Lynn Good - Chief Financial Officer and Group Executive Officer Stephen De May - Head of Investor Relations, Senior Vice President and Treasurer James Rogers - Chairman, Chief Executive Officer and President

Michael Lapides - Goldman Sachs Group Inc. Greg Gordon - Morgan Stanley Dan Eggers - Crédit Suisse AG Jonathan Arnold - Deutsche Bank AG Leslie Rich - Columbia Management Steven Fleishman - BofA Merrill Lynch Brian Chin - Citigroup Inc

Thank you, Marie C. Good morning, everyone, and welcome to Duke Energy's fourth quarter and year end 2010 earnings review.

Leading our discussion today are Jim Rogers, Chairman, President and Chief Executive Officer; and Lynn Good, Group Executive and Chief Financial Officer. Jim and Lynn will review our fourth quarter and full year results, discuss our performance in 2010, provide an update on key strategic matters and provide financial guidance and our outlook for 2011.

After their prepared remarks, Jim and Lynn will take your questions. Today's discussion will include forward-looking information as a use of non-GAAP financial measures.

You should refer to the information in our 2009 10-K and other SEC filings concerning factors that could cause future results to differ from this forward-looking information. A reconciliation of non-GAAP financial measures can be found on our website and in today's materials.

Note that the appendix to the presentation materials includes additional disclosures to help you analyze the company's performance. With that, I'll turn the call over to Jim Rogers.

Thank you, Stephen. 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 2010.

We delivered on our commitments: One, by increasing earnings in the dividend; two, by operating our fleet and grid exceptionally well at record levels; three, by continuing our cost control efforts; and four, by delivering excellent customer service. To begin today's discussion, let's take a quick look at the fourth quarter.

Then I'll spend most of the time reviewing last year's accomplishments. Today, we reported fourth quarter adjusted diluted earnings per share of $0.21.

That compares to $0.28 last year. The favorable impacts of rate increases and weather were offset by three factors: One, increased costs related to plant outages; two, a discretionary donation to the Duke Energy Foundation of $40 million or $0.02, and without this pre-funding of the foundation for future years, we would have met the consensus for the fourth quarter; thirdly, the continued impact of customers switching in Ohio.

For the full year, we announced adjusted diluted earnings per share of $1.43, an increase of 17% over last year's $1.22. Our full year results fell within the $1.40 to $1.45 earnings range we forecasted in the third quarter and significantly above our original guidance of $1.25 to $1.30.

Even without the favorable weather, which contributed around a net of $0.13, we would have landed at the high end of our original guidance. We continued growing our quarterly dividend to shareholders, increasing the per share dividend from $0.24 to $0.245, a 2% increase.

Our total shareholder return of 9.5% exceeded the 5.7% return of the Philadelphia Utilities Index. Despite the demands on our fleet and grid due to extreme weather, we delivered record performance in 2010.

Duke's nuclear fleet capacity factor of approximately 95.9% set a new fleet record. This is the 11th consecutive year in which the nuclear fleet exceeded 90%.

For 2010, our nuclear fleet had the lowest total operating cost per megawatt hour among domestic fleets for the third straight year as reported by the Electric Utility Cost group. Our nonregulated Midwest coal and gas generation fleet also performed well, generating power at record levels, while staying focused on controlling costs and being available.

We continued to diligently control costs. Our O&M expenses, net of deferrals and cost recovery riders, were held flat from 2007 to 2009.

In 2010, the modest cost increases we experienced were primarily due to weather-related demands on our system as well as increased costs associated with Duke Energy Retail. The bottom line is we held O&M virtually flat for four years.

We also continued to deliver superior customer service. J.D.

Powers 2010 residential customer satisfaction study ranked Duke Energy-Carolinas best among large utilities in the South region. And we just learned today that we were ranked second for satisfaction among business customers in the South, moving up from third last year.

Despite challenging record temperatures and high demand, our employees consistently delivered exceptional operating performance and excellent customer service. We are thankful for their dedication and commitment to serving our customers as well as our investors.

We also made progress on our four major fleet modernization projects in 2010. I will discuss these in more detail next.

Turning to Slide 5. You can see the status at Edwardsport, Cliffside, Buck and Dan River.

These projects are the centerpiece of our plan to modernize our fleet, positioning us to deliver efficient, reliable and increasingly clean power well into the future. In total, these projects represented investments of approximately $7 billion and about 2,700 megawatts of capacity.

By 2015, the completion of these projects will enable us to close about 1,200 megawatts of aging, less efficient coal units and reduce our emission's footprint, better positioning ourself for more stringent environmental regulations. Buck is scheduled to be in service later this year, and Edwardsport, Cliffside and Dan River are expected to go online in 2012.

