Duke Energy Corp (DUK) 2011 Q4 法說會逐字稿

Good day everyone and welcome to the Duke Energy fourth-quarter year-end 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. Bill Currens. Please go ahead sir.

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

Today's discussion will include forward-looking information and the use of non-GAAP financial measures. This forward-looking information is based on Duke Energy as a standalone Company, as regulatory approvals for our merger with Progress Energy are still pending. You should refer to the information and 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 from materials. Note that the appendix to today's presentation materials includes additional disclosures to help you analyze the Company's performance as well as our 2012 earnings guidance assumptions.

In today's call, Jim and Lynn will review our fourth-quarter and year-end earnings and provide you with our 2012 earnings guidance and related assumptions. We will also update you on our strategic initiatives, including our pending merger with Progress Energy. Additionally, we will highlight recent regulatory outcomes and our key priorities for 2012.

After the prepared comments, Jim and Lynn will take your questions. With that I will turn the call over to Jim Rogers.

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

We are extremely pleased with our financial and operational performance during 2011. Even though we faced some challenges, it was a year in which we continue to deliver on our commitments. Let me highlight a few of our accomplishments.

From a financial perspective we grew earnings, ending the year with adjusted diluted earnings per share of $1.46, which is $0.03 higher than our 2010 results. Considering that extremely favorable weather contributed about $0.13 to the prior year, our 2011 performance is truly exceptional. These results exceeded both our original and revised guidance range.

For the year, earnings from our ongoing modernization program and strong performance from our international business helped offset less favorable weather, significant storm restoration costs and the annualized effect of customer switching in Ohio. Continuing our commitment to increase the dividend, we grew our quarterly dividend by about 2%. Our dividend is supported by a strong regulated earnings base and we target a long-term payout ratio of 65% to 70% of adjusted diluted earnings per share.

We continued to finance our major construction projects at low interest rates and completed a new master credit facility supporting our liquidity.

In addition to solid financial results, we also had strong operational performance. Safety is a top priority for us. I'm pleased to report our safety record last year was the best in the Company's history, and it represented the sixth consecutive year we have improved our safety performance.

Our nuclear fleet performed very well, achieving a capacity factor of about 93% for the year. This marks the 12th straight year the fleet has been above a 90% capacity factor.

Our nuclear fleet also established some quarterly records during the year. During the third quarter we achieved a capacity factor of around 99.3% and set an all-time record by dispatching more than 15,000,000 MWh. Our fourth-quarter capacity factor of just over 95% was also a record for fourth-quarter performance.

And for the fourth consecutive year, our nuclear fleet was ranked number one among all other nuclear fleets in the nation for the lowest total operating cost per megawatt hour as reported by the electric utility cost group.

From a strategic perspective, our regulatory team executed well during the year, advancing our strategy to obtain regulatory clarity in Ohio as well as recover the cost of our modernization projects in the Carolinas. Our team in Ohio worked very hard to complete the move of Duke Energy Ohio and Kentucky to PJM, and obtained approval of an electric security plan or ESP that balances the interests of customers, the state and our investors. I am pleased the Ohio commission approved our settlement with intervening parties in late November and new rates are now in effect.

The terms of the ESP provide Duke Energy Ohio with non-bypassable stability charges of $330 million over three years. This gives customers the benefit of today's low market prices and allows us to transfer the generation assets to an affiliate. We've begun this work and expect to make a FERC filing in the near future. This move, which we have committed to complete no later than 2014, will provide greater clarity for our generation business.

In the Carolinas we reached constructive settlements and gained approval of customer rate increases. We also spent the year focused on advancing approvals related to our pending merger with Progress Energy as well as planning our integration efforts, leveraging best practices across both companies.

I want to thank each and every Duke Energy employee for their contributions to a very successful year. Despite a pending merger transaction, regulatory activity on many fronts, and an aggressive construction program, our employees maintained their focus on execution and cost control. Their achievements and dedication to excellence are very commendable.

Despite important challenges ahead of us in 2012, we are well-positioned to continue delivering value for our customers, investors and communities. For 2012 we are targeting an adjusted diluted EPS outlook range of $1.40 to $1.45 on a standalone basis. Our earnings projections continue to support our long-term 4% to 6% growth rate based off our 2009 adjusted diluted earnings per share.

At this time I will turn it over to Lynn for a more in-depth discussion of the year and our 2012 earnings outlook.

Thank you, Jim, and good morning everyone. Today I will start with an overview of our annual results for 2011 before discussing our financial projections and related assumptions for 2012. For reference purposes, quarter-over-quarter and year-over-year variance disclosures are included in the appendix.

