Duke Energy Corp (DUK) 2011 Q2 法說會逐字稿

Good day, everyone, and welcome to the Duke Energy second-quarter earnings conference call. Today's call is being recorded. At this time, for opening remarks I would like to turn the call over to Mr. Stephen De May, Senior Vice President of Investor Relations and Treasurer. Please go ahead, sir.

Thank you, Kelly. Good morning, everyone, and welcome to Duke Energy's second-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 our key priorities. 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. Thank you all for joining us today. We appreciate your interest and investment in Duke Energy.

During today's call, we will provide a review of our quarterly earnings followed by an update of, one, our pending merger with Progress Energy; two, our major construction program; three, our proposed Electric Security Plan in Ohio; and four, our base rate case filing in the Carolinas. These initiatives are positioning the Company for long-term stability and earnings growth in the future.

I will also update you on Edwardsport and discuss a proposal we filed with the Indiana Commission in April. It is an equitable proposal and provides a path forward on this important project.

Finally, I will end the call with some observations on the most recent EPA ruling and the NRC Task Force review of the events at Fukushima.

Today, we reported second-quarter 2011 adjusted diluted earnings per share of $0.33. That compares to $0.34 in the prior year's quarter. With the second quarter, we continued our positive momentum from the first quarter.

The Company's largest business segment, U.S. Franchised Electric and Gas, achieved solid performance due in part to its new generation investments in the Carolinas and Indiana. This helped offset less favorable weather and higher operations and maintenance cost primarily related to storm restorations.

Duke Energy International delivered strong results, as did Commercial Power despite the financial impact of 2010 customer switching in Ohio.

For the year, we are well on track to achieve our guidance range of $1.35 to $1.40 in adjusted diluted earnings per share. And as you all may recall, our third quarter is typically the most significant of the year.

I am very pleased with our second-quarter performance, and we are well positioned to execute on our business and financial plans for the remainder of the year.

Now, I will turn it over to Lynn, who will give more detail on our financial results for the quarter.

Think you, Jim. Slide 6 outlines the adjusted earnings drivers for each of our business segments for the quarter. For U.S. Franchised Electric and Gas, quarterly adjusted segment EBIT decreased from the prior year.

While we benefited from weather this quarter, it was less favorable than the second quarter of 2010. In addition, we incurred significant storm restoration costs. Both of these were offset by the continued earnings contribution from our new generation investments.

Destructive storms have been a theme in the first half of 2011. Storm costs for the quarter were approximately $53 million higher than the prior-year quarter.

In April, windstorms in the Carolinas and Indiana caused significant outages requiring extensive repairs. In May, severe thunderstorms in Ohio brought damaging wind, hail, and tornadoes. According to estimates from the Ohio Insurance Institute it was the third most expensive natural disaster in the state's history.

As they have in the past, our employees acted quickly to restore power. In fact, after the Carolinas windstorm in April, we restored service within 24 hours to about 70% of the 250,000 customers who lost power. We appreciate our customers' patience and are grateful for the dedication of our employees and those from our neighboring utilities.

Storm restoration costs in both the first and second quarter will challenge us to keep the increase in total Company O&M costs within our targeted range of 3% to 4%, net of deferrals and cost recovery riders. However, we continue to work actively to mitigate these unexpected expenses.

In Commercial Power, the quarter's adjusted segment EBIT was lower than the prior-year quarter primarily due to the annualized margin impact of 2010 customer-switching in Ohio, which we will further discuss in a moment.

Our nonregulated Midwest gas fleet continued to perform very well, supported by strong energy margins and higher dispatch. The gas fleet dispatched about 1,100 gigawatt hours more than the 2010 second quarter, consistent with the trend we saw in the first quarter this year.

Also during the quarter we entered into an agreement to transfer our 75% interest in the nonregulated Vermillion gas plant to Duke Energy Indiana and Wabash Valley Power Association. Pending regulatory approval, Duke Energy Indiana will hold a 62.5% interest in the plant, with Wabash Valley owning the remaining 37.5%. As a result of the transaction, which is expected to close in the first quarter of 2012, we recognized an approximate $9 million pretax impairment during the quarter.

Duke Energy International continued the strong performance we saw in the first quarter. Higher prices and volumes in Central America and higher average contract prices in Brazil contributed to the increase in the segment's adjusted EBIT. More favorable average foreign exchange rates and higher earnings from our equity investment in National Methanol also contributed to the increase.

In our Other category, we reported second-quarter 2011 net expense from continuing operations of $52 million, compared to $39 million in the second quarter of 2010, primarily due to higher captive insurance losses. Finally, we continue to anticipate a 2011 effective tax rate of approximately 32%.

