Duke Energy Corp (DUK) 2012 Q1 法說會逐字稿

Good day, everyone, and welcome to the Duke Energy first-quarter earnings conference call. Today's conference is being recorded. At this time I would like to turn the conference over to Mr. Bill Currens, Managing Director of Investor Relations. Please go ahead, sir.

Thank you, Cynthia. Good morning, everyone, and welcome to Duke Energy's first-quarter 2012 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 first-quarter results and provide an update on key issues. After their prepared remarks we'll 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 2011 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'll 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. Today we will review our quarterly earnings results, provide an update on economic activity and customer load growth trends, as well as summarize what we are experiencing with coal to gas switching.

We will also review the status of our combination with Progress Energy and discuss the settlement agreement we announced earlier this week with respect to the Edwardsport Project in Indiana. This settlement agreement resolves uncertainty regarding the cost recovery of this important investment. I will review the terms of this settlement later in my remarks, but let me begin with an overview of the quarter.

Today we announced first-quarter 2012 adjusted diluted earnings per share of $0.38, that compares to $0.39 in the first quarter of 2011. Reported earnings for the quarter were $0.22 as compared to $0.38 in the prior year. Current quarter reported results reflect $0.20 of charges related to the settlement agreement on the Edwardsport IGCC project in Indiana. This charge has been treated as a special item for the quarter. Consequently, it has been excluded from our adjusted diluted earnings per share.

The quarter was characterized by unusually mild weather across all of our service territories. In fact, this past winter was the fourth warmest winter season on record for the entire US. I am pleased with our employees' efforts to effectively manage costs during the quarter; this helped offset some of the impact from the weather. We also benefited from increases in customer prices in the Carolinas as a result of our rate case request last year.

In our commercial businesses international operations continued to deliver strong results, mitigating the reduced earnings we expected from our new ESP agreement in Ohio. In addition to cost control, our operational performance during the quarter was impressive. The regulated nuclear fleet delivered a capacity factor of 99.7%, meanwhile our non-regulated gas fleet in the Midwest continued to operate at record generating levels, benefiting from low gas prices.

I am pleased with where we stand at the end of the first quarter. While we cannot control the weather, I commend our employees for focusing on what we can control, specifically our fleet and grid performance as well as our expenses. Based upon our first-quarter results we're on track to achieve our 2012 adjusted diluted EPS guided range of $1.40 to $1.45.

Now I'll turn it over to Lynn for a more in-depth discussion of our financial performance for the quarter.

Thank you, Jim. Slide 6 outlines the significant adjusted earnings drivers for each of our business segments for the quarter. As a reminder, we are now evaluating our business performance on the basis of segment income rather than on our previous segment EBIT basis. As a result earnings for each segment include interest and income tax expense. In addition, corporate governance costs which were previously reflected in the category labeled other are now allocated to each segment.

First, let's review earnings for our regulated utilities, US Franchised Electric and Gas. Quarterly adjusted segment income was relatively flat with the prior year quarter. Revised customer rates in the Carolinas and lower operation and maintenance expenses helped offset the impact of unfavorable weather.

Let me give you some perspective on the mild weather which affected earnings per share by about $0.04. In the Carolinas we had the lowest level of heating degree days on record for the first quarter. Heating degree days were below normal by around 25% in the Carolinas and 28% in the Midwest.

We were able to offset about $0.01 per share of the weather impact with reductions in our O&M costs during the quarter. Due to the unfavorable weather and the low natural gas price environment, we are generating fewer megawatt hours from our coal plants. We've examined our operations for opportunities to reduce costs.

From a labor perspective we have displaced contractors, reduced overtime and have not filled open positions. Additionally, we will defer certain scheduled outages since the plants are not running at the levels we originally anticipated.

Assuming normal weather and storm activity, we expect or 2012 O&M to be down about 2% from 2011 as a result of the actions identified in the first quarter. We will maintain our focus on costs while also ensuring the continued safety of our employees and reliability of our systems.

Also during the quarter FE&G began to realize the benefit of recent rate case outcomes in both North and South Carolina which increased earnings per share by about $0.03. These revised rates primarily reflect recovery of investments in our fleet modernization program.

Now let me move on to Duke Energy International which continued to provide strong financial results. This segment's adjusted income increased principally due to higher volumes and pricing in Brazil as well as at NMC, more than offsetting the impact of the prior year favorable arbitration award in Peru.

