Duke Energy Corp (DUK) 2011 Q3 法說會逐字稿

Good day, everyone, and welcome to the Duke Energy earnings conference call. Today's call is being recorded.

At this time for opening remarks I would now like to turn the call over to Mr. Bill Currens, Managing Director of Investor Relations. Please go ahead, sir.

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

Jim and Lynn will review our quarterly results and provide an update on our key priorities. After these prepared remarks we will take your questions.

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

Now I will turn the call over to Jim Rogers.

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

This morning we released strong third-quarter results and are very pleased with the exceptional performance of our fleet. As a result of our year-to-date earnings, we are increasing our 2011 adjusted diluted per-share earnings guidance range from between $1.35 and $1.40 to $1.40 and $1.45.

We committed to you after announcing our proposed merger with Progress Energy that we would continue to stay focused on running the business, delivering results, and executing on our long-term strategic initiatives. The ability to increase our earnings outlook in a year that includes a pending merger transaction, a busy docket of regulatory proceedings, continuing economic uncertainty, and significant storm damage to our system is due primarily to our employees, who are single-mindedly focused on safety and excellence and execution. I thank them for their efforts.

Today, after Lynn reports on our quarterly earnings, I will provide updates on the key initiatives that are positioning the Company for the long term. These initiatives include -- one, the status of our fleet modernization program; two, our Ohio ESP stipulated settlement; three, the latest developments in our pending merger with Progress Energy; and finally, our rate cases in the Carolinas.

But first, let me give a brief overview of our earnings and performance for the quarter. Turning to slide 5, today we reported third-quarter adjusted diluted earnings per share of $0.50. This compared to $0.51 in the prior year.

Our year-to-date results through the third quarter were flat to the prior year. However, when we take into account the significant weather that favorably impacted our results last year, this performance is outstanding.

At U.S. Franchised Electric and Gas, our largest business segment, this strong operational performance and our generation investments helped offset less favorable weather and higher planned O&M cost.

At International, we saw strong results from our Latin American operations as well as increased earnings from our stake in National Methanol Company.

For the quarter, our nuclear fleet had a capacity factor of 99.27%. The fleet dispatched more than 15 million megawatt hours setting an all-time Company record for best quarterly nuclear generation performance. Additionally, our nonregulated Midwest gas fleet continues to generate at record levels.

Results at both Commercial Power and Duke Energy International, based upon their performance to date, are on track to exceed the earnings contributions we originally projected for the year.

Now I'll turn the call over to Lynn, who will provide more details on our quarterly results.

Thank you, Jim. Turning to slide 6, let me begin with a review of the adjusted earnings drivers for each of our business segments for the quarter. For U.S. Franchised Electric and Gas, quarterly adjusted segment EBIT was relatively flat to the prior year. Weather, while favorable to normal, was not as favorable as the prior year.

To put this in context, last year the Carolinas recorded the hottest third quarter since the Company began keeping records in 1961. Additionally, our operation and maintenance expense was higher than the prior year, reflecting our planned increase in outage and maintenance spending.

For 2011, we were targeting an O&M cost increase of 3% to 4% net of deferrals and cost recovery riders. This target has been pressured by year-to-date storm restoration costs of approximately $75 million, most of which was incurred in the first half of the year.

Excluding these significant storm costs, we are within our expected O&M increase range for the year. We will continue to aggressively manage our costs.

Quarterly results were favorably impacted by the continued earnings contributions from our new generation investments as well as the lack of the prior-year $44 million impairment charge related to Edwardsport, which was included in adjusted earnings.

In Commercial Power, the quarter's adjusted segment EBIT was lower than the prior year, primarily due to the expected financial impacts of customer switching in Ohio. This was partially offset by increased coal and emission allowance sales, higher base generation rates charged to existing ESP customers, and favorable O&M.