Please note that a discussion of our GAAP reported results for each quarter is included in today's press release.

Turning to slide 7, I will spend a few minutes on our customer volume trends for the quarter and the economic conditions within our service territories. Overall for the quarter, our weather-normalized volumes were slightly favorable, led by increased residential volume. As you will recall, last quarter we experienced a downturn in our weather-normalized residential volume, a trend we have been monitoring closely.

During the second quarter, however, we saw an increase in residential volumes of 1.6% on a weather-normalized basis. As you see from the chart in the upper left-hand section of this slide, quarterly residential activity has been volatile since 2010. We attribute the volatility to the continued pressure of the soft economy as well as energy efficiency efforts from our customers.

Importantly, though, we continue to experience modest retail customer growth in both the Carolinas and the Midwest, though not at the levels we were experiencing prerecession. In our Commercial customer class, the decline we saw beginning late last year has continued, as quarterly Commercial volumes were 0.7% lower than the prior-year quarter. Although our service territories have experienced relative stability in office vacancy rates, retail sales activity has recently slowed.

Industrial customer volumes for the quarter were flat, but they are around 2% higher on a year-to-date basis than the prior year. During the quarter, industrial volumes remained strong in the Carolinas, offset by softness in the Midwest.

Favorable industrial activity in the Carolinas continues to be broad-based across several sectors. However, it was especially supported by strong activity in the automotive and textile sectors. In fact, most of our textile customers continue to operate at or near full capacity levels.

The Midwest experienced declines in the primary metals and housing related sectors, as the overall economy and lack of rebound in the construction market has reduced demand. Sourcing issues in the automotive sector that resulted from the earthquake and tsunami in Japan also had temporary effects during the quarter.

Overall, the outlook for manufacturing activity across our service territories remains positive. We have found that our primary industrial customers are generally optimistic, but believe the recovery will be slow. A majority of them expect the remainder of 2011 will be favorable compared to 2010 and that this favorable trend will continue into 2012.

Yesterday's announcement of the July ISM manufacturing index, which fell to a level just above the expansion threshold, demonstrates the negligible growth being experienced by the economy. Until we see more consistent and sustainable growth, our economic outlook will remain cautious.

As a reminder, our 2011 guidance assumed we would 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.

Given the modest softness we have seen in the commercial and residential customer classes during 2011, we may be slightly below this overall 1% weather-normal volume increase for the year. We will continue to monitor customer volume trends and update our assumptions as we progress through the remainder of 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 slide 8.

As displayed by the light blue and red bars on the graph, you can see that switching has remained relatively stable for the past year. As of June 30, 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 switched load, helping to preserve margin. As a result, Duke Energy entities are providing generation services to approximately 72% of the customers in our Ohio service territory.

For the balance of this year, we do not expect to see significant financial impact from additional customer-switching.

In a moment, Jim will discuss our recently proposed ESP filing in Ohio. We are working toward resolution of this filing by the end of 2011. However, if we do not receive a Commission order by the end of this year our current ESP will continue.

As you know, Commercial Power's financial results in 2012 are dependent upon the timing and resolution of this ESP proceeding. We will continue to update you on our progress over the course of the year.

In summary, we are very pleased with our execution and financial results for the first half of 2011. Our regulated businesses continue to realize the financial benefits from our new construction projects as well as the benefits from favorable weather, a trend that continued into July. This has helped us mitigate the impact of considerable storm costs across all of our service territory.

Additionally, our Commercial Power and International segments have performed exceptionally well, and we expect the financial impact of customer-switching in Ohio in the back half of the year to be insignificant. The strength of our balance sheet and continued earnings growth supported our ability to increase the quarterly dividend from $0.245 to $0.25 effective with the September dividend payment.

Additionally, our financial strength allows us to avoid equity issuances, including those through our internal DRIP plans based upon our present business plan.

We are well positioned to achieve our targeted 4% to 6% long-term growth in adjusted diluted earnings per share as well as our current-year earnings guidance range of $1.35 to $1.40. Our focus for the remaining months of this year will be on effective cost controls, operational efficiencies, and advancing our strategic initiatives. I will now turn it over to Jim.

Thank you, Lynn. Let's take a look at slide 9, which contains our merger scorecard. As you see, we have completed all of our required regulatory filings for merger approval.

Our S-4 was declared effective by the SEC on July 7, and our joint proxy statement was mailed to shareholders the week of July 11. Duke and Progress have scheduled special shareholder meetings for August 23 to vote on merger-related matters. The boards of both companies have unanimously recommended approval of the merger to shareholders.

