Good day. 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 Currens. Please go ahead, sir.
Thank you, Tracy. Good morning, everyone. Welcome to Duke Energy's third quarter 2014 earnings review and business update. Today's discussion will include forward-looking information and the use of non-GAAP financial measures. Slide two 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. Thanks for joining us. Earlier today, we released third quarter adjusted earnings results of $1.40 per share. These results were impacted by milder than normal weather, unfavorable results in Latin America, and weaker retail load compared to the prior year quarter. Our year-to-date results remain above our internal plan. We remain on track to achieve our revised 2014 adjusted EPS guidance range of $4.50-$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 third quarter. Our regulated natural gas fleet also performed well, achieving at least an 80% capacity factor at eight of our nine combined cycle plants in the Carolinas and Florida.
We also continue to deliver significant benefits from the 2012 merger with Progress Energy. Through the third quarter, we've generated about $360 million of cumulative fuel and joint dispatch savings for our Carolinas customers. We are on track to achieve the guaranteed savings of $687 million over the first five years. By the end of this year, we expect to deliver non-fuel O&M savings of about $550 million, exceeding our original assumptions. It has been an active and successful quarter in advancing our strategy. Let's turn to slide four and several of our growth initiative announcements during the third quarter, including new generation and new gas and 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 Power business. The pipeline has a total construction cost estimate of between $4.5 and $5 billion. 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 have approved our regulated subsidiaries entering into these agreements. Since the announcement, the project has received broad support. Over 5,000 letters have been received across the project's three-state region, voicing support for the pipeline. An independent study estimates that the project can generate a total of $2.7 billion 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 seven-year, $1.9 billion 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 second quarter of 2015. As highlighted on our last earnings call, we finalized an agreement for the $1.2 billion 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 cost savings and increased fuel diversity. Last month, we filed for FERC approval of the asset purchase 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 million to solar expansion in North Carolina. This supports compliance with the state's renewable portfolio standard. In addition to signing power purchase agreements with five new solar projects for 150 megawatts, we will acquire and construct three 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%-6%. Now let me turn to slide five, 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 billion of investments through 2018. During the quarter, the Florida Commission held hearings to review the need for our proposed 1,640-megawatt combined cycle facility in Citrus County and the 220 megawatts of upgrades at the existing Hines facility. Last month, the Florida Commission issued certificates for both projects.
We expect the Hines 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 320 megawatts of peaking capacity at our Suwannee 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 six, I'll provide an update on coal ash management activities during the third quarter.
In August, the North Carolina legislature passed the Coal Ash Management Act of 2014, which became law in September. 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 nine-member Coal Ash Management Commission to oversee implementation of the law. It requires the North Carolina Department of Environment and Natural Resources 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 four sites.
We will be filing our excavation plans for these four sites with NCDENR 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 ash management program. First, we announced a new centralized internal organization to manage all coal combustion products. We also announced the formation of the National Ash Management Advisory Board, a panel of nine 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 emissions from existing power plants. Since issued in June, we continue to evaluate the rule and engage with our state regulators.
We are developing comments and plan to submit them to EPA by the revised deadline. We have made significant progress over the last decade in reducing the environmental impact of our generating facilities. We've invested over $9 billion in building new state-of-the-art plants, as well as $7.5 billion in environmental controls. These investments have resulted in CO2 emission reductions of more than 20% below 2005 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 four 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 seven 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 second quarter and 70% during the third quarter, including a planned maintenance outage that began in September. Gasification availability exceeded 90% during the critical months of July and 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 12 and 13 in February. Orders are expected for all three pending proceedings in the first half of 2015. The commission will examine the operational performance of the plant in the normal course of reviewing our semiannual 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 $2.8 billion in cash. As outlined on slide eight, we expect to close the transaction by the end of the first quarter 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, in 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 to 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 four areas. First, the primary drivers of our third quarter results. Second, our retail volume trends and the economic conditions within our service territories. Third, important accounting changes made in the third quarter. 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 nine. Our quarterly adjusted diluted EPS of $1.40 was below the prior year's quarterly results of $1.46 per share. As we discussed during our last earnings call, we expected slightly higher-adjusted earnings per share in the third quarter compared to last year. However, adjusted earnings this quarter were hampered by three principal drivers. First, 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 third-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 million pretax reversal of a first-quarter impairment charge related to the sale of our Midwest 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 second 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% 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 in 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&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 rainfall 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 fourth quarter 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 third quarter of 2013, we experienced strong retail load growth of 1.7%, a challenging level from which to grow period over period. As we saw in the first quarter 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 third quarter, weather 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 sixth 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 are monitoring in each major customer class. First, the industrial sector, where sales grew 0.6% over the rolling 12 months.
