Earnings Call: Q3 2014

Nov 5, 2014

Good day, and welcome to the Duke Energy Third Quarterly Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Bill Curranz. Please go ahead, sir. Thank you, Tracy. Good morning, everyone, and welcome to Duke Energy's Q3 2014 earnings review and business update. Today's discussion will include forward looking information and the use of non GAAP financial measures. Slide 2 presents the Safe Harbor statement, which accompanies our presentation materials. A reconciliation of non GAAP financial measures can be found on duke energy.com and in today's materials. Please note that the appendix to today's presentation includes supplemental information and additional disclosures to help you analyze the company's performance. Leading our call today is Lynn Good, President and CEO along with Steve Young, Executive Vice President and Chief Financial Officer. After our prepared remarks, we will take your questions. Other members of the executive team will be available during this portion of the call. With that, I'll turn the call over to Lynn. Good morning, everyone, and thanks for joining us. Earlier today, we released 3rd quarter adjusted earnings results of $1.40 per share. These results were impacted by milder than normal weather, unfavorable results America and weaker retail load compared to the prior year quarter. Our year to date results remain above our internal plan and we remain on track to achieve our revised 2014 adjusted EPS guidance range of 4.50 dollars to $4.65 per share. Steve will provide more about the financials in a moment. Let me spend a few minutes on operational performance and progress on how we are positioning our business for growth. Our regulated nuclear fleet set a record quarterly capacity factor of 98% in the Q3. Our regulated natural gas fleet also performed well, achieving at least an 80% capacity factor at 8 of our 9 combined cycle plants in the Carolinas and Florida. We also continue to deliver significant benefits from the 2012 merger with Progress Energy. Through the Q3, we've generated about $360,000,000 of cumulative fuel and joint dispatch savings for our Carolinas customers. We are on track to achieve the guaranteed savings of $687,000,000 over the first 5 years. By the end of this year, we expect to deliver non fuel O and M savings of about 5 $50,000,000 exceeding our original assumptions. It has been an active and successful quarter in advancing our strategy. Let's turn to Slide 4 and several of our growth initiative announcements during the Q3, including new generation and new gas electric infrastructure. I'll briefly summarize a few of our key announcements. In September, Duke and Piedmont Natural Gas announced a joint venture with Dominion and AGL Resources to build and operate the Atlantic Coast Pipeline. The 550 mile natural gas pipeline begins in West Virginia and runs through Virginia and into Eastern North Carolina. Duke will have a 40% ownership interest in this project through our commercial business. The pipeline has a total construction cost estimate of between $4,500,000,000 $5,000,000,000 The pipeline is over 90% subscribed and a binding open season for the remaining firm transportation capacity is currently underway. Our regulated subsidiaries in the Carolinas will enter into 20 year gas transportation agreements with the pipeline. The utilities commissions in both North and South Carolina support. Over 5,000 letters have been received across the project's 3 state regions, voicing support for the pipeline. An independent study estimates the project can generate a total of $2,700,000,000 in economic impact by 2019, supporting over 17,000 jobs. The project requires FERC approval, which the joint venture will seek to secure by the summer of 2016. Last week, Dominion, on behalf of the joint venture, submitted a pre filing with FERC, which begins the extensive review process. Construction is expected to be completed in late 2018. Secondly, we plan to invest in our transmission and distribution infrastructure in Indiana. In August, we filed a 7 year 1 point $9,000,000,000 grid modernization plan with the Indiana Commission under legislation recently enacted. The plan uses advanced technology and infrastructure upgrades to improve service to our Indiana customers. Hearings are set for December, with a decision expected in the Q2 of 2015. As highlighted on our last earnings call, we finalized an agreement the $1,200,000,000 purchase of the North Carolina Eastern Municipal Power Agency's minority ownership in existing nuclear and coal generation. This transaction provides significant benefits. The proceeds will allow the power agency cities to reduce their customers' rates and debt burden. Duke Energy Progress customers will also benefit from long term agreement and the 30 year full requirements wholesale agreement with the Power Agency. Under the agreement, the transaction must be completed by the end of 2016. In September, we announced plans to commit $500,000,000 to solar expansion in North Carolina. This supports compliance with the state's renewable portfolio standard. In addition to signing power purchase agreements with 5 new solar projects for 150 megawatts, we will acquire and construct 3 solar facilities totaling 128 megawatts. We have filed with the North Carolina Utilities Commission for approval to transfer the certificates of public convenience and necessity for the facilities to be acquired. These important growth initiatives support our ability to continue providing our customers affordable, reliable energy from an increasingly diverse generation portfolio as well as providing a solid foundation for our long term earnings growth rate of 4% to 6%. Now let me turn to Slide 5, which summarizes our new generation projects in the Carolinas and Florida. Overall, these projects will replace generating capacity that has or will be retired and will help us meet the long term load growth in our service territories. These projects represent