Finally I'll briefly discuss the results for our non-regulated Commercial Power segment. As expected, Commercial Power's adjusted segment income was lower than the prior year quarter, primarily due to the impact of the new electric security plant in Ohio. That plan resulted in a reduction to earnings per share of about $0.02.

As you'll recall, under our new market based ESP our coal-fired generation dispatches into PJM. That generation receives an energy margin as well as capacity revenues based upon PJM clearing prices. Duke Energy Ohio is also collecting an annual $110 million non-bypassable stability charge through the end of 2014 adding $0.01 to the first-quarter results.

Our non-regulated US gas fleet continued its strong performance contributing around $0.01 more than in the first quarter of 2011. The gas fleet's earnings were supported by higher volumes and margins resulting from low gas prices. Our Midwest gas fleet dispatched about 1,900 gigawatt hours more than the prior year quarter, nearly a 70% increase.

As expected, PJM capacity revenue received by the Midwest gas fleet was lower in first quarter 2012 as the capacity price fell from the $174 per megawatt day in the prior year to $110 per megawatt day. As a result of the reset of our ESP and Ohio to market-based rates volumes and margins realized by our competitive retail arm, Duke Energy Retail, were lower than in the prior year quarter. This reduced earnings by around $0.01 per share.

Despite a challenging environment the Commercial Power team continues to work to control costs and optimize performance of the non-regulated generating fleet.

Turning to slide 7, I'll spend a few minutes on our volume trends for the quarter and the economic conditions within our service territories. This slide presents our quarterly volume trends by customer class based on calculations that exclude weather impacts. As a reminder, our 2012 guidance assumes we'll experience whether normalized volume increases of about 0.7% driven by expected growth of approximately 1% in both the industrial and commercial customer classes.

On a weather normal basis quarterly volumes were around 1% higher than the prior year period. However, most of this favorable trend was due to an extra day in first quarter 2012 resulting from leap year. This increase continues to be largely supported by industrial activity which remains strong across both the Carolinas and Midwest. Weather normalized industrial volumes were 2.6% higher than the prior year quarter.

Growth persists across several major industrial classes, specifically the automotive, chemical and heavy equipment sectors. However, weakness continues in housing-related sectors and among our textile customers in the Carolinas.

Economic development activities continue to remain strong in our service territories bringing new investment and jobs. For example, tire manufacturer Michelin announced last month that it will invest $750 million for a new plant and a factory expansion in South Carolina, combined are expected to create 500 new jobs.

Let me move on to trends in the residential customer class. For the quarter, weather normalized residential volumes were essentially flat, an increase of about 0.3% principally supported by the Carolinas.

We are seeing positive trends in the number of residential customers being added in the Carolinas and Midwest. We've added approximately 20,000 more electric and gas customers than the prior year quarter, an average growth of around 0.5%. Even though this level of growth is below what we were experiencing before the recession, it is significantly higher than the 5,000 customers we added at this same time last year.

We continue, however, to experience a reduction in our residential customers' average kilowatt hours usage. A sluggish economic recovery, high gasoline prices and energy efficiency initiatives may all be influencing these usage patterns.

Finally, weather normalized volumes for our commercial customers were around 0.6% higher than the prior year. This customer class continues to be weighed down by hot high office and retail vacancy rates and low construction activity.

The economy within our service territories maintains its slow recovery. Industrial activity remains strong yet consumers continue to be cautious. Unemployment rates have improved but remain at historically high levels. Further, last week's announcement of first-quarter US GDP showed a slowing from the fourth quarter of last year. All of these factors leave us cautious and guardedly optimistic on the overall economic recovery.

As we forecast the remainder of the year we are seeing some challenges in our ability to achieve the 0.7% weather normal volume growth assumed in our 2012 guidance. We will continue to monitor customer volume trends as we progress throughout the year.

Finally, let me discuss the issue of coal to gas switching, which is resulting from the low natural gas price environment. The charts on slide 8 show our generation fuel mix over the last two years and our current projection for 2012, both in the regulated businesses and in our non-regulated Midwest generation business.

As demonstrated by these charts, the commodity price environment has significantly changed the mix of generation, resulting in less coal and more natural gas. For example, in the Carolinas, our Buck combined cycle gas plant, which became operational this past November, has been dispatching like a base load generating unit. In fact, it is currently dispatching just after our nuclear units in the Carolinas, ahead of even our most efficient coal units.