We are also working to advance merger approval in the states of North Carolina, South Carolina, and Kentucky. In North Carolina, we have filed testimony in support of the merger; and hearings have been scheduled for September 20. Intervener and staff testimony is due on August 26.

We are awaiting a procedural schedule from the South Carolina Commission.

In Kentucky, Duke and the Attorney General have filed a settlement agreement with the Kentucky Public Service Commission. Hearings were held in July and we expect an order soon.

In April, applications for approval were also filed with the Federal Energy Regulatory Commission, and we expect a ruling by early October. Last week, the FCC approved the transfer of the Progress Energy licenses and, as we highlighted on our first-quarter earnings call, the waiting period under the Hart-Scott-Rodino Act has expired.

We continue to move forward with merger integration planning. Integration teams have completed the analysis phase of their work and have begun the process of designing the organizational structure and policies for the combined Company. The second-tier of the new Duke Energy organizational structure has been developed. We expect to name leaders of each of these functions by mid-September.

Although the merger is expected to result in headcount reductions, our goal remains to minimize the number of job losses through a combination of normal attrition and retirements. To begin achieving the necessary reductions, we plan to offer voluntary severance benefits to certain employee groups by year-end.

All in all, we have accomplished a tremendous amount in just over six months. We continue to target a merger closing date by the end of the year.

The combination of Duke Energy and Progress Energy will provide the scale and strength necessary to manage future environmental compliance and to build or replace needed capacity. Our greater regulatory earnings diversity will enhance growth opportunities and reduce our risk profile. And with stable cash flows and a healthy balance sheet, the combined Company will continue to support the growth in our dividend.

Next, let me update you on the status of our major construction projects outlined on slide 10. We continue to move forward with our four projects at Cliffside, Buck, and Dan River projects in North Carolina and the Edwardsport IGCC project in Indiana. These projects represent a total investment of approximately $7 billion and about 2,700 megawatts of capacity.

They are the cornerstone of our strategy to replace and retire older, less efficient coal units in anticipation of more stringent environmental regulations.

Buck is expected to be in service later this year. Edwardsport, Cliffside, and Dan River are all scheduled to be in service in 2012.

Let me now spend a few moments discussing the Edwardsport project, which is about 90% complete. As you all are aware, earlier this year we filed a proposal with the Indiana Commission to cap the cost of the Edwardsport plant at $2.72 billion excluding financing cost. This cap, along with other provisions, mitigates near-term customer rate increases associated with cost we incur above $2.35 billion.

This project remains the best solution for our customers as we replace existing generation and ensure the energy future of Indiana. The average age of Duke Energy's coal-fired plants in Indiana is more than 40 years old.

Edwardsport is the first baseload plant to be built by Duke Energy Indiana in the past 30 years. It is the centerpiece of our fleet modernization strategy in the state and will allow us to close older, less efficient coal generation and to comply with more stringent EPA regulations. When the plant is completed, Indiana will have one of the cleanest coal-fired facilities ever built in the industry.

As a reminder, the Commission has separated our cost increase proceeding into two separate phases. The first phase, for which we have the burden of proof, is for approval to recover the $530 million increase in the estimated costs of the project from the currently approved amount of $2.35 billion. The second phase, for which the interveners have the burden of proof, is related to allegations of fraud, gross mismanagement, and concealment related to the project. Hearings on both phases -- phase one are scheduled to begin October 26, while hearings on phase two will begin on November 3. We expect a Commission decision on both phases by early 2012.

Interveners have recently filed testimony under both phases of the proceeding. For phase one they are recommending the Commission not approve the requested cost increase due to alleged imprudence. For phase two of the proceeding, interveners contend that Duke should only recover the project's original cost estimate of approximately $2 billion.

Our rebuttal testimony to phase one of the proceeding will be filed tomorrow; and our response to intervener allegations in phase two will be filed on September 9. Our testimony will demonstrate that intervener allegations are unfounded. We have diligently and prudently managed the Edwardsport project.

Slide 11 summarizes the key elements in our recently proposed ESP filing in Ohio. As you all may recall, our current ESP agreement expires the end of this year. In developing our proposal, we sought a long-term solution for the state of Ohio.

It balances the needs and objectives of our customers and our investors. It also recognizes the diversity of the regulatory models in the state.

We have threaded the needle between the FirstEnergy approach and AEP's proposal. Our plan creates long-term stability and certainty for both Duke Ohio and its customers. At the same time, it enhances customer choice and competition for energy.