around 3,000 megawatts of capacity and almost $3,000,000,000 of investments through 2018. During the quarter, the Florida Commission held hearings to review the need for our proposed 16 1640 Megawatt combined cycle facility in Citrus County and the 2 20 Megawatts of upgrades at the existing Heinz facility. Last month, the Florida Commission issued certificates for both projects. We expect the Heinz upgrade to be online by the end of 2017 and the Citrus County plant to be online in 2018. Site certification approval for Citrus County is expected in late 2015. We continue to evaluate our options for additional capacity in Florida. We are negotiating with Calpine on the potential purchase of their Osprey combined cycle plant. We are also continuing to evaluate the addition of 3 20 megawatts of peaking capacity at our Suwanee facility. We expect to ultimately move forward with one of these options. We will keep you apprised of our plans as we finalize our evaluation and make filings with the Florida Commission later this year or early next year. A potential Osprey acquisition would also require FERC approval. Turning to Slide 6, I'll provide an update on coal ash management activities during the North Carolina legislature passed the Coal This law requires closure of all coal ash basins in the state within 15 years, while preserving the ability to make site specific closure decisions based on science and engineering. It also establishes a 9 member coal ash to evaluate and issue a proposed classification for all ash basins as either high, intermediate or low risk by the end of 2015. The law designates the ash basins at Dan River, Asheville, Riverbend and Sutton as high priority and requires them to be closed no later than August 1, 2019. We have begun developing excavation plans, permitting applications and other work at these 4 sites. We will be filing our excavation plans for these 4 sites with N. C. Deener later this month. In a moment, Steve will provide an update on the accounting implications of the law. During the quarter, we also took proactive steps to advance our coal the National Coal Ash Management Advisory Board, a panel of 9 independent experts from fields such as engineering, waste management, environmental science and risk analysis. This panel will help guide our strategy for permanent ash storage and basin closure. Before updating you on Edwardsport, let me provide some comments on the EPA's proposed rule for regulating carbon dioxide We are We are developing comments and plan to submit them to EPA by the revised deadline. We have made significant progress over the last decade reducing the environmental impact of our generating facilities. We've invested over $9,000,000,000 in building new state of the art plants as well as $7,500,000,000 in environmental controls. These investments have resulted in CO2 emission reductions of more than 20%, below 2,005 levels, as well as significant SO2 and NOx emission reductions. It is important that the rule recognize these investments for the benefit of our customers. Our comments will focus on the composition and achievability of the 4 building blocks as well as the interaction between the building blocks. We are also focused on the pace and timing of the required reductions, specifically the interim date requirements and the potential impact on system reliability. Nuclear is an important part of our generation fleet in the Carolinas. The appropriate treatment of existing and new nuclear generation in goal setting and compliance will also be an important area of focus. We expect the rule will receive a significant volume of comments as well as legal challenges. We will continue to keep you updated on our thoughts on this rulemaking as it evolves over the coming months. Next, let's turn to Slide 7 and our Edwardsport plant in Indiana, which achieved commercial in service in June of last year. We have completed GE's rigorous performance testing protocol and have validated that all major technology systems are working. To achieve substantial completion under the contract with GE, we are finalizing the plant's ramp rate performance, which we expect to complete later this year. Plant output and overall performance has improved during the year. Gasification availability averaged 75% during the 2nd quarter and 70 percent during the Q3, including a planned maintenance outage that began in September. Gasification availability exceeded 90% during the critical months of July August. This plan is well positioned to reliably serve our Indiana customers for decades to come. The right side of the slide outlines the status of the regulatory proceedings associated with the plant. IGCC 11 is fully briefed and we are awaiting a commission order. The commission will hold hearings on IGCC 1213 in February. Orders are expected for all three pending proceedings in the first half of twenty fifteen. The commission will examine the operational performance of the plant and the normal course of reviewing our semi annual rider filings. Any Edwardsport IGCC related fuel costs are reviewed in connection with the quarterly fuel clause proceedings. We will continue to update you on these important regulatory milestones. Before turning the call over to Steve, let me update you on the sale of our non regulated Midwest generation business to Dynegy for $2,800,000,000 in cash. As outlined on Slide 8, we expect to close the transaction by the end of the Q1 of 2015. The closing date will depend on the timing of approvals, including FERC, Department of Justice and our release from certain credit support obligations. Use of proceeds for this transaction remains under evaluation and will be determined as we approach the closing. Proceeds could be deployed in a combination of funding growth investments, avoiding future holding company financings or a stock buyback. We are committed to maximizing shareholder value and expect the transaction to be accretive to our adjusted EPS beginning in 2015 or 2016 depending on the closing date and how the proceeds are redeployed. We will keep you updated on our progress in the coming months. Overall, and looking back at everything we've accomplished so far this year, I'm pleased with how we are executing our business plans, advancing growth initiatives, strengthening our operational performance and delivering reliable service to our customers. We look forward to a strong finish 2014. Now I'll turn the call over to Steve to discuss our financial performance for the quarter. Thanks, Lynn. Today, I'll focus on 4 areas. 