Duke Energy Corp (DUK) 2013 Q2 法說會逐字稿

Good day. Welcome to the Duke Energy second-quarterly earnings call. Today's conference is being recorded. At this time I would like to turn the conference over to Mr. Bob Drennan. Please go ahead, sir.

Good morning, everyone, and welcome to Duke Energy's second-quarter 2013 earnings review and business update. Leading our call this morning is Lynn Good, Duke Energy's President and CEO. Today's discussion will include forward-looking information and the use of non-GAAP financial measures. Slide 2 presents the Safe Harbor statement which accompanies our presentation materials. You should also refer to the information in our 2012 10-K and other SEC filings concerning factors that could cause future results to differ from this forward-looking information. A reconciliation of the non-GAAP financial measures can be found on our website at duke-energy.com and in today's materials.

Please note that the appendix to today's presentation includes supplemental information and additional disclosures to help you analyze the Company's performance.

Today, Lynn will provide an in-depth review of the second quarter results and offer perspectives on our expectations for the rest of the year. She will also take your questions following her prepared remarks.

This morning, we announced adjusted diluted earnings per share for the second quarter of $0.87 compared to $1.02 for the same quarter a year ago. Principal drivers of the lower quarter-over-quarter adjusted results were less favorable weather at our utilities compared to last year, reduced contributions from our Midwest coal and gas commercial operations and lower contributions from international operations, primarily due to an extended maintenance outage at our National Methanol investment.

These drivers were partly offset by positive revenue contributions from recently approved rate cases in North Carolina and Ohio. Also this morning, we are reaffirming Duke Energy's previously announced adjusted earnings guidance range for 2013 of $4.20 to $4.45 per share. Now I would like to turn the call over to Lynn.

Thank you, Bob, and good morning. I want to thank all of you for joining a call today. I am pleased to be joining you as the President and CEO of Duke Energy. As many of you know, Jim Rogers, who has led Duke or one of its predecessor companies for nearly 25 years, will remain Chairman through the end of this year. I'm grateful to Jim for his encouragement and support over the years and I am deeply honored by the confidence the Board has placed in me. As well, I want to thank you for your support in the past and for the messages I have received since this announcement.

Also yesterday, I announced Steve Young as Duke Energy's new Chief Financial Officer. Steve most recently served as the Company's Controller and Chief Accounting Officer and previously served as the CFO of Duke Power. In his previous roles, Steve has worked closely with the utility commissions in North Carolina and South Carolina as well as the Federal Energy Regulatory Commission. He has a deep understanding of our Company and the industry and will maintain our sharp focus on our financial objectives. Steve complements our exceptionally deep and talented leadership team and I look forward to introducing Steve to many of you over the coming months.

Now let me turn to our discussion of the quarter's results, expectations for the remainder of 2013 and our near-term strategic priorities. July 2 marks the one-year anniversary of closing the Duke-Progress merger. Thanks to the diligence and hard work of our employees and leadership teams, we have accomplished a great deal over the past 12 months. Slide 4 outlines our near-term priorities and our progress toward resolving them. Let me provide a brief update on these priorities.

First, we continue to make progress on our regulatory calendar in 2013. I am very pleased with the constructive orders we have received in the Duke Energy-Progress and Ohio Electric TND cases. Additionally, we have reached balanced settlements with intervenors in the Duke Energy Carolinas and Ohio gas cases and await commission decisions in the third quarter. I'll discuss these rate cases in more detail in a moment.

Turning to Edwardsport, in early June we placed the IDCT plant into service. This is a major milestone for the Company and for our Indiana customers. Over the next several months, our focus remains on plant performance, including ongoing performance testing, completing GE's new product introduction testing protocol and resolving the remaining punch list items from construction. As with any new plant, we expect to encounter issues in the early phases of operation. Our approach is to identify root causes and resolve issues as they occur. To date, we have not identified any issue that will impact the long-term performance of the plant.

Next, Crystal River -- last week, we announced a comprehensive settlement with parties in Florida, including the Office of Public Counsel. This settlement provides long-term clarity for Florida customers, the company and other key stakeholders. As I will discuss in a moment, the settlement addresses the pending Crystal River 3 regulatory proceeding, the proposed leading nuclear project, the Crystal River 1 and 2 coal units and future generation needs in Florida. Merger integration also remains a key priority. Significant work continues to integrate financial, work management and human resources systems. We are on track to achieve our targeted nonfuel O&M savings of between 5% to 7% in 2014.

