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Duke Energy (NYSE:DUK)

Q2 2012 Earnings Call

August 02, 2012 11:00 am ET

Executives

James E. Rogers - Executive Chairman, Chief Executive Officer and President

Lynn J. Good - Chief Financial Officer and Group Executive

Analysts

Dan Eggers - Crédit Suisse AG, Research Division

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Paul Patterson - Glenrock Associates LLC

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

Andrew Bischof - Morningstar Inc., Research Division

Kit Konolige

Operator

Good day, and welcome to the Duke Energy Second Quarterly Earnings Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Bob Brennan [ph], Vice President of Investor Relations. Please go ahead, sir.

Unknown Executive

Thank you, Nancy. Good morning, everyone, and welcome to Duke Energy's second quarter 2012 earnings review and business update. Leading our discussion today are Jim Rogers, Chairman, President and Chief Executive Officer; and Lynn Good, Executive Vice President and Chief Financial Officer.

During the course of this call, we will discuss the company's strategic objectives, the status of our merger integration efforts and its financial impacts, an update on Crystal River 3 and our other major construction projects, and our results for the second quarter and outlook for 2012. After the prepared remarks, we'll welcome 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.

Please note that the appendix to the presentation materials includes supplemental information for Progress Energy's second quarter earnings and additional disclosures to help you analyze Duke Energy's performance.

Now I'll turn the call over to Jim Rogers.

James E. Rogers

Thank you, Bob. Good morning, and thank you all for joining us on the call this morning. We appreciate your interest and investment in Duke Energy. As you saw in our release from earlier today, Duke Energy announced adjusted diluted EPS of $1.02 for the second quarter of 2012, $0.03 higher than our prior-year quarterly results of $0.99. These results exceeded consensus estimates and we continue to be on track to achieve our guidance range for 2012 of $4.20 to $4.35 per share. This range represents 6 months of Duke on a stand-alone basis and 6 months as a combined company with Progress.

After 18 months of hard work, we closed our merger on July 2. The strategic value of this transaction remains unchanged. The combination creates a new Duke with unmatched financial and operational scale and scope. The highly regulated business mix of the combined company supports the strength and growth of our dividend. We have a strong balance sheet that will allow us to manage through a time of transition in the utility industry.

Slide 4 illustrates our clear focus as a combined company. Our goals have not changed. We will continue our strong track record of meeting our financial commitments. We will complete our major construction projects to provide clean, reliable energy to our customers. We will continue to focus on the efficient, safe and excellent performance of our fleet and our electric grid. And finally, we will work constructively with regulators in each of our jurisdictions.

Let me highlight North Carolina and Florida. As many of you know, the sequence of events following the merger closing prompted the North Carolina Utilities Commission to schedule hearings about the unanticipated change in executive leadership. We presented testimony explaining the reasons behind the change. At the close of the hearing, before the North Carolina Utilities Commission, Chairman Finley mentioned the prospects for settlement. We are exploring the potential for an acceptable resolution.

We are also working as a team to resolve Crystal River 3 in a way that meets the needs of our Florida customers, regulators and our investors. I've been asked to appear in front of the Florida commission on August 13 to discuss how the merger impacts our customers in Florida. I look forward to reaffirming our commitment to our customers in Florida.

We have much work to do. Our deep bench of experience and talented leaders will keep us focused on the success of the new company. I'd like to highlight a few of our recent appointments as I turn to Slide 5.

Keith Trent has assumed the role of Executive VP of our regulated utilities. This is a familiar role for Keith, as he previously led Duke's regulated utility business from '06 to 2009. Keith and his team, including our state presidents, will be focused on our regulatory relationships in each of our 6 regulated jurisdictions, as well as on the federal level.

Chuck Whitlock has stepped in to lead our commercial businesses. Chuck has served as President of our Midwest generation fleet since 2009 and has over 12 years of service to Duke Energy or its predecessors. He and his team's significant experience in commercial markets will provide strong leadership for this business.

Also, Lee Mazzocchi has been named to lead our integration efforts and will report directly to me. Lee has demonstrated strong execution skills and leadership abilities, and previously served as Progress's Chief Procurement Officer. Lee and his team will ensure the organization is keenly focused on achieving the merger benefits.

The IT and supply chain's functions will now report to Lynn Good, and other administrative functions will report to our Chief Human Resources Officer, Jennifer Weber.