1st, the primary drivers of our 3rd quarter results second, our retail volume trends and economic conditions within our service territories third, important accounting changes made in the 3rd quarter and finally, I will close with our financial objectives, including the status of our 2014 adjusted earnings guidance range. Let's start with the major earnings drivers for the quarters as outlined on Slide 9. Our quarterly adjusted diluted EPS of $1.40 was below the prior year's quarterly results of 1.4 $6 per share. As we discussed during our last earnings call, we expected slightly higher adjusted earnings per share in the Q3 compared to last year. However, adjusted earnings this quarter were hampered by 3 principal drivers. 1st, weather was below normal by around $0.06 per share. Additionally, unfavorable results at International Energy and lower retail customer load growth also contributed to reduced 3rd quarter earnings. Overall, based on the strength of the first two quarters, we remain on track to achieve our revised 2014 adjusted earnings guidance range of $4.50 to $4.65 per share. On a reported basis, we earned $1.80 during the quarter compared to $1.42 last year. Reported results include an approximate 475 dollars generation business. This impairment reversal was recorded in discontinued operations and has been excluded from the company's adjusted diluted earnings per share results. Next, let me discuss the key quarterly earnings drivers for each of our major segments. I'll start with our largest segment, Regulated Utilities, where adjusted earnings were essentially flat during the quarter. For the 2nd summer in a row, we experienced mild weather compared to normal. However, the weather this quarter was warmer than last year, driving favorable quarter over quarter results. Cooling degree days were around 10% below normal in the Carolinas and almost 30 percent below normal in the Midwest. Other favorable drivers included higher pricing, primarily associated with our 2013 rate cases at Duke Energy Carolinas and a favorable effective tax rate. These impacts were offset by higher depreciation and amortization expense and interest expense, primarily associated with the new assets in rate base and lower retail customer volumes. We also entered into a fuel settlement this quarter offsetting the benefit of revised rates at Duke Energy Progress. Cost control efforts have helped us achieve flat non fuel O and M when compared to last year's quarter. We are driving costs out of the business through our merger related initiatives. International Energy's quarterly results were $0.05 per share lower this year, primarily driven by higher purchase power cost in Brazil resulting from poor hydrology. We also had an unplanned outage at one of our hydro facilities in Chile. This outage has been resolved and the unit is currently online. As you will recall, we operate hydro generation plants in Brazil that are dependent upon adequate reservoir levels to generate electricity. In 2014, Brazil has experienced the most severe drought in around 80 years and reservoir levels are at near historic lows. In response to the drought, Brazil's regulatory authorities are dispatching thermal generation at full capacity. In anticipation of below normal fall and challenging hydrological conditions, we reduced our contracted capacity levels for 2014 and have taken similar actions for 2015. We will closely monitor reservoir conditions as we move through the Q4 and enter 2015. Commercial Power's adjusted earnings were $0.05 per share higher, primarily driven by increased earnings at the Midwest Generation Business. Midwest Generation was supported by higher PJM capacity prices, which increased from $28 per megawatt day in the prior year to $126 per megawatt day currently. The other segment variance was primarily driven by a favorable prior year state deferred tax adjustment. More detailed quarterly adjusted earnings drivers for each of our segments are included in today's presentation materials and press release. Moving on to slide 10, I'll now discuss our retail customer volume trends. In the Q3 of 13, we experienced strong retail load growth of 1.7%, a challenging level from which to grow period over period. As we saw in the Q1 of 2014, adjusting for weather can be imprecise, especially over shorter periods of time. For these reasons, we find load growth trends more meaningful when evaluated over a longer term period. Through the Q3, whether normal retail load was 0.7% higher on both a year to date and a rolling 12 month basis. This is ahead of our full year expectations of 0.5% growth. We continue to see growth in the industrial class. In fact, this was the 6th consecutive quarter of growth in this sector. Results in our commercial and residential sectors have been more volatile. Based upon historic trends, we believe the consistent growth we have seen in industrial will expand to the other sectors as the economic recovery gains more solid footing. Let me briefly highlight some of the recent trends we We have experienced recent weakness in our Duke Energy progress territory, where sales continue to be negatively impacted by 2 chemical plant closures late last year. Outside of Duke Energy progress, industrial activity in our other jurisdictions remained strong with overall growth of around 2% over the rolling 12 months. The Midwest and Duke Energy Carolina's jurisdictions continue to see