We also continue to deliver customer savings through our fuel savings and joint dispatch (inaudible). Over the last 12 months, we exceeded our original forecast by achieving cumulative savings of approximately $120 million. We expect to continue this progress into 2014 and beyond.

Finally, let me update you on our nuclear fleet performance improvement efforts. Both the Oconee and Catawba sites in the Carolinas operated at record capacity factors for the first six months of the year. Additionally, our focus on the single-unit Robinson Nuclear Station has resulted in improved performance in several key performance indicators, including capacity factors and the INPO Index, an independent view of our overall performance. Over the remainder of 2013, we have four planned nuclear refueling outages and are performing the necessary preparation work to ensure their successful execution.

As we discussed with you in February, we will continue to focus on achieving top-quartile performance across the entire nuclear fleet. We are pleased with the improvements we are seeing and our focus remains on maintaining a standard of excellence throughout the nuclear fleet.

Slide 5 reaffirms our principal financial adjustments, achieving growth in earnings per share in the dividend while also maintaining the strength of the balance sheet. These adjustments have remained consistent over time and will continue as the centerpiece of our investor value proposition.

We are reaffirming our previously announced earnings guidance range for 2013 of $4.20 to $4.45 per share. Our results for the year will largely depend on the following -- resolution of our pending rate cases, an outcome in Ohio on our cost-based capacity request, our cost control efforts including merger integration and our third-quarter results, historically our most significant quarter of the year. We continue to target a long-term growth rate of 4% to 6% in adjusted diluted earnings per share through 2015. We remain focused on growing the dividend on an annual basis and continue to target a dividend payout ratio of 65% to 70% based on adjusted diluted earnings per share. Consistent with this objective, in June our Board announced an approximate 2% increase in the quarterly dividend payable in September.

Additionally, we remain focused on the strength of the balance sheet, supported by our liquidity and credit metrics. In fact, the credit rating agencies recently acknowledged the significant progress we have made in resolving our near-term priorities. Moody's placed Duke on review for possible upgrade and Standard & Poor's revised its credit outlook on the Company from negative to stable. Our financial plans do not call for any new equity issuances through the end of 2015.

Next I will provide a more detailed look at our financial performance for the quarter. As we discussed during our first quarter earnings call, we expected relatively weaker results in the first half of 2013 compared to 2012 as a result of the issuance of incremental shares in connection with the merger, low PJM capacity prices, Progress [holding] company interest expense and unfavorable foreign-exchange rates and results in Brazil.

Consistent with these expectations and impacted further by milder weather in the second quarter and an extended outage in National Methanol, our second-quarter adjusted results were $0.15 lower than the prior-year quarter. The quarterly drivers are outlined on the slide deck.

Our GAAP reported earnings per share for the quarter were $0.48 as compared to the prior-year quarter results of $0.99. These reported results for the quarter include special items such as the Crystal River 3 impairment, the cost to achieve merger savings and others. The special items are outlined in the reconciliation table in today's press release materials.

Let me begin now with a business segment overview of our second-quarter adjusted earnings results. Our regulated U.S. Franchised Electric and Gas segment recognized quarterly adjusted segment earnings in the quarter that were $0.36 per share higher than the prior-year quarter. This increase was primarily due to the addition of the former Progress Energy utility operations. These results were partially offset by milder weather. In the second quarter of 2012, we experienced above-normal weather, while we faced below-normal weather during this year's quarter. In fact, a significant amount of rainfall during the quarter contributed to below normal cooling degree days in the Carolinas.

In North Carolina we experience the second-highest level of rainfall from April to June that we have had during the last 100 years. This mild summer weather has continued into July. High temperatures in Charlotte reached above 90 degrees only two days during the month of July.

Let's now turn to International, which had segment earnings $0.03 per share lower than the prior-year quarter. International's results were impacted by lower volumes at our National Methanol investment, primarily due to an extended planned maintenance outage. Although reservoirs in Brazil continued to remain slightly below historical levels, results during the quarter were consistent with our expectations. We continue to monitor development in Brazil.

Turning to our nonregulated Commercial Power segment, adjusted segment income was $0.05 per share lower than the prior year's quarter, in line with our expectations. These results are attributed to lower PJM capacity revenues and lower generation volumes for our Midwest generation fleet and the prior-year recovery of a Lehman Brothers receivable that had been previously written off.

In Other, we incurred additional interest expense associated with the Progress Energy holding company debt and higher debt levels at Duke Energy Holding Company.