As you recall, our original outlook for 2011 assumed adjusted diluted earnings per share would fall within a range of $1.35 to $1.40. We increased this range to $1.40 to $1.45 after the third quarter, primarily due to favorable weather and stronger-than-expected results at our Commercial Power and International segments.

We ended the year with adjusted earnings of $1.46 per share, slightly above our revised guidance range and $0.03 higher than the prior year. To put this performance into perspective, it is important to remember that 2010 results included around $0.13 of favorable weather as compared to around $0.05 of favorable weather in 2011.

Let me briefly discuss the primary drivers for each of our business segments during the year. At FE&G, less favorable weather and significant storm restoration costs continued -- contributed to lower earnings for the year. However, the negative impact was mitigated through strong operational performance, cost control and increased earnings from the continuation of our major construction projects.

Strong results at International were supported by both higher contract prices and favorable average foreign exchange rates in Brazil, and improved earnings from National Methanol. Our fossil fleet in Central America dispatched more frequently due to lower hydrology, and stronger results in Peru included a favorable arbitration award.

At Commercial Power, results for the year were down due to the net effect of annualized customer switching in Ohio and exit fees related to our transfer from MISO to PJM. However, the segment performed significantly better than our original EBIT forecast. For example, our Midwest gas fleet produced better than anticipated earnings as a result of strong energy margins and another record year of generation volumes.

Other significant earnings drivers for the year included interest expense and taxes. First, interest expense was higher as we continued to finance our major construction projects. We took advantage of historically low interest rates and issued $2.5 billion of fixed-rate debt at a weighted average rate of 3.3%. Finally, the adjusted effective tax rate for the year was approximately 31%, slightly favorable to our expectations of 32%.

In summary, we had a strong year and are well-positioned to continue achieving our financial projections and objectives in 2012. Our results demonstrate the positive benefits of the diversification in our businesses.

Turning to slide 12, turning to slide 7 -- let me just not jump ahead here. Let me provide an update on the economic conditions and related customer load trends within our regulated service territories.

For 2011 we finished the year with an increase of about 0.2% in weather-normalized volume, slightly below our expectations. Continued economic volatility kept commercial and residential volumes relatively flat, but industrial volumes grew by about 1% with strong results from the automotive sector.

With continued expansion in the manufacturing sector, our major industrial customers are feeling more confident about 2012. And given the increasing levels of consumer confidence we're cautiously optimistic. Because the economy hasn't quite recovered from high unemployment, challenging housing markets and Europe's fiscal uncertainties, however, we expect growth to be modest.

From an economic development perspective, our service territories continue to attract new jobs and new capital investment. For example, BMW has announced it will add 300 jobs this year and invest nearly $900 million to expand its South Carolina plant. And Daimler has announced it will hire 1200 workers at its Freightliner plants in North Carolina.

For 2012 we are projecting overall load growth of approximately 0.7%, led by a 1% growth in both industrial and commercial.

Now let me move on to a discussion of our 2012 earnings guidance and related assumptions. As Jim mentioned today, we are initiating our 2012 adjusted diluted earnings per share guidance range of $1.40 to $1.45.

Slide eight contains a waterfall chart with the significant drivers expected from each of our segments, as compared to our actual results in 2011. But first, I want to highlight that we will no longer report adjusted EBIT for each of our segments. Instead, beginning with the first quarter of this year, we will report adjusted net income.

This new reporting measure will involve an allocation of interest and taxes as well as corporate governance to each of the segments. Our other category will primarily include captive insurance results and interest expense on our holding Company debt. For your reference, net income projections for each of our segments for 2012 as well as comparable amounts for the prior year are included in the appendix.

Let's start with a discussion of FE&G, which is expected to contribute approximately 75% of our consolidated net income for the year. In 2012 we expect segment results to increase by around $0.12. This is supported by the investments to complete our fleet modernization program and our most recent rate cases in the Carolinas.

These base rate increases effective earlier this month, along with other rate riders, are expected to generate increased earnings for the year.

As I previously outlined, we expect modest weather-normalized retail load growth for the coming year. For sensitivity purposes, a 1% change to our retail load growth impacts earnings by approximately $0.03, assuming the change is evenly distributed among our customer classes.

Partially offsetting these positive drivers are increases in depreciation expense and a reduction in debt and equity AFUDC, both resulting from the expected 2012 in-service dates for our remaining major construction projects and the impact of the Carolinas rate cases. In addition we removed the $0.05 effect of the favorable weather from our March 2011 results, as our projections for 2012 assume normal weather.

Also note that we have targeting O&M to be relatively consistent with 2011, as inflationary impacts are offset by less anticipated storm restoration costs.

Next, let me move on to our Commercial Power segment, which contains our nonregulated Midwest generation as well as our Renewables business. This segment is expected to contribute less than 5% of our consolidated earnings for the year.