Additionally, as I mentioned earlier, our non-regulated Midwest gas-fired generation continues to run at high levels. In fact, 2011 was the third straight year this fleet achieved record generation levels and if low gas prices persist 2012 is looking like another record year.

As a result of reduced coal burns expected in 2012 from mild weather and low natural gas prices, our coal inventory levels have increased. Inventory levels are currently above our target of about 40 days in the Carolinas and about 45 days in Indiana.

In 2009 the impacts of the economic recession put us in a similar situation, but we were able to work with our coal suppliers to effectively manage inventory levels. We are doing the same this year. We've had extensive discussions with our coal suppliers and we're evaluating contract deferrals or buyouts as well as additional coal storage options both on and off site.

In February we implemented a coal price decrement in Indiana, increasing the dispatch of our coal units. To the extent the units are dispatched, coal coming to the stations is consumed and other higher potential costs are avoided. Overall, customers benefit. We'll continue to monitor the situation and take appropriate action as needed.

In summary, for the remainder of the year we'll continue to monitor customer load growth trends and are focused on effective cost control and operational performance to help drive our financial results. We remain on track to achieve the $1.40 to $1.45 adjusted diluted earnings per share guidance range for 2012. However, actual results for the year will be largely dependent upon the third quarter, historically our most significant.

Additionally, we remain well positioned to achieve our targeted 4% to 6% long-term growth and adjusted diluted earnings per share on a stand-alone basis. Now I'll turn it back over to Jim.

Thanks, Lynn. Let me start with our pending merger with Progress. On March 26, Duke and Progress jointly filed a revised mitigation plan with the FERC to address their market power concerns. This slide summarizes the components of our revised mitigation plan. The filing features both interim and permanent mitigation components.

The permanent mitigation solution involves the building and upgrading of transmission at an estimated cost of about $110 million. The transmission projects are designed to significantly increase power import capabilities and enhance competitive power supply options in the Progress and Duke Carolina service territories.

The proposal also features a two- to three-year interim mitigation plan with firm power purchase agreements already signed with three third parties. The agreements will be in place from the date the merger closes until the transmission projects are operational at which time the interim mitigation will terminate. The cost of this interim mitigation which we are able to currently estimate are included on this slide.

Our regulatory and legal teams have spent considerable effort investigating solutions to address FERC's concerns about market power in the Carolinas. FERC's comment period on our mitigation plan ended last week and we responded to intervener comments earlier this week. We believe that our revised mitigation plan addresses the FERC's concerns and that the protests to the plan are without merit.

We've requested that FERC issue orders approving the mitigation plan, the joint dispatch agreement and the joint open access transmission tariff no later than June 8th. After satisfactory approval we will continue to seek final merger-related approvals from the North Carolina and South Carolina commissions.

Over the past several weeks we have had constructive discussions with the North Carolina public staff. These discussions have centered on how the cost of the proposed FERC mitigation plan will be handled for rate making purposes as well as some clarifications including timing on the $650 million guaranty of fuel and joint dispatch savings. We hope to have a revised settlement in place soon that balances the interest of consumers and shareholders.

We have restarted our integration planning on a limited basis focusing on those areas that are critical to day one operations of a combined Duke/Progress. We will continue to keep you informed on developments regarding the merger in the weeks ahead.

Next let me review the Edwardsport settlement, an important milestone in achieving clarity on the cost recovery of this investment. Earlier this week we announced an agreement with the Indian Office of the Utility Consumer Counselor, the Duke Energy Indiana Industrial Group and Nucor Steel-Indiana related to recovery of construction costs for the project. This settlement is subject to the approval of the Indiana Commission. Let me highlight a few provisions of the agreement.

First, the settlement includes a cap on construction costs, including financing costs, to be reflected in customer rates of approximately $2.59 billion as of June 30. This amount includes approximately $2.32 billion of estimated direct costs as well as estimated financing costs. To the extent we do not have a final Commission order by June 30, Duke Energy Indiana will be able to recover additional financing costs until customer rates are revised.

Second, Duke Energy Indiana will not request a retail electric base rate increase prior to March 2013 with rates in affect no earlier than April 1, 2014.

And finally, Duke Energy Indiana will incur approximately $20 million to reimburse the settling parties for attorney fees and litigation expenses as well as make other funding commitments for low income heating assistance in Indiana.

