient to get you to the compliance levels.

Can you give us any thought on that, your ability to do that? And as you see that 14% on the post modernization scenario in that upper right-hand corner, what is it that would still need to be evaluated? Why are these 14% not determined what you are going to do with them?

Nathan, let me just turn it over to Dhiaa Jamil who runs all our nuclear and fossil.

So, Nathan, the rules or the proposed rules, particularly on MACT and the air toxics, were within -- the MACT piece, the Mercury piece was within the expectations that we have had in our analysis. So from that perspective maybe we have lost a little bit of operational flexibility, but the scenarios that we are running remain as we have expected.

The new variable that has been introduced is the particular portion of that. It is too early for us, really, to see the impact of that to our plans. The limits that have been proposed include some aspects of the -- particularly the condensable ones that we do not have -- frankly, do not have data on that we need to go do some testing to see whether it will have an impact on our plans or not. So that is really the only new variable that is being introduced that we need more time to review.

We believe we may have a shot at meeting that. It may require some additional control equipment, like baghouses, but those are not -- in totality when you look at what we already have, what we plan to retire may move the number slightly but not significantly.

And just as a shape of CapEx for environmental, and I think you have been asked before, but there was this proposed rule. On that $5 billion over 10 years can we just get on idea of now with the EPA saying that compliance will be in 2015 is that going to accelerate, i.e., lift your CapEx expenditures between now and 2013 and looking out to 2015?

Nathan, once again, the variable here is the particulate and I don't think we are in a position to address that now. If -- we need to do some testing to determine whether our current control equipment can handle that. If it can't, then that would mean we need to accelerate some of that expenditure to the earlier years.

Of course, there is still possibility of, as Jim mentioned, pushing the compliance period beyond the three years.

Yes, okay. Great, thank you. Then just up on the Edwardsport. Could you -- as it relates to the construction schedule, how confident -- obviously as you make progress, you are now 85% complete -- are we past or are we getting close to a major milestone where you feel highly confident that there won't be any variances and that estimate that you have currently will be consistent with your plan? Or how -- could you just give us an idea of your confidence in that forecast today versus what you were 3 or 6 months ago? Thank you.

I think we are confident in our estimates. One of the issues that we are struggling with is labor productivity, and that could alter it. But one of the things that we have done, as you know, is put a cap on the construction cost. We were comfortable with putting a cap on it, primarily because we were comfortable with where we are.

But if the labor productivity continues to be a problem that doesn't -- that at the end of the day won't translate into huge dollars. But it could translate in costs greater than our current estimate.

Is there a timeline when we will know what that update would be?

I think it's -- again, the labor productivity issue is really kind of month to month. It's hard for me to give you, yes, we will know at the end of this year or we will know in February. It's having continuous, steady productivity from our workers. That has been a problem in the past and I think we have it fixed, but we are not positive of that yet.

Is there any way to quantify how much potential degradation there is relative to expectations at this point?

In the terms of a $2.88 billion plant the numbers are very small, but nonetheless it's difficult to quantify at this moment.

Thank you very much.

Paul Fremont, Jefferies.

Thanks. My first question relates to the MRO SSO filings. If we get to the end of the year is it safe to assume that whatever rate is in affect this year would remain in effect next year? And would -- what portion of that charge going into next year would be by-passable versus non-by-passable?

Paul, you are right to assume that the rate will continue into effect if we haven't reached any agreement with the commission in 2012. And virtually the portion that is by-passable in 2012 will be the same as it today.

Okay. So there is no change then in terms of what you are collecting, in terms of not by-passable charges, as a result of not having either an approved MRO or an ESP in place?

Doesn't change at all.

Okay. And then my second question relates to -- I guess it's your slide 13 on the EPA regulations. For the Midwest what would be sort of the net megawatt retirement number -- and I guess that includes I guess Edwardsport coming online -- under these two scenarios? So in other words, I guess it looks like 21% would be the low end and 35% would be the high end, if I am reading that chart right.

Yes, let me speak to Indiana first. I think in Indiana -- first of all, in the Carolinas we are looking at retiring roughly 1,000 MW. In Indiana the number could be as much as -- it's both the Gallagher and the Wabash units; they could be as much as 700 MW.

