Earnings Call: Q2 2012

Aug 2, 2012

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 Drennan, Vice President of Investor Relations. Please go ahead, sir. Thank you, Nancy. Good morning, everyone, and welcome to Duke Energy's Q2 2020 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 III and our other major construction projects and our results for the Q2 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 20 11 10 ks 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 include supplemental information for Progress Energy's 2nd quarter earnings and additional disclosures to help you analyze Duke Energy's performance. Now, I'll turn the call over to Jim 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 Q2 of 2012, dollars 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 20.12 of $4.20 to $4.35 per share. This range represents 6 months of Duke on a standalone 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 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 had much work to do. Our deep bench of experienced 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 2006 2,009. Keith and his team, including 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 are its predecessors. He and his team's significant experience in commercial markets will provide strong leadership for this business. Also Lee Mazzaki 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' Chief Procurement Officer. Lee and his team will ensure the organization is keenly focused on achieving the merger benefits. The IT and supply chain 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 for 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 our The first is non fuel O and 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 and 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 and M. This level of savings continues to be within our overall planning assumptions of combined O and M of around 6 $1,000,000,000 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 and 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 1100 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 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 the 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 fleets in the Carolinas. In fact, yesterday, we filed a request with the Carolinas commissions to reduce customers' rates by around $89,000,000 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 $650,000,000 in joint dispatch and fuel savings over the 1st 5 years after merger closed. We also have an additional 18 months of timing flexibility if we determine we're unable to achieve the savings within 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 an enhanced buying power and reduced coal transportation costs. Just over 60% of the projected fuel savings are already under contract. Jeff Laiach and his team have been closely monitoring the joint dispatch savings. On a typical day, we move more than 1,000 megawatts 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 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 III. Many of you recall that in late 2009, Crystal River III experienced a delamination of its containment structure and has remained out of service since that time. The delamination was repaired. Then in March 20 11, a second delamination occurred during retentioning of the structure. Throughout 20112012, 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 the status of ongoing discussions with Neil and 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 a repair option. Refinement of the engineering in 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, the repair costs were estimated at between $900,000,000 to 1,300,000,000 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 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. 1st, this is the largest claim that Neil has received in its history. Neil has established a special committee to carefully evaluate the claim. 2nd, related to the first delamination, Neil has made payments, but has withheld payments a payment of $7,000,000 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 2nd delamination. Neil has also not yet provided a final written coverage decision for either delamination. We continue to meet with parties, we have entered into a non binding mediation process with Neil. The mediation is expected to occur in the Q4. Let me highlight key next steps in our evaluation. We continue to analyze both repair and retire scenarios. Our final economic analysis 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 decisions 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, let me give you an update on Edwards 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 startup delays, which have occurred to date 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 to 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 August 17 and reply briefs to the intervener exceptions on September 14. We expect a commission decision in the Q4 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 Carolina's and Progress Carolinas later this year requesting the recovery of Cliffside, Dan River and Leith plant. The construction of all three plants were authorized by the North Carolina Utility Commission. We also expect to retire 3 of Progress Energy's Carolina's 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 1700 megawatts of capacity Duke Energy Carolinas has already announced that it will retire. In our Renewables business, we just completed the 131 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 on Progress's 2nd quarter results. She will also provide additional financial updates. Thanks, Jim. This morning, I'll begin with an overview of Duke Energy's standalone 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 Q3. As highlighted on Slide 10, Duke reported Q2 2012 adjusted diluted earnings per share of $1.02 This compares to $0.99 per share for the prior quarter. Both current year and prior year earnings per share have been adjusted to reflect the 1 for reverse stock split, which was completed immediately prior to closing the merger with Progress in early July. Our regulated U. S. Franchise electric and gas segment recognized quarterly adjusted segment income that was $0.09 higher than the Q2 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 and M costs as a result of fewer major storms. We continue to closely manage our O and 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 are 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 point 0 $7 per share. This was largely offset by the non bypassable 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 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 costs 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 Q2, 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 sector 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 increase of approximately 20,000 or 0.5 percent average residential customers in the Carolinas and Mid West. 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 keeps growth in this sector at modest levels. Consistent with our outlook during the Q1 earnings call, we remain cautious on the overall 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 discuss Progress's results for the quarter. Progress recognized 2nd 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 and 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 point 0 $9 per share impact. Finally, lower cost of removal amortization Finally, lower cost of removal 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 3rd quarter, we expect to recognize incremental goodwill of approximately $12,000,000,000 related to the Progress transaction. Additionally, we expect accounting charges resulting from the merger of between $450,000,000 $550,000,000 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 plan, 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 20 12 earnings guidance in the range of $0.20 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 $1,300,000,000 of long term financings at our Carolinas and Florida utilities, we have more than $2,000,000,000 of funding requirements planned at our holding company. Our holding company plan includes almost $1,000,000,000 of debt issued to reduce leverage at Duke Energy Ohio in connection with the pending transfer of generation assets out of the utility. These holding company needs will be met primarily with long term taxable and tax exempt debt, but may also include the 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% and 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. By 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 and P's decision to downgrade our credit ratings last week. The rating agencies cited lack of transparency and heightened regulatory risk around the CEO transition. While we were disappointed and disagree with S and 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 continues 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 commitments in order to achieve our financial objectives. Now I'll turn the call back over to Jim. 