Delivering the benefits of this merger for our customers and our investors is a key focus of our employees and our leadership team. Merger integration planning has been underway since we announced the merger in January 2011. Integration planning teams worked hard and put us in a great position for day 1 of the combined company. Key processes and systems were in place and up and running on July 2 to allow us to operate as one company.

The integration teams have identified more than 600 savings opportunities. Accountability for these initiatives has been assigned to each of our Executive Vice Presidents and their respective organization. The integration team, led by Lee, is responsible for monitoring and reporting on the status on these initiatives.

Our merger savings opportunities fall into 2 broad categories. The first is non-fuel O&M savings, which over time will benefit all customers and investors. The second is fuel and joint dispatch savings, which will immediately benefit our Carolinas customers.

Let me update you on our non-fuel O&M savings opportunities before discussing our fuel and joint dispatch savings. When we announced the merger, we targeted a savings run rate in the range of 5% to 7% of total non-fuel O&M. This level of savings continues to be within our overall planning assumptions of combined O&M of around $6 billion. Consistent with our plans, we expect to achieve the full run rate of savings by 2014.

Slide 6 includes a pie chart showing the broad categories of O&M savings opportunities we are projecting. Around 70% relate to consolidation of redundant functions, including labor savings and consolidation of IT systems. We are well on our way in both of these areas.

Around 1,100 employees across the organization have accepted our Voluntary Severance Program. Depending on their job function, these employees will transition their roles and leave the companies at varying points within the next 15 months. We expect over half of these employees will leave the company by the end of 2012 as we begin consolidating corporate functions. We expect to achieve the remaining targeted labor reductions by 2014 by not filling some of our current vacancies and through normal attrition.

We expect to consolidate duplicate IT systems into single platforms, leveraging investments made by Duke Energy to build scalable IT systems. 19 projects were completed in connection with legal day 1 and 55 more will be underway by the end of 2012. The remaining savings will come from implementing operational best practices, such as common operating models, centralized support organizations and standardized work practices. In addition, we expect supply chain and purchasing benefits that come from increased size and scale. Some of these have already been put in place.

Slide 7 shows you our progress in realizing fuel and joint dispatch savings. Beginning on day 1 of the merger, we are jointly dispatching generating fleets to the Carolinas. In fact, yesterday, we filed a request with the Carolinas commissions to reduce customers' rates by around $89 million over the next 12 months. This will allow our Carolinas customers to begin receiving benefits in their bills as early as this fall.

We have guaranteed a minimum of $650 million in joint dispatch and fuel savings over the first 5 years after merger close. We also have an additional 18 months of timing flexibility if we determine we're unable to achieve the savings within 5 years due to the impact of low natural gas prices on gas consumption. We are confident in our ability to achieve this level of savings.

Fuel savings are expected to be achieved primarily through coal blending and coal purchasing efficiencies, which result in enhanced buying power and reduced coal transportation costs. Just over 60% of the projected fuel savings are already under contract.

Jeff Lyash and his team have been closely monitoring the joint dispatch savings. On a typical day, we move more than 1,000 megawatts between Duke Energy Carolinas and Progress Energy Carolinas. Every megawatt-hour that flows between these systems represents savings for our customers. This success results from outstanding teamwork and is happening without sacrificing reliability during some of the recent hot weather.

We feel good about where we are from an integration perspective and will work hard to deliver on the level of savings we expected to result from this transaction.

I want to recognize our employees, nearly 30,000 strong, who have remained dedicated to their work and to achieving quick results. I am pleased with how our people are working together. We look to finalize the remainder of the organization very shortly. We're operating as one team, one company, united in our mission to deliver value and benefits to our customers, investors and the communities we serve.

Turning to Slide 8, I want to take a few minutes to discuss where we are with Crystal River 3. Many of you recall that in late 2009, Crystal River 3 experienced a delamination of its containment structure and has remained out of service since that time. The delamination was repaired. Then in March 2011, a second delamination occurred during re-tensioning of the structure. Throughout 2011 and 2012, work has been underway to refine and advance engineering on a potential repair solution.

We are also pursuing insurance recovery from NEIL, a mutual insurance company that provides coverage to the nuclear industry. In February 2012, a settlement agreement was approved by the Florida Public Service Commission which outlines a framework for regulatory treatment of either a decision to repair or retire the unit.

Let me give you an update on 3 critical items: one, the status of the technical repair option; two, the status of ongoing discussions with NEIL; and finally, our decision process on the best way to move forward with Crystal River 3.

