Duke Energy Corp (DUK) 2005 Q2 法說會逐字稿

Good day, everyone, and welcome to the Duke Energy second-quarter earnings conference call. Today's call is being recorded. At this time for opening remarks I would like to turn the call over to the Vice President of Investor and Shareholder Relations for Duke Energy, Ms. Julie Dill. Please go ahead.

Good morning, everyone, and thank you for joining us today. With me are Paul Anderson, Chairman and CEO; David Hauser, Group Vice President and Chief Financial Officer; and Fred Fowler, President and Chief Operating Officer. In addition, Rich Osborne, Group Vice President for Public and Regulatory Policy, Steve Young, Corporate Controller, and Lindsay Hall, our Treasurer, will also be available to answer your questions today. Today's call will include a review of the second-quarter results for 2005.

Before we begin with our prepared remarks, let me read to you the Safe Harbor statement.

Some of the things we will discuss in today's call concerning future Company performance will be forward-looking statements within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements and you should refer to the additional information contained in our second-quarter 2005 earnings release filed with the SEC on Form 8-K and other SEC filings concerning factors that could cause those results to be different than contemplated in today's discussions.

Since we do anticipate questions surrounding our proposed merger with Cinergy, I would ask you to please refer to the S-4 filing of Duke Energy Holding Corporation on file with the Securities and Exchange Commission for factors and risks related to the merger.

In addition, today's discussion includes certain non-GAAP financial measures as defined under SEC Regulation G. A reconciliation of those measures to the most directly comparable GAAP measures will be made available on our investor relations web site, www.duke-energy.com.

Following our prepared comments we will open the lines for your questions. With that I will turn the call over to Paul.

This morning we reported earnings of $0.33 per basic share for the second quarter of 2005, which included $0.02 per share in special items. Ongoing earnings were $0.31 per basic share this quarter compared with $0.42 per basic share last year and The Street's expectation of $0.38. While we might have fallen short of The Street's expectations for the quarter, we did not fall short of our own expectations. The Company's results as a whole are on plan with respect to where we thought we would be at this point in the year. For the full year of 2005, I am very comfortable in our ability to achieve our incentive target of $1.60 per basic share.

If you look at the comparison of the second quarter of last year, a number of unusual events that we did not consider special items had a positive impact on 2004 EBIT results that were not repeated this quarter. These include a particularly attractive transaction at Crescent for $45 million, a $24 million positive marked-to-market impact at DENA, and a $17 million favorable resolution of tax issues at Gas Transmission. In addition, results for 2004 benefited from a $52 million release in tax reserves.

Our major operating disappointment this quarter was associated with the effect of mild weather in the second quarter on electricity sales here in the Carolinas and in California. Weather alone had a negative $0.05 per share impact on the quarter. Based on the weather we experienced in July, we would expect to reverse this impact in the third quarter.

In addition to the effect of mild weather, Franchised Electric's results for the quarter were down due to higher planned O&M costs, which had been in the program for some time. We expect segment EBIT for 2005 to be flat or slightly below 2004's results. Franchised Electric remains on target to meet its segment growth EBIT target of 0 to 2% for the 2005 to 2007 time period.

Natural Gas Transmission delivered solid results this quarter. Reported segment EBIT was down about $9 million from the prior year, which included a $9 million gain on the sale of assets and also benefited from a favorable tax resolution for approximately $17 million. Barring these two items, results would have been up 6%. Natural Gas Transmission continues to expect its ongoing annual EBIT growth rate to be in the range of 3 to 5% for the 2005 to 2007 time period. The recent transfer of Field Services' Canadian assets and acquisition of the Empress system from ConocoPhillips will contribute to the earnings growth for Natural Gas Transmission business and will put us at the high end of this range for 2005.

Our Field Services business continues to see an increase in earnings as the result of strong prices for natural gas liquids. Segment results for the second quarter increased 75% over last year, but only 50% after adjusting for the de-designation of hedges which took place in the first quarter.

A key event for our Field Services businesses was the change in ownership to a 50-50 partnership with ConocoPhillips in early July. As a result of this transaction, we have to change how we account for this segment, and I will let David walk you through these details and where we expect we will end up for 2005.

Duke Energy North America reported an EBIT loss from continuing operations of $56 million this quarter. The losses at DENA were primarily due to lower margins on energy sale as a result of weak weather in the West which I mentioned earlier and losses in our gas marketing business.

As we have discussed before, DENA's earnings profile is seasonal and the third quarter is key to reaching our full-year goal. We're not as bullish as we were at the end of the first quarter, but we anticipate reaching our annual goal with not more than $150 million ongoing segment EBIT loss, provided we see some hot summer weather. It seems we're off to a good start as during the month of July every plant in DENA was dispatched at some point during the month.