In our renewable businesses, we put more than 250 megawatts of wind and solar projects into service in 2010, ending the year with more than 1,000 megawatts. Each project was completed on time and within budget and is underpinned by long-term power purchase agreements.

Additionally, during 2010, we executed more than $500 million of project financings in our renewable energy portfolio. Now let me spend a few minutes on the Edwardsport project Indiana, which is approximately 80% complete as of December 31.

It is expected to be in service in 2012. We continued to work to resolve the issues addressed in our April 2010 filing with the Indiana Commission.

In it, we requested approval of an increase in the project's estimated cost from $2.35 billion to $2.88 billion. As you know, several groups have opposed the continued use of coal in general and Edwardsport in particular.

These groups have raised objections to both the plant and its revised cost estimate. Last month, Duke Energy Indiana filed a motion with the State Regulatory Commission proposing an updated procedural schedule in order to address these issues.

Slide 6 includes a summary of the key dates in our proposed schedule. Although estimated construction costs have increased over the original estimates, our IRP analysis confirm that we need additional capacity and completing the plant is the best solution for our customers.

As construction progresses, we continued to monitor potential cost pressures with the project primarily related to labor productivity, including the impact of severe winter weather. In addition, due to the delays in the approval of our quip riders, AFUDC costs are increasing.

However, we continued to aggressively explore appropriate measures to mitigate these cost pressures and deliver the project within our $2.88 billion cost estimate. As we step back, it's important to remember the sound reasons for the project.

The reasons we started the project continue to exist today. As new environmental regulations are implemented, we expect as much as 1/3 of U.S.

coal plants to shut down by 2020. Due to the long lead times required to build base load plants, we cannot wait until our older coal fired units in Indiana are closed to begin replacing them.

We're building the next generation of power plants now to provide reliable energy to our customers for the next 50 years or more. From an environmental standpoint, Edwardsport is expected to produce 10x the power for the existing plants with less environmental impact.

When completed in 2012, Indiana will have one of the cleanest coal plants ever built, and most importantly, it will meet the long-term growth needs of our customers in the state. The new 618-megawatt plant will replace the existing Edwardsport units that date back to the 1940s.

It will use coal and abundant natural resource in the state, which supports local Indiana jobs. We believe Edwardsport is a sound investment in Indiana's energy future.

Next turning to Slide 7. I'll update you on our progress in Ohio.

You all are aware of the challenges we've experienced there and some of the shorter term and longer term strategies we generated in response. For example, the rapid deployment of our competitive retail suppliers, Duke Energy Retail, and the recent filing of our market rate offer.

First, let me update you on customer switching, which began in '09 and began to stabilize in the third quarter of 2010. By year end, customer switching was running about 65%, only a slight increase from 64% in late September.

For the year, we recognized about $0.06 negative earnings impact of net switching year-over-year. In response to this competitive pressure, Duke Energy Retail has quickly and effectively pursued customers both inside Duke Energy Ohio service territory and in other utility service territories within Ohio.

We have been pleased with the performance of our retail arm. It has acquired approximately 60% of our total Ohio switch load.

As we think about Ohio in the long term, our generating assets currently serve an essentially regulated function in that they must stand ready to serve our retail customers. However, under the current ESP structure, we are not adequately compensated for this obligation.

In November, we proposed a market rate offer to the Ohio Commission, which would eliminate some of the asymmetrical risks we now experience under the ESP framework. Our NRO is designed first to give us flexibility to deliver competitive and fair rates to customers; secondly, to provide mechanisms that gives us opportunities to earn more adequate returns on our investments in Ohio; and lastly, to provide more long-term clarity for Ohio generation business.

We weighed all the options and believe the MRO is the best solution under the current rules. The filing, which is subject to approval of the Public Utilities Commission of Ohio, meets the Senate Bill 221 requirements and positions our generation for the long term.

The statute in Ohio requires the commission to issue an order on our MRO filing by late February. In the coming weeks, we also expect to file a request for approval to transfer the Ohio coal generating assets to an affiliate of Duke Energy Ohio, providing us more flexibility in the future for our generation.

In essence, we believe the regulatory framework in Ohio is broken. Without provisions in place to assure a competitive and fair return on our investments, it is difficult for us to justify future power plant investments in the State of Ohio.

This is not good for Duke Energy or for Ohio. We will continue exploring options to maximize the returns from this business.

On Slide 8, you'll see our 2011 earnings outlook. Assuming normal weather and modest load growth, we expect our 2011 adjusted diluted earnings per share will fall within a range of $1.35 to $1.40.

This is consistent with our long-term projected growth rate of 4% to 6% based on 2009 adjusted earnings. Our growth is anchored by the investments we are making in the regulated business as we continue to modernize our fleet.

We also maintain our focus on cost control and strong operational performance. Now I will turn it over to Lynn for an in-depth look at our financial results in 2002 as well as our earnings guidance for 2011.