Our filing addresses our expectation that more stringent environmental regulations, increased demand, and the need to replace aging generation facilities will lead to higher and more volatile electricity prices in the future. Most importantly, our plan is designed to mitigate price volatility and offer customers price stability over the longer term.

This longer term certainty enables Duke Energy Ohio to earn a fair and reasonable return on its generating assets and provides a structure that will permit long-term utility investments. Additionally, it would help to attract industry, generate jobs, and spur economic investment to Southwest Ohio.

The plan also supports competition by preserving customer choice and incorporating competitive energy auctions. Because we have proposed auctions to procure of our customers' energy needs, our generation will be available to sell into the wholesale market when it is economic to do so. In exchange for recovering capacity charges on a non-bypassable basis, our plan proposes to return to all customers a majority share of net profits earned with the output of our generating assets.

In the near term, our proposed ESP will result in rates that are modestly higher than the rates that would be expected under a market rate offer. However, and most importantly, over the plan's 9.5-year term, energy and capacity prices are expected to rise substantially, which causes our proposed plan to be significantly more favorable to customers than the expected results under the MRO. In fact, we estimate that the ESP is lower on average by about 8%, resulting in a present value benefit to customers of approximately $1 billion.

Hearings on our ESP are currently scheduled for September 20, preceded by interveners' testimony on September 7 and staff testimony on September 14. We are targeting revised rates to go into effect on January 1, 2012.

Turning to slide 12 I will update you on recent regulatory activities in the Carolinas. On July 1, Duke Energy Carolinas filed a base rate increase with the North Carolina Utilities Commission. We requested approval of a $646 million increase. This translates into approximately 15% average increase to customer rates.

Our request proposes an allowed return on common equity of 11.5% with a 53% common equity component. This rate case reflects the need for additional rate increases as we continue to modernize our plans and system.

Almost three-fourths of the proposed increase is due to recovery of capital investments, such as the Cliffside coal plant, the Buck natural gas plant, investments in our T&D system, and upgrades to our nuclear units. These investments will ensure our continued ability to deliver affordable, reliable, and increasingly clean energy to our customers in light of more stringent state and federal environmental regulations.

Knowing that customer rate increase pressures were on the horizon, we have worked diligently over the last several years to manage our costs. In fact, 2010 represented the fourth straight year we were able to hold our total Company O&M costs, net of deferrals and cost recovery riders, essentially flat.

Hearings have been scheduled for November 28, and revised rates are expected to be in effect in February 2012. Within the next week, we plan to file a similar base rate case in South Carolina.

Next I will update you on two key industry issues, the finalization in environmental regulations from the EPA and the preliminary findings from the NRC's Task Force review of the events at Fukushima.

First, the EPA ruling. As we have frequently discussed, the US EPA continues to work to finalize new, more stringent environmental regulation which will significantly impact coal generation. In early July, the EPA finalized one of these rules, a cross-state air pollution rule, or CSAPR. All states in Duke's service territory are affected by this new version of the Clean Air Transport Rule.

Even though CSAPR is more restrictive and the compliance periods are more aggressive than originally proposed, the provisions are within our long-term planning assumptions. Over the short term, these environmental regulations could require curtailment of certain generating units and increased costs, such as purchasing additional emission allowances or purchased power.

However, the anticipation of more stringent environmental regulations has long been part of our long-term, strategic planning process. Over the past decade, we have invested approximately $5 billion to install equipment to comply with state and federal environmental requirements, leaving our coal generating fleet well-controlled for both sulfur dioxide and nitrogen oxide.

Additionally, when our new construction programs and related retirements are completed, approximately 90% of our coal generation capacity will have scrubbers in operation.

As we look forward, based upon our current plan and assumptions, we expect approximately $5 billion to $6 billion in additional capital expenditures over the next decade to comply with the portfolio of regulations. We will continue to adjust and refine these planning assumptions as the EPA finalizes the remaining pending regulations.

Our plans for compliance with existing environmental permit commitments and the new EPA regulations assume we have retired or will retire almost 3,500 megawatts of coal generation or about 20% of our existing coal fleet system-wide by 2015.

This coal generation consists of older, less efficient units for which it is not economically feasible to install advanced environmental equipment. For example, we have recently announced retirement by 2015 of 862 megawatts of coal-fired generation capacity at the W.C. Beckjord Station in Ohio as well as 163 megawatts at Miami Fort Unit 6.