The agreement also includes certain measures which help mitigate the customer rate impact of the project. For example, we agree to implement revised appreciation rates to the benefit of customers. Under the terms of the settlement agreement customer rate impacts of this project are to be implemented as follows.

First, recovery of project financing costs up to the hard cap amounts will be reflected in customer rates as soon as practical upon Commission approval and will result in an average increase in customer rates of 3.2%.

And second, recovery of post in-service costs, such as O&M costs and depreciation, is estimated to start mid-2013 based on our rider request to be filed after the expected in-service date of the plant and will result in an average increase in customer rates of 6.4%. Until such recovery is obtained these post in-service costs will be deferred following the in-service date of the project.

The provisions in the settlement agreement have resulted in an approximate $420 million pre-tax charge, or roughly a $0.20 EPS impact in the first quarter 2012. This impairment reduces the annual earnings contribution from this project by approximately $0.02 on an ongoing basis. I am pleased that the parties were able to reach this agreement.

The agreement is balanced and reasonable and achieves two important objectives. First, it mitigates the cost impact of this project to our Indiana customers; and second, it resolves the regulatory uncertainty regarding construction cost recovery. We have requested the Commission to establish a procedural schedule to address the settlement and expect a final Commission decision by this summer or fall of this year.

Our current focus is on bringing the Edwardsport facility to full operation later this year, allowing us to provide Indiana customers with cleaner power to meet increasingly strict federal environmental regulations as well as utilize a readily available local resource, Indiana coal.

Let me discuss the status of the Edwardsport construction project in our Carolina projects outlined on slide 11. Construction of the Edwardsport IGCC project is essentially finished and the start-up phase is well underway. The plant is undergoing an extensive testing process with first fire for both gas turbines successfully completed in March. Edwardsport is on schedule to go online this fall.

Cliffside is 97% complete with construction. Commissioning, start-up and testing of plant equipment are currently underway. The plant's first fire on coal remains targeted for later in the second quarter. We plan to bring the plant online this fall on time and on budget.

The 620 megawatt combined cycle Dan River gas plant is also on time and on budget with construction 85% complete and commercial operation scheduled for the fourth quarter.

Finally, let me give you an update on our growing renewables business. Last week we closed on a 50-50 joint venture partnership with Sumitomo for two large-scale wind farms that Duke Energy Renewables is building in Kansas, the 131 megawatt Cimarron II project and the 168 megawatt Ironwood project, both projects are scheduled to go online later this year.

In addition, we have three other wind projects currently under construction. We also continue to grow our renewable solar business, targeting the addition of around 25 to 50 megawatts of new capacity this year. By the end of 2012 our total owned renewable capacity is expected to grow to almost 1,700 megawatts, an increase of about 60% since the end of last year.

In closing let me say I am very pleased with where we stand through the first quarter of 2012. We remain on track with our earnings objectives and entered into a constructive agreement on our Edwardsport Project in Indiana.

Slide 12 summarizes the key short-term and long-term priorities we discussed during our year-end earnings call in February. For the rest of the year we remain focused on our primary strategic objectives -- first, obtaining the remaining regulatory approvals related to our merger with Progress; second, completing the remaining major construction projects; third, obtaining reasonable regulatory outcomes in the Edwardsport proceeding and our upcoming rate cases in the Carolinas and Ohio, which we will likely file with regulators around midyear; and finally, achieving our earnings guidance range for the year.

Our employees' hard work continues to support Duke Energy's ongoing mission of delivering affordable, reliable and clean energy, benefiting our customers, investors and the communities we serve. Now let's open up the phone lines for you all's questions.

(Operator Instructions). Jonathan Arnold, Deutsche Bank.

Jim, first on the merger. I just noticed that you mentioned that you've restarted the integration process. So I guess my question is, does that mean it's stopped and when was that and what changed and can you just provide some color on what you're referring to?

Sure. Let me ask Lynn to address that question, if I may.

You know, Jonathan, at the time we received the FERC order in December we really put pencils down a bit, finishing up what was going to be required for legal day one, but really putting it on the shelf so that we could get focused on running the Duke and Progress separately at the beginning of the year. We didn't have specific clarity on timing of the FERC filing and closing, etc.

So we've been focused first few months of the year on the things you would expect us to be focused on, running the business well. And now we believe we're getting to the point where we should start brushing off the legal day one work and restarting integration so that we're prepared for a July 1 closing.

