Duke Energy Corp (DUK) 2013 Q4 法說會逐字稿

Good day and welcome to the Duke Energy fourth quarterly earnings call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Bill Currens. Please go ahead.

Thank you, Whitney. Good morning, everyone, and welcome to Duke Energy's fourth quarter 2013 earnings review and business update. Leading our call is Lynn Good, President and CEO, along with Steve Young, Executive Vice President and Chief Financial Officer.

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. You should also refer to the information in our 2012 10-K and other SEC filings concerning factors that could cause future results to differ from this forward-looking information. A reconciliation of non-GAAP financial measures can be found on our website at 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 and our financial outlook.

We have a lot of material to cover today. Lynn will provide an overview of our key 2013 accomplishments and our key priorities for 2014. And Steve will review our 2013 financial results, introduce our 2014 earnings per share guidance range, and discuss our longer-term earnings growth objectives. Additionally, we will have commentary on yesterday's announcement that we have begun a process to exit the Midwest generation business.

Our prepared remarks today will be a little longer than normal. We will try to get to as many of you as possible during the Q&A portion of today's call. For those we are not able to get to, the investor relations team is available for any follow-up you may have. So now, I'll turn the call over to Lynn.

Good morning, everyone, and thank you for joining us today. 2013 was a year of great accomplishments for Duke, our first full year as a combined company. Our 2012 merger with Progress Energy gives us a unique platform to drive efficiencies and grow the business. We are pleased with all that has been accomplished in the last year and a half and also recognize we still have important work ahead of us.

As we announced earlier today, we delivered 2013 adjusted diluted earnings per share of $4.35 and introduced guidance for 2014 of $4.45 to $4.60 per share, with the midpoint reflecting 5% earnings growth over the midpoint of our 2013 guidance range. We also confirmed our earnings-per-share growth objective of 4% to 6% through 2016 off of a base of 2013.

Dividend growth has been and will remain central to our value proposition and our balance sheet remains strong. Our total shareholder return for 2013 was 13%, exceeding a UTY return of 11%. Our primary focus in 2013 was on positioning our regulated businesses for the future, and I believe we accomplish this objective. Our goals were clear. We had to complete our fleet modernization program, achieve constructive outcomes in five rate cases, and resolve key issues, including the future of the Crystal River 3 nuclear station. Additionally, we had to focus on improving the performance of our entire nuclear fleet and realizing our merger integration plans.

Let me summarize each of these as outlined on slide 5. During 2013, we completed our $9 billion fleet modernization program. This program added approximately 6600 megawatts of new combined-cycle natural gas and state-of-the-art coal capacity in the Carolinas and Indiana, replacing a similar amount of capacity for older plants we have or are retiring by 2015. The Edwardsport IGCC plant in Indiana went into commercial service in June, and in November the Sutton combined cycle natural gas plant in North Carolina was put into service.

At Edwardsport, we have completed GE's new product introduction testing protocol and are working towards conducting required performance testing. Testing has been delayed in early 2014 by the extreme cold weather in the Midwest, which has decreased plant output, but we expect to continue tuning and systems optimization in preparation for final testing. All major technology systems have been validated. We also remain on track to meet our total revised project cost estimate of $3.5 billion.

Next, we reached constructive regulatory outcomes in all five of our general rate cases to recover the investments made to modernize our fleet and replace aging infrastructure in our transition and distribution system. When fully implemented, these base rate cases will add about $600 million in additional annualized revenue, while at the same time keeping our customers retail rates below national averages.

In Florida, we made the decision to retire the Crystal River 3 nuclear plant, resolved insurance claims with our insurance provider NEIL, and obtained approval from the Florida Commission of a comprehensive settlement. This agreement addresses cost recovery not only related to the Crystal River 3 nuclear units but also to the Crystal River 1 and 2 coal units and the Levy nuclear project. Additionally, it contains provisions to invest in new generation in the latter half of the decade, helping us to meet the future needs of our Florida customers.

Next, let me also highlight the performance of our nuclear fleet. In 2013, the combined capacity factor for our 11 nuclear units was 92.8%. This was the 15th consecutive year for the nuclear fleet capacity factor above 90%. We are making investments to improve performance at our nuclear plants. While important work remains, we are pleased with the results to date, in particular at the Robinson plant.