strength in the metals, chemicals and transportation subsectors. Building product manufacturers have also shown recent recent strength. Next, the commercial sector, where sales grew 1.1% over the past 12 months. Overall, this sector continues to benefit recent strength in the healthcare, education and government areas across all jurisdictions. This strength has also been supported by positive long term employment trends. Turning to Slide 11, I'll provide some insight into our residential sector, which has experienced 0.5% growth during the rolling 12 month period. As you can see in the chart, the total number of customers in our jurisdiction continues to grow consistently by around 1%. We experienced 1.5% growth in Florida, 1% growth in the Carolinas and around 0.5% growth in the Midwest. However, volatile customer usage trends affect overall residential load growth. Customer usage can be impacted by energy efficiency and conservation efforts, changes in median household income, unemployment trends and rising demand for multifamily housing. Overall, we continue to be cautiously optimistic about the future based upon the broad trends in the economy. Economic expansion is projected to continue, with GDP expected to grow at nearly 3% for the remainder of 2014. Employment activity in the states we serve remains generally favorable, with unemployment rates at or below the national average. To date, in 2014, approximately 20% of U. S. Non farm job growth is in states served by Duke Energy, particularly in the manufacturing and construction sectors. Our affordable electricity rates continue to attract businesses to our service territories. Our economic development teams are actively pursuing potential projects representing around $3,000,000,000 in investments and more than 9,500 new jobs. Based on the retail sales growth we've experienced over the rolling 12 months and the underlying favorable economic forecasts, we remain confident in our longer term growth expectation of around 1%. We expect individual quarters to vary, but the longer term economic trends are generally favorable. Let me spend a moment discussing 2 important accounting matters that occurred during the Q3 as outlined on Slide 12. 1st, accounting rules require the recognition of an asset retirement obligation or ARO liability of approximately 3,400,000,000 dollars as a result of the passage of COAS legislation in North Carolina in September. This obligation has been capitalized on the balance sheet as property, plant and equipment for active sites and as a regulatory asset for retired sites. The ARO is based upon a discounted probability weighted assessment of various Ash Basin closure methodologies, costs and timelines. The ultimate cost will rely on the site specific risk classifications and closure methodologies approved by Diener and the Coal Ash Management Commission, as well as the anticipated federal rules for coal ash. We will update the ARO as closure plans continue to evolve. We also had 2 accounting implications related to the sale process of the Midwest Generation Business. As you may recall in the Q1, we recognized a pre tax impairment of 1 point $4,000,000,000 based upon the estimated fair market value of the assets. Our agreement to sell the Midwest Generation business to Dynegy for $2,800,000,000 is higher than our original estimated fair value. Therefore, we have reversed around $475,000,000 of the previously recognized impairment in the 3rd quarter. This reversal was recorded in discontinued operations and has been excluded from our adjusted diluted earnings per share for the quarter. As a result of the Dynegy agreement, our Midwest generation business now meets the accounting criteria to be classified as discontinued operations for GAAP reporting purposes. As we announced at the commencement of the sale process, the earnings from this business will continue to be included in our adjusted diluted earnings per share in 2014. Despite the mild third quarter weather and poor Brazilian hydrology, we are ahead of plan for the year. We are confident in our ability to achieve our revised 2014 adjusted earnings guidance range of $4.50 to $4.65 per share. This range implies 4th quarter adjusted earnings between $0.80 $0.95 per share. Slide 13 outlines the key drivers to consider when evaluating our expectations for lower earnings per share in the Q4 as compared to the prior year. Many of these drivers are consistent with what we have encountered during the year. Let me briefly discuss a few of the drivers that may not be as intuitive. First, we do not expect a significant quarter over quarter variance for revised customer rates as our prior year rate cases were all in effect for the entire portion of last year's Q4. Related to the 2013 rate case activity, we expect a negative driver in the Q4 due to the implementation of nuclear outage cost levelization in late 2013. You might recall that we realized $0.11 of favorable earnings per share in 2013, mostly in the 4th quarter, as we implemented this accounting treatment. This year, we expect about $0.05 to 0 point 06 dollars of a lower benefit in the 4th quarter. We also expect lower results in Latin America, principally driven by the impacts of drought conditions in Brazil and unfavorable foreign currency exchange rates. Finally, we expect a higher effective tax rate in the 4th quarter than the 31% we recognized last year. We anticipate a full year adjusted effective tax rate of 32% to 33%. Slide 14 highlights the building blocks of our long term adjusted earnings growth objective of between 4% to 6% through 2016. The left side of this slide shows the components of our base plan, which supports an adjusted earnings per share growth of around 4%. This base plan is underpinned by around $3,000,000,000 in annual growth investments and assumes modest retail and wholesale load growth, coupled with effective cost management. Lynn outlined the progress that we've made this quarter advancing our incremental