Work continues on the technical repair option, which involves removing and replacing concrete in substantial portions of the structure. Over the last year, progress has been made on the engineering and vendor selection required for the repair option. Refinement of the engineering and the associated risk assessment for the repair option continues, including completion of an independent technical review initiated by the Duke board. Based on the preliminary results of this independent review, the repair plan appears to be technically feasible, but issues remain that need to be resolved as the engineering and risk assessment continues.

As of June 2011, repair costs were estimated at between $900 million to $1.3 billion based upon preliminary engineering. These estimates are under continuing review, and while this process has not yet been finalized, the cost estimate is trending higher.

Let me move to insurance coverage. Insurance coverage related to repair costs and incremental costs of replacement power is held through NEIL. There are a few important points to note. First, this is the largest claim that NEIL has received in its history. NEIL has established a special committee to carefully evaluate the claim. Second, related to the first delamination, NEIL has made payments, but has withheld a payment of approximately $7 million, the majority of which related to replacement power cost. We expect these costs will be recoverable through the fuel clause in Florida.

Further, NEIL has not made any payments on the second delamination. NEIL has also not yet provided a final written coverage decision for either delamination. We continue to meet with NEIL representatives. In order to attempt to resolve differences between the parties, we have entered into a non-binding mediation process with NEIL. The mediation is expected to occur in the fourth quarter.

Let me highlight key next steps in our evaluation. We continue to analyze both repair and retire scenarios. Our final economic analysis and our decisions will be informed by the following factors: engineering, vendor selection, contract negotiations, risk assessments, insurance availability, insurance recovery and customer impacts. Although we recognize the importance of making a repair or retire decision by the end of 2012 under the Florida settlement agreement, we are not prepared, at this time, to set a date certain by which such decision will be made. We will continue to update you on key decisions and milestones related to our assessment as they occur. Our decisions will be made within the context of the existing and very important regulatory settlement provisions in Florida. Crystal River is a high priority for Duke, our customers and the communities that we serve.

Turning now to Slide 11 (sic) [Slide 9], let me give you an update on Edwardsport in Indiana and other major construction projects in the Carolinas. The target date for placing Edwardsport IGCC plant in service has moved from early September 12 to early 2013. This is due to testing and start-up taking longer than originally expected as we work through this large, complex project. The new target date gives us more time for the remaining testing and start-up procedures to ensure that we have identified and corrected all issues prior to the in-service date. The start-up delays which have occurred today have impacted the level of contingencies related to this project. As a result, we're continuing to evaluate the estimated cost to complete the project and we'll provide updates as appropriate. We presently do not expect additional costs to be material in the overall cost of the project.

We've achieved major milestones, including operation of the plant's turbines. We put power into the electric grid during testing and we expect the plant to produce power using natural gas ahead of commercial operations. More than half of all the operating systems of the plant are under the care, custody and control of the operations group, meaning they were successfully constructed, tested and ready for service.

General Electric's new product introduction validation process is well underway, with both gas turbines having cleared GE's stringent process using natural gas. Validation of the gasification system is the next critical step. Related to the settlement agreement we reached with certain intervening parties in late April, hearings were completed in mid-July. The next steps include the settling parties filing a proposed order on August 17 and reply briefs to the intervenor exceptions on September 14. We expect a commission decision in the fourth quarter of this year.

In the Carolinas, the Cliffside clean coal project and 3 combined cycle gas projects, Dan River, Lee and Sutton, are all on schedule and on budget. We intend to file rate cases at Duke Carolinas and Progress Carolinas later this year, requesting the recovery of Cliffside, Dan River and Lee plant. The construction of all 3 plants were authorized by the North Carolina Utilities Commission.

We also expect to retire 3 of Progress Energy's Carolinas coal plants later this year: the H.F. Lee Plant, the Cape Fear Plant and Robinson Unit 1. These plants represent total capacity of approximately 900 megawatts, which is in addition to the approximate 1,700 megawatts of capacity Duke Energy Carolinas has already announced that it will retire.

In our renewables business, we just completed the 130 megawatt Cimarron wind project. We have remaining projects of 640 megawatts expected to come online by the end of 2012.

Now I'll turn it over to Lynn, who will provide a more detailed look at our financial performance for the quarter, as well as some perspective on Progress's second quarter results. She will also provide additional financial updates.