Through the third quarter, gross customer switching is at approximately 68%, consistent with the first half of 2011. Switching for the year is forecasted to negatively impact 2011 earnings by approximately $0.07 per share. It is important to remember that under the terms of our stipulated ESP settlement, which is subject to PUCO approvable, beginning next year Duke Energy Ohio will no longer be subject to significant customer switching risk.

Consistent with the first half of 2011 our Midwest gas fleet continued its exceptional performance with generation volumes at around 40% above last year's quarter. The fleet is on track to set an annual generation record for the third straight year.

In total, Commercial Power is well above plan through the third quarter and is expected to significantly exceed its annual segment EBIT target for 2011. Before leaving Commercial Power I want to highlight that during the quarter we recognized an impairment of excess emission allowances.

Due to the EPA's finalization of the Cross-State Air Pollution Rule, and in 2012 the Company will no longer need the SO2 emission allowances held for CAIR compliance. As a result, we recognized an approximate $79 million pretax charge for the quarter which has been excluded from our adjusted results.

Turning now to Duke Energy International, this segment continues the strong performance it has shown all year. Results were impacted by higher average volumes and prices at National Methanol, favorable hydrology in Central America, and favorable pricing and foreign exchange rates in Brazil.

Additional financial drivers for the quarter included increased interest expense due to higher average debt balances, and a higher adjusted effective tax rate of 33% compared to 31% in the prior-year quarter. We continue to expect a full-year effective tax rate of around 32% on an adjusted basis.

Now let me briefly discuss the pretax impairment charge we recognized during the quarter on the Edwardsport IGCC project. As you may recall, a few weeks ago we updated our cost estimate to complete the project including startup testing. Total estimated cost, excluding financing charges, increased from $2.72 billion to $2.98 billion. We estimate the total financing costs will now be approximately $300 million.

This cost increase was primarily driven by incremental material quantity and scope changes and unfavorable labor productivity. We currently have a proposal pending with the Indiana Commission to cap our recoverable construction costs at $2.72 billion, excluding financing costs. This cap, if approved, limits the construction costs that will be passed on to Indiana customers.

Because the new incremental project costs are estimated to exceed the proposed cost cap, recovery above $2.72 billion is not considered probable. Therefore, we recognized an approximate $220 million impairment charge for the third quarter. This charge has no impact on the Company's current liquidity and is not expected to change the credit ratings or outlook of either Duke Energy Corporation or Duke Energy Indiana.

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

Turning to slide 7 I will spend a few minutes on economic conditions in our service territories and customer volume trends in the regulated businesses. As we entered late summer the overall US economy faced a new set of challenges. The European debt crisis and S&P's downgrade of US government credit ratings resulted in an increased skepticism regarding the sustainability of the economic recovery.

Although we are seeing some expansion, the economy is growing at a slower pace than was originally expected earlier this year. GDP estimates have been revised downward. Consumer confidence continues to remain low. And manufacturing, while still growing, has slowed.

Additionally, we continue to experience the effects of depressed housing markets and high levels of unemployment, even though both have stabilized. As a result, we expect an extended period of low growth, and we remain cautious in our economic outlook.

For the quarter our overall customer volumes were essentially flat to the prior year on a weather-normalized basis. Volumes in our residential class have been volatile in 2010 and 2011. On a year-to-date basis, weather-normalized volumes are flat to slightly negative to the prior year.

We continue to add customers in both the Carolinas and the Midwest, but at a slower rate than before the recession. For example, over the last 12 months we have added an average of around 10,000 customers as compared to the approximate 60,000 customers we added in 2007.

In the commercial class we saw a modest increase in quarterly usage for the first time in a year. Even though this development is promising, it is too early to assume this is a continuing trend. Volatile retail sales and historically high office vacancy rates continue to affect the commercial customer class.

Finally, turning to our industrial customer class, volumes have rebounded slightly from the flat growth we saw last quarter. Industrial activity in both the Carolinas and Midwest has been supported by strength in the automotive and primary metals sectors and continued improvement in the chemicals sector.