growth opportunities, including the Atlantic Coast Pipeline and the NCEMPA asset purchase. These incremental opportunities, along with load growth in excess of 0.5% and optimization of our commercial portfolio, give us confidence in our ability to achieve our targeted 4% to 6% adjusted earnings per share growth objective through achieving each of these objectives. We are on track to achieve our 2014 revised guidance range and our long term adjusted earnings growth objective. We are also focused on the dividend, which is central to our investor value proposition. During the 3rd quarter, we increased our dividend by 2%. This was the 7th consecutive year we have increased the dividend. We expect to move into our targeted long term dividend payout ratio of 65% to 70% this year, providing additional flexibility going forward. Our balance sheet and credit ratings remain strong, allowing us to invest in our business without the need for new equity issuances through 20 16. As we normally do in February, we will provide updated financial plans for 2015 and beyond. Now, I'll turn it back over to Lynn. So in closing, the Q3 demonstrated significant positive momentum in delivering value for our customers, communities and shareholders, and we're laying a strong groundwork and foundation for the future. Now we welcome your questions. We'll go first to Julien Dumoulin Smith from UBS. [SPEAKER JULIEN DUMOULIN SMITH:] Hi, good morning. [SPEAKER JULIEN DUMOULIN SMITH:] Good morning morning, Julien. Good morning. Thanks. First question on the ARO and the overall CapEx, OpEx composition of potential spend with the coal ash, could you just give a little bit of flavor around how much of this could turn into an earnings opportunity in whatever parameters you can describe? Well, we have recorded at this point the ARO liability and we have not begun to spend any significant funds. We will begin spending that money in 2015 as we've identified 4 plants that we're going to work on pretty quickly. Our focus right now is getting these plans approved, getting the permitting done, getting the logistics in place. The ultimate cash spend will be impacted by the decisions made by Deaner and Coal Ash Commission regarding many of the sites. Ultimately, the cost recovery aspect has been kicked to the Utilities Commission. We've made no applications for recovery because we haven't incurred any costs. So ultimately, the dispositions of that into customer rates is yet to be decided. Fair enough. And turning to the international business, I'd be curious where do you stand in the strategic review? And specifically, does the latest hydrological developments in Brazil impact that review in any sense? And really what's on the table at this point as the process continues? Yes. So we're continuing to review all options and had set an internal timeline of late 2014, early 2015 for our review and we're on pace for that, Julian. I wouldn't say specifically that the hydrology in the year of 2014 is impacting that review, but certainly hydrological risk, regulatory risk, market risk and opportunities are part of what we're assessing. So when we reach any important milestone in that review, we'll certainly update you. But at this point, don't have anything further to discuss. Great. And then if you will, just turning to Florida quickly, Nexter has talked about some other opportunities potentially adding solar in the state gas reserves. I'd be curious, what's your thought process on pursuing those avenues generation significant generation build that we have underway to replace capacity in the state. So we're focused, as we remarked in our comments, on combined cycle, upgrades and adding additional capacity. We certainly believe that solar represents an opportunity for the State of Florida as it makes sense for public policy and the requirements of our customers and we'll pursue that at the right time. But I would say our focus at this point is on the gas capacity. Great. Well, thank you very much. Thank you. Thank you. We'll take our next question from Greg Gordon from Evercore ISI. Thanks. Good morning. Good morning, Greg. Good morning, Greg. Going back to Page 7 on Edwards Port, can you review the dollars that are being reviewed for recovery in the rider proceedings? And what risk is if the commission were to decide that you weren't performing up to their expectations? Greg, I think we can take you offline on the specific dollars in each of the filings, and the team would be ready to do that as soon as the call is over. Let me just give you some color generally about the proceedings. So the commission will be taking up IGCC 1213 in February. They'll be focusing on the operating results of the plant. There have been challenges by certain of the interveners during November of 2013 around the concept of negative generation when the plant was down and was drawing power from the grid. We also have discussed previously that we had some challenges during January with freezing 30 degrees below normal in Indiana. We'd expect the commission to be reviewing operating activities during that period. So I think between the IGCC filings as well as fuel, there will be a comprehensive review of operations. And our focus has been on continuing to improve performance and I think the demonstrated results that we shared on the call with 90% availability for the gasifier in July August and the overall capacity factors demonstrate that we're moving in the right direction. Thanks. I'll get them offline. That's all I have. Thanks. And we'll go next to Stephen Byrd from Morgan Stanley. Good morning. Good morning. Good morning, Stephen. I wanted to just discuss your tax position and your Latin American assets. For instance, we don't know where ultimately you'll come out in terms of your strategic review. But if you were to think about selling assets and repatriating the money back to the U. S, can you discuss your tax position at a high level? I know you have a large U. S. Tax loss