International Energy continues to deliver solid earnings. This quarter's results were up 26% and benefited from our National Methanol business, solid operations in Brazil, and favorable foreign exchange. International Energy is operating smoothly and we still expect to see ongoing annual segment EBIT growth in the range of 2 to 3% over the 2005 to 2007 time frame. However, for 2005 International Energy is now expected to have an exceptional year as the result of improved Latin American operations, higher prices at National Methanol, and favorable foreign currency exchange.

Crescent Resources' results were lower for the quarter, primarily due to a large transaction contributing about $45 million in EBIT in the prior year's quarter. While this quarter did not have a comparable transaction, the expectations for the full year are far exceeding our original plan. The real estate market for commercial and multi-family properties continues to be strong, and we expect Crescent to deliver another year of outstanding results. Segment EBIT from continuing operations and discontinued operations for 2005 is expected to be at or above comparable results for 2004 which were approximately $250 million. A $39 million decrease in interest expense also helped offset lower earnings for the quarter.

We've always touted the portfolio effect of our different businesses, and it's times like this when you can see the benefit of our combination of assets and geographic diversity. The anticipated merger with Cinergy will build on this portfolio effect by increasing earnings from regulated sources but in different geographic regions. I will update you on the merger at the end of our presentation.

Now with that I would like to turn the call over to David to review our results in a little more detail.

Paul gave you the overview for the quarter. Let me move on to the details by business unit.

Segment EBIT from Franchised Electric was 274 million in the second quarter of 2005 compared with 338 million for the second quarter of 2004. As Paul mentioned earlier, results for the quarter were negatively affected by milder than normal weather and higher operating and maintenance expenses of approximately 48 million related primarily to an additional planned nuclear outage, higher right of way maintenance expenses and higher storm costs compared with 2004. The decrease in segment EBIT for the quarter was partially offset by improved bulk power marketing sales.

In addition to increased sales, the improvement in bulk power marketing results was driven by a $27 million charge recorded in the second quarter of 2004 related to the commencement of the profit-sharing program with customers in North Carolina and South Carolina. As we told you last quarter, we expect total O&M for 2005 to be about 50 million higher than last year. We have already recognized all of this higher O&M in the first half of 2005.

Regulatory amortizations totaled 70 million for the second quarter of 2005 compared with 69 million last year. We expect the North Carolina Clean Air amortization for the full year 2005 to be approximately 300 million.

While the average number of customers increased 2%, or approximately 42,000, over the second quarter last year, overall sales suffered as a result of mild weather in the region. Cooling degree days were more than 37% lower compared to last year's quarter.

Industrial sales to non-textile customers have continued to show steady growth, up 2% over the second quarter last year. Sales to textile companies in our service territory continued to decline. Year-to-date there have been 15 plant closings, largely due to the expiration of tariffs that previously protected this industry from Chinese imports.

I also want to draw your attention to the capital expenditures this quarter. We will now be including our clean air expenditures in our capital expenditures number. The prior year has been revised to reflect this change as well. Please be aware that this is not the amortization amount, but actual expenditures related to the same legislation.

Now let's move on to Natural Gas Transmission. Natural Gas Transmission delivered 302 million in segment EBIT for the quarter compared with 311 million for the second quarter of 2004. Ongoing segment EBIT was flat for the second quarter. Results would have shown an improvement if you also excluded the tax benefit of 17 million from last year's results. Favorable changes in the Canadian currency of approximately 9 million and increased segment EBIT from US pipeline expansion projects of approximately 4 million both benefited results for the quarter. As you may have read, our pipeline business has had a number of recent announcements, and Fred will cover these in just a moment.

Next up is Field Services. Field Services recorded segment EBIT of 166 million from the second quarter 2005 compared with 95 million for the same period last year. Second quarter's results included a special item totaling 22 million related to the de-designation of hedges which took place in the first quarter. This amount is the portion of the charge taken in the first quarter that relates to hedge contracts that actually settled in the second quarter. We will continue to adjust Field Services' reported earnings in the third and fourth quarters by 38 million and 35 million respectively to reflect the impact of hedge settlements as they occur.

Results for the quarter benefited from strong commodity prices for NGLs, but were partially offset by operating expenses primarily related to pipeline integrity work and the absence of earnings from TEPPCO which was sold in the first quarter.

The weighted average NGL price for the second quarter 2005 was $0.75 per gallon compared to $0.61 per gallon in the second quarter of 2004.

Now that we have closed on our 50-50 joint venture with ConocoPhillips, you will see a number of accounting changes in the prospective financial results. With the move from a majority interest to a 50% interest we are required to deconsolidate Field Services from Duke Energy's financials. Earnings from this business will now be recorded as equity earnings and the investment in Field Services will now be reflected on the balance sheet in the line item Investments in Unconsolidated Affiliates. We have provided in a Duke Capital 8-K filed on July 11 the pro forma effect of deconsolidating in Field Services for 2004 and for the quarter ended March 31, 2005.