However in the Carolinas, we have begun to see a slowing in the textile industry as capacity levels have decreased slightly. In general, industrial growth is somewhat stronger in the Carolinas than in the Midwest, but both regions continue to be adversely impacted by soft market conditions in industries that support the housing and construction markets. Overall, our industrial volumes are currently at about 90% of prerecession levels.

The outlook for manufacturing activity across our service territories remains steady. Our customers, however, are generally less optimistic about the remainder of this year and early 2012 than they were several months ago.

Based on where we are after the first three quarters of the year, we expect weather-normalized volumes for the full year to be relatively flat, falling short of our original target of a 1% increase.

In summary, we had another strong quarter with excellent operational performance, beneficial weather, and the strength of our Commercial and International businesses. We have increased our adjusted diluted earnings per share guidance for the year. Additionally, we are well positioned to achieve our targeted 4% to 6% long-term growth and adjusted diluted earnings per share.

Now I'll turn it back over to Jim.

Thank you, Lynn. We often discuss the challenges our industry is facing and how we are positioning our Company for the long term. Cost to replace and modernize our aging infrastructure and to comply with more stringent environmental regulations mean our customers will face increasingly higher energy prices now and in the future.

In response to these industrywide challenges, we are focused on several strategic initiatives -- our fleet modernization program, our Ohio ESP, rate cases in the Carolinas, and our pending merger with Progress Energy. Taken together these initiatives will help us continue to deliver affordable, reliable, and cleaner energy to our customers while helping us earn reasonable and fair financial returns.

We'll begin with a discussion of our fleet modernization program. Slide 9 outlines the status of our major construction projects. When completed, they will introduce approximately 2,700 megawatts of new generation into our system at a total investment of roughly $7 billion. These new modern facilities will allow us to retire older, less-efficient coal plants which cannot be cost-effectively retrofitted with emissions controls.

First of all, let me bring you up-to-date on the Edwardsport IGCC project, which is nearly complete at about 96%. Extensive startup testing is underway.

All of the mechanical and electrical systems will be turned over to the startup crews later this year. We continue to remain on track for an in-service date in the fall of next year.

The plant, which will use Indiana coal, will provide cleaner, more efficient energy to our customers in the state. Due to its efficiency and low cost of energy, Edwardsport will be the first plant to be dispatched on our Indiana system and remains the best solution for our customers' needs, helping to ensure the energy future of this region.

As a reminder, the Indiana Commission separated the Edwardsport cost increase proceedings into two phases. In the first phase we are seeking approval to recover the estimated cost of the project up to $2.72 billion. This is the cost cap on our project.

At the hearing, which is still underway, our case is supported by independent auditor testimony, demonstrating the costs of the Edwardsport plant were both reasonable and necessary, and that we prudently managed the project.

Phase 2 hearings will begin subsequent to the completion of the phase 1 hearing. That phase of the proceeding involves allegation by interveners, who have the burden of proof, to show fraud, gross mismanagement, or concealment related to the project. Most interveners contend that Duke should recover only the project's original cost estimate of approximately $2 billion, including financing costs.

Our testimony in phase 2, presented in early September, demonstrates that the interveners allegations are unfounded. We expect a Commission decision on both phases by early 2012.

Looking now at our other three projects, the new 620-megawatt combined-cycle Buck plant is about 96% complete and expected to be in service later this year. Cliffside and Dan River are both on track to be in service in 2012.

These projects allow us to begin retiring existing generation. For example, Buck's old coal units 3 and 4 were retired earlier this year, and units 5 and 6 are expected to be retired by 2015 for a total of 369 megawatts. Also, unit 1 through 4 at Cliffside, comprising 198 megawatts, were officially retired on October 1.

When our modernization program is complete, nearly 100% of our coal generation capacity will have scrubbers in operation. This positions us well as the EPA continues to finalize more stringent environmental regulations.