position. Just curious how we should broadly think about tax implications if you were to try to repatriate a fairly large amount of capital from Latin America? Okay. Let's look at the cash on hand and we've got about $1,600,000,000 overseas off right now. If we were to make an assertion that all the previous earnings were to be repatriated over time, we would record a tax liability of in the ballpark of $300,000,000 to $350,000,000 We have not accrued any U. S. Taxes on the international operations, but if we said all the past earnings we're going to ultimately repatriate, that's what we would record on our books. Now because of our current NOL position, and under the current tax laws with the expiration of bonus depreciation. We would expect to come out of the NOL in 2015 and start utilizing tax credits, we would not be a significant taxpayer until 2016 or 2017. So the actual cash outlays related to income taxes on our international operations wouldn't be made for a few years down the road. Okay. So you do essentially, Steve, get some benefit from that tax loss position that you have when you think about bringing capital back, but there is still an accrual, there is still some degree of a cash cost when you bring that money back? Yes, that's correct. We booked the accrual to catch up taxes on all the previous earnings. And then the actual cash outlays would be a bit later. And so the GAAP accounting or the generally accepted accounting principle would require recognition of the liability, Stephen, but the cash payment would occur, as Steve indicated, after the NOL is absorbed and we move through the utilization of renewable credits and so on. I see. If you were to bring try to bring capital back, let's say, in late 2015, would you still would your tax loss position allow for some degree of a shield of the cash that would be coming back from Latin America? I'd have to look back at the numbers more closely, but I believe there would be some tax shield there for a period of time, a couple of years perhaps. Okay. Coming into 2014, the NOL was $2,700,000,000 Stephen, and I think the other thing that we would need to evaluate depending on what happens in the lame duck session is bonus depreciation extended. I think there are a number of other moving pieces that could impact that assessment as well that you may want to consider. That's a good point. I just wanted to shift over to your pipeline investment and I wanted to better understand how to think about the actual cost of gas that you'll be procuring. When you source the gas, would you be procuring gas at sort of the overall Henry Hub price? Or would it need to be at a discount to Henry Hub because it's essentially coming from low cost shale plays and you've got to factor in transport costs? In other words, is the cost of the pipeline kind of in your mind a sunk cost and then you'll pay prevailing Henry Hub rates? Or does that transport need to factor in and therefore you would be paying a lower price for gas essentially than what we might see in the Gulf of Mexico? So I think the combination of things that you're talking about are still under evaluation on specific, Stephen. So we don't have a specific price of natural gas that we've locked into in Rosales. We will have a price that's applied in the transport as we look at making that multi year commitment for the utilities. But as we stand back and look at the diversity of supply, look at the pricing out of Marcellus, look at the pricing of this additional transport facility into the Carolinas. We think there's a very compelling business case for our customers to have access low price diverse sources of gas. And so that's exactly the business case that we believe exists for underpinning this investment for the benefit of our customers. Understood. Thank you very much. Thank you. Thank you. We'll go next to Jonathan Arnold from Deutsche Bank. Good morning. Good morning. Good morning, John. Just one last this might be I'm reading too much into this, but last quarter you on your 4% to 6% growth build up slide, you said finalizing international strategic review and now you just have you've dropped the word finalizing. Were you close to something that you're now not close to and the process sort of extended out a bit? Or are you communicating anything there? I think you're reading more in it and we should use you as part of finalizing our slides, Jonathan, to point out where we've used language differently. No, in all seriousness, we're on the same pace we were on Q2. And I would love to tell you that analyzing international tax is something that can be done quickly, but there are a variety of complexities in the analysis. We're taking our time. This is an important part of our business that has contributed well for a long period. And so when we have an update on that, we will certainly share it, but we're on target to complete our work late 2014 early 2015. So you're fairly confident then that you'll know the outcome on that by the time you give your 'fifteen outlook, I guess, with the year end call? So that's certainly our target, Jonathan. And just to step back for a moment, when we undertook this review, we were looking at several dimensions. One of them one dimension is how do we optimize cash. We've had opportunities to bring home cash in a couple of large transactions over the last several years, but we would love to solve cash in a way that was more predictable and more consistent with funding of the dividend. And then secondly, we're evaluating is there a way to improve the growth profile of the business in light of what we see as mid term, near term to mid term headwinds, currency pricing, etcetera. So, our intent as we finish our review would be to share our perspectives on both of those objectives and the work we've completed that could accomplish some or all of those objectives as we complete our work. Okay. Thank you. And then just this is somewhat similar question, I'm afraid. But when you first announced the