Segment results in 2012 are expected to decline as we begin to recognize the financial impacts of the new ESP in Ohio which was effective January 1. Historically our coal-fired generation in Ohio was generated dedicated to serving our native load customers, and for customers that had not switched, we received negotiated ESP rates that were above market. In our new market-based ESP, our coal-fired generation will dispatch into PJM and will receive an energy margin as well as PJM capacity revenues.

Currently these amounts are less than what we collected under our prior ESP. However, the decline is partially offset by an annual $110 million non-bypassable stability charge which Duke Energy Ohio will collect for 2014.

Within the fully competitive environment in Ohio, we expect to continue pursuing opportunities to capture margin both inside and outside of our service territories. Duke Energy Retail is expected to contribute about $0.02 of earnings, a reduction of around $0.03 from the prior year. Finally, contributions from our Midwest gas-fired fleet are expected to decline slightly, primarily due to lower PJM capacity revenues.

Next, our International businesses delivered record earnings in 2011 and we expect strong operational performance this year as well. The segment is projected to contribute about 20% of our consolidated results for 2012.

For the year, we expect an approximate $0.04 decrease in earnings contribution largely driven by three factors. First, during 2011 we had a favorable $20 million arbitration award in Peru that will not recur. Also, we expect the average Brazilian foreign exchange rate and our O&M expenses for the year to be slightly unfavorable.

Now let me briefly mention some of our consolidated expense items. These are included in the projected net income for each segment as outlined in the appendix to our presentation.

Our overall interest expense is expected to increase around $0.04 as compared to the prior year. Of this amount, about $0.01 relates to holding Company interest which is included in other. Even though we expect a low interest rate environment in 2012, the full year effect of our 2011 financings is expected to result in an increase to our consolidated interest expense.

Finally, our consolidated effective tax rate for the year is projected to be around 31%, which is consistent with 2011.

Turning to slide nine, I will now discuss our expectations for capital expenditures. In 2011 we spent approximately $4.5 billion and we expect 2012 CapEx to be fairly consistent at $4.3 billion to $4.5 billion. In 2013 CapEx is expected to trend down slightly as we complete our remaining modernization projects and a significant number of renewable projects later this year.

Over the three-year period from 2012 to 2014, we expect to deploy about 80% of our forecasted CapEx into our regulated businesses, consistent with our overall business mix.

Overall annual capital expenditures at FE&G are expected to range between $3.2 billion and $3.5 billion. Of this, approximately $2 billion is related to ongoing maintenance capital and nuclear fuel for our regulated fleet. The remaining $1 billion to $1.5 billion is targeted toward growth investments such as completing our major construction projects, our grid modernization program, and environmental compliance spending.

Our nuclear fleet is also performing a series of upgrades which will add additional net capacity of around 100 MW when completed in 2014. These upgrades are expected to be completed at a cost of less than $2 million per megawatt.

As we enter 2013 and 2014 we expect to begin increasing our environmental spending. After the recent finalization of the utility mercury rules, we refined or CapEx estimates.

To comply with the new regulations as well as potential rules which have not yet been finalized, including air emissions, coal ash and water intake, we could spend around $5 billion over the next 10 years. This is at the low end of our previous $5 billion to $6 billion range. Over the next three years we expect to spend about $1 billion for environmental compliance.

In our nonregulated businesses we expect to deploy ongoing maintenance capital of $100 million to $200 million, as well as make investments to strategically grow our Renewables portfolio. In anticipation of expiring wind tax incentives at the end of the year we expect to spend around $500 million to complete 770 MW of contracted renewable projects by year-end.

Finally, we continue to maintain a level of discretionary capital for both our nonregulated and regulated businesses, giving us future flexibility to pursue projects. The significant capital investments we anticipate making in our regulated businesses lead to rate base growth over time. This rate base expansion is one of the more significant drivers in achieving our targeted 4% to 6% long-term earnings growth rate.

Slide 10 gives you a view of the growth potential of the regulated businesses. As outlined in the previous slide, we expect to invest capital of approximately $10 billion over the three-year period from 2012 to 2014. Of this amount, about $5 billion is maintenance capital which substantially offsets or depreciation expense. The remaining $5 billion is expected to add to future rate base growth.

From these investments, rate base could expand from the current level of $25 billion to around $30 billion by the end of 2014, principally in the Carolinas. This represents a compounded annual growth rate of about 6%.

As a result of our significant investments in the regulated business, we expect to file rate cases to update customer rates for these costs. A regulatory calendar with our current rate case timing assumptions is included in the appendix.

Another driver for potential rate base growth is investments in new nuclear, and we anticipate receiving our COL for the Lee nuclear station in South Carolina in 2013. We expect to invest a total of $100 million between 2012 and 2013 as we continue to pursue this option. Also, we continue analyzing our option to acquire a 5% to 10% interest in the new nuclear reactors at V.C. Summer, but we have not yet made any firm commitments related to this project.