We have experienced recent weakness in our Duke Energy Progress territory, where sales continue to be negatively impacted by two chemical plant closures late last year. Outside of Duke Energy Progress, industrial activity in our other jurisdictions remains strong, with overall growth of around 2% over the rolling 12 months. The Midwest and Duke Energy Carolinas jurisdictions continue to see strength in the metals, chemicals, and transportation subsectors. Building product manufacturers have also shown recent strength. Next, the commercial sector, where sales grew 1.1% over the past 12 months. Overall, this sector continues to benefit from 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 within our six-state footprint. So far this year, several new business relocations and expansions have been announced in our service territories, representing around $3 billion 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, the longer-term economic trends are generally favorable. Let me spend a moment discussing two important accounting matters that occurred during the third quarter, as outlined on slide 12.
First, accounting rules require the recognition of an asset retirement obligation, or ARO liability, of approximately $3.4 billion as a result of the passage of coal ash 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 DENR 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 two accounting implications related to the sale process of the Midwest Generation business.
As you may recall, in the first quarter, we recognized a pretax impairment of $1.4 billion based upon the estimated fair market value of the assets. Our agreement to sell the Midwest Generation business to Dynegy for $2.8 billion is higher than our original estimated fair value. Therefore, we have reversed around $475 million of the previously recognized impairment in the third 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 fourth quarter adjusted earnings between $0.80 and $0.95 per share. Slide 13 outlines the key drivers to consider when evaluating our expectations for lower earnings per share in the fourth quarter 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 fourth quarter.
Related to the 2013 rate case activity, we expect a negative driver in the fourth quarter 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 fourth quarter, as we implemented this accounting treatment. This year, we expect about $0.05-$0.06 of a lower benefit in the fourth 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. We expect a higher effective tax rate in the fourth quarter than the 31% we recognized last year. We anticipate a full-year adjusted effective tax rate of 32%-33%. Slide 14 highlights the building blocks of our long-term adjusted earnings growth objective of between 4%-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 billion 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%-6% adjusted earnings per share growth objective through 2016. Slide 15 outlines our financial objectives for 2014 and beyond. These objectives have remained consistent over time, and we have an established track record of 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 third quarter, we increased our dividend by 2%. This was the seventh consecutive year we have increased the dividend. We expect to move into our targeted long-term dividend payout ratio of 65%-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 2016. As we normally do, in February, we will provide updated financial plans for 2015 and beyond. I'll turn it back over to Lynn.
In closing, the third quarter 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. We welcome your questions.
If you would like to ask a question, please signal by pressing *1 on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press *1 to ask a question. We'll go first to Julien Dumoulin-Smith from UBS.
Hi, good morning.
Good morning, Julien.
Good morning.
Excellent. First question, on the ARO and the overall CapEx, OpEx composition of potential spend with 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 four 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 DENR and the Coal Ash Management Commission regarding many of the sites. Ultimately, the cost recovery aspect has been kicked to the North Carolina Utilities Commission. We've made no applications for recovery because we haven't incurred any costs. Ultimately, the dispositions of that into customer rates is yet to be decided.
Fair enough. Turning to the International Energy 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? Really, what's on the table at this point as the process continues?
Yeah. 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, Julien. I wouldn't say specifically that the hydrology in the year of 2014 is impacting that review. Certainly hydrological risk, regulatory risk, market risk, and opportunities are part of what we're assessing. When we reach any important milestone in that review, we'll certainly update you. At this point, don't have anything further to discuss.
Great. If you will, just turning to Florida quickly. NextEra 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 as well?