Thank you, Jim. Today, I'll give you a brief overview of our 2010 results.

Then I'll discuss our outlook for 2011. As Jim reported, our adjusted EPS for 2010 was $1.43, a 17% increase from adjusted EPS of $1.22 in 2009.

This growth was supported by weather, higher rates in the Carolinas and strong operational performance of our fleet and grid. We experienced favorable weather in both the summer and winter seasons.

For the year, our cooling degree days in the Carolinas and Midwest were more than 30% higher than normal, and our heating degree days were also favorable to normal by 16% in the Carolinas and 7% in the Midwest. Because of higher generating volumes from our fleet, our O&M costs, net of deferrals and cost recovery writers, were slightly higher than 2009.

We worked diligently during the year to control costs at a level consistent with the prior year. However, the increased costs of plant outages and the operating costs of Duke Energy Retail made this objective challenging.

We continued to grow the quarterly dividend from $0.24 to $0.245 per share. At the same time, we maintained the strength of our balance sheet and our credit ratings, which were affirmed by both Moody's and S&P in January 2011.

A more detailed information on the earnings drivers for each of our segments for both the quarter and the year is included in the appendix of this presentation. The table on Slide 9 shows the 2010 full year results for each of our business segments compared to our projected segment EBIT.

As shown, each of our three business segments exceeded our original projections. The strong results of franchised electric and gas compared to plan were principally driven by favorable weather.

Our regulated businesses has also experienced weather normalized customer load growth compared to our original expectation of flat load growth for the year. Our weather normalized customer load increased approximately 2% in 2010, principally driven by a 7% increase in our Industrial customer class.

Our Residential and Commercial customer classes were flat for the year. Even though we've seen some improvement from the 2009 decline in our total customer load, we have not yet returned to 2007 pre-recessionary levels.

In fact, we do not project returning to those levels until about 2015. Commercial Power's results for the year were down about $100 million compared to the prior year largely due to customer switching in Ohio.

However, these results exceeded our original segment projections by more than $80 million or around 25%. Commercial Power mitigated some of the customer switching pressures in Ohio by effectively deploying Duke Energy Retail, our competitive arm, allowing us to recapture some of the margins lost from switching.

Our 3600-megawatt Midwest gas-fired generation fleet also performed well with record volumes and higher margins due principally to favorable weather. Overall, our strong results for the year gave us the ability to make a discretionary $40 million contribution to the Duke Energy Foundation in the fourth quarter in support of our local communities.

This contribution was in addition to $15 million we had made earlier in the year. Our adjusted effective tax rate for 2010 was approximately 33%, slightly higher than our projections for the year.

This increase was primarily driven by the recently enacted extension of bonus depreciation, which eliminated the manufacturing tax deduction. In 2011, our focus remains on increasing earnings, growing the dividend, successfully managing our upcoming rate cases and maintaining a strong balance sheet.

Slide 10 shows our key assumptions for 2011 earnings drivers. As we pointed out, our 2010 adjusted diluted earnings per share of $1.43 was impacted by favorable weather.

Excluding weather, our adjusted results would have been around $1.30. Remember that our budgets assume that weather will be average or normal.

This slide contains the estimated earnings per share impacts of our segment EBIT projections based upon the midpoint of our $1.35 to $1.40 guidance range. Taking $1.30 as the normalized starting point, we expect U.S.

FE&G to contribute an incremental $0.14 toward our 2011 EPS guidance. The first and single largest driver of this growth is expected to come from incremental earnings associated with our capital spending program.

The second driver of FE&G's year-over-year growth is the expected economic expansion. If the economy continues its upward momentum, we expect higher volumes in 2011 of about 1%, reflecting modest growth in all customer classes but continuing to be anchored by Industrial growth.

2011 is expected to be the second consecutive year of increases in our weather normalized load. Our Industrial customers policy expect growth to continue into 2011 but at a modest level.

Specifically, the automotive industry is expecting to continue the recovery that began in 2010. According to recent projections by J.D.

Power, domestic auto sales in 2011 are expected to increase over 2010 levels by approximately 10%. Our remaining Industrial classes are expecting more modest increases.

Our Industrial load grew at 7% in '10 over 2009, and we expect an additional 2% increase in 2011. In 2010, the average number of Residential customers increased by about 0.5% over the prior year.

Due to continued high unemployment and a difficult housing market, we project that Residential growth in 2011 will be slightly less than 1% on a weather normalized basis. In the Commercial sector, office vacancy rates in our principal metropolitan areas remain high at about 20%.

While vacancy rates did stabilized during 2010, we don't expect substantial growth in the Commercial sector until vacancy rates decrease and retail sales strengthen. Similar to the Residential class, we expect the Commercial sector to grow less than 1% in 2011.