Okay, thank you. And then on the coal piles, could I ask -- can you give us any sense of where you are currently within this -- you said you're above the 45 to 50 day range, but you're not at the 75 to 80. Where are you in that range? Do you think you get to the maximum and is this any -- very similar to '09 or more dramatic?

You know, Jonathan, we are at about 90% of the peak levels of 2009. So we're not quite to the point we experienced in 2009. And the teams are very focused on managing through this, taking all the steps we think are necessary including off-site storage and other measures. So we're managing through it and believe we will be able to manage through it.

Okay, thank you.

Dan Eggers, Credit Suisse.

Jim, there certainly seems like there's some momentum with the conversations you guys are having with the staffs in North Carolina and South Carolina. But can you just maybe mechanically or logistically walk through how a settlement would synchronize from the states with trying to get a FERC decision done and how they would marry together because obviously they're kind of -- or at least the stage are dependent upon the FERC decision -- how that would all play out in June if things worked as you guys have them scheduled right now?

Absolutely. Dan, first, let me say that our aspiration is to get a decision from the FERC in early June. In the interim period we're working with the public staff in North Carolina as well as the consumer Council in South Carolina to reach settlement agreements that we can present to the state commissions for their approval.

We've had detailed conversations with the public staff in North Carolina. Our discussions have focused on what is the appropriate treatment for the $110 million investment in transmission. It has been focused on some additional flexibility with respect to our guarantee of $650 million in the joint dispatch in fuel blending. It's also been focused on other items such as our sale of electricity during the interim period.

So we are very close to reaching agreement with the (inaudible) staff. Have not reached agreement with other parties with respect to this in North Carolina. And so, more to come there and we hope to have a settlement soon.

With respect to South Carolina, we're also working very close with Duke Scott and his team so that we can satisfy his requirements. And I think an important part of the relationship between North and South Carolina is that Duke Scott negotiated early on a most favored nations clause which really allows them to track whatever agreement is reached between us and the public staff in North Carolina.

And so, Dan, maybe just to put those things together. The intent would then be to be in a position where the commissions could approve the settlement following FERC approval in that June time frame.

So the -- because the commissions wouldn't decide basically you'd have the settlement which could then be adjusted if the FERC makes adjustments and bring it to them so they wouldn't actually have it to revise what they had done because they wouldn't have made a decision?

That's a very good observation on your part. We are building in a provision in our settlement that we're working through now with the public staff for the possibility that the FERC will not fully embrace our proposal, they will modify it in a way -- one way or another. And if that happens then we have the capability to really reopen the agreement we have with the public staff and make any adjustments that are appropriate given the FERC's action.

Okay, and I guess just one other question. You guys have talked on the merged basis of 4% to 6% earnings growth as the target without any equity. Are you still feeling comfortable with that at this point in time? And do you feel comfortable without the equity needs given some of the loss of cash you guys have with the Edwardsport deal and some of the loss of cash that Progress put up in the Crystal River deal?

You know, Dan, we are still targeting the 4% to 6%. We think the combined company has the fundamental growth drivers of investment and load synergies of course will be very important to drive that growth. We will be finalizing guidance as we near completion, restart integration, get a better sense of synergies, timing, etc., and be prepared to give you more specifics post closing.

Okay, thank you.

Hugh Wynne, Sanford Bernstein.

My questions went primarily to Edwardsport and what, if anything remains to be (technical difficulty). You mentioned you're in the testing phase. Has the gasifier at Edwardsport (technical difficulty) -- hello? Has the gasifier at Edwardsport been tested yet?

Hugh, we're having trouble hearing you. Could you -- can you restate?

Mr. Wynne has disconnected. We'll take our next question from Michael Lapides, Goldman Sachs.

One real quick thing. When I go back and look at your guidance that you provided at the end of the fourth quarter call or during the fourth quarter call, look at the USFE&G, you expected it to be up year over year about $0.12. Nowhere in there is there any bullet points for O&M cost reductions and yet based on the commentary and what I'm seeing in the abbreviated data at the back of your release, it seems like you have actually managed O&M down a bit in the first quarter.

Can you comment on that? Can you comment on expectations for O&M for the rest of the year relative to last year both at USEF&G and maybe at Commercial Power?