Let me move on to a discussion of our 2012 cash flow assumptions and financing terms which are contained on slide 11. As we enter the year we're well-positioned with stable outlooks on our investment grade credit ratings along with strong liquidity, which was around $4.5 billion at the end of 2011.

Our liquidity is supported by our recent $4 billion five-year credit facility involving 30 financial institutions around the world. This facility supports the Company's commercial paper program and replaces Duke's previous $3.14 billion credit facility which and set to expire in June of this year. Another $2 billion of credit under the facility will become available upon the successful closing of the pending merger with Progress Energy.

As outlined on the slide, we have around $1.9 billion of debt maturing in 2012 principally focused in the Carolinas and Ohio. In order to fund these maturities and our cash flow requirements, we expect to issue around $2.2 billion in financings during the year. These financings will mostly occur at the operating utility level as well as in our International and Renewable portfolios.

In the fourth quarter we anticipate making about $200 million of voluntary contributions to our pension plan. Our plans are currently fully funded, based upon Pension Protection Act requirements. We remain committed to maintaining the strength of our credit ratings and our current business plans do not require any incremental equity issuances through 2014. Details on our projected credit metrics for 2012 can be found in the appendix.

Before I close, let me discuss the primary drivers supporting our ability to achieve our long-term 4% to 6% growth rate. As you see on slide 12, investments in the regulated business and resulting rate base increases are expected to drive earnings growth over time. Next, we expect to see long-term average weather-normalized load growth of about 1%.

As I mentioned previously, (technical difficulty) [each 1%] change in customer load results in an EPS impact of around $0.03 or approximately 2% earnings growth.

Increased wholesale transactions were another growth area for our regulated businesses. We enjoy a strong base of existing customers for whom we offer competitive power supply options. We have recently extended several existing full requirements contracts and have attracted new wholesale customers.

For example, in 2009 we partnered with South Carolina's largest electric cooperative to provide power under a long-term contract beginning in 2013. Peak demand for this contract is projected to grow annually to around 900 MW by 2019. Our wholesale agreements involve creditworthy counterparties, stable returns and formula rates that true up annually, thus eliminating any regulatory lag.

Based upon our current plans and rate case timing assumptions, our entire wholesale origination business is expected to add incremental margin of around $0.02 to $0.03 annually through [2016]. And our nonregulated Midwest generation growth will be supported by margin expansion and increases in future PJM capacity prices. We also expect to realize contributions from investments in our Renewables business, our International business, and from strong economic conditions in Brazil.

And of course, as we demonstrated during the recent weak economic environment, cost discipline is an available lever to help us achieve our long-term growth rate.

In summary, I am pleased with our historical financial performance and how we have delivered on our commitments. For 2012 our focus will be on achieving our earnings guidance range of $1.40 to $1.45, maintaining the strength of our balance sheet and continuing to increase the dividend.

Now I will turn the call back over to Jim.

Thank you, Lynn. I am going to spend a few minutes updating you on our strategic initiatives, including our pending merger with Progress and our recent regulatory outcomes.

Slide 13 contains an updated scorecard related to our pending merger with Progress Energy. Recently Duke and Progress jointly extended the initial merger termination date to July 8. We still have merger-related proceedings open with FERC with both the North and South Carolina commissions.

As you may remember, in December, the FERC rejected our proposed mitigation plan because of market power concerns. We were disappointed by this action.

As we continue to finalize our analysis of the FERC order and the development of a revised mitigation plan, it is important that this plan balances FERC's market power concerns with the ability to retain the benefits of the transaction for our customers and our investors. We are considering both short-term and long-term mitigation provisions.

Our longer-term solution will likely involve building new and upgrading existing transmission to improve the import capability of power into the control areas. On a short-term basis until the transmission upgrades can be completed, we would offer firm sales of capacity and energy into the wholesale markets.

Before we file with FERC, we are required to make a 30-day notification filing with the North Carolina commission. We expect that a filing could be made next week.

On a parallel track, we will also be seeking clarification on certain state rate-making issues. A potential merger closing date will ultimately depend on the regulatory approval process.

Now, let me turn to the status of our major construction projects.

As you see on slide 14, 2012 will mark a milestone year in our modernization program. We expect to bring more than 2000 MW online with the completion of our remaining major projects -- Cliffside, Edwardsport, and Dan River.

In November we brought the 620 MW combined cycle Buck plant online and we expect it to be completed under budget. Because of low natural gas prices, Buck has been running like a baseload-generating unit. It is currently dispatching just after the nuclear units in the Carolinas, ahead of even our most efficient coal units.