Our final FE&G driver for 2011 is increased operating costs due to the Buck plant coming online and additional planned nuclear outage, increased employee benefit costs and normal inflationary impacts. These cost increases will be somewhat mitigated by cost reductions from our voluntary separation plan and office consolidation efforts.

Moving to our Commercial Power segment. We expect a negative impact of around $0.09.

Approximately $0.05 to $0.06 of this change is expected to come from annualizing the impact of the level of switching in 2010. We do not expect a significant change in switching levels in 2011.

The balance of the year-over-year change in Commercial Power is primarily due to lower expected results from the Midwest gas assets because of lower PJM capacity revenues and lower projected volumes based on more normal weather. Moving now to our International segment.

We expect an approximate $0.03 increase largely due to higher prices in Brazil. Finally, the last two drivers are interest and taxes.

For 2011, we expect interest expense to be approximately $100 million higher due to increased debt balances and higher anticipated interest rates. Our adjusted effective tax rate is projected to be approximately 32% in 2011.

Before I discuss our capital expenditures, let me mention our expected operating costs for 2011. Our total company O&M, net of deferrals and cost recovery riders, is projected to grow between 3% and 4% in 2010 compared to $3.4 billion in 2010.

Since 2007, our costs have increased an average annual rate of approximately 2%. We're pleased with our efforts to control our costs, and we will remain focused as we anticipate additional cost pressures over the next several years from new plant additions.

Next I'll walk you through our capital expenditure projections. As you can see on Slide 11, we expect to spend $4.5 billion to $5 billion in 2011, which is consistent with the $4.9 billion spent in 2010 and includes approximately $1.4 billion for continuation of our system modernization projects.

As illustrated on Slide 11, we project the annual spending at about $3.5 billion to $4.3 billion per year for 2012 and 2013, reflecting the wind down in capital spending associated with our modernization program. Over this period, we also anticipate that environmental spending will increase.

As you know, the potential compliance costs are subject to considerable uncertainty and will be dependent upon finalization of the rules. Environmental regulations pending by the EPA could require us to install additional environmental controls and could result to the retirement of additional older coal-fired units.

Our system modernization efforts and related committed retirements have positioned us well for these compliance requirements. However, under certain scenarios, our capital expenditures for these environmental rules could total approximately $5 billion over the next 10 years.

While very little environmental capital is expected to be spent in 2011, for planning purposes, we have included approximately $250 million in 2012 and $500 million in 2013. This level of environmental capital is based upon a reasonable estimate of potential remediation needed for compliance with our current understanding of these anticipated rules.

Our expectations primarily involve costs to update some of our current emission controls mostly in the Carolinas and Indiana. We expect significant rate-based growth in our regulated utilities as we finalize our modernization projects and look to recover our investments in customer rates.

Depending on the timing of rate case activity, our system wide rate base of approximately $22 billion has the potential to grow to around $28 billion by the end of 2013 principally in the Carolinas. Rate base beyond 2013 will be driven by future environmental expenditures and any new nuclear and natural gas generation investments.

Finally, we continue to maintain a level of discretionary growth capital in both our Regulated and Commercial businesses. These discretionary levels represent capital that has not yet been designated to specific growth projects such as new renewable investments, market development or opportunities in our International business.

If we do not find projects that meet our return expectations, we will not invest this discretionary capital. Before we move on, I'd like to update you on our progress in exploring new nuclear development opportunities.

In 2013, we anticipate receipt of our commercial operating license for the Lee Nuclear Station in South Carolina, targeting a potential in-service state in the early 2020s. Last week, we finalized an agreement with the Jacksonville Electric Authority, giving them an option to acquire up to 20% of the lease station, a demonstration of interest in new nuclear generation in all regions.

This agreement is consistent with our measured approach to reduce risk. We continued to pursue legislative frameworks in North Carolina such as cash clip, which is a must have for us to move forward with new nuclear plant investments.

The modest amount of nuclear capital included in the 2011 to 2013 time horizon reflects capital required to continue pursuit of our commercial operating license for Lee. Consistent with the level of our CapEx in the regulated business, we plan to file rate cases in the next few years.

Slide 12 reflects our anticipated rate case activity between now and 2013. In 2011, we plan to file in North and South Carolina to update our rates for additional capital investments made since our last rate case filing in 2009.

We are evaluating the potential for filing rate cases in Ohio and Kentucky during 2011. The recently enacted bonus depreciation rules, which I'll discuss further in a moment, may diminish immediately for these rate cases.

We will make that decision later this year. We also expect to file rate cases for 2012 as we complete our baseload generation facilities.

The timing of our filings in Indiana will depend on the outcome of our Edwardsport proceedings. Slide 13 shows our anticipated operating and investing cash flows for 2011 as well as our anticipated sources of financing.