Let me move to another important area of accomplishment for 2013: fuel and joint dispatch savings, which are benefiting our Carolina customers. Through December 31, we exceeded our original targets and have reported approximately $190 million of cumulative fuel and joint dispatch savings since the merger closed. We have contractually locked in or generated about 65% of the total guaranteed savings of $687 million over five years.

We are also realizing cost synergy by eliminating duplicate functions and have exceeded our original target of 5% to 7% in non-fuel O&M savings. We are on pace to deliver about 9%, or $550 million, of non-fuel O&M savings in 2014, helping us to achieve flat O&M expenses from 2011 to 2014. Overall, we have accomplished what we've set out to do and have strengthened our regulated utility businesses in six jurisdictions comprising 85% to 90% of Duke's annual earnings. Over the next several years, we will focus on levering our scale, driving out additional efficiencies, and deploying capital for the benefit of our customers.

Next, let me provide a brief update on recent events at our Dan River steam station in North Carolina. You may recall that we retired our coal units at this site in 2012 and replaced them with a new combined-cycle gas station. In early February, we detected a break in a storm water pipe beneath the coal ash basin of the site, which resulted in ash basin water and ash being discharged into the Dan River.

We estimate that between 30,000 and 39,000 tons of ash was released into the river. We have permanently sealed the pipe and stopped the discharge. Now that the flow of ash into the river has been contained, our immediate focus is on remediation and cleanup at the site. We will apply any lessons learned to our other coal ash basins.

We continue to monitor and test the water quality of the Dan River. Our tests to date show the drinking water supplies downstream from the site are safe. We are working collaboratively with the ETA, the North Carolina Department of Energy and Natural Resources, U.S. Fish and Wildlife, and other state and local authorities as we respond to this matter.

We received a subpoena from the US attorney in the Eastern District of North Carolina related to the Dan River coal ash discharge. We will cooperate with this investigation. This accident should have never occurred. We take responsibility and will learn from this event. We will continue to update you on this matter.

Last week, a significant winter storm struck our Carolina service territory. We quickly deployed about 3900 field workers from the Carolinas, Midwest, and Florida to focus on restoration efforts. We've been able to restore more than 900,000 outages and remain focused on restoring service to the few who remain without service. I appreciate the efforts of the crews that worked safely and diligently in a challenging environment.

Next, let me discuss yesterday's announcement, that we are beginning a process to exit our Midwest generation business. After an 18-month regulatory process, we were disappointed the Ohio Commission denied our application for our cost-based capacity charge late last week. I want to thank the entire Ohio regulatory team that worked so diligently on this filing. However, this decision gives us clarity.

The volatility inherent in a merchant generation portfolio has challenged our ability to earn the level of consistent and fair returns our investors expect. This business is not a strategic fit for Duke Energy. We have commenced a process to exit the business and have retained advisors to assist in the process. The redeployment of proceeds from this process is expected to be accretive to our adjusted earnings per share.

We will work closely with employees, community leaders, and our joint owners during this process to ensure a smooth transition. Additionally, we will move quickly to finalize the required transfer of our coal-based generation assets out of the utility and expect that to occur in the next 60 days. It's important for me to emphasize that we remain committed to our electric and gas distribution utilities in Ohio and the 1.3 million customers we serve. These utilities are not a part of this strategic process.

Before I turn the call over to Steve, let me summarize our strategic positioning with our remaining commercial businesses. We see opportunities to continue to grow our renewables platform over the next two years and expect a greater mix of solar in our capital deployment. We are targeting $400 million of renewables capital annually and we have the potential to deploy more if opportunities arise.

We also continue to develop commercial transmission options through our DATC joint venture. We expect the projects from this venture to mature over the next several years.

Our international business has also been an important contributor to earnings and cash flow. This past September, we returned $750 million of cash in a tax-advantaged structure. In 2014, we will undertake a strategic review of our international business as we periodically do with all of our businesses. The review will focus on positioning the business for growth and optimizing cash flows. We will provide updates as we finalize our review.

Now I'll turn the call over to Steve to discuss our financial performance in 2013 as well as our financial plan for growth in 2014 and beyond.

Thanks, Lynn. As Lynn highlighted, 2013 was a very good year for Duke. Let me start with our financial results for the year as outlined on slide 8. As expected, our fourth quarter results were significantly higher than 2012 due to the settlements in our 2013 rate cases, the adoption of nuclear levelization in the Carolinas, growth in our wholesale business, and the benefits of cost control. Our adjusted diluted earnings per share for the fourth quarter were $1 compared to $0.70 for the prior year quarter. On a reported basis, our quarterly earnings were $0.97 cents compared to $0.62 for the prior year.