Cliffside, Edwardsport and Dan River are anticipated to be in service by the end of this year. Cliffside had a successful first fire on oil in January and its first fire on coal is targeted for the second quarter.

At Edwardsport construction is essentially finished and the startup phase is more than 60% complete. The plant is undergoing an extensive testing process with first fire for both gas turbines expected later in the first quarter.

Let me bring you up to date on the regulatory proceedings related to the proposed cost increase for Edwardsport. In January we completed extensive hearings in both phase 1 and phase 2 of the project before the Indiana commission. We presented a strong case, including extensive testimony from independent respected experts.

After thorough analysis and review, these experts testified that the Company's decisions and management of the project were prudent, except for around $12 million in costs related to pursuing deep well injection system. Post-hearing filings are scheduled to be complete by mid-July. Therefore a commission order is not expected before the end of the third quarter. We continue to believe the cost of Edwardsport project were reasonable, prudent and necessary.

Before moving on, let me give you a quick update of the growth we expect in Duke Energy Renewables through 2012.

We have five major wind projects currently under construction, which will nearly double the Company's existing wind generation capacity by the end of the year. The projects will add almost 800 MW of wind power into operation, increasing our total wind generation fleet to around 1800 MW.

Turning now to slide 15, we recently received commission approvals to increase our customer base rates in both North and South Carolina. Revised rates became effective in early February. In North Carolina, customer base rates increased by about $309 million or an average of 7.2% for each customer class. In South Carolina, the commission approved an increase in base rates of approximately $93 million, an approximate 6% average customer rate increase.

In both states, the increase is based upon a return on equity of 10.5% and a 53% equity component of the cap structure. To help mitigate the impact of this rate increase to customers in North Carolina we have deferred cash recovery of Cliffside CWIP, about $1 billion, until the next rate case.

We are pleased the commissions approved the constructive settlements we reached in both North and South Carolina. Along with the settling parties, we were able to strike a balance between the economic challenges facing our customers and the Company's need to recover its capital investments. These projects will ensure our customers in the Carolinas have access to reliable, cleaner and affordable energy well into the future.

Moving to slide 16, I want to highlight our total shareholder return metrics. One of the Company's key objectives is to deliver competitive returns for our shareholders. We monitor our success for comparing our stock price and dividend return performance against our peers as well as the broad markets.

We performed exceptionally well in 2011. Our dividend payment and growth objectives appeal to investors, especially with the overall uncertainty in the macroeconomic environment. Our current dividend yield is about 4.8%, which is very attractive in today's market.

For the year, Duke's total shareholder return was 30.3% which exceeded both the 19.3% return on the Philadelphia Utility Index, as well as the 2.1% for the S&P 500. Additionally, as outlined on this slide, our shareholder returns over the past three- and five-year periods significantly exceeded both indices.

We remain focused on continuing to position the Company for long-term shareholder value. Our highly regulated business mix and our expectations for continued growth in the dividend offer opportunities for attractive shareholder returns.

Before we take your questions, I will quickly highlight our key priorities for 2012 and forward. For the remainder of the year we will stay focused on the day-to-day business of serving our customers and delivering strong operational performance. We will work toward constructive regulatory outcomes in the merger with Progress Energy, in cost recovery for Edwardsport and our planned rate cases.

For the longer term, we will continue to work to dance our legislative and regulatory priorities. We plan to complete the remaining three major capital projects -- Cliffside, Edwardsport Dan River -- as well as bring 800 MW of wind power into operation by the end of the year.

The strength of our balance sheet will support our ability to grow earnings and increase the quarterly dividend. Our standalone 2012 adjusted diluted earnings per share outlook range of $1.40 to $1.45 positions us very well to achieve our long-term targeted 4% to 6% earnings growth.

We've covered a lot of information today. Now let's open up the phone lines for your questions.

(Operator Instructions) Daniel Eggers, Credit Suisse.

Hi, good morning guys. (multiple speakers) Hey, Jim, can you just talk a little bit more about how you see the timeline working on -- once you file a statement with North Carolina on the remediation plan, you have 30 days and then it goes to FERC. How would you see that playing through a best case scenario to getting to a point of resolution on the merger?

Dan, my judgment is that -- I mean we have actually spent almost 2 months trying to finalize our analysis of the FERC order and the development of this revised mitigation plan. This has proved to be a very complex analysis and we have really worked try to address the concerns of the FERC, and at the same time address the concerns of our state commissions. And in many senses of the word, we're really trying to thread the needle between federal and state policy.

In terms of how to play it out, I'm almost reluctant to predict the timeline given what has happened in the past. But I think a best case scenario is that the North Carolina commission will review for 30 days. And maybe it will take them a shorter period of time to review it.