Now that we have closed this transaction, we wanted to provide an update to our earnings expectations for 2005. Field Services delivered 295 million in ongoing EBIT for the first half of the year. For the second half of 2005 we expect to see ongoing equity earnings for our 50% interest in Field Services of approximately $200 million, which is not adjusted for the remaining recognition of the de-designated hedges equaling a negative 73 million. Keep in mind, this 200 million is also net of interest expense due to our change in accounting.

Because we're 80% economically hedged on our NGL production, the earnings sensitivity to a $0.01 per gallon move in NGL prices equates to 5 million in equity earnings over the second half of the year, but will be partially offset by approximately 4 million in the other EBIT line.

So now let's move on to Duke. Duke Energy North America ended the quarter with an ongoing segment EBIT loss of 56 million compared with a 28 million ongoing segment EBIT loss to in the same period last year. Results for the quarter were down as a result of lower generation sales due to mild weather in the West and losses related to the current weakness in the gas transportation business which resulted in lower margins in 2005 versus 2004. Generation sales in the West were down about 27% for the quarter.

Also contributing to lower results was the absence of 24 million, or 22 million before minority interest, in marked-to-market gains on disqualified hedges recognized in the second quarter of 2004. As you know, by the end of 2004 we had mitigated the earnings volatility associated with these hedges. DENA's continued progress on reducing operating and G&A costs partially offset these lower results.

Let me takes a minute to address some confusion surrounding our anticipated merger with Cinergy and how the transaction will be accounted for through purchased accounting. According to Generally Accepted Accounting Principles, the acquiring company, in this case Duke Energy, would only record changes in value related to the acquired company assets, or Cinergy's assets. We would not record any change in value related to DENA's assets or trading books or any other of Duke Energy's assets.

Now let me move on to International Energy. International Energy's segment EBIT from continuing operations was 86 million in the second quarter of 2005. This compares with 68 million in segment EBIT from continuing operations last year. We're very pleased with the results for our International operations. This quarter's results benefited from strong prices at our National Methanol business, and our operations in Brazil benefited from higher volumes, although at lower prices, and a favorable move in the valuation of the Brazilian real.

Next up is Crescent resources. Crescent resources, our real estate business, delivered segment EBIT from continuing operations of $39 million for the second quarter of 2005 compared to 87 million for the same quarter last year. Last year's second quarter benefited from a $45 million positive EBIT impact related to a sale of commercial property in the Washington D.C. area.

Let me also point out that even with the strong sales we saw last year and our expectations for the remainder of 2005, Crescent's portfolio of properties is growing. The current book value of their real estate portfolio is approximately 1.3 billion compared to 1.1 billion at the end of 2004.

I would also like to point out that Crescent's forecasted capital expenditures have been increased from 475 million to 625 million for 2005.

Now I will move on to other EBIT. Other EBIT, which largely represents the cost of corporate governance at Duke Energy, also includes the change in marked-to-market value of the de-designated hedges from Field Services which we discussed last quarter. On a reported basis other EBIT was an 88 million expense of the second quarter of 2005 compared with a $26 million expense for the same period last year. Last year's results included a $21 million gain related to the Enron bankruptcy settlement and a $7 million loss on asset sales. Included in this quarter's results is a $7 million gain classified as a special item relating to the change during the second quarter in the marked-to-market value of the 2005 DEFS hedges that have not settled as of June 30th. On a year-to-date basis these hedges have deteriorated by $47 million. This amount is classified as a special item and will net to 0 by year end as the 2005 hedges actually settle. The difference between the actual 2005 hedge settlement value and the value at the time of de-designation is recorded as an ongoing item as settlements occur. To date this amount is 6 million in expense.

The marked-to-market change related to the 2006 contracts was a $22 million loss in the second quarter and is included in ongoing earnings. Any moves, both positive and negative, in the mark of this position in future quarters will also be included in ongoing earnings.

We also recognized a charge related to increased liabilities associated with mutual insurance companies during the quarter.

I believe it's important to note that even with the year-to-date impact of the marked-to-market move on the 2006 hedges which are included in our ongoing numbers we are on plan for our earnings expectations for the year. We have absorbed year to date approximately 78 million associated with these 2006 hedges.

Ongoing other EBIT is still expected to be about 200 million in net expenses, excluding any changes due to marked-to-market fluctuations on the de-designated hedges as we have no way of estimating what that variance would be at this time.

Now let me move on to briefly review some other income statement and balance sheet items.

Duke Energy's consolidated debt balances are 464 million lower from year-end 2004. Total debt at the end of the second quarter was just under 18.4 billion. Included in this amount is approximately 2.25 billion of debt belonging to Field Services, which will be de-consolidated in our third-quarter reports as a result of the change in ownership to a 50-50 partnership with ConocoPhillips.