Turning to slide 7, let me spend a few minutes discussing our progress toward achieving our 2013 earnings guidance range. As I previously highlighted, we remain on track to achieve between $4.20 and $4.45 per share of adjusted earnings for the full year. As demonstrated on this slide, we expect the second half of the year to be relatively stronger than the first half, primarily as a result of three items. First, constructive rate case outcomes including nuclear outage levelization, which I will discuss further in a moment. Second, additional merger synergies; and, third, increased contribution from our regulated wholesale operations.

The impact of Duke Energy Carolinas rate case, the Ohio cost-based capacity case and the deferral of nuclear outage costs will be most significant in the fourth quarter. The recent rate case order for Duke Energy-Progress and pending settlements for Duke Energy Carolinas in both North and South Carolina provide for accounting recognition of nuclear outage expenses over the refueling cycle, for example, 18 or 24 months, rather than when the outage occurs. This deferral of nuclear outage costs, known as nuclear outage levelization, is expected to add between $0.07 and $0.09 to our results for the remainder of the year, up to approximately $0.04 for Duke Energy-Progress and $0.05 for Duke Energy Carolinas.

Approvals of the Duke Energy Carolinas cases are still pending. The appended materials to today's presentation contain an overview of how nuclear outage levelization works. For the year, we expect Franchise Electric & Gas to exceed its target while International is expected to fall slightly short of its annual target. Commercial Power's results will largely depend on the outcome of the cost-based capacity filing pending in Ohio, which we expect in the fourth quarter.

We will provide additional updates to our annual guidance range after we complete the third quarter, which is historically our most significant one.

Slide 8 contains our quarterly volume trends by customer class in total, based on calculations that exclude weather impact. For the second quarter, our overall weather-normal volumes were around 0.4% higher than the prior-year period, driven primarily by growth in the Commercial and Industrial sectors. On a year-to-date basis, weather-normal volumes were also around 0.4% higher excluding the impact of the 2012 leap year. In the industrial class, quarterly weather-normalized volumes were 1.2% higher. We continued to experience strength in automotive in the Carolinas and the Midwest. However, lower activity in the primary and fabricated metal sectors in the Midwest reflects a softening of global demand.

On the positive side, the continued housing market recovery has also supported related industrial activity throughout our service territories. Weather-normalized volumes for our commercial customers were approximately 0.5% higher than the prior-year quarter, continuing the recent trend of modest growth.

Finally, residential volumes were 0.4% lower for the quarter. We continue to experience growth in the average number of residential customers as they have increased by 49,000 or 0.8% since the prior-year quarter. However, usage per customer continues to trend slightly lower due to the challenging economy and increased energy efficiency penetration. In particular, we continue to see weakness in Florida due to the number of low usage customers and higher vacancy rates.

Consistent with our outlook during the first quarter earnings call, we remain cautious on the overall economic recovery. We expect fairly stable economic outlook and activity in the back half of the year as household income growth is projected to remain flat. As a result, weather-normalized load for the full year 2013 is expected to be slightly below our previous assumption of around 0.5% growth.

Next I would like to briefly address the revised settlement agreement we have reached with intervening parties in Florida, as outlined on slide 9. This revised settlement agreement addresses issues related to Crystal River 3 that are pending before the Florida commission, including our acceptance of the mediator's proposal related to NEIL insurance coverage. It also addresses the termination of the engineering, procurement and construction agreement, or EPC, and related cost recovery at the Levy nuclear project. , recovery of cost related to a potential retirement of the Crystal River 1 and 2 coal units and a regulatory framework for the addition of new generation. As you know, resolving issues related to Crystal River 3 has been a priority since the closing of the merger.

This agreement is an important step and provides a balance between moderating rate impact to our customers, providing clarity on cost recovery and providing a framework to meet future capacity needs.

Let me highlight some of the key provisions of the agreement; first, Crystal River. The settlement clarifies cost recovery of past investments at the Crystal River 3 site. Excluding the extended power upgrade investment and the future dry cap storage facility, which are separately recoverable, we have agreed to cap the recoverability of remaining costs related to the site at $1.466 billion. Costs under the cap are recoverable in base rates over a 20-year period beginning no later than 2017. Note that our current cost estimates are within the cost cap. We have also agreed to accelerate the cash recovery of around $135 million from retail customers between 2014 and 2016.

In order to mitigate the impact of Crystal River 3 investment to retail customers, we reduce the carrying investment to be recovered by $295 million.