And then we will file with the FERC, and then the FERC will take 30 days for comment from the various parties, and then they will deliver at roughly 30 days, and then issue our order approving the merger along with a joint approval of our joint dispatch agreement as well as our tariff. So you can see that the timeline plays out by late May, June, I would say mid to late May we would in all likelihood have an order from the FERC. And then we expect orders from the state commissions, both North and South Carolina, after they have had an opportunity to review the FERC order and the issues that are pending before them.

Okay, got it, and I'm going to ask a relatively impolite question, so I apologize in advance. But given the fact you guys have been able to put up better numbers and maintain growth your rate while Progress' numbers have I guess deteriorated expectation-wise from when the deal was struck, is that causing you or the board have any reconsideration on the overall value of the transfer or the acquisition I guess?

Well, we consider -- we continue to look at the performance of Progress. They have had a few issues in Florida that they seem to be working through.

I think the important point here is this. You have to look at this deal both in the short and long-term, and we continue to analyze their performance. And over time we will -- we are on a path to get approval of this. And so again, more work to do, more information to gain as we move through the process.

Okay, thank you guys.

Greg Gordon, ISI Group.

Kind of a question along the same line as that, as I look at 4% to 6% earnings growth aspiration and I think about it in the context of the merger, presuming we reconcile the issues with the FERC and the states, I have two questions regarding what your assumptions are in that 4% to 6% aspiration.

One is does it presume that your earned returns in the Carolinas, Indiana, Ohio and Kentucky accrete to your authorized levels through synergies? Is that sort of one of the critical paths to getting to that range?

And second, are you making any contingency assumptions in that range with regard to negative outcome on Edwardsport, and for that matter, a negative outcome on Crystal River on the Progress Energy side in terms of write-offs and balance sheet impact?

Greg, those are good questions. We continue to target 4% to 6% and I'm talking about the combined company, because your question is directed toward the combined company.

I think the fundamental drivers for growth will be the regulated business with rate-based investment, with rate cases, with load growth, and as you said, demonstrated cost control in the form of synergies. I do think over time our aspiration, as you know, at Duke has been to close the gap between the allowed and earned return, and we expect to be able to do that over time.

And the range of planning assumptions that we look at of course include outcomes around Edwardsport and Crystal River. But as we have indicated, there's more work to do on a number of these things, including achieving the approvals to get the companies together before we can give you any specific guidance about the combined company.

Okay, but at least on the first question it's fair to presume that somewhere in the midpoint of that guidance range is a scenario where you're -- the synergies drive your returns to their authorized levels?

You know, Greg, it wouldn't get a specific to authorized levels. What I would say is we'll close the gap between earned and allowed over time through a combination of costs and rate cases. I think to assume that we're going to be right on top of allowed returns is probably a stronger assumption than I would make year in, year out as I look ahead.

Okay. And then post-merger close, to the extent there's guidance to be given on contingency plans or more information with regard to outcomes on Edwardsport and Crystal River, you will brief us then?

That's right, more guidance to come as we get closer. Thanks so much.

Steve Fleishman Bank of America Merrill Lynch.

Hi, good morning; a couple questions. First of all, on the International business, could you give us a number of how much cash you had at year-end held overseas?

And just also generally International has been fantastic the last couple of years. Is there any part of that that's -- I know you mentioned a Peru arbitration. There was little bit of temporary gain.

But are all the gains you have seen in the last few years kind of sustainable type growth? Or is there some things we should be wary of that falloff over time?

Steve, I think I will take that one. On cash, we ended the year with close to $1 billion overseas. Some of that of course is directed toward working capital requirements in the countries, so I would think about maybe $500 million to $600 million as being something that we could readily repatriate if we chose to do that. Of course we have not made that decision.

As we think ahead, there's no question international has had an exceptional year. And we do think there's some fundamental drivers to that business. The re-contracting, re-pricing in Brazil has been a nice driver.

We also continue to add a modest number of new resources that will drive earnings in the future. So we continue to think of it as a very important part of the business.

As you know, there will be some volatility in variables such as hydrology, foreign currency, perhaps pricing of MTBE impacting National Methanol. But we believe that business is very well-positioned for the future.

Okay, a couple of other quick questions. Do you have the gas capacity factors from the old DENA assets for 2011, and maybe what they had been in the prior year?

You know, I don't have a capacity factor number but the generation almost doubled. It was kind of a 70% to 80% increase in generation volumes year-over-year 2010 to 2011. And we are projecting that could continue to increase into 2012, so, they are running well. We are running a lot.

The interesting point is that with gas prices where they are, both in MISO as well as in PJM, you see gas being dispatched before coal plants. In the Carolinas we brought on the Buck plant. And it has great heat rate, low-cost gas, and it's dispatching just behind our nuclear and before our most sufficient coal plants. So this is a good outcome for consumers with respect to the low price of natural gas.