For interest expense Duke Energy reported a $39 million reduction from last year from 336 million in the second quarter 2004 to 297 million in second quarter 2005. This reduction is the direct result of the debt reductions which took place over the last year. We continue to expect interest expense for the full-year 2005 to be approximately 1.1 billion.

The effective tax rate for the second quarter was approximately 33%. As a result of the Jobs Creation Act and its impact on taxes, our Franchised Electric business will have a reduction to income tax expense of approximately 10 million this year. This will negatively affect Duke Power's segment EBIT by about 15 million in 2005 as we must consider this impact on our return on equity calculations.

Cash and cash equivalents, along with short-term investments, totaled approximately 2.05 billion at the end of the second quarter. Had the change in ownership for Field Services occurred on June 30, cash, cash equivalents and short-term investments would have been about 90 million higher or 2.14 billion, the important distinction being that the 2.14 billion is now directly available to Duke Energy.

While Duke Energy retired the 30 million shares associated with the share buyback in the first quarter of 2005, Merrill Lynch is still in the market repurchasing these shares and will continue to do so until mid-November. As of July 31, they had repurchased 20.4 million shares. An additional 2.6 million shares were repurchased on or before May 6 under a separate agreement with Merrill. We suspended any further repurchases under this second agreement when we announced the proposed merger with Cinergy.

Next I would like to address the legal structure anticipated with the Duke/Cinergy merger.

We have received numerous calls from the financial community asking about the restructuring associated with the merger that we have outlined in several regulatory filings. At issue is the language surrounding step five in the restructuring process, which says, quote, "Hold Co. assumes or becomes co-obligor on the senior unsecured long-term debt of Duke Power LLC". Without walking you through all of the details, let me assure you that it is Duke Energy's intent to remain obligated at the Duke Power level for the existing senior unsecured debt of Duke Power and for the servicing of this debt to occur at Duke Power.

This concludes my prepared remarks, and now I will turn the call over to Fred.

Let me just quickly review some of the business activities that we have been focusing on over the past few months.

Ruth Shaw, the President and CEO of the Duke Power business, did hold an investor chat in June that did cover in detail the operations of Duke Power, as well as their future expectations. And I would encourage you to listen to a replay of that call from for an in-depth review of that business. However, there are a couple of things that I would like to mention about the power company.

On July 22 Duke Power did file with FERC to amend its open access transmission tariff and implement a system by which an independent entity would be retained to give users of the grid additional confidence that decisions affecting them are made independently and fairly. The proposed changes have had a relatively modest price tag and do address certain of FERC's concerns about functional control of the grid, although the actual functional control of the grid is left under the jurisdiction of the state regulators.

Last week we did set a new all-time record with a peak demand of 18,687 MW. Both our generation and distribution systems did perform extremely well during that period in meeting our customers' demand. And even with that record demand across our region, we do have adequate supplies of coal to meet the projected demand.

Generally, Duke Power contracts for up to two to three years for varying percentages of our coal supply, and we currently have commitments for 100% of our projected coal needs for 2005, and we have more than 75% contracted for 2006. As of the end of July we had 2 million tons of coal on hand. That's about 28 a day supply.

In Natural Gas Transmission, the Maritimes and Northeast pipeline reported a strong response to its open season for the 2007/2008 timeframe. As a result, they have signed two new proceedant (ph) transportation agreements with two major energy companies, Anadarko and Repsol, for a total of capacity of more than 1.5 billion cubic feet per day. Gas supplies for these contracts will be from proposed LNG terminals planned by each of those companies. Those services, those transportation services, are planned to begin in 2008.

In addition, our Algonquin pipeline recently filed an application with FERC to build a 16 mile pipeline that would connect a proposed deepwater LNG project to the Algonquin system. This LNG project is being proposed by Excelerate Energy. That new pipeline would have a capacity of 800,000 MMBTU per day and it would have an in-service date expected in 2007.

Our total investment to support the addition of these LNG supplies could be as much as $1 billion over the next few years. And that investment would be in the form of incremental expansions around our existing asset base.

In June the Gulfstream pipeline began flowing at 350,000 MMBtus per day of gas to Florida Power and Light under a long-term firm transportation contract. Gulfstream also contracted additional firm capacity of 50,000 MMBtus per day to Progress Energy. Those contracts bring the Gulfstream contracted capacity to 700,000 MMBtus per day out of a total available capacity of 1.1 Bcf per day. So we're making good progress there.

We're also at Gas Transmission studying the formation of a Canadian income trust for a portion of our Canadian assets. We're pretty early in the stages of that evaluation and no decision has been made yet, but look forward for something on that.

At Field Services I think the most notable event was that in July we closed on the change in ownership of Duke Energy Field Services with ConocoPhillips. We sold a 19.7% stake to ConocoPhillips, which brings our ownership to a 50-50 split.