Midwest generation sale, you sounded more robust about the idea that it would be accretive. Now you're saying that it depends on the timing and the ultimate use of proceeds. I mean, are you where it's erring one way or another on use of proceeds that makes you less confident that this is an accretive deal? Jonathan, we continue to see accretion. What we were trying to communicate is the timing is not completely firm. We were hoping actually when we started to close by the end of 'fourteen. We think it's probably more early 15. And so we're just kind of talking about that timing as we share that perspective. But ultimately, we do see this as an accretive transaction certainly. All right, great. Well, thank you very much. Thanks so much. We'll take our next question from Michael Lapides from Goldman Sachs. Hey guys, Just curious anything changed in terms of your thought process regarding rate case timelines, if any, in the Carolinas? Only reason why I ask is the solar CapEx, the development of the LEAF facility. Just curious about how you get those in rates? We have no direct plans for rate case activity in the Carolinas right now. We'll look at our cost structure as we move forward. Moves into moves into service because your cost structure changes at that time. Lee has been scheduled for late 2017 or during 2018 Shortly following that are planned additions for DE progress as well. So that's kind of your starting point. But we'll look at our cost structure between now and then in light of other factors, and that could compel us to move earlier or could push us back later if other events occur. And can you give us changing topics a little bit? When thinking about the Indiana Smart Grid rollout, what the annual kind of the average annual revenue increase tied to that would be? So it's about less than 1% or around 1% lower for industrial. The industrial class will not participate in all of the investment. And we're targeting somewhere around $250,000,000 of spending a year around over the 7 year period. Got it. Thank you, Lynn. Thanks, Steve. Much appreciated. Thank you so much. And we'll go next to Huynh from Sanford Bernstein. Thank you. Hi, My question goes to slide 14, where you outline your sort of 4% to 6% EPS growth trajectory and the drivers that will get you there. 4% growth over 2015 2016 in earnings is kind of an 8% increase against a 1% increase in retail load over that period. 6% growth over 2015, 2016 would be a 12% increase in earnings against maybe slightly more than 1% growth in retail load. I was just wondering if you could help me understand how you're going to close that gap in a way that's tolerable to ratepayers. I understand that 4% range are hoping to do it with wholesale growth and cost control and the 6% range are hoping to do it with accretive acquisitions. But I wonder if you just might give more color on how you close that gap? And secondly, what the long term implications for EPS growth of 5% Lynn mentioned, we've put together some investments in the pipeline. Lynn mentioned, we've put together some investments in the pipeline, the NC EMPA acquisition. Those provide a strong earnings growth. The Senate Bill 560 during the 3 to 5 year period will start produce some earnings as well. So we feel confident about the earnings growth rate on a longer term basis. When you look year to year, some of the drivers to think about, you've got weather normalized customer growth and that's modestly forecasted at 1%. We also have wholesale sales growth in contracts that we're stepping into that have produced earnings for us as well. Some of our investments, although not put into rates, do accrue AFUDC between rate cases, and that can provide some earnings enhancement as well. Our commercial renewables business has provided a solid 1% earnings growth total company on a total company basis as well, and we think that business will continue to grow for us. So those are some of the metrics that we look at when we think about our longer term earnings growth rate trajectory. And the ability to control O and M between rate cases is critical to utilities as well, and we certainly demonstrated that. Okay. Let me just ask a more specific question about the international business. You mentioned that you have this very severe drought in Brazil. What are the earnings implications of that beyond the quarter? Are you expecting a year of depressed earnings? Or will it take even longer to reestablish reservoirs in Brazil? I think when you're thinking about Brazil hydrology, one of the probably the key factor to think about is the upcoming rainy season, which typically runs November, December through March, April. And I think the results of that rainy season will be critical to decisions made in 2015. I wouldn't try to guess at what that rainy season would look like. But I don't think that you'd see any rationing occur unless there was a 3rd consecutive poor rainy season. And it's the forced rationing that really has an impact on earnings. Great. Thanks a lot. Thank you. We'll go next to Ali Agha from SunTrust. Thank you. Good morning. Good morning. Good morning. Steve, I wanted to be clear on the growth rate targets you had talked about, the 4% to 6%. So as you pointed out, your some of your growth initiatives like the pipelines and the additional buyback of the assets from the municipalities, etcetera, those are going to start really contributing to you more in the timeframe beyond 2016. So if I'm hearing you right, should we assume that, that contribution keeps you on the 4% to 6% growth rate beyond 16% or should we think of those actually taking you above the range? How should we think about these growth initiatives relative to the 4% to 6%? We will be rolling out beyond 16% in February as we've traditionally done. And that's the point which we'll be discussing the longer term projections of earnings. But right now, we feel comfortable through 2016 with the 4% to 6% earnings growth rate. Okay. But in a high level