I will focus most of my comments on our full-year results. For more details on our quarterly earnings drivers, see our press release materials from earlier this morning.

As Lynn reported, for the full year, we recognized 2013 adjusted diluted earnings per share of $4.35 compared to $4.32 for the prior year. On a reported basis, our full-year earnings were $3.76 per share compared to $3.07 in 2012.

Here are highlights of our results compared to our original expectations. For the year, our regulated utilities experienced favorable O&M expenses compared to 2012, supported by the impact of increased merger synergies and the adoption of nuclear levelization. This helped to offset the impact of unfavorable weather during the year. Our consolidated results benefited from a lower than expected effective tax rate of 33% for the year, which is principally in our other category. These improved results helped offset lower commercial power contributions, which included results at renewables, lower Midwest coal generation margins, and the lack of a favorable decision on our Ohio cost-based capacity filing.

Results in international energy were consistent with our expectations. For the year, we experienced unfavorable foreign exchange rates as well as lower results at National Methanol. Unfavorable rain conditions in Brazil impacted our results early in the year. However, these conditions moderated in the back half of the year and our generation volumes were favorable. On slide 9, you can see our weather-normalized customer volume trends for the fourth quarter and the full year of 2013, as well as our future growth projections.

For the fourth quarter of 2013, our weather-normalized load growth was 0.9% higher than the prior year quarter. This continued a favorable trend we began seeing in the third quarter as the economy strengthened. We continue to experience growth throughout our service territories.

For the full year, our retail load growth was 0.6% higher, consistent with our expectations. 2013 was the fourth consecutive year we have experienced overall positive retail load growth, principally driven by 0.9% industrial usage growth and 0.8% growth in the commercial sector. All jurisdictions, except Florida, reported strong retail and office building activity.

Residential demand was 0.3% higher for the year, benefiting from 0.8% growth in the average number of customers. Usage on a per customer basis continues to trend flat to slightly negative. In Florida, we are encouraged by a modest recovery in the housing market and in residential load.

As we look ahead to 2014, we are using 0.5% as our overall load growth planning assumption, roughly comparable to 2013. Although the third and fourth quarter of 2013 were relatively stronger, we continue to remain conservative as we have not yet obtained consistent, sustained growth at these levels.

We expect to see growth in 2014 due to an approximate 1% increase in the number of residential customers, modest growth in commercial, including data centers, and continuing growth in our industrial sector, specifically automotive and housing-related industries. Through 2016, we expect growth to trend between 0.5% and 1%, as the US economy and GDP strengthen. Over time, we expect the continued growth in our service territories will result in higher demand for electricity.

On slide 10, you can see our 2014 earnings guidance range of between $4.45 and $4.60 per share. The primary segment drivers I will discuss in a moment, but based upon the $4.53 per share midpoint of this range.

Our largest segment, regulated utilities, is expected to generate approximately 90% of our 2014 consolidated results. We expect this segment to deliver around $0.11 of additional earnings per share in 2014 over 2013. Significant drivers include the full year impact of customer rates from our 2013 rate cases in the Carolinas in Ohio; normal weather; customer load growth; and increased wholesale contributions. These benefits are expected to be offset by higher depreciation and lower AFUDC equity and reduced benefits from cost of removal amortization in Florida, and nuclear levelization in the Carolinas.

Let's briefly discuss each of these drivers. During 2013, we implemented revised customer rates in May for Duke Energy Ohio, in June for Duke Energy Progress, and September for Duke Energy Carolinas. As a result, in 2014, we recognized a full year of the benefit of these revised customer rates, providing year-over-year earnings per share growth of approximately $0.30 cents over 2013.

Our 2014 outlook assumes modest weather, normalized retail load growth of around 0.5%, which should generate around $0.04 to $0.05 of additional earnings per share. 2013 was a mild year in terms of the weather. Our assumptions for 2014 are based upon normal weather, which should add $0.08 of additional earnings per share.

In fact, the recent blast of cold temperatures we experienced in the Carolinas and Midwest during January resulted in favorable weather, but we also expect storm restoration expenses from last week's winter storm in the Carolinas. It's too early in the year to revise our full-year projections as we still have 11 months ahead of us. As you know from past experience, weather trends can change quickly.