Our estimated 2011 CapEx of around $5 billion and the approximate $1.3 billion required to fund the annual dividend are expected to exceed our cash sources. This deficit will be met by new debt issuances of around $2.2 billion.

Scheduled 2011 debt maturities are relatively low and most of our required funding will be satisfied through utility company and holding company financings. We will also evaluate pre-funding of 2012 maturities if market conditions are favorable.

During 2010, we raised approximately $285 million from our internal equity plans. Because of the strong cash flows in 2010 and the strength of the balance sheet, we do not expect to issue equity through 2013 based upon our current business plans.

We are also expecting significant cash flows overtime from bonus depreciation. So let me spend a few minutes on bonus depreciation and pension funding, two important discussion topics during this earnings season.

First, bonus depreciation. Many of our current capital expenditure projects, including system modernization and renewable investments qualify for bonus depreciation.

Our best estimate is that overtime, we could generate cumulative cash benefits between $1.5 billion and $3 billion from these provisions. This is a broad range and reflects uncertainty over how the bonus depreciation rules will be applied.

We are waiting for clarification from the U.S. Department of Treasury to determine which projects will qualify for 50% or for 100% bonus depreciation deductions.

As we learn more, we will refine our estimates and share them with you. Of course, the timing of these cash benefits will depend on future taxable income.

Even though bonus depreciation related to our regulated projects reduces rate base, the cash benefits will decrease our need for financings overtime and help to mitigate future customer rate increases. Now I'll turn to pension funding.

We expect to make contributions to our pension plans of $200 million in 2011. In 2010, we contributed $400 million.

We project our plans to be fully-funded based upon Pension Protection Act requirements. In closing, I'm very pleased with how we delivered financially during 2010, and we are well-positioned to achieve our targeted long-term adjusted diluted earnings growth of 4% to 6% and our targeted dividend payout ratio of 65% to 70%.

Now I'll turn it back over to Jim.

Thank you, Lynn. Before I give you all a brief overview of our focus for the upcoming year, let me update you on our pending merger with Progress Energy, which we announced on January 10.

We are targeting a closing date by year end. This combination creates a utility unprecedented in size and scale.

But size is not the only consideration. This transaction gives us the ability to more effectively manage the challenges we face today and the transformation now occurring in our industry.

This will result in benefits for all our stakeholders, our customers, investors, employees and the communities we serve. Specifically, customers in the Carolinas will benefit from fuel and joint dispatch savings day one.

All of our customers will benefit overtime from cost efficiencies as a consequence of the combination. Our investors will benefit from earnings accretion in year one in the strength of the combined balance sheet and dividend policy.

Slide 15 contains a merger scorecard we will use throughout the year to provide you with updates on the status of our various filings and approvals. We expect to file our initial S-4 with the SEC in March, after the Form 10-K is filed.

Meetings to conduct shareholder approvals of the merger will be scheduled later in the year after we receive clearance from the SEC on the S-4. We are also finalizing various state and federal regulatory filings related to the merger and expect to file most of these beginning in mid-March.

In addition to state regulatory filings in the Carolinas, we anticipate filing with the Kentucky Commission for merger approval. Our merger teams have begun initial integration planning.

To achieve earnings accretion in 2012, we must aggressively and relentlessly identify and pursue cost savings opportunities this year. Clearly, completion of the merger and integration planning with Progress Energy will be top priorities for us in 2011.

During this process, we will fully recognize the need to stay focused on running the business and delivering for our investors, customers and communities. To do so, we'll maintain exceptional operational performance and efficient cost management.

We delivered on our financial commitments in 2010. We grew our adjusted diluted earnings per share.

We increased the dividend, and we maintained the strength of our balance sheet. We plan to continue this momentum and remain focused on our financial and operational performance during 2011.

In our regulated business, in 2011, we will file rate cases in up to four of our jurisdictions, driving for constructive regulatory outcomes. We'll maintain focus on our long-term legislative agenda to effectively reduce the gap between our allowed and earned returns overtime.

In the short term, we are pursuing cash quip provisions for new nuclear investments in North Carolina. Our major construction projects are nearing completion with the first of these projects, the 620-megawatt Buck combined cycle gas unit expected to come online in 2011.

In Indiana, we're managing costs related to Edwardsport in working towards a constructive outcome with the cost increase proceedings. In our Commercial businesses, our attention will be on successfully reaching a workable and constructive outcome with the Ohio Commission on our standard service offer, which would establish generation rates for 2012 and beyond.

And Duke Energy Retail will continue to pursue customers and protect margins in Ohio. We will look for the right opportunities to grow our renewable energy business and our international operations.

Finally, we will continue to support the communities in which we operate, helping to drive economic development activities during these challenging times. 2010 was a very successful year.