At this point, our focus is on the significant generation build that we have underway to replace capacity in the state. We're focused, as we remarked in our comments, on combined cycle uprates 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. 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.
Morning, Greg.
Going back to page seven on Edwardsport, can you review the dollars that are being reviewed for recovery in the rider proceedings and what the 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. 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. The commission will be taking up IGCC 12 and 13 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. I think between the IGCC filings as well as fuel, there will be a comprehensive review of operations.
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 and 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've got.
Thank you.
Thanks.
We'll go next to Stephen Byrd from Morgan Stanley.
Good morning.
Good morning.
Morning, Stephen.
I wanted to just discuss your tax position and your Latin American assets. Granted, 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 $1.6 billion overseas, offshore right now. If we were to make an assertion that all of the previous earnings were to be repatriated over time, we would record a tax liability in the ballpark of $300 million-$350 million. 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.
The actual cash outlays related to income taxes on our international operations wouldn't be made for a few years down the road.
Okay. You do essentially, Steve, get some benefit from that tax loss position that you have when you think about bringing capital back. 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'd book the accrual to catch up taxes on all the previous earnings, and then the actual cash outlays would be a bit later.
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 try to bring capital back, let's say, in late 2015, 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, I believe there would be some tax shield there for a period of time, a couple of years perhaps.
Okay. I understand.
Coming into 2014, the NOL was $2.7 billion, 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, it's 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?
I think the combination of things that you're talking about are still under evaluation on specific, Stephen. We don't have a specific price of natural gas that we've locked into in Marcellus. We will have a price that's implied in the transport as we look at making that multi-year commitment for the utilities. 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 to low price, diverse sources of gas. 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.
Yeah. Good morning.
Morning.
Morning, Jon.
Yeah. I might be reading too much into this, last quarter, on your 4%-6% growth buildup slide, you said finalizing international strategic review, and now 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 into it, 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 second quarter. I would love to tell you that analyzing international tax is something that can be done quickly, 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. When we have an update on that, we will certainly share it, we're on target to complete our work late 2014, early 2015.
You're fairly confident then that you'll know the outcome on that by the time you give your 2015 outlook, I guess, with the year-end call?
That's certainly our target, Jonathan. Just to step back for a moment, when we undertook this review, we were looking at several dimensions. 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, we would love to solve cash in a way that was more predictable and more consistent with funding of the dividend. Secondly, we're evaluating, is there a way to improve the growth profile of the business in light of what we see as near-term to mid-term headwinds, currency pricing, et cetera? 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.
Thank you.
Just, this is somewhat similar question, I mean, I'm afraid. 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 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 2014. We think it's probably more early 2015. We're just kind of talking about that timing as we share that perspective.
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 change in terms of your thought process regarding rate case timelines at FE and the Carolinas? Only reason why I ask is the solar CapEx, the development of the Lee 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. Typically, when you try to plan rate cases or think about data points on rate cases, you'll look at when a base load plant moves into service because your cost structure changes at that time. Lee has been scheduled for late 2017 or during 2018 for commercial operation for the Carolinas, that might be a point that you'd look at there. Shortly following that are planned additions for DE Progress as well. That's kind of your starting point. 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.
Can you give us, changing topics a little bit, when thinking about the Indiana smart grid rollout, what the average annual revenue increase tied to that would be?
It's about less than 1% or around 1% lower for industrial. The industrial class will not participate in all of the investment. We're targeting somewhere around $250 of spending a year over the seven-year period.
Got it. Thank you, Lynn. Thanks, Steve. Much appreciated.
Thanks so much.
We'll go next to Hugh Wynne from Sanford C. Bernstein.
Thank you.
Hello, Hugh.
My question goes to slide 14, where you outline your sort of 4%-6% EPS growth trajectory and the drivers that will get you there. 4% growth over 2015 and 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 palatable to ratepayers. I understand that there's 4% range are hoping to do it with wholesale growth and cost control, and then the 6% range are hoping to do it with accretive acquisitions. I wonder if you just might give more color on how you close that gap.
Secondly, what the long-term implications for EPS growth of 5% load growth are beyond 2016.