Related to our wholesale business within our regulated footprint, we expect our long-term contracts to provide between $0.07 and $0.08 of additional earnings-per-share growth in 2014 due to increasing annual load requirements embedded in our contract. Additionally, we will see reduced benefits from certain regulatory amortizations in 2014. Let me briefly review them.

First, you may recall that the Florida Commission approved our ability to amortize a certain amount of our cost of removal liabilities into earnings in a 2010 regulatory settlement. We amortized the final $110 million in cost of removal liabilities in 2013, contributing around $0.10 per share, although there will be no benefit in 2014 from this non-cash amortization.

Additionally, as part of our 2013 general rate cases, we received approval to implement nuclear outage cost levelization in the Carolinas. Once fully implemented in 2015, this levelization results in lower earnings volatility due to the timing of refueling outages. In 2013, nuclear levelization added $0.11 earnings per share. Due to the timing of planned refueling outages and amortization of deferred cost, we expect a benefit of $0.05 to $0.06 per share in 2014, less than the benefit recognized in 2013.

Depreciation and other property-related expenses are expected to be higher and we will accrue less AFUDC equity in 2014, resulting in lower earnings of approximately $0.25 per share. This unfavorable impact is principally due to placing our recently completed new generating projects, such as the Sutton combined-cycle gas plant, into service. Further, our costs will increase as the result of the recognition of previously deferred costs resulting from our recent rate cases.

Finally, excluding the impact of nuclear levelization, we are assuming fairly flat O&M costs from 2013 to 2014. Additional merger synergies and lower benefit costs during 2014 will help to offset the impact of inflation and other emerging costs, such as higher fossil outage costs. Next, we expect Commercial Power to generate around $0.16 of additional earnings per share in 2014.

For 2014, PJM capacity revenues for the Midwest generation fleet will increase by an average of approximately $60 per megawatt day. This will result in higher earnings contributions from Commercial Power of around $0.12. Our 2014 earnings guidance assumes a full year of contributions from the Midwest generation fleet, which we have started the process to exit.

We believe it is unlikely we will close on a sale transaction in 2014. As the estimated fair value of this fleet is below current book value, we expect to recognize a pretax impairment charge of between $1 billion to $2 billion in the first quarter of 2014. This loss will be treated as a special item and excluded from our adjusted earnings-per-share results.

Additionally, it is possible the business may be reclassified for accounting purposes to discontinued operations at some point in 2014. Even if it is classified as discontinued operations, we expect to continue reflecting any Midwest generation fleet earnings in our adjusted earnings-per-share results. Earnings contributions from our commercial renewables fleet are also expected to increase in 2014.

We currently operate a portfolio of 1740 megawatts of mostly wind generation with a small but growing amount of solar. Our results in 2014 will be supported by the 33 megawatts of solar projects we put into service in 2013, as well as the 200 megawatts of wind projects which are expected to be in service later this year.

Next, International Energy. In 2014, we expect segment net income to increase by approximately 3% per share -- $0.03 per share, up 5% from 2013's results. During the year, higher pricing and volumes in Brazil will help mitigate unfavorable foreign exchange rates. In January, reservoir levels in southeast Brazil were lower than expected, but closed the month at levels slightly above where they were at this point last year. Weaknesses continued in the early portion of February. The rainy season in Brazil continues through April and we will continue to monitor conditions and keep you updated as the year progresses.

Due to a change in regulatory stipulations, short-term energy prices in Brazil now include the full cost of thermal dispatch. In order to minimize our financial risk due to extended drought conditions, we are currently contracting at slightly lower percentages than the previous years. As a result, we are less exposed to poor hydrological conditions and positioned to benefit from any excess hydro generation.

For Other, we expect an increase in the effective tax rate. On a consolidated basis, our effective tax rate is expected to be between 33% and 34%. We expect nonfuel O&M to remain flat during the three-year period from 2011 to 2014. Our cost control efforts will be an important factor in achieving our 2014 earnings-per-share guidance range. Let me provide a brief overview on where we are.

Turning to slide 11, a significant amount of our savings to date has been related to corporate center costs and we expect further corporate center cost reductions in 2015 and 2016 as employees are able to work on a single, integrated financial and HR platform. By the end of the first quarter, the remaining employees under our voluntary severance plan will leave the Company as we drive further efficiencies.