We do expect the finalization of the CSAPR rules to have some financial impacts. Since the provisions of CSAPR replace the previous Clean Air Interstate Rules, the SO2 emission allowances we hold for CAIR compliance will no longer be needed, beginning in 2012.

These allowances were recorded as intangible assets at fair value in connection with purchase accounting related to the Duke-Cinergy merger transaction in April 2006. As a result, we expect to record an approximate $80 million pretax impairment charge at Commercial Power in the third quarter of 2011. This non-cash charge will be recognized as a special item and therefore will be excluded from our adjusted diluted earnings per share for the year.

Before I close I will comment on the Nuclear Regulatory Commission's report on the Fukushima crisis and update you on our nuclear development plans. As you all know, the report from the NRC's Japan Task Force did not suggest risk associated with the current safety of US plants, spent fuel storage, or disaster planning. Neither did it raise any potential issues that would preclude licensing new plants nor relicensing existing ones.

In fact, since March the NRC has continued licensing work, including its reviews of new plant licenses and issuing license extensions for several existing plants.

After Fukushima, Duke Energy took immediate action to affirm our plants are ready to respond quickly to extreme conditions, whether natural or man-made. As a Company, we regularly re-examine our processes and procedures to ensure the highest level of safety in our nuclear operations. This is part of our safety and continuous improvement culture.

Over the years, we have made numerous modification upgrades to further enhance the ability of our plants to withstand devastating events. We are continuing to carefully review the NRC's report and are working cooperatively with the industry to identify any additional safety enhancements we should make for the long term.

We expect there may be some new oversight requirement as the NRC identifies additional lessons learned from the events in Japan. But, until there has been a more detailed analysis of the Task Force recommendations and the process that will follow, it is too early to speculate on any final regulation and the timing or cost associated with them.

We believe strongly that nuclear energy will be an important source of carbon-free generation in the years ahead. Consistent with our long-range plans we continue to explore regional generation opportunities to meet future load requirements.

In July, we signed a letter of intent with Santee Cooper that provides the framework for Duke to take a 5% to 10% interest in the new nuclear reactors at V.C. Summer in South Carolina. Once we have completed a number of important steps and the NRC issues the Summer combined construction and operating license, the letter of intent allows us to buy an interest in the project if we so choose.

Also recently, the South Carolina Commission gave us authorization to spend an additional $120 million through June of 2012 on development activities for the Lee Nuclear Station. We are awaiting a similar decision from North Carolina and remain on track to receive our COL in the 2013 time frame.

As we have noted before, a significant investment in new nuclear by Duke Energy is dependent upon the passage of legislation in North Carolina that provides assurances of timely recovery of financing cost on nuclear investments during the construction period.

Slide 15 lists the key priorities we presented to you in February. I am very pleased with our progress to date.

We are on track to achieve our financial objectives and recently increased the quarterly dividend to our shareholders. We continue to advance on our strategic objectives to provide our customers with affordable, reliable, clean, and safe energy over the long term.

The proposed merger with Progress Energy, targeted to be closed by year-end, will create a combined Company with the size, scale, and diversity to be very successfully positioned for the future. Now, let's open up the phone lines for your questions.

(Operator Instructions) Daniel Eggers, Credit Suisse.

Morning. Jim, I guess the focus of the day seems to be on Ohio right now, with the potential for AEP to come to some sort of settlement announcement this week, per the staff filing on Friday. What bearing do you think a settlement could have on what you guys have proposed recently? What has been the conversation you have had since you guys put out your new plan in the state?

I think historically, the Ohio Commission has structured different plans for each of the companies of the state. There is one that has been designed for FirstEnergy, for instance; Dayton; and now they are in the process of working on a plan for AEP.

We have presented a plan that in my judgment, as I said during our prepared remarks, it really threads the needle between the FirstEnergy plan and AEP's proposed plan and we believe is in the best interest of our customers over the long term.

I think that is very important as we look at the forward curves on power in the region. Again, it is about providing affordable, reliable, clean, and safe electricity over the long term. We believe we have a proposal that works for our customers over the long term.

So again, it's important to watch what happens with the developments at AEP; and we are, of course. But I would urge you to remember that historically there have been very different plans for each utility in this state.

Jim, can you remind me when you guys need to have an agreement done if you wanted to have the auctions in place for effective 1/1/12 rate implementation?

My belief is that we probably need approval in the October/November time frame to be able to do that. But in the event that we don't get it till later, as you know we keep our existing plan in place until we are able to implement the new proposal.

Okay. I guess with the changes at the Commission and one more seat to be filled, are you guys comfortable that you can get through a settlement agreement and get the Commission to sign off in a timely fashion? Or do you think it's going to be a little more drawn out, given the changes?