Michael, let me respond on USFE&G. We actually came into the year assuming O&M would be flat 2011 to 2012. And as a result of the meek whether that we experienced also continuing to build in some flexibility for the possibility that load growth doesn't show up as strongly as we anticipated, we've taken some actions that now put us in the position to forecast that O&M will be down 2% year over year. This gives us some flexibility in FE&G as a result of the start to the year. So that's the way I would think about it.

In commercial -- a lot of the O&M and commercial can actually be tied to generation, particularly in Latin America. And so we look at that O&M a bit differently and really try to give you a sense for margin and other things that we see in those businesses.

Got it, okay. One other question just in terms of thinking about PJM coming up in the next couple of weeks, assuming the auction results are actually released in the next couple of weeks. When you guys look at the market just in general, do you still have the view that coal plants are needed at peak in PJM? And if so, is it entirely just scrubbed coal plants or even -- does PJM still need some of the unscrubbed coal plants at the peak?

You know, Michael, it's my judgment that in PJM they still need all the scrubbed plants and some of the unscrubbed plants at peak period.

So, when you think about market fundamentals or what's normal or long-term, either an unscrubbed coal plant, whether it's energy or capacity, needs to set the clearing price or some other asset replacing that plant needs to?

I think that's right. I think historically -- and let me see if I remember the -- I think it's about 85% of the time gas is on the margin in PJM, and I think that will continue to be the case even though there's been a flip in gas prices and coal prices and a flip in the dispatch. Said another way, the gas units, particularly combined cycle units, are dispatching with the 7,000 plus heat rate before most coal plants -- or virtually all coal plants in the region.

Got it. Okay, Jim, thank you. Last question, just Commercial Power, really Duke Energy International. Any change in your thoughts about the growth outlook, especially with kind of the next year sharing at National Methanol, kind of what the growth trajectory of this business is relative to your US businesses?

Michael, I think we talked a little bit about growth on International as we put forward guidance. We think International is a very solid contributor to the Company, it has growth prospects with the repricing of the contracted load in Brazil and there's actually some information in the year-end package that might be helpful on that.

We will also bring some new resources into the International business as we go forward. I thing as you look at Commercial Power growth is going to occur over a longer-term basis as we see capacity prices rise and hopefully broader spread in energy.

Got it. Thanks, Jim; thanks, Lynn. Much appreciated, guys.

Brian Chin, Citi.

Jim, if the FERC says it needed another month to review this and that sort of drags out the process into August, would you be willing to extend the merger agreement another couple of months?

Brian, I'm not going to speculate on what we'll do with respect to extending the time of July 8. We're going to wait until we get there and wait to see what orders we get from the FERC and from the commissions and address that issue at that time.

Fair enough, thanks.

Hugh Wynne, Sanford Bernstein.

Hugh, I'm sorry, you dropped off the somehow.

We're having a difficult time hearing you, Mr. Wynne. If you could pick up your handset or increase your volume somehow.

Hugh, we can barely hear you. Hello?

Mr. Wynne has dropped again, sir. We'll move on to Andy Levi, Avon Capital.

I've known you for a long time, so a very simple question for you -- just concerning the merger. I just want to make sure that you're still very committed and still very excited about this merger.

We are very committed to getting this merger across the goal line, this is the third time we've filed with the Federal Energy Regulatory Commission; we've reopen negotiations with both states in an effort to get this done. As the prior question from Brian was all about July 8, and in our judgment there's adequate time for both the stated and the FERC to act so we can get this across the goal line. So I'm confident that we will and if you had to put a probability on it you'd say more likely than not we'll get it done.

And you're still excited about it as you were when it was announced?

Oh, I don't know at my age if I'm excited about much.

Fair enough, Jim. You're still a young man, come on.

Yes, yes, yes, yes. But if you look at this transaction from a long-term perspective, this positions us well for the future. And we wouldn't be continuing to work as hard as we've worked and our teams have worked if we didn't think this was the right thing going forward. So, thank you.

That's terrific. And thank you, Jim. Have a great weekend.

Okay, you too.

Andy Bischof, Morningstar.

A question for you -- I'm trying to get a grasp of the likelihood of an approval by the Indiana Commission for Edwardsport? What discussions were had with the Commission during Edwardsport and how are their concerns taken into consideration?

Andy, as you might imagine, we didn't talk to the Commission when we negotiated this settlement. We worked hard with the Consumer Council who plays a very important role in the state, as well as the industrial group in Nucor. We had many negotiating sessions to get to that settlement.