sense, is it fair to say this keeps you on track for that kind of run rate? Ali, the I'll jump in. 4% to 6% is our long term growth aspiration. We've spent a lot of time in 2014 laying the foundation and groundwork for that by putting projects in place that will give us an opportunity to deploy the capital necessary to achieve that growth rate. And so, we are on track to do that. We think we've demonstrated that with tangible projects that will deliver earnings that are consistent with what we're trying to accomplish, consistent with a strong dividend paying company. So we'll, as Steve said, update more specifics in February, but we believe that we are putting the pieces in place to deliver a strong growth rate. Okay. And then, Lynn, can you remind us, the grand jury investigation around the coal ash spill, what's the status of that? Is that still ongoing? Or what's happening there? So the litigation continues, Ali, and I can't discuss any specifics on those matters. What I will say is we're cooperating fully defending the company. We cannot predict the outcome of these proceedings at this point, but of course would provide updates when there are milestones met. Okay. And my last question, as you talked about using the proceeds from the Midwest sales, one of the potentials for that is share buybacks. But if I put that in the context of these big mega projects, the pipeline and the acquisitions coming up and put them in the equation, Steve, you said no equity issuance through 2016. Should we think of this as no equity issuance even beyond '16 when some of this big capital spend is going to be used in that 'seventeen, 'eighteen period? Well, again, right now, I can't project beyond 16. We'll be finalizing our plans for beyond 16 and discuss that in February. But we'll be looking at our various spin for coal ash, other investments such as the pipeline and NCEMPA as we make those decisions. And we'll be firming up beyond 16 in February for you. Okay. But conceptually, you're okay with buying back stock now if you think that makes sense, but then issuing equity in a year or 2 later if it's required? I mean conceptually that's not an issue? No, Ali, I would say that as we look at the options for the Midwest generation, we'll be considering the timing of all these matters, including investments. And our objective is to optimize proceeds and investments in the way that creates the greatest value for shareholders. So I would say all options are on the table at this point and we'll share more specifics as we move forward. Fair enough. Thank you. Thank you. We'll go next to Andy levy from Avon Capital Advisors. Hi, guys. Good morning. Just a very, very quick question. Just on the international, I guess with again oil is up actually today. But with oil down so much, I just remember from your initial guidance that you gave back in February. You had a sensitivity on Brent Crude. I think it was a $10 movement is like 0.02 $2 and never really paid a lot of attention to that. So as you get into next year, obviously, we don't know where Brent Crude is going to be, but I guess it's down about $30, dollars 35 from the beginning of the year. How should we think about that for National Methanol? Well, the sensitivity that we gave, Andy, is correct. About a $10 movement is $0.02 and that's a $10 average movement on an annual basis to make sure that's clear. So that's the sensitivity and that relates to our national methanol subsidiary, which is a portion roughly 25% of our international business. So we will bake that into our forecast and keep an eye on where oil prices are moving as we make our projections in February. And the Saudi policy, that has nothing to do with it at all as far as how they allocate oil to Asia or to the U. S. And their pricing there? That doesn't No. And Andy, this correlation that we're sharing with you is a rough correlation. We're not actually in the oil business. Right, right, right. Okay. So the correlation has generally worked over time. We make more money when oil prices are high and less when oil prices are low, but it's not a perfect correlation. Okay. Thank you. Thank you. And we'll take our next question from Greg Gordon, Evercore ISI. Thanks. I have a follow-up question on the pipeline. Just maybe you can clarify a bit. Traditionally, the shippers bear the cost of moving gas to the to where it's been consumed. And I guess the question is whether or not because the cost of transportation on new pipes like this especially given the negative basis that the Marcellus producers are already facing versus Inrihub so high might be prohibitive for them to make it economic. Is it likely that the transportation costs will be borne to some degree by the consumers? So we are entering into long term transport contracts on the part of our utilities. That was what we put in front of the commission, Greg, this quarter, so that we could enter into those multiyear transport contracts. And that's part of the transaction. So the utility customers will bear the transport. That's right. And these costs are typically passed through the fuel clause mechanisms. No, I completely understand. It's just it's a nontraditional framework relative to what E and P analysts generally think about. Your pipeline as well as some others have gotten pushback from investors that well it just seems like a very expensive transportation cost. And I pointed out to them that these are consumer sponsored pipes. And I just wanted get some clarification on that. That's right. Demand sponsored versus supply. So I think that's a key distinction. But Greg, as we look at the need for natural gas in the Carolinas and our dependency on a single pipeline, we think this diversification makes sense for our customers. I completely agree. I just wanted to understand the economics. Thank you. Thank you. This does conclude thank you everyone and thanks for your interest in Duke. We look forward to seeing many of you next week in Dallas at EEI. So thanks again.