We're also evaluating opportunities to launch a master limited partnership within the Field Services business later this year. Field Services has already identified a number of existing assets that are appropriate for an MLP structure. Once we get it in place, the MLP would then be in a position to buy third-party assets to continue to add to that portfolio.

For our DENA businesses we spoke to you at the beginning of the year on what it would take to improve DENA's earnings. It basically came down to three items -- increased generation sales, lower operating and G&A expenses, and the rebuilding of our gas marketing business. We've had very good success in lowering our costs. And while weather didn't help our generation sales in the first half of the year, we did see an increase in demand in the month of July, as well as early August.

DENA's gas marketing business, however, it's not fared as well as we had hoped. We are working to rebuild this business, but it is taking a little more time that we had originally anticipated because we are being pretty cautious in the rebuilding of it. However, if we do have decent summer weather for the balance of the third quarter, we still feel that we can meet that target of no more than $150 million ongoing segment EBIT loss for the year.

You may recall when we announced our proposed merger with Cinergy we indicated one of the benefits would be to kick start our gas marketing business as Cinergy already had a profitable business model in place. Many of you are also probably aware that Cinergy reported lower earnings with their gas marketing businesses quarter, and I would just like to make sure that you understand that we will be taking a very close look at this part of Cinergy's business as a part of our integration efforts to determine the best path forward on that part of the business.

As we continue to work on a sustainable business model at DENA, our view is of what that model should be is obviously evolving as we revisit options and additional capabilities that the merger with Cinergy provides. While it's not a complete solution, the combination with Cinergy is a major step forward in developing and delivering positive earnings from of our merchant generation business.

Our International operations, they continue to improve their returns. And our marketing teams in Brazil into continue to have success in contracting available capacity. We remain contracted for 100% of our available capacity for 2005, and we're now up to 84% contracted for 2006.

Let me turn the call back over to Paul for his closing remarks.

Overall I'm very satisfied with the quarter. We're delivering on our plan and we've taken significant strides in optimizing our portfolio by closing on the change in ownership at Field Services and announcing the proposed merger with Cinergy. Let me give you a brief update on where we are in the merger process.

To date we have filed for regulatory approval from all five states -- Indiana, Ohio, North Carolina, South Carolina, and Kentucky. On the federal level we've filed the preliminary draft of the S-4 with the Securities and Exchange Commission on June 30, and we've submitted information required under Hart-Scott-Rodino and filed for approvals with the FERC on July 12. Now we still need to file with the Nuclear Regulatory Commission and the Federal Communications Commission, but we don't have expected filing dates for those two at this time.

As you're well aware, new energy legislation is expected to be signed into law on Monday in New Mexico. This new legislation includes a wide variety of provisions aimed at enhancing the reliability, affordability and availability of energy and creating jobs. And Duke Energy believes the bill addresses issues that have long obstructed the development of a rational energy infrastructure. The legislation also repeals the Public Utility Holding Act six months after enactment, and thus certain consumer protections with FERC and the states. But with respect to our anticipated merger, we would not expect to register under the 35 Act. This results in simpler, more cost-effective operations and gives us options with regard to Crescent.

While we will be focusing our efforts on preparing for day one of the merger, rest assured we're not losing sight of our primary goal this year. Everyone at Duke Energy remains committed to efficient and safe operations, reaching our incentive goal of $1.60 per basic share, and delivering value to our shareholders. It bears repeating that we're comfortable with our results to date and we're on plan for our expectations.

Now we would be happy to take your questions.

(OPERATOR INSTRUCTIONS) Dan Eggers, CS First Boston.

I'm going to ask a question everybody probably is going to die to ask, and that is with Cinergy's second-quarter earnings release as it was and the mention of 2006 guidance, is this going to affect the outlook for the deal, the terms of the deal? And did this shape anything about the value (inaudible) of the transaction?

The simple answer is no. It doesn't really change it at all. Obviously when you do a deal the size of our deal with Cinergy, you're doing it for the long-term; you're not doing it for the next quarter. If you look at Cinergy's results, and I have talked to Jim Rogers about that and he pointed out that they had 12 great quarters in gas trading and 1 bad quarter, and they addressed it immediately with some changes in management. Obviously we're going to be taking a quick look and a hard look, as Fred said, at that part of their business.

In terms of the rest of the business, it was very solid. And all the reasons the we want to do the deal are still there. So I think the fact that one quarter was a disappointment, probably not only to The Street but to ourselves, is not at all a setback in terms of what are we trying to do for the long-term here.

And then on the gas marketing business, I know you're going to assess that more thoroughly. But historically that business back in the old days was a 50 to $100 million business for you guys. I think aspirations were getting to 50 or better. Was any of that put into the Cinergy expectations in the deal originally? And how should we think about DENA's earnings power with or without that gas marketing piece?

We took a very conservative view as to what to expect in that arena. I would say that our bias was to cut expectations as opposed to add expectations in terms of what the merger would bring to the party. I'm not the least bit uncomfortable with the assumptions that we took to the Board versus what we're seeing there right now.