Yes. Let me discuss the growth trends broadly here. As Lynn mentioned, we've put together some investments in the pipeline, the NCEMPA acquisition. Those provide a strong earnings growth. The Senate Bill 560 during a 3-5-year period will start to produce some earnings as well. 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 and 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 on a total company basis as well, and we think that business will continue to grow for us. Those are some of the metrics that we look at when we think about our longer-term earnings growth rate trajectory. The ability to control O&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, probably the key factor to think about is the upcoming rainy season, which typically runs November, December through March, April. 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. I don't think that you'd see any rationing occur unless there was a third consecutive poor rainy season. It's the forced rationing that really has an impact on earnings.
Great. Thanks a lot.
Thank you.
As a reminder, it's star one to ask a question. We'll go next to Ali Agha from SunTrust.
Thank you. Good morning.
Morning.
Morning.
Steve, I wanted to be clear on the growth rate targets you had talked about, the 4%-6%. As you pointed out, some of your growth initiatives like the pipelines and the additional buyback of the assets from the municipalities, et cetera, those are going to start really contributing to you more in the timeframe beyond 2016. If I'm hearing you right, should we assume that contribution keeps you on the 4%-6% growth rate beyond 2016? Or should we think of those actually taking you above the range? How should we think about these growth initiatives relative to the 4%-6%?
We will be rolling out beyond 2016 in February, as we've traditionally done. That's the point at which we'll be discussing the longer-term projections of earnings. Right now, we feel comfortable through 2016 with the 4%-6% earnings growth rate.
Okay. In a high-level sense, is it fair to say this keeps you on track for that kind of run rate?
Ali, I'll jump in. 4%-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'll give us an opportunity to deploy the capital necessary to achieve that growth rate. We are on track to do that. We think we've demonstrated that with tangible projects that'll deliver earnings that are consistent with what we're trying to accomplish, consistent with a strong dividend-paying company. We'll, as Steve said, update more specifics in February. We believe that we are putting the pieces in place to deliver a strong growth rate.
Okay. 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?
The litigation continues, Ali, 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. My last question, as you talked about using the proceeds from the Midwest sales, one of the potentials for that is share buybacks. 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 2016, when some of this big capital spend is going to be used in that 2017, 2018 period?
Well, again, right now, I can't project beyond 2016. We'll be finalizing our plans for beyond 2016 and discuss that in February. We'll be looking at our various spend for Coal Ash, other investments such as the pipeline and NCEMPA as we make those decisions. We'll be firming up beyond 2016 in February for you.
Okay. Conceptually, you're okay with buying back stock now, if you think that makes sense, then issuing equity in a year or two 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. Our objective is to optimize proceeds and investments in the way that creates the greatest value for shareholders. 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 Levi from Avon Capital Advisors.
Hi, guys. Good morning.
Good morning.
Hi, Andy.
Hi. Just a very quick question. Just on the international, I guess with, again, oil's up actually today. 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 and never really paid a lot attention to that. As you get into next year, obviously, we don't know where
Brent crude is down about $30-$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. That's the sensitivity, and that relates to our National Methanol subsidiary, which is a portion, roughly 25% of our international business. We will bake that into our forecasts and keep an eye on where oil prices are moving as we make our projections in February.
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.
No. Andy, this correlation that we're sharing with you is a rough correlation. We're not actually in the oil business.
Right.
Okay. 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.
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 where it's being consumed. 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 Henry Hub is so high, might be prohibitive for them to make it economic. Is it likely that the transportation cost will be borne to some degree by the consumers?
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 multi-year transport contracts. That's part of the transaction. The utility customers will bear the transport.
That's right.
Thank you.
These costs are typically passed through the fuel clause mechanisms.
No, I completely understand. It's a non-traditional framework relative to what E&P analysts generally think about. Your pipeline as well as some others have gotten pushback from E&P investors that, well, it just seems like a very expensive transportation cost. I pointed out to them that these are consumer-sponsored pipes, and I just wanted to get some clarification on that.
That's right.
That's correct.
Demand sponsored versus supply. I think that's a key distinction. 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 today's question and answer session. I'd like to turn the conference back over to Lynn for any additional or closing remarks.
Thank you everyone, and thanks for your interest in Duke. We look forward to seeing many of you next week in Dallas at EEI. Thanks again.