Next, let me discuss the Levy nuclear project. In 2008 we announced plans to construct two new Westinghouse AP 1000 nuclear units in Levy County, Florida. Our EPC for Levy was based on the ability to obtain the combined construction and operating license, or COL, from the NRC by January 1, 2014. As a result of delays by the NRC in issuing COLs for new nuclear plants as well as the increased uncertainty and cost recovery costs by recent legislative changes in Florida, we are terminating Levy's EPC contract.

Despite this decision, we continue to regard the Levy site as a valuable option for future nuclear generation and will continue to pursue the COL. We now expect to receive the COL in late 2014 or early 2015.

We will continue to recover the Levy investment, including the contract termination cost, through the nuclear cost recovery clause. We can seek recovery of additional costs to obtain the COL in future proceedings upon the in-service state of any new nuclear unit.

Next, I will discuss Crystal River 1 and 2, approximately 875 megawatts of unscrubbed pool generation in Florida. These units are being evaluated for retirement due to compliance with the [MAST] and other environmental regulations. In the event we are required to retire these units early, this settlement permits us to continue recovering normal annual depreciation expense through the end of 2020 and recover any remaining net book value in 2021.

To continue to meet the future energy needs of our customers in Florida, the agreement also gives us the ability to construct, acquire or up-rate up to 1150 megawatts of capacity prior to the end of 2017 and place the investments in rates, without a general rate case. We have an outstanding solicitation to address short-term capacity needs. We will evaluate these proposals along with the construction of peaking units, up-rates and potential capacity acquisitions. Our capital plans will be updated to address these requirements as decisions are made.

We also project the need for additional generating capacity in Florida during 2018. We expect to issue an RFP for this capacity this year, which will include a self-build option. If the self-build option is the most cost-effective alternative and if the commission grants us a determination of need for this generation, we will be able to establish a generation base rate adjustment for up to 1800 megawatts of new combined cycle gas-fired generation.

Prudent costs associated with these new generation investments will be recovered in customer rates without a general rate case upon the in-service state, based upon a 10.5% ROE.

Finally, we will agree to stay out of the general rate case proceeding until the end of 2018, an additional two-year period to our current four-year base rate freeze. However, if Duke Energy Florida's return on equity falls below 9.5% during this period, we will be allowed to seek base rate relief.

Overall, this settlement has minimal adjusted earnings and cash flow impact. In the second quarter, we have recognized a $295 million pre-tax write-off of the Crystal River 3 investment balance, as well as a $65 million pre-tax write off related to the wholesale allocation of Levy investment. These write-offs are special items and therefore have been excluded from our adjusted diluted earnings per share for the quarter.

This settlement is a balanced agreement providing longer-term clarity to both our Florida customers and the Company. The agreement is still subject to the review and approval by the Florida commission, which we expect by the end of the year.

Before I move to our pending regulatory calendar, I want to highlight that we are continuing negotiations with certain of our joint owners of the Crystal River 3 site to resolve any remaining issues that they have related to the initial outage and our decision to retire the unit. As you will recall, these joint owners hold an approximate 8% interest in the nuclear unit. We will provide updates as these negotiations progress.

Next, let me move on to our regulatory calendar on slide 10. 2013 is an important year with a number of regulatory proceedings to position the Company for the future. We operate in constructive regulatory jurisdictions and have five approved or pending settlements with annual revenue increases of around $600 million.

First, we've resolved the Duke Energy Progress case in North Carolina with revised rates that became effective in June. We also have constructive and balanced settlement agreements pending commission approval for Duke Energy Carolinas in both North and South Carolina. These rate increases will likely go into effect next month.

All of these cases are based upon a 10.2% ROE and a 53% equity component of the capital structure. They each contain rate mitigation mechanisms which minimize the initial impact of increased rates to our customers.

Additionally, we have a final order from the Ohio commission on our electric PND case and await a decision on our gas PND request.

Finally, we anticipate an order for the Ohio commission on our cost-based capacity request in the fourth quarter of this year. Clarity on this filing will help us form our long-term strategic plan for the Midwest generation fleet.

Other than a potential filing by Duke Energy Progress in South Carolina later this year, we do not forecast the need for additional rate cases in the next few years. This will result in less regulatory risk to the Company as well as more rate certainty for our customers. These constructive regulatory outcomes position the Company for the future, establishing timely rate recovery of over $9 billion of modernization investment.

As we look ahead, we will continue to harvest merger synergies, drive additional cost out of our business through continuous improvement efforts, grow our wholesale business and deploy capital in our jurisdictions, including new generation in Florida and the Carolinas. Our commercial businesses will also complement our growth.