I might just add the biggest thing we did with DENA was cost reductions, which were 95 million in year one of the merger and 125 million in year two of the merger.

I think that's a good point, because if you look at the synergies, the synergies were based solely on cost reductions. They were not based on new business development.

Great. One last one. David, is there going to any other financial benefits we should be looking for out of the Energy Bill other than avoiding the nuisance of having to comply with the 35 Act with the deal?

I think the biggest one is it gives us flexibility with regard to Crescent. Assuming this passes and the Holding Company Act is repealed, then we would not be required to sell Crescent as a result of this merger. So that gives us some flexibility there.

There will be some benefits that aren't necessarily immediately identifiable with financial benefits. For instance, some of the provisions of the Energy Bill should expedite our pursuit of Islander East, which has kind of been dead center for three years. And the bill provides a venue for us to be able to have a federal hearing on the issues that we've got with the state.

Got it. Thank you guys.

Paul Fremont, Jefferies & Company.

Thank you. I'm curious if we could get a comment on the Dynegy sale of their gathering and processing properties and what you thought about the cash flow multiples on that transaction and whether that sort of improved the outlook. Or how does that impact what you see happening potentially with your Field Services, either MLP or other transactions?

I'm not sure that -- I obviously never want to comment on somebody else's deal because unless you're there and know all the facts it's always dangerous to say that was a good deal or bad deal. We obviously looked at those assets along with everybody else, and our conclusion, or I guess our knee-jerk reaction, is that they got a very good price for it.

As far as what it means to us going forward, Fred, why don't you make a comment or two?

I'm not sure it means a lot going forward. There's no doubt that set of assets is a good set of assets. It's been well run. It's basically the same set of assets and another good management team. So very viable competitors, no doubt about it, but they have been before. So I don't see it having major impact on us.

Thank you.

Maureen Howe, RBC Capital Markets.

I'm just wondering if you can elaborate a little bit on the potential (indiscernible) Canadian gas assets. And I believe most of assets are regulated, and I'm wondering if you're in discussions with the National Energy Board or the Ontario Energy Board about potential of putting those assets into a non-taxable structure and still collecting the tax and rates.

That study is being done by Fred, but let me answer that question because I don't want him to get into too much detail on that.

We're in the very preliminary stages in terms of what is in an income trust. I think you know, as you realize there are some assets that fit into that structure and some the don't. And beyond saying that we're in the preliminary stages of looking at it, I don't think we want to get into any more detail. Probably this time next quarter we will be in much better shape to talk about it.

Can you perhaps elaborate also just on your thoughts on your natural gas transmission assets in general? Are you going to look at alternatives for those assets perhaps before completing the Cinergy merger? Do you have any thoughts in that regard? Does the new energy legislation give you greater flexibility? And has your thinking perhaps either evolved or changed?

Our thinking will be evolving, but I guess I don't want to get too far down the road in exploring alternatives until we get our approvals for this merger because the worst thing that you want to do is come up with a great idea and start pursuing it and suddenly find that you have to refile under all these filings that you've made. So I have kind of put my mind in neutral with regard to strategy with regard to the options for the gas business until we get through the approval process. And then once we get things approved, then I think we will jump in with both feet. But we don't want to get out ahead of ourselves until we get through the approval process.

And then just one final question. Does the passing of the US Energy Act change your thoughts with respect to timing of the completion of the merger?

I would say it gives us more confidence that we will be able to do it in a year. Rich Osborne is here, and I'll just ask him to comment on that because he's in the middle of that approval process.

Thanks, Paul. As Paul says, it gives us a lot more confidence that we can accomplish it in the time we had estimated.

The Holding Companies Act typically required 30 to 60 days beyond receipt of all other approvals. That will be gone. We will not have to file and register as a 35 Act company. So it will make a month or two off the estimated time to complete all the regulatory approvals. I would say we're still looking at the first half of next year; probably not the summer of next year, but the first half.

That's great. Thank you very much.

(OPERATOR INSTRUCTIONS) Paul Patterson, Glenrock Associates.

I was wondering if you could give us an idea of the currency impact corporate-wide was for the Company for the quarter.

Sure. David, do you want to do that?

Yes. It was about 9 million in Brazil, and that's on their EBIT. And then it's about the same thing for the quarter in DEGT. And those were all set in interest expense, and the bottom line is about 8 million of net income impact.

I noticed that this National Methanol has done very well and that it produces MTBE. But it is located in Saudi Arabia and sort of a regional producer. Should we assume there's no -- none of those litigation issues that we're hearing about in North America would apply to them being located that far away? Or could you discuss that a little bit?

Sure. The markets for MTBE are Europe. Obviously energy markets are all sort of interrelated and some of these things are fungible. But as far as liability for MTBE producers and what have you, National Methanol is primarily a supplier to Europe.