I believe that this Commission has acted timely. There has already been a significant transition of new commissioners, new chairman. But I don't think they have missed a beat in terms of addressing issues before them. So we are confident that they will act in a timely manner.

Okay. Thank you, guys.

Greg Gordon, ISI Group.

Thanks. Good morning. A couple questions. First, when I look at the Ohio assets that are still within the regulated umbrella and I look at the incremental impact that declining gross margins from shopping have had, it looks to me like from a practical perspective you're not really making any meaningful return on asset on those assets currently. Or least on a -- if I run out -- if I assume the gross margins you are today, annualized for the impact of shopping, you are really not earning a reasonable return on those assets. Really not earning any return on those assets. Is that a fair analysis or unfair?

You know, Greg, I think it is fair that the returns are under pressure for the Ohio business. The one specific data point I would point you to is the SEET filing for 2010 for all of Ohio, which would include generation and T&D, with it just above 7%. So we would project to be below that in 2011.

That is why as we think about constructing something in Ohio we are very focused on ensuring that the returns that we earn or putting a proposal forward that puts us in a position to earn returns commensurate with the investment in the state.

Right. Well, if the average return is 7% and your distribution returns are ostensibly more stable that would mean that your generation returns are even below that average number, correct?

That's correct.

Right. So in some way, shape, or form what is happening is the retail entrants are basically getting a free ride on the back of your capacity and are able to undercut you on energy without paying what a reasonable return would be to backstop, on a capacity backstop. And that is what you are attempting to resolve with this filing?

Right, and based on your statement, is it possible you could testify?

(laughter) Maybe in my next career. So, my second question is on North Carolina. The base rate increase you have asked for is obviously justified by the investments you made. But it is a very substantial customer increase.

Is there anything happening on the fuel side or other pass-through costs that would mitigate the impact of that when it gets implemented?

I think first and foremost, 74% of the rate increase is really tied to our capital program that has been preapproved by the Commission. That is really a very important statistic with respect to the recovery.

I would suggest that this merger that we have proposed, when it goes into effect and we have joint dispatch, that will mitigate some of this increase that we're expecting from the approval of the rate increase in North Carolina.

Okay. But on a stand-alone basis, there is no big offsetting cost savings that you can point to that would substantially mitigate it?

I guess the only point I would make is that as we went into this rate case in the test year, we basically have kept our O&M costs flat for four years -- as I said earlier, in anticipation of this case.

So we're going to be able to demonstrate to the Commission that we have acted very prudently during this period, holding our costs down, knowing there is going to be a rate increase coming. And even prior to that we went to the Commission to get approval so we could invest in energy efficiency so that we could help our customers reduce their usage as prices go up.

So, again, we have been very sensitive to our customers because they are at the heart of our business, and we want to make sure that we are doing these increases in a way that allows them to handle them comfortably -- as comfortably as they can during this period of modernization of our generation and distribution system.

Thank you. A final question. As you look at the impact of the Crystal River 3 delamination event at Progress, both in terms of the exposure to replacement power costs, and the uncertainty regarding the claim at NEIL, how do you assess the impact that might have on Duke's shareholders vis-a-vis the combination?

I think what's important to know is that Progress has provided updates to the NRC and the Florida PSC on the status of Crystal River 3. More detailed engineering and construction analysis needs to be completed by Progress, and they are currently undertaking those responsibilities.

The Florida PSC is working to establish the proposed hearing schedule. We're continuing to monitor all of this very closely. This is an issue that is very important that Progress and ultimately a new Duke Energy addresses in an appropriate way. And I have every confidence that we will, balancing the interests of our customers in Florida as well as our investors in the new Duke Energy.

Thank you very much.

Steve Fleishman, Bank of America.

Yes, hi, Jim. Good morning. A couple questions.

In the -- first of all, with the DOJ looking like they effectively approve the merger, I assume that means the market power issues are not -- are resolved, if there were any?

I would say the conclusion to draw is that the period expired and so the DOJ has no opposition to this. I am certain that the FERC in their deliberations -- and they have their own specific tests that they undergo -- will take notice of the fact that that period has expired, in their own deliberations.

Okay. In the Carolinas, it looks like we are going to get interveners and staff in late August and then hearing in September. If you were to be in a position to attempt to settle the merger case in the Carolinas, where would the typical timing be for that in the process?

I think that we are working on settlement today, both with respect to the merger application, as well as starting conversations with our customers with respect to the rate case. So it is difficult for me to predict the timing of when we are able to bring those two cases to a constructive close through a negotiated settlement. But clearly that is our objective going forward.