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 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 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 $70,000,000 I said 7, maybe that was just wishful thinking, but they withheld payment of approximately $70,000,000 the majority of which relate to replacement power costs. With that, let's open up the phone lines for your questions. Thank you, sir. Sir. Jim, just and 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 or Raleigh settlement? Can you just help us understand what that conversation is actually headed toward? Sure. Dan, I'm not going to speculate on the outcome of the commission's investigation or 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. But Jim, can I just I'm really, Dan, not going to 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. Okay. Got it. And then Jim, I guess just along these awkward 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? 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 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. 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 going on to give a little bit more breathing room before you get back before the commission? 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 to customers and investors and I don't expect that to change in the future. Okay. Thank you. Thank you. We'll go to the next question from Jonathan Arnold from Deutsche Bank. Hey, good morning, guys. Good morning, Jonathan. Good morning, Jonathan. I have a quick question on it seems like the weakness in progress in the first half in their numbers was largely result of these additional nuclear outage costs. And they look back to the Q1 call they were it seemed they were assuming there would be an accounting order allowing levelization of those costs approved sometime later in the year? And then 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. 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 levelization, 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. Okay. So you're not even going to file that? That's the present plan. So could you would you be able to tell us Lynn sort of how beneficial to the 2013 outlook progress in next year? Yes. Jonathan, the impact of nuclear levelization 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 and bringing the companies together and we'll have information around that early 2013. Okay. Thank you. Thank you. And we'll move next to Michael Lapides from Goldman Sachs. Hey, guys. Congrats on a good quarter. Thanks, Michael. When you think about O and M synergies, the 5% to 7% off of a $6,000,000,000 base, Is it safe to assume that kind of just for back of the envelope math, you would take that $6,000,000,000 base, you would grow it by inflation or some number and then you would subtract the midpoint, let's say 6% of the $6,000,000,000 to kind of get to what would be a normalized post merger run rate for O and M? Michael, I'm not sure I followed all 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 2013 beyond as we give you more visibility into our guidance. Got it. One other question, Indiana, does the delay in the in service date to early 2013 for Edwards Port, does that delay or impact 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? 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, 1st 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 and M. We've agreed to stay out on a general base rate case, but that would be through a filing date of 2013. So I don't see those dates changing with the 2013 to get Edwardsport anything left of Edwardsport or anything else in Indiana in the rates by early 2014? That's correct. Okay. Thank you. Thank you. We'll take the next question from Paul Patterson from Glenrock Associates. Good morning. Good morning, Paul. Good morning. 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 changed here with respect to just the environment in general and what we've seen in progress. I'm just sort of like to sort of get a general sense as to 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? 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. Okay. Okay. And then there's just the capacity 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. Yes. 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. I mean the basic issue is that a cost based method of recovery for capacity in our mind would be resulting 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. Could you just remind us how many megawatts you have in Ohio? Around 4,000. Okay. Thanks so much. Thank you. Thank you. The next question comes from Hugh Wynne from Sanford Bernstein. Hi. Good morning. Good morning. 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 the Board to kind of rethink the value of the Progress merger. And that statement seems to have been borne out by the Q1 results. I wonder if you could comment on what you perceive to be the primary operational challenges at the Progress Nuclear fleet and what your plans are to rectify them? I'll start really commenting on the results and then turn it to Joan for any further color. I think the results or 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 twenty twelve, one outage in the half of twenty eleven. So our focus on nuclear spending, investment, capital, O and M is something that 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. 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 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 geographically in the 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 costs 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. I also had a question if you don't mind on Edwards Port. Given your coal supply contract at Edwards Port 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? In that until we get to the validation process on the gas processor, I we will be primarily focused using natural gas. That plant has ability to use syngas or natural gas. In this interim period, while we're 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. 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 used and useful status of the gasifier? 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 Thank you very much. Thank you. Thank you. The next question comes from Andy Bischoff from Morningstar. Hi, good morning. Good morning. Is there any clarity you can give us on when you might receive a final decision on the total cost really in the Crystal River III? And you also mentioned they were trending higher. Can you put a specific dollar amount on that? I'll start, Andy. Work continues on the engineering related to Crystal River, the risk assessment, was 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. Okay. Thank you. And one other question regarding non fuel savings. You mentioned 100% by 20 14. Can you provide a little more clarity on the expectation of savings obtained in 2013 2012? Not at this point. Andy, that will be important an important part of consideration and guidance for 2013, but you can think of us ramping up savings over time between now and 2014. Great. Thanks so much. Thank you. And We'll move next to Kit Panalya from BGC Financial. Good morning. Thank you. 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. Yes. You know, 2nd quarter 1.3%. On a year to date basis, we're up 1.1%. But 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. And how about then looking say ahead to 2013 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? 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 trend to 1.5% as you get further in the decade. But we are not forecasting anything stronger than that at this point. Okay. Thank you. 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? Ted, 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 decision. So that's the perspective I would give you. Okay. Thank you. Thanks so much. 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 Have a great day. That concludes today's presentation. Thank you for your participation.