As we look forward to our merger opportunity, our modernization projects and our commitment to both customer service and shareholder value, Duke Energy is poised to deliver superior, long-term performance in 2011 and the years beyond. With that, let's open up the phone lines for your questions.

Jim, one of your other brethren in Ohio has been talking about the idea to potentially re-evaluating SB 221 from a legislative perspective later this year. I don't know if you have any thoughts on that issue.

And if that could potentially reshape, how you guys are thinking about pursuing the MRO option?

I think it's clear to us that the regulatory model in Ohio was broken, and we need to find a way to revise it and to structure it in a way that's fair to both our customers and our investors. As I mentioned earlier, there's asymmetrical risk in Ohio today with respect to the impact it has on our investments and generation there.

So I believe the time has come or is coming to make a change in the regulatory regime in Ohio.

And do you still believe that the MRO route is the best option or is it just the best option available given the construct of SB 221?

I would consider it the best option available given the Commission's position on the ability to get a non-bypassable charge that allows us to earn a fair return on the generation that we're required to stand by and provide if and when customers come back. In a sense, Dan, customers in Ohio have a free option.

And as you know, in Commercial markets, there are no free options. So we need to get the rules right, so that we have an opportunity to earn a fair return on our generation.

And then I guess there was a call recently and some talk potentially about re-evaluating Edwardsport to the sense of just turning into a CCGT and stopping the full coal gasification process. Can you share your thoughts on that alternative and kind of the economics of that versus completing the project as designed?

Well, I think the call you may be referencing, we weren't involved in. I think that was by the Sierra Club.

And the fact of the matter is we've done detailed analysis of a variety of options from shutting it down to basically continuing it versus converting it into a combined cycle plant. And based on our analysis, the best answer for customers is to complete the plant, and we're on that track.

We've done updated IRPs, and virtually every one of them continue to say we need the capacity and that this is the best option for customers going forward.

And just one last question. So on the Industrial demand outlook for 2011, the 2% growth, maybe it seems like a lot of that 2% growth has already occurred just at the momentum of how 2010 played through.

How would you handicap the likelihood of demand looking better than where you guys are for the year? And you had indications from your customers that would suggest 2% is the right number or is it more on the range of being conservative today?

Dan, it will be interesting. I think we'll have more to say on that as we get into the first and second quarter.

We think it's a reasonable estimate based on what we believe is happening on our territory as well as a discussion with our Industrial customers, but more to come.

A couple of questions. My first was, in the third quarter, you had numbers that implied about $0.13 above normal for weather through the third quarter and then another $0.03 or so in the fourth quarter, but your annual factor showed that as $0.13, but talk about it being net of a mechanism.

Can you just explain how that works?

Jonathan, what we did on the slide, I guess, Slide 10 is we actually netted the weather impact with the impact of incentive short-term and incentive payments that put us from target to maximum because as we look forward, we of course would plan that our incentives will be paid at the target level. So that difference between the $0.16 and whether that's a referencing in the $0.13 is the incentive.

Are they incentives that related to weather sales or these are...

Related to the fact that we went to maximum on our incentive payout, and that was largely driven by weather.

So these are employee incentives?

Yes, it is. Yes.

And then how do you treated weather in 2011 because you obviously had this very strong start to the first quarter, I would guess.

You're reflecting on that Northeastern weather, Jonathan?

Something like that.

We've had a little bit of that down here.

We always plan for normal weather, which I think is the only thing to plan for. And so that's the planning assumption going into the year.

We'll update on how that looks as we progress.

So the guidance is weather normal for the year?

Yes.

And, Jonathan, the other important point is, if you remember last year, we started out at a $1.25 and $1.30. And as the weather kept improving and we were holding our costs down, we increased our guidance twice actually until ultimately to the $1.45, and we will probably do the same thing if we're blessed to have the same weather this year as we did last year.

And can I ask for this related guidance topic? I was wondering if you could provide some more granularity around the $0.14 growth you expect out of the utilities because you say that net that costs are likely to be higher.

And on math, sort of 1% sales growth may be at $0.02 or $0.03 at best of a $10-ish billion revenue number. So that kind of -- and you did say that the modernization program would be the largest piece of this.

And it seems to imply a couple of hundred million or more of EBIT coming out of the program. So can you talk through what specifically are the mechanisms that provide those revenues in 2011?

Yes. And, Jonathan, you need to think about a couple of things.

Allowance for funds would be a part of that. It's one of the ways we recognize earnings for capital investment that's not yet in rig.

And then we also have riders for Edwardsport. We have quick cash coming into the picture in 2011 for Cliffside.

So it's Cliffside, it's Edwardsport, it's Buck and Dan River. We also have investments in our nuclear fleet.

We have smart grid. We have energy efficiency.

It's all of the programs that generate rider or allowance for funds revenue.

And I read the slide that the AFUDC might have been in the other category but...