One last quick question on the merger, just based on your planned updated kind of market power related solutions, do you expect the joint dispatch savings will still be in the range you have talked about before?

It is our judgment they will generally be in that range. But we have more work to do with the changes that are occurring in gas prices, in coal prices. All of these have impact on what the joint dispatch savings will be. We continue to monitor that and update it as we go forward.

Okay, thanks a lot.

Jonathan Arnold, Deutsche Bank.

Good morning guys. Going back to guidance for second, I apologize; the 4% to 6% you have characterized as long-term, I know on the last quarterly call there was some confusion as to whether it was off of 2009 or off of sort of weather-adjusted 2011. So how should we think about that as the merger obviously is being delayed a little bit? And what is the right base?

Jonathan, that's a good question. I think for Duke standalone, which is what we're talking about today, we're talking about a base of 2009. We haven't advanced that base for Duke standalone.

We did advance the base for the combined company, as you will recall, when we announced in January. And so we will, as I said, give guidance and specifics around and the combined company when we get closer to closing.

So you are not sort of reiterating 4% to 6% for the combined company? Is that what you are saying?

You know, I -- we continue to target 4% to 6% for the combined company with the drivers we have talked about, investments in the business, synergies, etc. But as we said, with work to do around the timing of the closing, the synergies, the approvals, North Carolina and South Carolina FERC, we have just some more work to do to finalize where we are. And we will continue to update you as we make progress, but continuing to target the 4% to 6%.

Thank you. On another topic, picking up on something else, can you give us a view of where we are in terms of total inventories today, how that is marrying up with your contract situation and any efforts to defer deliveries, etc.?

Yes, Jonathan. The outgrowth, as you know, of dispatching gas plants ahead of the coal plants, because we're not running the coal as much, this is particularly the case in the Carolinas and in Indiana, so coal inventories are up. We are continuing to look at that very closely, also addressing issues with our contracts. We think we have got a plan to manage through it. But there is some market issues resulting from low gas price environment.

We are in a very good situation in Ohio. We have more flexibility on the way we have contracted in Ohio, so not much of any issue at all in our nonregulated business.

Would you say your coal piles in the Carolinas are kind of up to the levels they reached in 2009 yet? Or is that sort of somewhere you're heading towards?

You know, I don't have a specific comparison of today versus 2009. I would be happy to look at that, but I haven't looked at that statistic.

Michael Lapides, Goldman Sachs.

Yes, Lynn, one question -- two questions; one on the transmission comment you made regarding the merger. Can you give a little more detail in terms of -- are we talking about sizable transmission investment measured in the billions? Or are we talking about one or two kind of smaller or even 345 KV types of lines into the state? That's my first question.

And second, can you provide any detail about the coal that you have hedged for your fleet in Ohio in terms of just how long that's been under contract, how long you might have it under contract going for -- whether those contracts are kind of above or below market?

Let me talk about transmission first and then I will move to Ohio. As Jim mentioned, Michael, we are proposing or will propose as part of our mitigation plan a longer-term solution to the market power issues which will include building new and upgrading existing transmission.

We are estimating the cost to be about $100 million. That of course will be refined as we go through this process. We will be presenting specific details to the FERC on these projects, and of course we will get feedback as we move forward.

We'll also be discussing those projects with the North and South Carolina commission. On -- Jim did you have something to add?

Yes, I was just going to add with respect to the coal. Our plants in Ohio are all on the river, and so as a consequence of that, we're able to really take advantage of the spot price. And so we really don't enter into long-term contracts as we might in the Carolinas or in Indiana. So that's why we are in relatively good shape there, because of the term of our contracts with the coal suppliers.

Michael, we are fully hedged in Ohio for 2012, a modest amount of coal secured for 2013. And I'm not going to comment on market prices of the coal.

Hugh Wynne, Sanford Bernstein.

Hi, I just wanted to follow up on some of the questions regarding coal for gas switching. In particular, what are the biggest impediments for your commercial power fleet and your US (technical difficulty) fleet to capitalize on lower gas prices?

I wonder if you could maybe comment on the difficulties of handling your coal contractual commitments, your rail contractual commitments, and for that matter, the difficulty of serving load during peak demand months like the summer when both the coal and the gas fleets may be called into service. Can you give us a little bit of color on what the operational challenges are to respond to these new relative prices of gas and coal?

I will comment on the commercial business and I'm sure Jim will have something to add.

I feel like our commercial business is very well-positioned to operate in low gas price environment. As I mentioned a moment ago, their generation volumes have just continued to steadily increase in this market condition, and we see that continuing from 2012 to 2013. And those assets are run directly into the market based on price signals in the market. We're aired to run any day and every day, and have had very consistent run times for those gas assets.