Fred, do you have anything to add to that?

No, I think that's exactly --

And Europe doesn't have the same issues that we hear at least being talked about here, is that correct?

That's correct.

Okay good. And then the weather impact, I noticed it was obviously a benefit to utility and -- I mean a hurt at utility and at DENA. I was wondering if you could just tell us sort of corporate-wide what the impact of weather was or what it would have been if it was normal.

You're talking about for July?

No. Well, that would be interesting. But no, for the quarter.

David, do you have a --

Versus normal.

(multiple speakers) that we talk about. So $0.05 a share was the weather impact for the quarter.

For the whole Company? That's versus normal?

Yes.

And then finally, with the LNG facilities and the CapEx that you're putting in there as well as in Crescent and what have you, do you guys -- I know that you cut back on the buyback and what have you. Any ideas about how that's all going to be financed or any idea or any projections you can sort of give us? I know you have got the merger going on as well and what have you, but any thoughts there? Do you think you're going to need any additional equity or do you think we're okay?

That sounds like a Hauser question.

We don't anticipate needing any additional equity. We are achieving our capital structure that we've set out to achieve, so I don't think you'll see us using any equity for that. I do think you'll see us using some of our cash balances for that.

Okay. Thanks a lot.

Let me make one clarification on the $0.05 of weather. That's really compared to last year as opposed to normal. I don't have right in front of me how last year compared to normal. But it is compared to last year.

Last year I think it was a little bit better than normal.

Mark Minincus (ph), Citigroup.

Just a question for you on your other EBIT. You have the charge taken for increased liability associated with mutual insurance. Is this a onetime item or is this an ongoing item? Could you just elaborate on what that was and maybe the magnitude of it?

This is another Hauser question.

Yes, I can elaborate on that. Under accounting rules now you have to record the liability for a mutual insurance company. The amount we recorded in the second quarter was 24 million. That's associated with two different mutual insurance companies and it's events that have happened in the first half of the year. So you'll see us recording every quarter something associated with those. It could be positive if there's more events so that there's an expense or it could be negative as they settle out events. So it will move both ways over time.

How much do you have invested in these mutual insurance companies?

These are part of our captive insurance and I don't have the answer to how much we have invested. I don't think it's a consequential number.

Great, thanks.

You should actually be seeing these similar sorts of movements in other companies because this has been an accounting change that I don't think many people had picked up until fairly recently.

That's correct.

Great, thanks.

Ashar Khan, SAC Capital.

Paul, any update on the strategic side versus work on the gas-electric breakup and DENA -- an update on DENA, how things are going? Any thoughts whether still on the cards that you could do something more strategic before the transaction closes?

As I mentioned with regard to whether or not it makes sense to separate gas and electric, we really are not actively pursuing that until we get through our approval process because we don't want to come up with an option that would screw up any of the filings that we've made.

As far as where we are with DENA, I'll let Fred kind of comment as to where he sees DENA at this point.

I think from the standpoint of DENA's operation, just operations in general, I feel much better. We continue to get ourselves better control around our costs. Again, we think we have the business well positioned for the third quarter. We set it up on that basis because we saw the dry hydro year setting up in the Northwest. So we actually covered in some of hedges that we had on our West Coast assets to position for if we did have a good -- some summer weather that we could see some tightness in the West. So far that's setting up as planned, but we will have to see. July was good. Hopefully we will continue to see follow-through. So I think from the standpoint of just the basic day-to-day operations I continue to see improvement there.

We continue to have a lot of discussions with a lot of different people concerning different options about, as I said, trying to get it to a more sustainable model. To me, what we've really done with the Cinergy deal is put that business in a position where it is earnings and cash flow positive. So that gives us -- I am a little more patient in looking at options when I'm not losing money. So I think we've kind of improved our negotiating position from the standpoint of doing a strategic deal.

I think that's really the critical point, is that at this point we don't feel compelled to do something if it's not -- if it's not going to create value. We don't feel compelled to sell at the bottom of the cycle or to cut an unfavorable deal because once Cinergy and Duke come together we will have a profitable merchant function.

Paul, one comment, if I remember my memory right, you had mentioned about a member of the Board who had joined in who was going to give you advice on your International operations by the middle of the year. And I was trying to check in on that whether you got some new assessment of the International business or what the thinking is there.

Roger Agnelli is the Board member who we put on, I think it was in September of last year or maybe it was November before he was effective because of the FERC approval. But Roger and I have chatted a bit, and he's had meetings with our International folks. In fact, we're going to have a major operating meeting in Brazil in the first week of December where we will take all the troops through a kind of I guess team building and development session.

But the actual strategy as to where we're going hasn't changed an awful lot. I think he's been very helpful in understanding the landscape. But the bottom line is that at the current time the market for international assets is weak enough that these assets are worth more to us than they would be to others. And we've gotten to about double-digit returns, which when I first came that was our first objective, was can we get to at least double-digit returns.