It is not. It's listed as other information, but it's actually reflected in FE&G.

Just finally, I didn't hear you specifically reiterate, but I'm wondering if you are reiterating the 4% to 6% growth target post merger after the '11 base.

Yes, that's our long-term growth aspiration, Jonathan, and we would be using 2011 as the base for the new company.

Long term, meaning?

What do you think long-term should mean?

I'm not saying it.

Yes, that's a really good point. Jonathan, I made the point of long term because it will vary from year-to-year as we have rate increases coming into effect, et cetera.

And I know there's a lot of interest in us giving more specifics around '12. We're not prepared to give more specifics around '12 because all of the activities that we have to accomplish here in '11, including rate cases, MRO, closing of the merger, et cetera.

Right, 4% to 6% is a very good planning assumption for us as we look forward.

I wondered if you could just touch on the International segment for a minute. You have an EBIT projection growing 13%.

And wondered if you could talk about the drivers of that. I know you mentioned increased pricing in Brazil.

Is that driven by an inflation adjustment? And looking forward, what's your PPA status and sort of the earnings growth potential there?

Because I see you're not really investing all that much capital in that area.

Good questions, Leslie. We have actually some repricing in Brazil impacting '11 where we run a very contracted business in Brazil but have the opportunity to update prices overtime.

And so the single largest driver year-over-year is updated pricing in Brazil. We do expect our National Methanol entity to continue to contribute about 20% of the earnings.

That would be the other point that I would make. In terms of capital growth, we continue to designate capital.

We have a few projects underway in our International business, one of which or a couple of which we would expect to come online in 2011, but that capital growth will really depend upon our ability to find projects that meet our risk appetite and return expectations.

So is that recontracting in Brazil sort of a onetime thing or that's an annual repricing?

There will be an annual feel to it, Leslie, because we have contracting ranges or tenders between five and seven years in Brazil, some of them longer than that. And we will have the benefit of inflation pricing on those contracts if inflation starts to take off in Brazil.

We have inflation protection.

And then separately, if you could just discuss the strategic rationale between for filing to separate your Ohio generation into an affiliate.

I think, Leslie, the thought here is it gives us flexibility, and it's consistent with the MRO because the way the MRO works overtime, you're moving toward, I mean, you start with the blend of your existing generation and market. And overtime, it becomes increasing market.

So at the end of the MRO period, your generation is free from being committed to the load. And so it's very important for us to move it out from under the regulated utility.

So we have the flexibility to make decisions about what to do with those assets going forward.

Jumping off a little bit on Leslie's last question, when you mentioned, Jim, that the transferring of the coal generating assets gives you a little bit more flexibility, I could take that one or two ways. I could think of it in terms of flexibility to manage your customer load.

You don't have that poll of requirement. But then I could also think of it as flexibility strategically to potentially separate out that generation fleet into a more merchant affiliate and do something more strategically with that business.

So when you think about flexibility, the term flexibility, are you thinking about it in both senses of the word? Are you thinking about it more in one type or another?

Can you just give a little bit more clarity on what you mean by that flexibility?

Sure, Brian, a good question. And let me start out by making a point.

If we had a bias, we would prefer to have our assets dedicated to the Ohio load and earn a fair return on that investment, like 10%, 10.5% or 11% return on equity. That's our first choice.

And we've been clear with the commission that was our first choice. But if they're not going to allow us to earn that type of return, then we don't want the assets dedicated first, and that's why we selected MRO.

And second, we want to get them out because the flexibility we're seeking is primarily, at that point, make the decision with respect to whether we want to be in the merchant business or we want to sell the assets. And I would tell you, my bias today is not to be in the merchant business, particularly in PJM.

But again, the timing, the decision about that will be something that will come in the future. The timing of the decision will be driven by the movement in the market.

And eventually, the price of power in PJM is going to rise. Even if gas prices are flat, overtime, demand will come back as the economy recovers.

And secondly, and this is a fact that's been hard to quantify for many, as you did see a retirement of the old coal plants as a consequence of these stricter, newer regulations on coal plants, if that's going to translate into upward pressure on the price per power in PJM. So we don't have -- our bias is to dedicate to kind of summarize this at a regulated return.

But absent that is to free it and at appropriate time make a decision. And our bias at the current time is not to be a merchant player and pursue that strategy, but to exit it.

That's our current bias, but we won't make that decision until we have clear facts in future periods.

And then one separate question on your guidance. On Slide 19, you make the point that you're looking at annualized impact of 2010 switching levels in Ohio.

Am I to assume from that phrase that you're assuming that you're only getting the annualized impact of the 2010 switching levels, but you're not assuming any further switching since the switching appears to have levelized out in your 2011 numbers?

Brian, we have a modest amount of increased switching, but the majority of that driver is annualization of what we experienced in '10. And it's because we have seen stabilization.