With our focus on resolution of near-term priorities and constructive regulatory outcomes, we have positioned Duke for low-risk, primarily regulated growth, through 2015. We will provide details around our 2014 financial guidance and a strategic priority early next year.

Before closing, let me provide some perspective on my transition and current focus. I've had the opportunity over the last month to meet with employees and key stakeholders, and I am very encouraged by these conversations. Our work matters to the customers and communities that we serve and our employees are passionate and proud of what they do. We have built a lot of momentum over the last year, resolving our near-term priorities and integrating two great companies.

My focus is in three areas -- continuing to deliver on our commitments, strengthening our relationships with all of our stakeholders and positioning the Company for long-term success.

Let me briefly discuss each one. You can expect us to continue delivering on our commitments. We will build on our track record of delivering safe, reliable service to our customers, operating our assets with excellence and meeting our financial objectives. Achieving our merger synergies and ongoing cost discipline will be an important part of this mission. Effective capital deployment for the benefit of our customers and constructive regulatory outcomes will also play a key role.

We will also focus on strengthening stakeholder relationships. We play an important role in the success of our customers and communities, adding strong, constructive relationships with our customers, regulators and community leaders based on trust, respect and transparency. Their success is vital to our success.

Finally, the Duke Energy leadership team will focus on positioning the Company for long-term success. The electric industry is changing. Low load growth, new technologies, new regulations and ongoing cost pressures are just some of the forces that require new thinking and actions. As we position the Company and the industry for the future, we must innovate in every part of our business to address these challenges for the long-term benefit of our customers and our stakeholders. This includes innovation in technology deployment, continuous improvement and regulatory mechanisms. We must also engage and lead in public policy discussions that will impact our customers and our business.

The scale and portfolio of businesses we have position us well to successfully navigate the road ahead.

In closing, I want to thank Jim and the Board for building a strong company with talented leaders, dedicated employees and a performance-based culture. We have met many important milestones over the course of the year and are focused on finishing the year strong, achieving our objectives and setting the stage for success in 2014 and beyond. Throughout the remainder of the year, I will update you on our progress, and at this point I would like to open the phone lines for your questions.

(Operator instructions) Greg Gordon, ISI Group.

Good morning and congratulations. I just want to go over the general guidance you've given for the balance of the year, maybe review it. You said you are still on track to meet your overall guidance expectation with the regulated utilities being better than forecast, International being slightly below and generation being uncertain, depending on the outcome of Ohio. Is that a fair recap?

No. I think the success of commercial, Greg, will depend on where are Ohio comes out. But we also have the third quarter in front of us for commercial, and just seasonally you can expect more earnings from the base operations in the third quarter.

Okay, but a big piece of the change in the utility -- I'm looking in the appendix, which you referenced during your comments, page 22, is the potential second half impact of the change in accounting for nuclear outage levelization. But it looks like one of the outages already happened, so I presume that if that decision goes in your favor, that that would in fact be retroactive.

So Greg, if I could refer you to slide 7, I think you've got a comprehensive list of drivers for the second quarter. Let me just talk for a moment about nuclear outage levelization.

For the Duke Energy Carolinas plant, that accounting method will be adopted prospectively, so you will see the benefit through the fourth quarter of the outages in the Duke Carolinas fleet.

The Duke Progress adoption of levelization was retroactive to January, so you see a couple of cents in Progress's results in the second quarter on levelization and you will see another $0.04 in the back half of the year for the Progress piece of the levelization.

Perfect, that's exactly what I needed. And then prospectively, if we think about our forecasting, that means that there will be much less volatility in underlying O&M, such that it actually will be sort of less of a -- all things equal, less of a benefit in years where you have fewer outages?

And less of adjustment in years that we have more.

Correct, great.

So (multiple speakers) that stabilization is helpful. So yes, that's right, you got it.

But it won't change the cash flow? Obviously, the ongoing cash expense profile of the Company in years where you have outages, you will be booking those cash expenses.

That's right. The next rate case, if we think back beyond 2015, rates will be set in the future based on the levelized outage. So you will see the cash impact at that point.

Got you, thank you very much.

Stephen Byrd, MSSB.

Good morning, congratulations. I just wanted to talk broadly, Lynn, you mentioned the third of the strategic priorities, positioning the Company for long-term success. The international business -- we have seen volatility in the performance of the business over time. As you think about the long-term vision for the Company, how might we think about that volatility in the long-term, ways to address that, to reduce that to be more in line with the US core utility business?