In the coal fleet, you know, now that we are completely situated in the wholesale market, the coal fleet nonregulated. We run them in an economic matter manner. If the coal is in the money, we run them. If it's not in the money, we don't. And maintain flexibility in the way we contract for coal to make that operationally successful.

And on FE&G I think we have got a nice portfolio mix. I think about the Carolinas; what dispatches first is the nuclear plants. We're now bringing Buck in behind the nuclear plants, but still get into the coal stack at various times of the year and continue to look at ways that we can introduce flexibility into coal contracts. And I think that's part of everyday business and will continue to be.

I don't see any threat to our ability to meet peak demand because of the low coal -- gas prices or the blend of our coal and gas assets in meeting demand. I think we're well-positioned to meet any peak demand that we may have in the coming summer or future summers.

Ali Agha, SunTrust.

Lynn or Jim, I wanted to come back to your comments. And again just looking at Duke stand-alone little bit, dive a little bit more into the growth rate. The 4% to 6% you talked about from the 2009 base, which implies just mathematically if we were to push it up to 2011, the number would be mathematically lower than that, just given the way the math has worked.

But when I look at the numbers you have given us for 2011 through 2014, you are telling us rate base is growing 6% a year. ROE is trending up. There's no equity issues, so there's no dilution coming to the equity. So, I'm a little confused in terms of the disconnect between 2011 through 2014 and the implied EPS growth for Duke standalone 2011 through 2014.

You know, Ali, the rate base growth is always going to be a bit stronger than the EPS growth as we look about financing the business. We look at inflationary impacts on O&M and other costs that would go into an EPS view. I think what we are saying is that we feel like we have a number of opportunities to continue to invest in the FE&G business, which will be a fundamental driver for growth.

Okay, but you're not assuming any major drop-off either in International or the unregulated commercial business to offset that? I didn't hear that from any of your earlier comments.

Well, you know, Ali, if you look at the waterfall from 2011 to 2012, you do see a resetting of commercial in light of the current market conditions. And so, that business will be one that will continue to work through what I would call a low commodity, low capacity price environment for 2012/2013. And then over time, it will demonstrate growth around energy margins and capacity prices.

Okay. My other question, going back to Edwardsport for second, could you just update us? There was the other phase 2 discussion going on regarding fraud, (technical difficulty) gross mismanagement. Is that issue finished or is it out there? What is the latest on that?

That was part of phase 2 and that issue has been -- the witnesses have been presented and there has been cross examination and it's completed. Both phase 1 and phase 2 are now in the process of being briefed for the commission, and proposed orders will be presented to the IURC for approval.

So in both cases you expect third-quarter timeframe?

That is our best guess at this time. Given the fact that the briefs have to be completed by July, I think that is a reasonable expectation.

Jim von Riesemann, UBS.

Hi, Jim. Hi, Lynn. Good -- good morning I mean.

It is still morning, isn't it?

Yes, it sure is. Hey, two quick questions; one is following up on the coal to gas switching questions. Do your gas plants have any limitations under their air permits with respect to capacity factors?

It's my recollection that our new Buck plan has no restrictions. In fact it's actually been running a little bit above its nameplate in the production of electricity, which we are very pleased with, of course. But with respect to our other gas plants, I think they are all running consistent with the permits that were granted when they were cited.

Okay, so then I guess a follow-up question is can those air permits be amended to increase those capacity factors?

I think they could, but I don't think we need to, actually, given how they are currently structured.

The second question is on the LEED project. Where do you stand with respect to the EIS, the environmental impact study?

We are going to turn to Dhiaa Jamil, who is our Chief Nuclear Operator, to address that.

The draft EIS was issued late last year and we are currently in the comments period which will end in March. And after that we will follow the published schedule for the final environmental impact statement.

March this year or March next year?

March this year.

Okay, great. That's all I had. Thank you so much.

Travis Miller, MorningStar.

Good morning, two quick questions, unrelated; one on the coal to gas switching. Can you tell us what your capacity factors, coal and gas, in the Midwest were December, January, February, roughly?

We don't have specific capacity factors by month available.

If you call Bill Currens and his team, we'll put together that information for you.

Okay, great, and then unrelated question, what type of target payout ratio are you thinking about on the 4% to 6% growth that you have talked about?

We are targeting a dividend payout ratio of 65% to 70%, which we believe is an appropriate range given the level of capital spending we have and growth expectations.

At this time I would like to turn the call over to Mr. Currens for any closing or additional remarks, please.

Okay. I would like to thank everyone for joining us today for the fourth quarter and year-end earnings review and business update. As always, the investor relations team is available for any follow-up. Thanks and have a great day.

This concludes today's conference. Thank you for your participation.