Lynn J. Good

Thanks, Jim. This morning, I'll begin with an overview of Duke Energy's stand-alone second quarter earnings results for each of its business segments; an update on retail customer volume trends and economic conditions; our financial objectives for 2012, including our earnings per share guidance range for the combined company; our financial objectives going forward; and finally, a few comments on Progress's quarterly results.

It's important to highlight that our quarterly results do not include Progress Energy's results, as the merger closed on July 2. However, Progress will be included in our consolidated results beginning with the third quarter.

As highlighted on Slide 10, Duke reported second quarter 2012 adjusted diluted earnings per share of $1.02. This compares to $0.99 per share for the prior quarter. At current year and prior year earnings per share have been adjusted to reflect the 1-for-3 reverse stock split which was completed immediately prior to closing the merger with Progress in early July.

Our regulated U.S. Franchised Electric and Gas segment recognized quarterly adjusted segment income that was $0.09 higher than the second quarter of 2011. This increase was primarily due to revised customer rates in the Carolinas implemented in February of this year. We also had lower O&M costs as a result of fewer major storms. We continue to closely manage our O&M costs, particularly in our fossil fleet, given the lower natural gas price environment and lower generation from our coal plants. These favorable results were partially offset by less favorable weather for the quarter as compared to the prior year. Even though cooling degree days were 18% higher than normal, this was lower than the approximate 25% variance to normal in the prior quarter.

Let's move on to international, which as expected, had segment income $0.05 per share lower than the prior year quarter. International's results were negatively impacted by unfavorable pricing in Central America, as well as unfavorable foreign exchange rates during the quarter. Partially offsetting these results were favorable results in Brazil and Peru due to higher average prices.

Turning our attention now to our non-regulated Commercial Power segment, adjusted segment income was fairly consistent with the prior year quarter. However, there were a few key drivers to highlight. Due largely to the implementation of our new market-based Electric Security Plan in Ohio, we entered 2012 anticipating lower results from Commercial Power. As expected, our coal generation margins were down $0.07 per share. This was largely offset by the non-bypass-able stability charge which we are collecting through the end of 2014, which added $0.05 per share.

Our non-regulated Midwest gas fleet continued to generate at record volumes, as quarterly generation was around 80% higher than the prior year quarter. However, these higher volumes were offset by lower PJM capacity revenues.

Let me close with a few comments about our Ohio operations. Ohio has recently approved a state compensation mechanism for FRR entities, authorizing the recovery of their cost for capacity. As you know, Duke Energy Ohio is an FRR entity through May 2015, receiving market-based payments for capacity. We are reviewing the applicability of this recent decision to Duke Energy Ohio.

There have also been recent market rumors about a potential sale of our Midwest generation assets. It is not our practice to comment on market rumors of this nature. But as we have shared with you, we are evaluating strategic options for this asset portfolio, but no decisions have been made. We will continue to update you as our plans develop.

Slide 11 contains our quarterly volume trends by customer class for the Carolinas, Midwest and in total, based on calculations that exclude weather impacts. For the second quarter, our overall weather-normal volumes were around 1.3% higher than the prior year period, with similar increases seen in both the Carolinas and Midwest. This increase continues to be largely supported by industrial activity, which was 2.8% higher than the prior year quarter.

In the Carolinas, the automotive sectors showed strength, while textiles continued their recent weakness. The Midwest experienced strength in the heavy equipment and automotive sectors, while softness was seen in the primary and fabricated metals sectors.

Our residential customer class continues to grow at a modest level. For the quarter, weather-normalized residential volumes were higher by around 0.3%, principally supported by the Carolinas. This level of growth is mostly due to an increase of approximately 20,000, or 0.5%, average residential customers in the Carolinas and Midwest. Average residential kilowatt-hour usage has remained fairly consistent to the prior year.

Finally, weather-normalized volumes for our commercial customers were around 0.8% higher than the prior year quarter. Continued volatility in retail sales trends and high office vacancy rates keep growth in this sector at modest levels.

Consistent with our outlook during the first quarter earnings call, we remain cautious on the overall economic recovery. As a result, we are currently expecting fairly flat weather-normalized load for 2012 compared with 2011.