So it's been a good quarter for International. It looks like it's going to be a good year for International. It's sort of like DENA -- we don't feel compelled to do something. In fact, we feel even less compelled because they are a profitable operation. We don't feel compelled to do something unless we can get a really good price for them.

Thank you very much.

(OPERATOR INSTRUCTIONS) Stephen Dafoe (ph), Scotia Capital.

In your reply to Maureen's question about rich Canadian assets are being considered for an income trust you said some assets fit and some don't. I can think of Canadian gas dissipation utilities that sort of fit and Canadian gas pipelines that sort of fit. That describes most of your Canadian assets. Could you elaborate a bit more on which ones are being considered? And just further on that, if any of your assets end up not fitting for whatever reasons, the star is not aligning, would you consider other means of monetization of those assets?

I don't think you can necessarily categorically say that all of them fit, because it depends on how they are treated by the regulators. And while gas pipelines probably fit, distribution assets are less likely to fit. But Fred is -- I don't want -- like I said, I don't want to get into too much detail. Fred, is there anything you would like to say?

All I would say is that I think if you look in terms of regulated assets in Canada right now the NEB is not particularly -- has not been particularly favorable about the treatment that they are willing to give about moving those assets over and what happens on the taxes. So that seems to be evolving as well. And I think just kind of in simple terms probably if we do decide to do this you would probably start out with your unregulated assets. And we have quite a few unregulated assets in Canada when you think in terms of the fact that we just did the deal where we took in all of Field Services' processing assets in Canada.

Thank you.

(OPERATOR INSTRUCTIONS) Keith LaRose (ph), Bradley, Foster & Sergeant (ph).

You highlighted most of the synergies with the Cinergy deal, 95 million in year one and 125 million in year two. Can you speak to the prime mover synergies in the deal as opposed to just the cost reduction synergies of the deal?

You mean what will we be able to do to create value that isn't associated with cost reductions?

From a prime mover perspective, as I look at the assets that you have within the unregulated businesses of the two companies, what synergies and benefits do you get at the prime mover level of this transaction beyond just cost reduction, just beyond overhead?

Probably the biggest benefit -- well, you know, there's a little scope and scale and there. But the biggest benefit is the flexibility in size and compatibility of the fleet, particularly in the Midwest because we now have a full range from very low cost base coal-fired generation to a much more flexible but higher cost gas-fired peaking to the mid-range generation there of gas-fired combined cycle, which -- we were 100% gas, as you're probably well aware and Cinergy was 85% coal and they had no real mid-range. So you put the two fleets together and it gives you a lot more dispatch flexibility to be able to have that mid-range combined with the base and the peaking. They kind of have a hole in the middle and we were kind of focused on the middle up and we didn't have any base load. I would say there's probably a good example of one of the best synergies, if that's what you're looking for, of putting the two together.

Of course just the fact that you have a larger fleet to trade around is a benefit. The fact that we can take the two organizations and take the best of best practices from each, combine the ways that they've done operations and maintenance with the ways that we have, there's some upsides there that they're not necessarily cost-related, but they could be financial nevertheless.

That's helpful. This question may not be completely clear because the bill is not completely clear to me yet. But in the Energy Bill, are there opportunities with that merchant fleet relative to the regional capacity issues in the bill that might build in generating capacity in smaller regions, if I understand that correctly? Does that question make sense?

I'm going to ask Rich if he knows even a partial answer to that question because the bill is pretty new at this point.

Are you referring to the reliability provisions?

That's right.

I think we'll have to see what the FERC does to promulgate those before we know whether -- well, I'm sure there'll be some impact on the regulated and unregulated generation as they promulgate them. But we really couldn't addressed what that impact would be until the FERC starts to explain how they're going to implement it.

I'll ask the question a different way maybe and more directly. And it will be my last one. Is there an opportunity for any of these merchant assets to move into a regulated base?

Certainly there's nothing explicit in the Energy Bill that would open that door. I think again that that's going to depend upon how the FERC structures its response to reliability. They could have aspects of reliability, and you see some of these in some of the RTOS and some of the grids that are out there, where they do pay for capacity in a long-term contractual mode and a fixed mode. That would have a sort of regulated aspect to it, although it's technically not regulation the way you and I might think of it. But we really have to see how they implement. I think it's just speculation at this point.

I appreciate the time, gentlemen.

That's all the time we have for questions today. Speakers, I will turn the conference back to you for additional or closing remarks.

Thank you Kim. Thanks, everyone, for joining us today.

Just a reminder quick reminder that Duke will be having an analyst or conference day in conjunction with Cinergy discussed more on the merger on September 15 here in Charlotte. We will hold the date and we will be sending more information. As always, my team and I are available to answer any other questions that you might have. Thank you so much.

That does conclude our conference call today. Thank you all for your participation.