And I think what's important is by putting these parties together and presenting it to the Commission, we're presenting to them a package that really allows them to address all the issues that have been raised in the proceeding and put this behind the Commission, behind us and allow us to go forward to build what may be the last coal plant that will be built for maybe a decade or more given the price of gas and given the new proposals for EPA with respect to carbon.

Great. So you're pretty comfortable that the Commission will look favorably upon this agreement?

I'm hopeful because we've had a long history in Indiana as well as other states of reaching agreements with the parties and presenting settlements to the Commission and having the Commission approve them. And we hope that that occurs here and that's certainly our expectation.

Great, thanks so much for the clarity.

Jim von Riesemann, UBS.

Just two questions for you if you don't mind. The first one is on Edwardsport and I have the same question that Hugh was trying to ask because I could hear him. But could you just give us an update as to how the test firing is going on the Edwardsport facility?

So, Jim, I'll give it a try and Dhiaa Jamil is here to correct me when we get into maybe more detailed questions. But we have tested on gas -- firing of the turbines. We have scheduled tests for the gasifier within the next six to eight weeks and are moving through the start-up process in a very methodical way, we have operations teams on the ground ensuring we have a smooth transition from construction to start-up to operation.

Have you had any issues come up yet with that -- out of the course of the ordinary I should say?

You know, I would characterize it as things that you would expect to happen as you're turning over systems and processes. Dhiaa, would you add anything to that?

In any start-up of course you will have issues and that's why you go through the testing. We did experience some, but I would not put it outside of the normal range of what you would expect for a first of a kind type of system.

Okay. My second question is -- I listened to the annual meeting yesterday. And, Jim, you made a statement saying about your commitment to new nuclear. It's as a clarification question if you don't mind. You said 5% to 10% -- you're still interested in a 5% to 10% stake of Santee Cooper's stake. Now is that 5% to 10% of the total project or just Santee Cooper's piece of it?

It's 5% to 10% of the total project.

Okay, super, that's all I needed to know. Thank you.

Ashar Khan, Visium Asset Management.

(Technical difficulty). All my questions have been answered. Thank you.

Ali Agha, SunTrust.

I apologize, I got on a little late. But on Edwardsport, assuming the settlement is approved, what does that mean, if anything, for the Phase II [hearings] that were separately going on?

This settlement resolves both Phase I and Phase II issues.

Okay, okay, good. And secondly -- again I apologize, you may have done this. But on an LTM basis what are the utility ROEs looking like for your [utility] portfolio?

Ali, we had a slide in the year-end package that had targeted ROEs and what I'd love to do is have Bill Currens walk you through that off-line.

Yes, I know, I recall that I've seen that. But I'm wondering, are you -- I know it's early in the year and all that, but still -- that would still be the right target?

I think that's right, yes. As you know, third quarter is very important for the regulated business. So we'll continue to build on the progress that we've made first quarter. But on track.

All right, thank you.

Greg Reiss, Catapult.

Congratulations on a good quarter.

Thank you.

A quick question on the merger again. If for some reason you guys saw a material reduction in the expected benefits of the merger, would you be able to call upon the burdensome effect clause in the merger agreement? And how would it affect this -- and would this allow you to avoid having to pay a breakup fee?

Greg, you know that the merger agreement is clear on the burdensome effect provision, it's clear on MAE provisions, it's clear on the reps and warranties. And I think rather than me trying to opine with respect to how these provisions will operate, I would urge you to read them and draw your own conclusions as to what effect they would have under the scenario that you presented to us.

All right, thank you.

Michael Lapides, Goldman Sachs.

Real quick, just rate case time line in the Carolinas. When do you expect to file? More importantly, do you expect to get all of Cliffside in the rates and what portions of Buck County and Dan River would you get as well?

Yes, so, Michael, Buck was in last year's case and we would file this year's case with the intention of picking up both Cliffside and Dan River. So (technical difficulty) filing midyear, maybe early third quarter and with a planned in-service date for those plants we would be able to pick both of them up in this case.

And does that include both the capital and the expected OpEx?

Yes.

Okay, thank you. Much appreciated.

And that is all the time we have for questions today. I'd like to turn it back to Mr. Currens for any closing or additional remarks.

Great, thank you. And thank you, everyone, for joining us today for the first-quarter earnings review and business update. As always, the Investor Relations team is available for any follow-up questions. Have a great day.

And this does conclude our conference call for today. We'd like to thank you for your participation.