And then lastly, on the stabilization, what do you think has caused that to levelize out at such a flat rate?

I think it's a reflection of the way switching occurred, Brian. So the more savvy energy users, the Industrial's and the Commercial's customers switched first, and now we're into the Residential class.

And frankly, we have not seen a lot of government aggregation, and our Residential customers have proved to be sticky. We'll use that technical term.

Just a quick question on the bonus depreciation. So in the 2011 cash flow forecast that you've included your current estimate.

Yes.

And the deferred taxes, okay. And when you talk about rate base, I think you said growing from $22 billion to $28 billion, are you encompassing the impact of the deferred taxes in that from bonus depreciation?

We are.

So that's a good net number of all this?

Yes. And, Steve, what I would say is, the low end of the range would be included in that rate base adjustment.

So when I talked about cash flow benefits of $1.5 billion to $3 billion, we use the low end of the range for an estimated rate base.

I'm sorry, I'm not sure what you mean by that.

Yes, so let me try again. So we have a range of expectation in what can happen on bonus depreciation, if things qualify the level of 50% or things qualify the level of 100%.

And there would be an associated impact to deferred income taxes at those two levels.

So you're using the low end when you talk about the rate base forecast?

That's correct.

Two questions. One sort of in the weeds and a little bit follow-on to the prior question.

It looks like you've also tweaked your CapEx budget a bit, at least relative to the last specific disclosure to 2012. CapEx range looks like it is $300 million lower on the low end and $500 million or $600 million lower on the high end than you last disclosed.

Should I presume that that's because -- I remember you saying that you had sort of a placeholder for discretionary CapEx in there. Should I presume that that's now gone?

Or is it a lot more puts and takes that go into that? And then the second question is, I presume that's also factored into your rate base growth update.

The answer to the question is, Greg, we do refine CapEx as we get closer in, and as '11 and '12 develop we get more specific in the way we're think about it. We have made some adjustments on discretionary.

We've also reflected environmental for the first time. So it's a combination of being closer and then more refined in our estimates.

And the revised estimates are what are implied in the rate base number as we just talked about.

And then the second question relates to the growth rate aspiration. I presume that the growth rate aspiration is predicated on the assumption that the merger does in fact close and sort of your looking at sort of the opportunities for the company pro forma post '11 as opposed to standalone post '11 when you worked that growth rate.

Greg, it's a good question. What I would say is that the merger really positions us more solidly within the growth range of 4% to 6%.

As you know, we've got some weakness in Ohio. We've got repricing that's going to happen as a result of the MRO in '12.

So on a standalone basis, we would've been trending in the lower end of that range, so the merger gives us an opportunity to have greater confidence and positions us more solidly within the range.

I'm looking at Slide 24, and it's the estimated and the actual ROEs at you're various regulated businesses. I guess, historically, Duke had been an industry leader in terms of actually earning at or even, in some cases, better than the authorized ROE levels, but it looks like your 2011 outlook is kind of showing that you expect to under earn in a number of the jurisdictions, almost a little bit of a mean reversion towards kind of what most of your peers actually do in the industry.

Just curious, is lag becoming more of a long-term challenge than it historically had been for Duke? And what are the items or steps you guys can take to help mitigate lag?

I'll take a shot, and I'm sure Jim has some comments as well. I think '11 is an interesting year, Michael, in that we have no new rate cases coming in.

And so we will have inflation impacts, we also have a slower load growth assumption that we might have had several years ago that would contribute to lower returns. But we believe, overtime, as we put these rate cases into effect and as we continue to work on legislative initiatives in our jurisdictions that we have an aspiration of closing that gap.

We targeted to be within 75 basis points in the Carolinas, and I think we'll be pretty close to that. So I think it's a combination of factors that are affecting us.

No, I think that's correct. And of course, we probably have the largest building program in the country.

I mean, we're building two advanced coal plants. We're building two combined cycle plants, and the combination of all that gives us AFUDC, which helps in terms of closing the gap.

But at the of end the day, what we recognize we need for a variety of reason is to move toward formula rates. This is a good answer for investors.

It's a good answer for consumers because, as I mentioned a few moments ago, we're in a period of rising prices over the next several decades. Formula rates allows us to smooth out those cost increases.

In the interim, what we would do, because it takes a while to get legislative changes, we're looking for riders, for instance. Environmental riders would be very important to achieve in the states we operate in.

And in fact, we have those riders in Indiana and Kentucky today as we spend more money on retrofits or meeting more stringent environmental requirements. So I think it's a combination long term of riders and trackers around specific items and morphing overtime into formula rates.

That would be the vision, and certainly, that would be the aspiration we have going forward.

Thank you, and thank you, everyone, for joining us today. As always, the Investor Relations team is available for your follow-up questions.

Thank you, and have a good day.