Just a few months ago, CSAPR was finalized. Recently the EPA has proposed to amend the CSAPR penalty provisions, increasing the transition time and decreasing the excess emission penalties into January of 2014 instead of 2012. We are well along with our strategy to achieve the new compliance limits by January 1.

Also, the EPA is expected to sign the Utility MACT rule in mid-December. At this time our current plans for compliance assume we have already retired or will retire almost 3,800 megawatts of coal generation, or about 20% of our existing coal fleets systemwide by 2015.

Finally, I would like to highlight over the past few months Duke Energy Renewables has announced nearly 800 megawatts of new wind projects. Consistent with our strategy, each of these projects is backed by long-term Power Purchase Agreements. Our total wind capacity, once these wind farms are operational in 2012, will be nearly 1,800 megawatts -- enough to power more than 0.5 million homes.

Turning your attention to slide 10, let me update you on our pending ESP filing in Ohio. Our current ESP expires at the end of this year and over the past 12 months we have explored various options to replace it.

We have sought a solution that balances the needs of our customers, our investors, and the Company while at the same time recognizing the state's preference for competitive electric markets, market base rates, and customer choice. Throughout the negotiations to seek agreement on a new ESP, our objectives have remained constant.

We have sought to obtain longer-term clarity and predictability of price-setting mechanisms. Secondly, to support the evolving competitive market in Ohio. Thirdly, to gain financial stability and strategic flexibility to help mitigate the margin losses for Duque Energy Ohio. And finally, earn fair returns on our investments over the long term.

Early last week we entered into a stipulated settlement with nearly all intervening parties including the Commission staff, various industrial groups, wholesale and retail suppliers, and the Consumers Council. This slide summarizes the key provisions of the stipulation, which is still subject to approval by the Ohio Commission.

The term of the ESP is a little more than three years, beginning in January of 2012 and extending until May of 2015. Upon implementation of the ESP, Duke Energy Ohio would immediately move to pricing based on competitive markets.

Additionally, the stipulation provides for a total non-bypassable stability charge of $330 million, which would be collected from all customers over the three-year period from 2012 to 2014. Under the terms of the agreement, Duke Energy Ohio would transfer its coal-based generation to a separate generation company outside of the utility on or before December 31, 2014. This will provide future strategic flexibility for these assets.

The parties to the stipulation have recommended that the Commission approve the settlement by November 15 so auctions can be conducted to serve our customers effective January 1.

I am sure many of you are wondering how the stipulation will impact our earnings for Commercial Power in 2012 and forward. The stipulation, if approved, provides financial results within the range of our planning assumptions through 2014. After consideration of a number of earnings drivers -- including merger benefits, constructive rate case outcomes, and effective cost control, among others -- we are well positioned to achieve our long-term 4% to 6% earnings growth target.

Next, let's take a look at slide 11 which contains an updated scorecard on our pending merger with Progress Energy. As the Progress Energy management team provided an update on the merger status during their earnings call earlier today, I will not repeat all the details. However, let me spend a few minutes on the mitigation plan we filed with FERC in response to their horizontal market power concerns.

That plan, which was filed on October 17, includes a virtual divestiture. This involves offering a certain amount of energy into the wholesale markets during the summer and winter months for eight years.

We have asked FERC to rule on our mitigation proposal by December 15. In my judgment these mitigation measures address FERC's concerns about market power in the Carolinas, allowing us to maintain the important customer benefits of this transaction.

Also, earlier this week we filed a request for rehearing with FERC related to their conditional order. This filing was made in order to preserve our rights. If FERC accepts our proposed mitigation plan by December 15, we agree to withdraw this request.

We continue to move forward with merger integration planning as we work toward a potential closing by year-end. However, the ultimate closing date of the merger will be dependent upon the timing of various regulatory approvals including FERC, the North Carolina Utilities Commission, and the South Carolina Public Service Commission.