I think that's a good question. There is natural volatility in international around foreign exchange rates, and to some extent the National Methanol entity is impacted by oil prices or other commodity influences. And that volatility, as you know, has been in our favor in recent years as the US dollar has weakened. Now the US dollar is strengthening; it's going to other direction.

We continue to look at ways to position the international business and address that volatility. I don't have any specific plans that I can share with you at this point, but positioning international to complement the growth of the Company is a priority.

Understood. And just on the overall O&M position of the Company, you are obviously making great progress in looking at your cost structure. Should we be thinking about substantial continual review of that? Or as you look out at the cost structure of the Company, do you see further opportunities that are as yet untapped or areas that you would want to focus more on down the road? Or, is it more likely to be relatively stable from here?

I think focusing on cost structure has become a way of life and will continue to be such. You think about the merger integration plans that we developed, a lot of that work was in 2010 and early 2011. The business has continued to change and we continue to look for ways to deploy continuous improvement, look for ways to optimize labor and contract labor to continue to drive cost savings. And I think you are hearing that throughout the industry as we grapple with a low load growth environment, and we are very keenly focused on improving our cost structure.

Great, thank you very much.

Shahriar Pourreza, Citigroup.

Just on Ohio, assuming you don't get the Ohio capacity, the cost-based approach that you are seeking, how soon could we see a more defined plan on strategic options with the Ohio, the Midwest assets?

We are expecting an order probably late September or October, I guess could slip into November. We don't have a specific procedural schedule. We will take our time to analyze that order, understand what it says about the plant, understand what it says about the position the commission is taking. And then we will analyze and make a decision as it makes sense to do so.

So I would say -- I can't say it will be by the end of the year, necessarily, but I would think by the end of the first quarter next year we would have finalized our thinking.

Okay, got it, very helpful. And then if you -- looking at the second half of this year, how much would the capacity case impact your 2H outlook, especially if you don't get an order until potentially late or mid-fourth quarter?

I think that will depend on what the order says. So you may recall that when we filed the request, we actually asked for retroactive treatment back to August in 2012. So I think we are going to have to see how the commission addresses that and at what point the recovery is granted.

So what I would point to is our plan for commercial is roughly $90 million of net income. We have delivered roughly $3 million through the second half, so that gives you a range of what the second half could include from a balanced target.

Alright, got it. Lastly, shifting to Florida, as far as the potential new addition of gas assets in 2017 and 2018, when could we start seeing builds occur, assuming you decide and you win the RFP process for 2017 power?

I'm going to ask -- I have Alex Glenn with me, the President of Florida, to jump in and give us an update on that.

On the 2018 combined cycle, our timing on that would be to go out for RFP this year and file a need case next year so that we would get, if we select the self-build option, approval from the commission. And then that would be an in-service date before the summer peak of 2018. That's on the larger combined cycle.

On the 2014 to 2017 time frame, we are really looking at capacity needs in the 2016 to 2018 timeframe, so we could be looking at new capacity, whether it's purchase, build or acquiring existing facilities in that 2015 -- 2014, 2015, 2016 time frame.

Terrific, thank you very much.

Steven Fleischman, Wolfe Research.

Could you give us a sense of earned ROE's at the utilities, either, I guess, trailing or in your forecast for this year?

That's a good question. We have so many pending regulatory proceedings, you are asking us at an interesting time. Why don't we take that off-line, because I think what we would want to do is to reflect the benefit of the rate cases for the partial year and probably give you a sense of what 2013 could look like. We do file surveillance reports in North and South Carolina, but both of those calculations have some unique characteristics to them that I don't think is really indicative of what we are earning. So I will ask Bill and Bob to follow up with you on that.

Okay, great. And just to clarify your comment on rate cases, so after this round of cases is complete, you don't have any intention to file -- did you say next year or for the next few years?

Next few years. The one case we are evaluating is Duke Energy Progress in South Carolina, and that would be the only one.

Okay. Where are you on any potential interest in the [Sumner] plant?

We are continuing to look at that. We have been in negotiations for some time with Santee Cooper. As we have said before, we believe in regional nuclear. We still believe in diversification. We think that is going to be important to the Company long-term, but we have not yet reached agreements and don't have any further updates at this point.

Okay, thank you very much.

Julien Dumoulin-Smith, UBS.

So perhaps just to follow up on Steve's question, what are the various considerations for timing on a South Carolina case as it goes?