We are also achieving significant supply chain benefits as we continue to renegotiate procurement contracts. We continue to benefit from our scale as a larger purchaser of materials, supplies, inventory, equipment, and services. We have completed around 60% of our merger initiatives and expect the remainder to be essentially complete by the end of this year.

Next, let me discuss the shaping of our quarterly results in 2014 as highlighted on slide 12. In 2013, our earnings were more heavily weighted toward the back half of the year due to the significant impact of our regulatory activity. As we move into 2014, we expect a more normal distribution of our quarter-by-quarter earnings compared to last year. As a result, you will find during the year that comparisons of our quarterly results from 2013 to 2014 will, once again, be challenging.

We expect higher year-over-year results in the first three quarters of 2014 and lower comparable results in the fourth quarter. These expectations assume normal weather. As in past years, we expect the third quarter to be the most significant contributor to our annual results due to summer load demand.

Our 2014 cash flow and financing assumptions are summarized on slide 13. You can see that our sources of cash flow in 2014 are estimated at approximately $7.7 billion compared to total sources of around $7.3 billion in 2013. This increase is largely driven by the full year benefit of revised customer rates in 2013 as we convert our modernization investments into cash earnings.

We expect capital investments of approximately $6.1 billion, mostly in regulated utilities. Dividend distributions to our shareholders are expected to be around $2.2 billion, while discretionary contributions to our pension plans are expected to be approximately $145 million.

Due to the significant growth investments we are making, we expect our uses of cash will exceed our sources of cash by around $800 million during the year. In order to fund this deficit, as well as our debt maturities of approximately $2 billion, we expect to issue around $3 billion of total debt, including commercial paper. Our financing plan for 2014 is outlined in the charts on the right side of the slide. As you can see, most of our financings are driven by maturities of long-term debt.

Our current credit ratings and projected metrics for 2014 are outlined on slide 14. We were pleased with Moody's action a few weeks ago to upgrade the ratings of our holding company and four of our utilities. As a result of the strength of our metrics, our plans do not require any incremental equity issuances during our three-year planning horizon from 2014 to 2016. As of the end of 2013, we have total available liquidity to $5.6 billion, excluding cash held offshore of approximately $1.1 billion.

Slide 15 provides an overview of the primary drivers of our 4% to 6% earnings-per-share growth objectives through 2016. Let me explain how we get there. Our regulated utilities are expected to contribute an average of 4% growth, underpinned by rate base growth. Customer load growth of between 0.5% and 1% and growth in our wholesale business. Wholesale is expected to contribute an additional $0.07 to $0.08 of earnings per share in 2014 and 2015, while moderating to around an additional $0.01 to $0.02 per share in 2016.

This adds around 2% of earnings-per-share growth through 2016. This growth is expected to be partially offset by the impacts of regulatory lag and additional depreciation since we do not have significant rate case activity planned through 2016. We are targeting flat O&M cost from 2014 to 2016, as the success of our merger integration savings helps offset inflationary pressures and other emerging costs. More details on that in a minute.

Next, we expect our nonregulated businesses to be modestly higher through 2016. Commercial Power is expected to add around 1% of average earnings-per-share growth as we continue to expand the renewable portfolio. International Energy is expected to be relatively flat through 2016. A reduction in contributions from National Methanol, as well as unfavorable Brazilian foreign currency exchange rates is expected to be substantially offset by an average annual increase in Brazil pricing of approximately 6% through 2016.

You may recall that our ownership percentage in National Methanol decreases from 25% to 17.5% upon completion of the new production facility, which is estimated to occur in mid-2016. The incremental earnings from this new facility are not expected to fully offset the reduction in our ownership percentage. As a result, the annualized impact of this change is estimated to reduce our equity earnings from National Methanol by around 25% to 30%.

As you know, earnings from National Methanol are correlated to Brent crude oil prices. Our forecast assumes low year-over-year volatility in Brent crude oil prices through 2016. Our Other category is expected to incur higher interest expense as we continue to finance at the holding company level, and our effective tax rate is expected to trend higher.

We have also included up to 1% of additional growth from capital redeployment and incremental investment opportunities. Redeployment of proceeds from our Midwest generation process is expected to be accretive. We also continue to develop additional growth opportunities such as the NCEMPA transaction, which I will discuss in a moment. Taken as a whole, our plan results in solid earnings-per-share growth within our long-term 4% to 6% growth objectives.