The merger transaction with Progress Energy gives us the ability to more effectively manage the transformation occurring in our industry, resulting in benefits for all our stakeholders -- our customers, our investors, and the communities that we serve. [Later] regulatory and earnings diversity will also reduce our risk profile, supporting the strength of our balance sheet and the dividend.

Let me quickly update you on a couple of topics that we haven't yet covered in today's call. First, the rate cases in the Carolinas.

As you all will recall, in July we filed a base rate increase with the North Carolina Utilities Commission. We requested approval of a $646 million or 15% increase in customer rates effective in February 2012 based upon 11.5% ROE and a 53% equity component of the cap structure.

Earlier this week, Public staff in North Carolina filed testimony on our proposed rate increase. This testimony recommended an overall rate increase of approximately $211 million, reflecting a number of adjustments to cost of service, an ROE of 9.25%, and a 50% equity component of the cap structure.

In August we filed a similar base rate case in South Carolina. We requested to increase electric rates by approximately $216 million or 15% with revised rates in effect in February. This request was also based upon 11.5% ROE and 53% equity component of the cap structure.

We recognize that rate increases are challenging in these tough economic times. However, it is very important to remember that these increases are principally the result of investments we have been made to modernize our infrastructure and implement federal environmental mandates.

Hearings are scheduled to begin November 28 in North Carolina and December 7 in South Carolina. We will continue to explore opportunities for settlements in the weeks ahead.

In closing, I am very pleased with our performance year-to-date. Despite numerous challenges we have delivered on our operational and financial objectives.

Also, I am proud to report that we were recently recognized for our commitment to sustainable business practices. For a second year in a row, Duke was included in the prestigious Dow Jones Sustainability World Index. We were one of only two utilities in the US and among 13 utilities worldwide to receive this honor.

As we look to the fourth quarter and into 2012, we will remain focused on operational excellence, constructive regulatory outcomes, successfully closing the merger with Progress, and aggressive cost control. Before we take your questions, let me highlight one important consideration.

With regard to the ongoing hearings on the Edwardsport IGCC project, the Indiana Commission has ordered that witnesses in the case, including myself, may not be debriefed on what has occurred in the hearing. Therefore, we ask that any questions related to Edwardsport IGCC project be limited to the status of the project. And now let me take your questions.

(Operator Instructions) Dan Eggers, Credit Suisse.

Morning, guys. Hey, Jim, the demand recovery situation has been disappointing across the country, but you guys have been struggling maybe a little more than others, it seems, on a weather-adjusted basis. As you look out the next year or two years, three years, are you guys seeing signs that this could start to come back?

When you look at the regions between the Carolinas and the Midwest, are you seeing different trends that might give you more confidence or pessimism from here?

I think our current view is that the recovery is very anemic and that with unemployment at 9.2% the rebound in the demand for electricity is going to be slow. Historically the rebound in electricity from a deep recession like we have is an early indicator that the economy is recovering. And in my judgment, we don't see the rebound yet. And that is not good news with respect to the economy, at least through this year and through 2012.

Jim, when I take that to the next step, as you are thinking about trying to earn your allowed returns and obviously you got a lot of rate cases going on; but what kind of cost management do you guys see forward that can help offset the lack of top-line growth to support your long-term EPS growth strategy?

Dan, that is really a good point. Obviously, we went through a number of years where we were able to keep our O&M flat in the early days, the early years of the recession. But as we move forward and we close the deal with Duke, that is really going to allow us to really reduce further our cost and allow us to maintain strong ROEs on our business.

Jim, when you think about the rate base growth you guys have and the rate increases you are asking for, without the volume growth the customer impact appears to be more significant. Are there mitigation opportunities you guys see out there? Any sort of conversations you have with the Commission during these rate cases, kind of talking about the net bill impact to customers?

Sure, that also is an important point. As you know, over the last several years we worked hard in every state that we operate in to put in place the right incentives for us to invest in energy efficiency and to put control of the use of electricity in the hands of our customers.