Lloyd Yates is with me. I will ask Lloyd to step in on timing.

So in terms of timing we are looking at filing, if we file that case we are looking at filing that case sometime late in the fourth quarter of this year.

Any considerations as far as whether or not you would? Anything need to happen or not happen, shall we say?

I don't understand your question.

Julien, we analyze rate case needs based on returns that we are earning, based on what we see in terms of cost structure, O&M and also maintenance additions. So Duke Energy Progress has the same capital as the North Carolina jurisdiction. So it's Sutton and [Meade] and Smith complex. So we are looking very closely at it, just have not made a final decision and, therefore, haven't notified the case and all the things that would go with that.

In terms of numbers, if you think about Duke Energy Progress South Carolina, it's about 20% of the entire utility. Duke Energy North Carolina was 80%; Duke Energy South Carolina will be about 20% of the utility. So think about it that way in terms of filing.

Great, excellent. And then turning back to Ohio, if you will, quickly, so many of your peers have talked about driving costs out of that business specifically, given the transition to restructured markets. Any comments there? Any kind of reevaluation as you think about that business's future?

We have been focused on cost in the Midwest fleet really dating back to 2010, and that team has been very aggressive in driving costs out. I think, as you know, with where capacity prices are in this year, in particular, you are not going to solve the economics by driving cost out in 2013. But we do have a very keen focus on running as efficiently as we can.

Very fair. And then, perhaps lastly, as it relates to Florida, if you could just walk through quickly the interim capacity needs prior to 2018, is it more likely to think of that as a temporary need more than a permanent self-build opportunity? How do you think about that, just given this being more of a transition area opportunity?

I will ask Alex to step in, Julien.

We look at it as more of a permanent need. We have got -- we are retiring roughly 1700-1800 megawatts of capacity in the 2016 to 2018 time frame. We have got real needs to fill capacity in 2016, 2017, 2018. That doesn't go away over the long-term. So we are looking at the 2016, 2017 and 2018 as needs for additional generation, whether it be purchased power or peaking units or possibly upgrading some plants. And there may be possible acquisitions out there of plants that are existing in the market. So that's both a short and a longer-term need.

So in total, you are really looking at 3 gigs, in aggregate, of permanent needs, if you will, roughly?

Up to; I would say up to that.

Excellent, thank you.

Michael Lapides, Goldman Sachs.

First of all, Lynn and Steve, congratulations. Congratulations to both of you, especially Steve, with your announcement this week.

I want to focus a little bit on cash flow. Would love it if you could just talk about things like significant items like pension contribution needs over the next year or so, any change -- how the potential change in cash that's outside of the US, how the change in that tax law could potentially impact Duke, whether you could bring back more cash from Latin America as well as bonus depreciation.

Sure. So I will take pension first. We are forecasting a $350 million contribution in 2013, which is comparable with what we did in 2012. It will be a combination of the Duke Energy Progress plans as well as the Duke plan.

On the international front, we have got about $1.5 billion overseas. We've talked a little bit in the past about two things, one being a structured transaction that we can pursue to bring some cash home. That's still under evaluation. And then the second option would be flat-out repatriation. We could do it with or without a tax holiday, but you've got basically $1.5 billion offshore.

And bonus depreciation -- the bonus depreciation in 2013 is about $1.2 billion. We are in an NOL position, so the cash associated with that bonus is really going to be realized out in the 2015-2016 time frame.

Meaning you are not expecting to be a significant cash taxpayer in 2013 or 2014 as well?

That's correct.

Got it. One other question -- when you closed the Progress Energy merger, there was a significant amount, almost $4 billion, of holding company debt at the Progress Energy level at interest rates that are a little bit above current first mortgage bond or senior secured debt. What are your plans for the Progress Energy holding company-level debt, and does that present a refinancing opportunity for you that could be a positive tailwind for earnings?

We have done a little bit of that. I believe we took the CWIPs instruments out earlier this year and continue to look at the economics of refinancing to see if that makes sense. But I would not say that's a huge driver.

Thanks, Lynn. And once again congrats, guys.

Hugh Wynne, Sanford Bernstein.

My questions have to do with a couple of the items that are excluded from adjusted earnings. The nuclear development charge of $87 million -- I take it that's related to the cancellation of the PC contract at Levy?

That's primarily Levy, and also Harris. You may recall that we suspended the commercial operating license pursuit on the Harris plant and took a charge for the wholesale allocation of those costs as well.