Before we move on to the financial impacts of the merger, let me briefly discussed Progress' results for the quarter. Progress recognized second quarter ongoing earnings per share of $0.27 compared to $0.71 in the prior year quarter. One of the largest contributing factors to these lower results was higher O&M costs of $0.23 per share, primarily due to an additional planned nuclear outage in the Carolinas. In addition, quarterly results were unfavorably impacted by weather in the Carolinas and Florida, a $0.09-per-share impact. Finally, lower costs of renewable amortization in Florida reduced earnings by $0.11 per share.

We have included several earnings-related slides that you are accustomed to seeing for Progress in the appendix to today's presentation.

Let's turn now to the financial impacts of the merger. In the third quarter, we expect to recognize incremental goodwill of approximately $12 billion related to the Progress transaction. Additionally, we expect accounting charges resulting from the merger of between $450 million and $550 million to be recognized primarily in the last half of this year. These charges will be treated as special items and primarily consist of employee severance costs, costs related to the interim and permanent FERC mitigation plans, concessions agreed to with the Carolina commissions in order to receive merger approval and merger transaction costs.

For the combined company, we continue to target 2012 earnings guidance in the range of $4.20 to $4.35 per share, adjusted for the 1-for-3 reverse stock split. As outlined on this slide, we expect the contribution from Progress in the last half of the year will be largely offset by the dilution from the issuance of shares in connection with the merger.

Let me also highlight a few highlights of our financing plan. We have a busy financing calendar for the remainder of the year focused on funding our capital expenditures and debt maturities. In addition to about $1.3 billion of long-term financings at our Carolinas and Florida utilities, we have more than $2 billion of funding requirements planned at our holding company. Our holding company plan includes almost $1 billion of debt issued to reduce leverage at Duke Energy Ohio in connection with the pending transfer of generation assets out of the utility. This holding company needs will be met primarily with long-term taxable and tax-exempt debt, but may also include issuance of commercial paper. We will also complete non-recourse financings internationally and in our renewable energy business.

Our current business plan continues to support no equity issuances through 2014. We have included further details on our assumed 2012 cash flows and financing plan in the appendix to today's presentation.

I will close with Slide 13, which addresses our main financial objectives. We continue to target a long-term earnings growth range of 4% to 6% in adjusted diluted earnings per share for the combined company. The earnings growth potential of the company will continue to be anchored by investments in the regulated businesses, achieving reasonable regulatory outcomes, achieving merger integration benefits, managing our costs and continued contributions from our commercial businesses.

We expect to provide more specifics on our earnings growth opportunities by early 2013. At that time, we will have completed our normal 3-year financial planning process with the new management team and Board of Directors. We also expect to have greater clarity around the timing and expected financial impacts of our rate case filings in the Carolinas by early next year.

We continue to focus on growing the dividend on an annual basis with a targeted dividend payout ratio of 65% to 70% based upon adjusted diluted earnings per share. In fact, in June, we announced an approximate 2% increase to our quarterly dividend payable in September.

Before I close, I would like to briefly address S&P's decision to downgrade our credit ratings last week. The rating agency cited lack of transparency and heightened regulatory risk around the CEO transition. While we were disappointed and disagree with S&P's rating action and its assessment of the company's risk profile and governance practices, we remain committed to maintaining high credit quality and constructive relationships with our rating agencies. Our balance sheet, liquidity and credit metrics continue to be strong, and both Moody's and Fitch have maintained stable outlooks for Duke Energy following the close of our merger.

In summary, the size, scale and higher regulated business mix of the combined company gives us a solid base upon which to build. We expect to deliver on our commitment in order to achieve our financial objectives.

Now I'll turn the call back over to Jim.

James E. Rogers

Thanks, Lynn. In summary, we are focused on our overall mission to deliver affordable, reliable and increasingly clean energy to our customers in a safe manner, while providing attractive returns to our investors. We have important work ahead of us for the remainder of the year and we know what we need to do. Our efforts will center on efficiently integrating the operations and people of the combined company; achieving the benefits to customers and investors we expected from this transaction; meeting our financial objectives of achieving our earnings guidance range, increasing our dividend and maintaining a strong balance sheet; successfully managing our generation projects and resolving Crystal River 3; filing rate cases in the Carolinas for both Duke and Progress by the end of the year; and finally, moving forward constructively with our regulators and key stakeholders.

Before I open up the phone lines for your questions, let me correct one thing that I've said earlier. In talking about the first delamination, I said that NEIL has made payments but has withheld payment of approximately $70 million. I said $7 million. Maybe that was just wishful thinking, but they withheld payment of approximately $70 million, the majority of which relate to replacement power costs.