We have foreseen for some time, as we modernize our fleet and our grid, that the price of our product is going to go up. That is why we acted early to be able to help consumers control the bill. As our price goes up, if they can control the volume that will help mitigate these increased prices.

Clearly everyone today understands, probably more than they did when we first introduced our energy efficiency measures, the importance of having those in place and giving control to our consumers during this rising price environment.

Maybe turning to the Carolinas just real quick. With the last two plants coming into service next year, how much more of a rate increase do you guys anticipate requesting after this rate case gets done?

Dan, we do need an additional case to pick up in-service of these plants. We have not estimated an increase at this point. I think it will be dependent upon the success of this case as well as what we see in terms of our cost structure for next year. So more to come on that.

Okay. Thank you guys.

(Operator Instructions) Jim von Riesemann, UBS.

Question for you, just following up on Dan's. Would you -- you mentioned on your prepared remarks, Jim, that you saw 4% to 6% earnings growth. And that now seems to add an upper end to that range. Would you mind taking a moment to bucket the major categories of that growth?

So saying that differently, how much is from merger savings? How much of it is from new plant, reducing regulatory lag?

And then the follow-up to that is -- can you refresh my memory as to how much of your O&M is clause versus discretionary?

Sure, that is a great set of questions. Let me with that turn it over to Lynn.

You know, Jim, I think those are good questions; and we will of course give you better feel for what '12 looks like as we come to the Street after the merger closes, with expectations for '12. But what I would think about in terms of the 4% to 6% is, as you think about the new Company being largely a regulated, company, it is going to be dependent on rate base growth. It is going to be dependent on outcomes, regulatory outcomes -- the ones that we are in the process of as well as ones in the future. Merger benefits. Ongoing cost control.

We do expect that we will have some load growth, although as we have been talking about, perhaps not as strong as we might have thought even a year ago.

So I think it's going to be a collection of all of those things. And we can talk further about that as we give more specific guidance for 2012.

Super. Just in a separate question on the merger, why do you think the FERC took a different tack this time in terms of the market power issues?

It is my understanding that the FERC has been in the process of reviewing its whole criteria for approving mergers. It appears to me that in this case, because you are combining and creating the largest company in the industry, that they made the decision to go on and apply some of their new criteria to this case.

So I think that is what it is. I think it is part of a -- we're in the middle of a period where they are reviewing their historic criteria. And I don't think it is any more than that.

Okay. Then the final question is on dividend, the dividend policy. With this seemingly higher EPS outlook, how are you thinking about the dividend going forward?

You know, Jim, that is something that we continue to evaluate and we will do so. We are committed to the dividend, committed to growing the dividend.

We moved the growth rate to roughly 2% at the time we saw a sluggish economy. I think that is a good planning assumption; but we will continue to evaluate growth as we move into the new Company.

Great, thanks. Look forward to seeing you in EEI.

Greg Gordon, ISI Group.

Thanks, hello. Morning. So when looking at the generation assets in Ohio, is it fair to say that based on the current level of revenues they are generating that they basically make no money?

You know, Greg, that's a good question. I think the coal assets are challenged in this environment with low power prices. I think our team in Ohio has done an extraordinary job of optimizing around those assets and delivering returns that are consistent with what you would expect elsewhere. They have also been very aggressive on O&M and will continue to be.

One of the things we like about the settlement agreement is with the stability charge it does provide a bit of strength to the earnings over the next three years.

Okay. Would you characterize the capacity or the -- would you characterize the revenue stream that you are asking for being at a level that would allow you to earn a return commensurate with what you would expect from a regulated asset? Or is the math different?

It's -- Jim, do you want to take that?

Yes, I think the math is different. I think the actual ROE is lower than what you would expect from a regulated business. I mean, that is the reality of the settlement.

But the good news is the settlement -- is that we have all the key parties onboard, and that increases the probability that it will be approved by the Commission.