Okay, but with the Florida nuke costs, those are recoverable under the nuclear clause in that state. Is that right?

Let me pause just for a moment. So that's the wholesale allocation of Levy, and under the wholesale terms of this contract, we do not have an ability to recover them and, as result, impair those costs. You may recall that these were identified back in the 2012 settlement in Florida as being amortizable in the same way as POR. But in connection with the 2013 settlement, that provision of the 2012 settlement was set aside and we made a decision to take the impairment at that point.

Okay, and then the litigation reserve of $50 million -- I believe that's in connection with Crescent. I don't know if you could perhaps give us some background there.

You know, it is. We have made a settlement offer to certain creditors that are involved in the Crescent bankruptcy litigation really dating back to the Crescent transaction in 2006. The terms of this offer are confidential. The litigation is ongoing, and at this point I can't comment any further on that litigation. We, of course, continue to believe that the claims are without merit, but we are working through this litigation.

Great. Finally, if I could, could you just brief us on the post commissioning outages at Edwardsport and what, if anything, they portend for the plant's capacity factor over the next year, year and a half?

We have made good progress on Edwardsport. The focus over the post and service period over the first few months is really consistent with early operations of a new power plant. We have been focused on system testing; we have been focused on tuning. So all of the major technology systems, the power block, the gasifier have been tested. The plant is running on those gasifiers as we speak. And as we have identified issues, we have dispatched the team to do a root cause analysis and resolve them and at this point do not see anything that has developed of a long-term nature. You can expect us to continue to address issues as they arise over the next several months until we get the plant to the point of its full capacity and potential.

Great, thank you very much.

Kit Konolige, BGC Capital.

I will add my congratulations to Lynn and Steve. A couple of questions, Lynn -- I believe you spoke about sales growth being slightly disappointing compared with your expectations.

What I would say is we are at 0.4% against an aspiration of 0.5%. We've seen good growth in industrial, in certain segments, but weakness in others. I would point to primary metals.

Probably the most -- the weakness that concerns us a little bit about the back half is really in Florida, where we have continued to see static low-usage customers and not really the rebound that we had hoped as we were forecasting the 0.5%. That's probably the area I would point to that gives us lack of complete confidence on a 0.5% growth rate.

So we will continue to update this in the third quarter and the fourth quarter, but we just remain cautious about the outlook.

And is there anything that you see developing on the sales growth that would have implications for your 4% to 6% EPS growth over the next couple years?

I think we have been very conservative with our low growth assumptions. So we are looking at kind of a 1% type range and we are adding customers in roughly that percentage right now. And so I don't see a significant risk to the growth rate, given the way we have forecasted this volume.

Okay, and one other area, if I could. You mentioned in positioning for long-term success, one of your goals is to advocate for new regulatory mechanisms. Anything in particular you have in mind there?

I guess I would point back to something that we successfully partnered with other utilities on in Indiana. The Senate Bill 560 that gives us an opportunity to modernize the grid, for example, under a multi-year plan to bring those costs into rates in a way that is more smoother for customers and more consistent with the deployment of capital. That would be an example, if we could achieve things like that in other jurisdictions.

Okay, very good, thank you.

Kamal Patel, Wells Fargo.

I had two quick questions, hopefully. With regard to Indiana and the Edwardsport startup issues, is there any cost-sharing requirement with repairs, or will you be passing those costs through to them? How does that work?

We are operating under a cap in Indiana and the costs that we have incurred are under the cap. So we do not have positive risks in Indiana at this point.

Okay. This is probably better answered off-line, but the Florida settlement -- I just wanted to get an idea of the various remaining balances that there might be for recovery related to Crystal River 3 and Levy, or is everything basically getting fleshed out as part of the settlement?

As per the recognition of the $295 million impairment, the remaining investment in Crystal River should be recoverable under the various provisions. So we have got roughly $1.2 billion at the end of June on the Crystal River plant, approximately $300 million on the upgrade investment. And then the Levy investment is probably around $250 million.

This is Alex. Right now, it's around $200 million that has not been collected.

But that, again, would fall under the nuclear cost recovery --

-- Provisions of the settlement and the statute.

Okay, all right, that's it for me, thank you.

Michael Lapides, Goldman Sachs.

Hate to end on this, but asked and answered.

Okay, thanks, Michael.

Okay, well, thank you all for participating and for your questions. We are looking forward to visiting with many of you in the fall conference season. As always, the IR team is available if there are follow-up questions. So thank you so much.

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