With that, let's open up the phone lines for your questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll go first to Dan Eggers from Crédit Suisse.

Dan Eggers - Crédit Suisse AG, Research Division

Jim, just -- I know you're going to probably dance around this a little bit, but as it relates to the commission's openness to some sort of settlement discussions, can you maybe give some context? Does that -- does "settlement discussion" mean a financial settlement, a corporate governance settlement, a job settlement, a Raleigh settlement? Can you just help us understand what that conversation is actually headed toward?

James E. Rogers

Dan, I'm not going to speculate on the outcome of the commission's investigation or our settlement discussions. We're going to continue to work closely and maintain an open dialogue with the commission. Chairman Finley, at the end of the hearings, offered up the possibility of a settlement and we're clearly working in that direction.

Dan Eggers - Crédit Suisse AG, Research Division

But, Jim, can I just dumbly ask, what exactly are you guys settling, other than the fact of their investigation is to the CEO change?

James E. Rogers

I'm really, Dan, not going to address the issues that are being discussed in the settlement process, but as we get this resolved -- and our goal line is, as quickly as possible, to put this behind us and move forward, and that's the road that we're on.

Dan Eggers - Crédit Suisse AG, Research Division

Okay, got it. And then, Jim, I guess just along these awkward kind of questions, with the 2 board members leaving from the Progress side, how is the board thinking about sizing and potential replacements and any kind of view on balance relative to the legacy Duke board membership?

James E. Rogers

The decision with respect to whether to replace the members that left really resides with the corporate governance committee and ultimately with the board. And they will make that decision in the coming weeks and months. And so my hope is, as we build this great company, I want everyone at the company to be part of that going forward, and that includes our new board members.

Dan Eggers - Crédit Suisse AG, Research Division

Okay. And I guess just as it relates to the Carolinas rate cases for both utilities this fall, or this winter, is there any thoughts on changing the timing, given all that's gone on, to give a little bit more breathing room before you head back before the commission?

James E. Rogers

Our intent, Dan, is to file our rate cases in the Carolinas by the end of the year. We expect they will address each case on its merits. I look back over the last 5 years. We've had 3 certificate cases, we have had 3 rate cases and all of them have resulted in fair outcomes. And as I look at the commission and its history, it has had a long history of fairly and equitably balancing the interest of customers and investors, and I don't expect that to change in the future.

Operator

We'll go to the next question from Jonathan Arnold from Deutsche Bank.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

I have a quick question on -- it seems like the weakness in Progress in the first half in their numbers was largely a result of these additional nuclear outage costs. And I look back to their first quarter call, they were -- it seemed they were assuming there would be an accounting order allowing level-ization of those costs approved sometime later in the year. And when we look at your slide showing the impact of the merger in the second half, it doesn't appear that you've assumed success on an order like that, but I just wanted to verify that, that's the case or not.

Lynn J. Good

Jonathan, your recollection is right. The 2012 earnings guidance for Progress did assume a successful regulatory order. And although we're still evaluating that regulatory order around the matter of nuclear level-ization, we are presently not planning to file it in 2012. As Jim mentioned, our focus is really on the rate cases for both Duke and Progress.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

So you're not even going to file that. Could you -- would you be able to tell us, Lynn, how beneficial to the 2013 outlook the absence of such an accounting structure would be as you fold in a better first half from Progress next year?

Lynn J. Good

Yes, Jonathan, the impact of nuclear level-ization in any given year is dependent upon the nuclear outages and the cost considerations and so on, so I can't give you any further insight into that. As we said, we will -- are working diligently on 2013 guidance in bringing the companies together and we'll have information around that early 2013.

Operator

We'll move next to Michael Lapides from Goldman Sachs.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

When we think about O&M synergies, the 5% to 7% off of a $6-billion base, is it safe to assume that kind of just for back-of-the-envelope math, you would take that $6-billion base, you would grow it by inflation or some number, and then you would subtract the midpoint, let's say, 6% of the $6 billion, to kind of get to a -- what would be a normalized post-merger run rate for O&M?

Lynn J. Good

Michael, I'm not sure I followed all of that math, but I do think you should consider inflation. As you think about projecting costs into the future, I think you should consider new resources that we bring into the mix. And the 5% to 7% is kind of an industry average of what companies have been able to accomplish. We're going aggressively after that and we'll have more specifics on the impact on '13 and beyond as we give you more visibility into our guidance.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. One other question. Indiana. Does the delay in the in-service date, early 2013 for Edwardsport, does that delay your impact of the timing, not just of the settlement that's been reached to date, but also the timing of rate increases related to Edwardsport and even kind of filing a true-up case down the road?