Okay. Then in '15 obviously we transition to a fully deregulated model where your revenue streams will be driven by capacity and power market pricing?

That's right, and I think that's a good thing. Because if you look at the forward curve you start to see the prices rise more the '16, '17 time frame. But as you can imagine in PJM -- and I am sure you heard from others who have a much larger position in PJM -- with the retirement of a lot at the old coal plants that will happen by 2015 and with the new regulations on emissions, I believe the prices -- there will be upward pressure on the prices and the forward curve will in all likelihood move up even more.

Okay. So if I were to summarize it in nonfinancial terms, assuming this settlement is approved, it makes the assets financially viable in the transition?

I think that is true. But I think --

Now the returns are unsustainably low, right?

Oh, absolutely. And here is the most important point about this settlement -- it fives us flexibility with what we want to do with these assets. Remember after the close of the merger, that they represent less than 5% of our total earnings. So that kind of puts it in perspective.

Got you. Thank you.

Jonathan Arnold, Deutsche Bank.

Hi, guys. Just not to belabor that topic, but Jim, I think in your prepared remarks you said that the earnings implications of the ESP settlement as filed, when coupled with everything else including the merger, benefits, etc., will be consistent with your growth rate forecast. But within -- should we think of the net of all of that within the Commercial Power segment as an up EBIT year in '12 or a down EBIT year in '12? Can you at least give us some directional view on how this all translates into top-line numbers?

Jonathan, we are not going to give specific guidance today on Commercial Power as a segment. I think we have some elements to it that you can consider -- generation margins, the stability charge, O&M, depreciation, the results of the Midwest gas assets. All of those are drivers for Commercial Power.

We will give you some more specifics on that as we come to the Street in '12. But we thought it would be helpful that within the context of those results as well as the other things that we see (technical difficulty) we are positioned within our growth rate.

Okay. Then on a separate topic, your benefit at National Methanol surprised us. It seemed to come in higher than your sensitivities to WTI would suggest, just in the quarter. Is there a Brent spread factor there? That that is more the relevant oil price?

You know, it is at this point, Jonathan. We are seeing a bit more correlation to that. We also saw higher methanol prices, so a couple of sensitivities there.

Okay, thank you.

Steve Fleishman, Bank of America Merrill Lynch.

Hi, good morning. Just to clarify some of the questions previously, the 4% to 6% growth rate, if I recall, that was not off of 2011. Was it off of 2010?

Off of '11.

When you kind of base that growth rate?

Steve, we set it off of 2011 to be the basis for the post-merger, the combined new Company. So you can think about 2011, and I would think about it in a weather-adjusted way, as we typically do to start the foundation for driving earnings growth.

Okay. In that context, what is the weather benefit this year so far versus normal?

You know, it is on slide 18. Steve, you can see weather normal. So we had $0.06 to $0.07 in 2011.

Okay, so you're still kind of on the same base roughly that you were. My recollection when you have talked about the 4% to 6% I think you typically mention there is some lumpiness to that, the 4% to 6% growth by year. I remember if you go back to your S-4 documents, things like that on the merger, there certainly was some lumpiness.

I think there will always be lumpiness on a long-term basis because of regulatory outcomes, etc. So I think we will be able to give you a better sense of how it will look when we give guidance on '12. but I think some lumpiness is just consistent with the nature of this industry.

Okay.

But Steve, on a historic basis, our 4% to 6% on a stand-alone basis was really off of '09. Just to level-set.

Right, right, okay. Then just the last question, again on International. All the drivers of upside this year versus your expectation, how many of those are things like weather or things that might be more temporary versus ongoing benefits that are exceeding plan? Can you give us some sense of that?

Sure. Steve, I think the International business has a nice diverse mix of geographies. We have seen some benefit of hydrology in Central America, but you can expect hydrology to benefit some region almost every year.

We have core fundamental improvement in Brazil with prices rising. We will also see a modest amount of new resources coming in, in future years, as we are building a small hydro in Brazil and other assets.