Okay. Okay, that's it. Thank you.

Hugh Wynne, Sanford Bernstein.

Hi, Jim. I had a question regarding the Ohio ESP -- which by the way I think is a very, very clever plan. I very much hope that it is approved.

But the question is this. My understanding -- and please correct me if I am wrong -- is that you are proposing to provide the capacity of your coal-fired units in return for a capacity charge; and at the same time to procure energy for your retail load in the marketplace area.

The nature of the energy that you are procuring, as I understand, is full requirements, load following retail electricity, whatever is needed to supply the load at Duke Ohio. Have I got that right so far?

Yes, you are on track.

The difficulty that I have with the plan or conceptually is this. It would seem to me that in procuring full requirements retail electricity, the supply load, you will be basically requiring the winning bidders in that reverse auction to procure capacity themselves. They will have to have backup capacity to ensure that they can supply the energy required during peak hours.

And yet on the other hand, you are seeking compensation for your capacity in a separate charge. My question is how to reconcile those two things. Would the Commission view that as causing the customers of Duke Ohio to pay for their capacity requirements twice?

Well, I think the important thing is the auction is going to be around energy; and people will bid into that energy auction. They in all likelihood will not back it up with capacity. And that the capacity that we have in our capacity charge will basically be the backstop in the event they can't deliver the energy in a timely manner.

Would you supply, say, peak requirements from your fleet or procure peak requirements in the marketplace from others, if the energy suppliers chose not to do so? Or would you expect energy suppliers to meet the full requirements load of your customers?

We would expect the energy suppliers to supply the entire load even on the peak.

That again implies that they need to have the capacity to do so; no?

No, it just means they have to go to market and meet their requirements that they have committed to us. Quite frankly, as you talk to the various suppliers they all say they have the capability to provide load following energy without lining up capacity.

Okay, okay. Good enough. I will follow up off-line with the IR department. Thank you very much.

Michael Lapides, Goldman Sachs.

Hey, guys. Real quick, the announcement of the voluntary severance plan and thoughts on O&M. How big of an impact, just trying to think about it in terms of what it means for 2012? And also when do you expect to get a full year's impact from it?

Michael, we have just begun some preliminary disclosure around the voluntary offering. We have informed employees that we will offer a voluntary program, the specifics of which will be communicated later in the year.

We will then identify which pockets of the Company will be eligible for the plan. That will occur later in the year.

So this is part of preparing the Company for the merger, and we will have more specifics around expectations for '12, which will include O&M and the other moving parts to our numbers, after the first of the year as the Company comes together.

Got it. The other -- when we think about the Indiana and Edwardsport -- changing topics here a little bit. What is the earliest you think you could see the next agreed-upon rate increase for Edwardsport actually put in a rate?

Well, based on the current status of the case, we believe that the pending requests we have with respect to CWIP will be resolved when the Commission acts on phase one and phase two of the procedural schedule, which in all likelihood is the first quarter of next year.

You are saying you would have new rates at the beginning of next year or at the beginning of second quarter next year? And that is just on IGCC 4 which is under review; and that is not dealing with 5, 6 or 7?

You know, Michael, we have hearing dates for 5, 6, and 7 scheduled in November and December. I guess our planning expectation is that the Commission would move through phase one and phase two, and then move through the IGCC trackers within the time frame that Jim just discussed. So it is probably early '12 for resolution of all of those matters.

Got it, okay. Thank you. Much appreciated.

Jonathan Arnold, Deutsche Bank.

Jim, I wanted to make sure I just didn't mishear you. Just then you were talking about the settlement to the timetable on North Carolina, and it sounded like you were suggesting it is possible that the rate case and the merger could somehow be settled together. Were you going that far?

No, no. I appreciate the question. We view these as on two separate tracks. Basically we would push back against any effort to try to tie these two together going forward.

But you did say you are beginning settlement discussions on the rate case, or at least talking to the parties?

We are talking to the parties. Again, this is what I call a rate base case, with such -- almost three-quarters of it tied to actual capital expenditures that have been preapproved by the Commission. So this is, in many senses of the word, there's not many moving parts and it is pretty straightforward.

The debate will probably, in all likelihood, be around the return on equity. That is where the debate will be. Because virtually everything else is straightforward and speaks for itself.

When you say you will push back on efforts to link the two cases, are those -- are there other tangible efforts already underway to do that? Or is that more a conceptual statement?

We have seen no effort by anyone to attempt to tie these two together.