Paul, I would direct you to slide 28 that gives you -- 27. I am sorry, 27. It gives you the breakdown by jurisdiction of the no SCR and scrubber category.

Right.

I am sorry, Jim.

No, that is good. And actually both pages 27 and 28, where we break down each facility that we own -- coal facility we own, I think would be a very valuable information for you all to read and review. Because we wanted to give you really kind of as granular detail, with respect to each of our units, so you all were able to draw your own conclusions rather just than accepting our statements about it.

All right. I think the slide sort of tells me where -- what is scrubbed, what is not scrubbed. But sort of going back to what Jim was talking about, Jim, you were saying roughly 700 MW potentially of net closure in Indiana. Anything in -- and what would be the equivalent number for Ohio?

Okay, it 1,000 MW in Carolina, 700 MW in Indiana, and I believe it would probably be the [Beckshort] plant.

860 MW at [Beckshort].

Thanks. Thank you very much.

Jim von Riesemann, UBS.

Good morning, everyone. How are you?

Good, Jim. How are you?

I am well up here. Just a couple of questions, really on a different topic. This American Transmission joint venture that you announced in mid-April, can you provide some more color around that JV, why you got into it? And then what is some of the monies that might need to be committed now and then in the future?

Jim, we have been pursuing and looking at commercial transmission opportunities -- you might recall we announced a pioneer joint venture with AEP a couple of years ago -- really looking at opportunities to move into transmission to the extent we can find projects. And so this relationship with American Transmission is nothing more than that. We have not made a specific capital commitment at this point, but really have begun to explore transmission with ATC.

Okay, thanks.

Ali Agha, SunTrust.

Thank you, good morning. I know it's early, obviously, in the year right now, but if I look at your commercial results year-over-year and for the quarter and I compare that to what your full-year guidance is year-over-year looks like you are doing significantly better than what you would have planned for the year. Does that change your outlook for the year going forward?

And related to that, how did the first quarter actually end up versus your original expectations, given that you did come in fairly positive?

Ali, it's a good question and if you parse the words I just read it was higher than expectations. So certainly the commercial group had a very strong first quarter. I would point you to improved performance of the Midwest gas assets as being a key driver of that. The generation was up 200% on-peak, 500% off-peak. We were able to take advantage of some market conditions.

It's premature to reset expectations for the year on this. We would like to get deeper into the year to understand the full composition of all aspects of the business before we raise expectations. But as you noted, off to a very strong start.

Okay. And also, could you remind me, when you look at your utility business right now on a blended basis on average, what kind of rough ROEs are embedded in your 2011 guidance versus what you actually earned in 2010? Is that a pickup, some basis points pick up in 2011 versus 2010 assumed there?

Ali, we had a slide in our year-end results, our guidance, that kind of set out ROEs for 2011 and gave some perspective of where it relates to 2010. So for example, in the Carolinas on an adjusted basis we delivered 10.8 in 2010. We are expecting 2011 to be in the range of 9.5 to 10. As you know, 2010 had an extraordinary amount of weather in it.

So we have each of the jurisdictions broken down actually in that year-end guidance, which we would be happy to direct you to.

Yes, so those expectations -- again, it's early in the year, but O&M expenses, etc., that you highlighted doesn't change your thinking for the year for the utility business?

That is correct, not at this point.

Okay. And last question, to be clear, when you folks talked about $800 million of environmental CapEx embedded in your next 3-year CapEx budget related to the $5 billion you plan to spend over 10 years, are those the same? So the $800 million is part of the $5 billion?

Yes, it is.

Okay, thank you.

Jonathan Reeder, Wells Fargo.

Can you talk about what your strategy would be as far as extending the EPA compliance period? I mean is that trying to get the final rule extended or is it presidential order? What is the strategy there?

Well, I think we still have a comment period with the EPA and there has been testimony on -- by EEI before congressional committees with respect to extending the time. There is also the possibility that a company could negotiate its own compliance plan in terms of scheduling the retirements and the compliance. There is a possibility to pursue that. No company has done that yet, but I think it's a possibility.

So my judgment is this is -- these regulations are moving targets, but they are inevitable. We have accepted that and we have run many scenarios, as Dhiaa said, as to what the schedule will be, what the costs will be, what the implications are for every unit. And so, again, we think that we are in the right place in terms of positioning ourself, one, given our prior investments, as we mentioned earlier, and two, the modernization plan.