And then of course you can expect to see some volatility around oil and FX, which should be somewhat visible to you based on what you see in the market.

Okay. Thank you.

Michael Lapides, Goldman Sachs.

Hey, guys. Real quick question on Indiana. Looking at, I think it was slide 15, the dockets for -- not necessarily for IGCC 4, but for the other three ones -- 5, 6, and 7. They all imply that this all gets wound down and you get all of your rate increases for multiple IGC Edwardsport dockets early next year.

Just curious what is the -- what are your level of concern of that being pushed out somewhat into later in 2012? Then can you walk us through when you would go in for follow-on increases? You know, IGCC 8 and beyond.

Michael, I will take the cost riders. We have been filing those biannually from the beginning of the project and will continue to do that. They get filed every six months.

What you see on slide 15 is the schedule for hearings. So we will have an opportunity to present those hearings -- or those cases; and the Commission will rule in accordance with their own time frame. I think our expectation would be 2012. But I think we will await the actual timing as we see how this progresses.

I think IGCC 8, for example, would be filed in November or December of this year.

Got it. When would you go in for your final rate increase related to Edwardsport?

We would typically go through a conversion of this plant at in-service in Indiana through a rider mechanism. The mechanism we have in place would have an ability to convert at that time. And then we would evaluate the need for a general rate increase based upon other costs in the business, other maintenance spending, etc. So that is something that is still under evaluation.

Okay. How should we think about the -- I am just thinking about the math in Ohio as part of the settlement. I think your current residential rate was around $90 or so a megawatt hour, kind of directional. If I just look at forward power prices for 2012 and known capacity prices plus the $5 or so stability charge, that is a pretty decent drop-off in Ohio. How do you make up for that?

Michael, I think you've got some of the pieces -- margins, stability. You need to consider O&M; how we are managing the plants. You need to consider any optimization activity we may have around coal or emission allowances. You also need to evaluate the Midwest gas assets which have been a strong contributor.

So I think it is all of those pieces together.

Okay, thank you.

Paul Patterson, Glenrock Associates.

Good morning. With respect to the FERC filing, I know that the lawyers often -- it is protective in that it is somewhat defensive. But I am just wondering. Since this new market power criteria conditions were put on the merger, do you guys feel -- how do you feel about the outlook for the merger being completed, I guess? Do you feel any less confident about it? Or how would you describe -- how would you characterize it?

Paul, I still am highly confident that we will successfully complete this merger. The Commission gave us three alternatives when they conditioned the approval, and we picked the virtual divestiture, and we have submitted it to them. We think in all likelihood they will approve that.

Now, we filed -- because I want to clear up what has been a misunderstanding with a number of people. We filed on October 31 a request for a rehearing of the conditional merger order. That was a very aggressive filing; but it was something that we had to do because to preserve our rights under the 30-day rule that required filing prior to -- at that time.

So I think the important point is think about that filing as protecting our rights; but the outcome of this case is really going to be driven by our proposed mitigation proposal. And I believe that the Commission will review it, and we have asked them to rule on this by December 15.

That is important because both North Carolina and South Carolina Commissions will only give us final approval once they have got a final order from the FERC. That is with respect to the merger as well as a joint dispatch agreement.

Okay, great. Then just finally on Edwardsport, you are not expecting to see -- this latest revision is probably the last revision we are going to see. Is that a good way to think about it, in terms of cost?

Yes, that is a very good way to think about it.

Okay, great. Thanks a lot.

That concludes our question-and-answer session for today. Mr. Currens, at this time I'll turn the conference back to you for any additional or closing remarks.

Great. Thank you. Thanks, everyone, for joining us today for the third-quarter earnings review and business update. We look forward to seeing many of you at the EEI financial conference next week. As always the Investor Relations team is available for any follow-up questions. Have a great day.

Ladies and gentlemen, this does conclude today's conference call. Thank you for your participation.