Okay. Thank you. Then could you just clarify? There was a reasonably meaningful movement in Central America during the quarter we weren't expecting. What was -- can you be a little more specific what drove that? Is this a recurring type of item or was it a one-off or something unusual?

I'll take that one. Jonathan, we have had good experience over the years with DEI experiencing diversification among the countries. In this instance, Central America has actually had a dry season. We owned thermal plants in the country and have experienced both higher volume and higher margins. So it is the portfolio at work this quarter.

Okay, great. Thank you. Then -- sorry; one other just clarifying, following up on the Ohio questions. If there were a customer or customers that were, say, being served under a contract that had a life on it that went beyond your current ESP -- I am not sure how many that might be, but I do believe there are some -- who are effectively paying for capacity under that contract. How would you avoid the situation where that sort of customer ended up paying twice at least until their current contract with their supplier ends? Is there some provision for dealing with a situation like that in the ESP?

Let me ask Keith Trent, who leads our Commercial business, to address that question.

Yes, thanks for the question, Jonathan. First of all, I think you are right that there are not a lot of customers who would be in that situation. Now most of the customers who have switched or are using other providers, their contracts expire at the end of this year. But to the extent that there are customers that have contracts beyond this year, I think it is going to be on a contract-by-contract basis to look at that.

Some of those contracts I think will have express outs that would allow them to -- for example, if they are paying capacity today, to get out of paying the capacity in the event that they are going to have to pay capacity under our plan.

Another way of looking at that, though, is at this point in time anyone who is entering into agreements beyond the end of our term are taking on some regulatory risk. So that is certainly an issue that they, I am assuming, took into account as they entered into contracts beyond a year. But I think for the most part, those situations can be handled via the contracts they entered into.

Thank you very much.

Jim von Riesemann, UBS.

Hi, Jim. Hi, Lynn. Good morning. A couple questions here.

One is, the first one I guess is following up on Jonathan's questions on Latin America. Can you talk a little bit about some of these recent news articles that suggested that you might be interested in selling the Brazilian assets?

I think, first, I have seen the articles; but I have been seeing them for five years.

Agreed.

About every three to six months, one pops up and says we are selling this to that. But quite frankly DEI has really saved our bacon in the first two quarters in terms of hitting our earnings targets. It has been a very successful operation, and we are not currently entertaining any offers or any discussions with respect to the purchase of those assets.

They proved this year the value of diversity in earnings streams and has really allowed us to meet our earnings targets because they have successfully stepped up and delivered.

Great. The second question, switching topics, is on this letter of intent agreement on Santee Cooper. Maybe -- I know you are in negotiations, but hoping that you could still provide a little bit more color and maybe talk about some of the mechanics.

From your prepared remarks it sounds to me like there is a chicken-and-egg situation going on, meaning you might actually execute an agreement to buy the minority stake shortly after the COL is issued, but before you have enabling legislation in North Carolina. Is that correct?

That's correct.

Okay. Could you talk or frame some of the economic considerations in terms of what you might expect to pay for and how comfortable you are taking a minority stake in the facility without presumably any operational control or say?

That's a very -- it's actually a very good question and actually it is one of our concerns as we evaluate the potential of taking a 5% to 10% interest. We have always said that we really need and we continue to believe we need legislation in North Carolina that would allow us to track CWIP on a periodic basis.

So that has been -- and that is obviously, as you might imagine, part of -- one of the conditions that we put forward in making the offer and starting down the road that we have started down with them. But, again, without any -- we have not done any true due diligence. We don't really know what we would be buying into. We are working hard to avoid buying a pig in a poke.

Right.

And we have structured it that way. So my hope is that we can diligently work through this and see if there is an opportunity that really makes sense for our customers as well as for our investors.

But more to come on all that. It is really too early to give you any more color on the current negotiations.

Okay, now, just my understanding is that the folks at SCANA have a say in all this at the end of the day as well. Is that true?

It is not totally clear to us. We are negotiating with Santee Cooper.

Right.

We have not, as I said earlier, we have not stepped into the due diligence process to know what the contractual relationship is between Santee Cooper and SCANA.

Super.

The only thing I would add to it is, we have long been supporters of regional generation. This is an opportunity for regional generation in our service territory. This is a framework for us to look at taking an interest; and the due diligence is something we will be focused on over the next couple months and have more clarity around that step as we complete that work.

Super. That's all I had. Thanks so much.

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

Thank you, Kelly, and thank you everyone for joining us today. As always, the investor relations team is available for any follow-up questions. Have a great day.

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