Lynn J. Good

Michael, I don't believe so. We have -- we're working on the settlement and the construct of the settlement which would have us placing into rates, first of all, the return on the agreed-to amount of capital investment and then subsequently placing the plant into service under a rider with depreciation and O&M. We've agreed to a stay-out on the general base rate case but that would be through a filing date of '13. So I don't see those dates changing with the schedule we've talked about today.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Meaning you'd file a full case in '13 to get Edwardsport -- anything left of Edwardsport or anything else in Indiana in the rates by early 2014.

Lynn J. Good

That's correct.

Operator

We'll take the next question from Paul Patterson from Glenrock Associates.

Paul Patterson - Glenrock Associates LLC

I wanted to touch base with you on the 4% to 6% growth. I know that you guys, in early July, indicated that you guys still targeted that. I know you're not giving guidance for 2013 and we're going to get more information as time goes on, but a lot has changed here with respect to just the environment in general and what we see in Progress. I'm just sort of -- like to sort of get a general sense of your level of confidence, I guess, Jim, with respect to how you feel about that 4% to 6% growth. I mean, do you feel better about it, less better about it? You've had a month now to sort of, with the integration process and what have you -- I mean, can you give us any sort of flavor for that?

James E. Rogers

Paul, my view is that we're in the process of reviewing all the numbers, working through them, but we believe that we will be able to hit that 4% to 6% growth. We're going to have to be aggressive with respect to reducing the cost and we're about that now. So more to come on that.

Paul Patterson - Glenrock Associates LLC

Okay. Okay, then there's just the capacity, the potential for, I guess, a capacity uplift, it sounds like, in Ohio. Could you give us a sense as to how that would work with respect to your recent settlement there, or just in general, how we should think about that? You mentioned it, and of course, it is a point that they did put out that order. I'm just trying to get a sense as to how we might be able to think about that.

Lynn J. Good

Paul, we're evaluating the recent rulings in Ohio. And because we are an FRR entity, we think there could be some applicability of that ruling and we'll be evaluating that. And the basic issue is that a cost-based method of recovery for capacity, in our mind, would be -- result in a greater level of earnings than the stabilization charge that we negotiated in our existing settlement in Ohio. And so we're closely looking at it, we're evaluating it and we'll have more to say as we complete that evaluation.

Paul Patterson - Glenrock Associates LLC

Could you just remind us how many megawatts you have in Ohio?

Lynn J. Good

Around 4,000.

Operator

The next question comes from Hugh Wynne from Sanford Bernstein.

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

I wanted to ask a question around the nuclear operations. I think in the testimony before the North Carolina Commission, it was mentioned that the state of Progress nuclear operations was one of the factors that led to the board to kind of rethink the value of the Progress merger, and that statement seems to have been borne out by the first quarter results. I wonder if you could comment on what you perceive to be the primary operational challenges of the Progress nuclear fleet and what your plans are to rectify them.

Lynn J. Good

Hugh, I'll start really commenting on the results and then turn it to Jim for any further color. I think the results of Progress really reflect normal refueling outages for 3 plants, and what you're seeing is the difference between the number of outages in 2012 versus 2011. There were 3 outages in the first half of '12, one outage in the first half of '11. So our focus on nuclear spending, investment capital, O&M is something that we're working through. It's in connection with our normal planning cycle and we'll be reflecting what we believe is appropriate spending across our entire fleet as we look to the years ahead.

James E. Rogers

And I would address it by simply reflecting on the testimony that was given earlier. We had seen over the last 18 months a deterioration in the operation of the fleet. And one of our missions is to basically invest in the fleet, change the operation of the fleet in a way to allow us to return all those plants to excellence, and that's the mission we are on. Dhiaa Jamil is leading that effort. He has been to all the facilities. They're working together and I have great belief, as we have one of the largest fleets in the country with 11 different units located geographically just in the Carolinas, which is kind of a unique footprint to have all the plants so close together, that we will be able to invest more in the plants that need more investment, but at the same time save cost because we're operating on a fleet basis. So that's something, I think, that at the end of the day, our focus is always on safe and reliable operation of the fleet, and doing it in a cost-effective way is what we plan to do.