We have really mitigated a lot of the risk and the cost associated with this program by the early steps that we took.

Do you feel that there is, I guess, consensus within the industry to get behind the extension, be it out to, call it, like 2018, where there is going to be a concerted voice telling the EPA this is what is required? Or is it more just company by company basis depending on the generation mix?

I think, first, I think the industry overall would like to see it delayed, but there is a mix of positions within the industry. Because there are those that are in PJM, for instance, where if you get an acceleration in the retirement of coal plants it's going to drive prices up. So if you are a nuclear Operator there or have gas plants there you will benefit from those retirements.

So it's kind of where you sit is your position on these things and how you prepared yourself for what is coming sort of informs your position. So there are differences of opinion, but I think that overall the industry believes it needs a little more time. And there is not a consistent -- there isn't a clear view as to how much time -- and a little more flexibility in terms of compliance with these new rules.

Okay. And then shifting years a little bit to the state level. Two questions, one with North Carolina and the lack of the quip legislation. Is that something -- if it gets introduced I guess in the next legislative session and presumably you get it passed, that would still keep your aspirations for Lee on time, is that correct?

Absolutely correct. I was on the stand discussing this. And as I explained to them, it was really key -- and this was testimony before the state commission. It was key to us building this plant that we get a quip provision that allows us to track the cost.

The alternative to that isn't very appealing to either us or to them, and that is filing a rate case every year. That would be an alternative way to achieve what we could get with tracking, but it would be very (technical difficulty) and time consuming for both the regulatory agency and for us. But that would be another way to achieve that objective.

Okay. And then last question on Ohio. Is it your understanding that the PUCO is still, I guess, open to an MRO as opposed to an ESP or do they prefer the ESP option in general?

Well, if I was betting today I would say their bias is for ESP and again -- for an ESP and against an MRO. The truth of the matter is the commission wants to have -- continue to have control over the low-cost coal plants that we own and we are perfectly comfortable with them having control as long as we get a fair return on that investment. That has been really the whole debate in terms of working our way through this.

And a fair return that is not by-passable. It could be in a demand charge. It could be designed a number of different ways. But we think it's really critical that if they want us to commit the assets and we do commit the assets -- and it might be for 10 years or 20 years or longer -- if they are going to get that benefit, we need to get a fair return on it.

All right. Thank you for your time.

[Dan Jenkins], Bank (sic) of Wisconsin Investment Board.

State of Wisconsin Investment Board. But first question related to your financing plans you are showing on page 32 of the slides, particularly for the Carolinas. I was wondering if you could give us any more detail as part, when in the year you expect that to occur. Is that primarily for CapEx financing or are you refinancing some short-term debt too?

It's primarily CapEx financing, Dan, and it will be later in the year. We haven't announced specific timing on those issuances.

Okay. So probably not this quarter then, this current quarter?

Second quarter? We just started second quarter; I would say maybe. We tend to look at market conditions and also measure our cash positions, short-term borrowings, etc. So still under review; we would intend to finance this.

We may also take advantage of some pre-funding of planned maturities in 2012, but that would be later in the year 2011.

Okay. And then you mentioned that you expect -- I think I heard you say this -- you expect to file another rate case in North Carolina sometime this year.

That is correct.

Probably midyear.

Okay, midyear. And then what is the current ROE that you are earning in North Carolina? Do you know that?

It's around 10% -- 9.5% to 10%, Dan. And so this will be a case that we have planned for some time. It's primarily rate based case. It's continuing to pick up the Cliffside investment, the Buck plant that is scheduled to go in service this year. So you can expect that to be filed midyear, both North and South Carolina.

Okay. And then the last thing I had kind of related to that is if you could give us a little bit of an update on Cliffside as far as a little more detail on what are the critical path items coming up on that and how the budget is going on Cliffside?

Cliffside is about 85% complete. We expect to bring it online in 2012, and we are on plan and on budget.

Okay, thank you.

That concludes the question-and-answer session for today. At this time, Mr. De May, I would like to turn the conference back over to you for any additional or closing remarks.

Thank you for joining our first-quarter earnings review and business update. As always, the Investor Relations team is available for any follow-up questions. Have a great day.

This does conclude today's conference. We thank you for your participation.