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

I also had a question, if you don't mind, on Edwardsport. Given your coal supply contract at Edwardsport and the currently prevailing forward price curves for natural gas, do you expect the combined cycle gas turbine at that plant to operate on synthesis gas from the gasifier? Or would you expect to dispatch it using pipeline natural gas?

James E. Rogers

In that, until we get through the validation process on the gas processor, I mean, we will be primarily focused at using natural gas. That plant has the ability to use syngas or natural gas. In this interim period, while we are going through that validation process, we will run the unit on natural gas. And then when we finish, we will connect the gasifier and produce natural gas because it will be one of the cleanest, most efficient coal plants in the world.

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

All right. Are there going to be any difficulties, however, I guess is what I'm trying to get at, with respect to fuel cost recovery, if there's a cheaper alternative available by taking gas from the pipeline? And then, conversely, if one takes gas off the pipeline, is there going to be any regulatory difficulty around the use and useful status of the gasifier?

James E. Rogers

We don't view that as a problem and it really goes to 2 things. One is it's in MISO. It will be dispatched in MISO. And at the end of the day, because of the efficiency of the plant, it will be one of the -- the first plant -- coal plants to be dispatched.

Operator

The next question comes from Andy Bischof for Morningstar.

Andrew Bischof - Morningstar Inc., Research Division

Is there any clarity you can give us on when you might receive a final decision on the total costs relating to Crystal River 3? And you also mentioned they were trending higher. Can you put a specific dollar amount on that?

Lynn J. Good

I'll start, Andy. Work continues on the engineering related to Crystal River, the risk assessment, a number of factors. And so that preliminary estimate that was shared, $0.9 billion to $1.3 billion, was really developed back in 2011. And the work continues, as we referenced in the script today, and as we learn more and complete the work, we'll be prepared to talk about a more definitive cost estimate, but nothing beyond just trending higher at this point.

Andrew Bischof - Morningstar Inc., Research Division

Okay, and one other question regarding non-fuel savings. You mentioned 100% by 2014. Can you provide a little more clarity on the expectation of savings obtained in 2013 and '12?

Lynn J. Good

Not at this point, Andy. That'll be important -- an important part of consideration in guidance for '13. But you can think of us ramping up savings over time between now and '14.

Operator

[Operator Instructions] And we'll move next to Kit Konolige from BGC Financial.

Kit Konolige

On your sales, Lynn, I think you discussed, obviously, sales were up year-over-year. I think you mentioned that you have an expectation for flat sales going forward. Can you just backfill that for me? I'm not sure I caught all of it.

Lynn J. Good

Yes, Kit, we are up, for the second quarter, 1.3%. On a year-to-date basis, we're up 1.1%. So we just continue to be cautious about what we're seeing, slowing in the broad U.S. economy. Even some of our industrial customers are not particularly bullish, looking at their production to be basically flat with '11. So we believe a reasonable assumption could be flat to 2011, and of course, we'll update you as we know more. But read nothing more into it than just some caution about the U.S. economy.

Kit Konolige

And how about then looking, say, ahead to '13 or even a little longer term? I mean, structurally, what kind of sales growth do you see on either side of the system at this point?

Lynn J. Good

That's a really good question and something we look at a couple of times a year as we try to forecast what trends we're seeing. I think a reasonable planning assumption, Kit, is kind of in the 1% range. Maybe we'd trend to 1.5% as you get further in the decade, but we are not forecasting anything stronger than that at this point.

Kit Konolige

Okay. And one final area, separately. Obviously, you're not going to comment in detail about any potential sale or divestiture of the Midwest unregulated plants. Could you give us any idea, though, on -- if you did no longer own those, what would the EPS impact be? In other words, suppose they were -- you were not to own them, does that hurt earnings, help earnings?

Lynn J. Good

Kit, I think the assets that we're talking about are very significant contributors to the Commercial Power segment, so that would be the place to look in terms of your overall contribution to the company. And I think in terms of, is it accretive, dilutive, would depend upon pricing and the timing of any decisions. So that's the perspective I would give you.

James E. Rogers

At this time, I'd like to thank you all for joining us today. We look forward to seeing many of you in the upcoming weeks during the fall sell-side conferences. As always, our Investor Relations team is available for your follow-up calls. Have a great day.

Operator

That concludes today's presentation. Thank you for your participation.

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