Now, let me move to our efforts to maintain productivity and efficiency in our cost structure. We've made tremendous progress in achieving cost savings from the merger. Our rigorous process has given us confidence that we can continue to drive operational efficiencies throughout the organization. In generation and power delivery to additional savings in the corporate center, we are applying lessons learned from our merger integration initiatives and driving further efficiencies from our recent system consolidation efforts.

We have initiated efforts to consolidate our enterprise and asset management and work management systems into a single platform and process, underpinning efficiencies in many of our functional departments. As a result, we are targeting flat O&M through 2016.

Our overall growth is supported by investments in our businesses. In 2013, we spent approximately $5.6 billion, of which approximately 90% was in our regulated utilities. As outlined on slide 17, from 2014 to 2016, we are forecasting total CapEx investments of between $20 billion and $22 billion. Consistent with our business mix, about 85%, or approximately $17 billion of this CapEx is expected to be deployed in our regulated utilities, an annual average of around $6 billion.

Let me provide a further breakdown of our regulated utilities capital investments over the three-year period from 2014 to 2016. Over the three-year period, we expect to spend $3.4 billion on new generation growth projects, principally in the Carolinas and Florida. These investments also include nuclear performance improvements and compliance with NRC regulations.

First, let's discuss the Carolinas. We have a Certificate of Public Convenience and Necessity request pending with the South Carolina Commission related to the 750 megawatt Lee combined-cycle natural gas plant. Hearings have been held and we expect a Commission decision by the end of the second quarter. If approved, the plant could be in service as early as mid-2017. This project will accrue non-cash AFUDC earnings during the construction period.

We also continue to make investments to improve the performance of our nuclear fleet in the Carolinas and to comply with the NRC's Fukushima requirements. Further, we are evaluating regulated solar investment opportunities to meet our renewable portfolio standard requirements in North Carolina, as well as a growing desire for renewable generation sources. We recently issued an RFP for up to 300 megawatts of solar in North Carolina, targeted to be in service by the end of 2015. We'll evaluate both purchased power and ownership options as part of the RFP process.

Moving next to Florida, our recent settlement agreement gives us the ability to invest in additional peaking and base load generating capacity. Once in service, we were able to recover prudently incurred investments related to this generation without the need to file a general base rate case. We continue to evaluate options related to the need for up to an additional 1150 megawatts of capacity by 2017. This could consist of a mixture of self build, acquisition, upgrades, or PPAs.

The amount of additional capacity is likely to be reduced if we are able to obtain approval to burn nontraditional coal at the Crystal River 1 and 2 units through 2018. We expect to make filings with the Florida Commission by mid-2014, outlining the most cost-effective options for our customers.

We also issued an RFP to add approximately 1640 megawatts of combined-cycle gas-fired base load generation in Florida in 2018. We are evaluating proposals submitted from other potential power providers and also submitted our own self build option. We expect to finalize an announcement of the most cost-effective options for our Florida customers by late summer of this year. We are also assessing transmission and distribution investments to increase the reliability of our systems.

In Indiana, we are continuing to develop a plan under Senate Bill 560 that could potentially be filed with the Indiana Commission later this year. Items under consideration include investments to improve our reliability to our customers, as well as to improve the type and timing of information we can provide to them. While our analysis is still ongoing, we expect potential investments of between $1 billion to $2 billion over seven years. We will provide further updates on the scope of our plan when it has been finalized. Senate Bill 560 allows for recovery of qualified transmission distribution projects through a rider mechanism.

Our plan also includes T&D investments in Ohio, which are subject to rider recovery, as well as further consolidation and investments to upgrade certain control centers throughout all of our service territories.

Next, let me review our environmental compliance expenditures. Over the past decade, our legacy companies spent approximately $7 billion investing in scrubbers and SCRs. Based on our current assumptions on the timing of final regulations and how the EPA will adopt rules around air, water, and residual waste, we currently estimate we will spend between $4.5 billion and $5.5 billion over the next 10 years, with $900 million expected to be spent in the 2014 to 2016 time frame.

Approximately 85% of our expected environmental compliance investments will be in the Carolinas and Indiana. Both of these jurisdictions have a strong track record of allowing utilities to recover costs related to environmental compliance investments. We have environmental tracking mechanisms in Indiana and Florida.

In 2014 to 2016, we will spend $1.6 billion on nuclear fuel. The cost of this recovery is utilized through our fuel clauses. Another $1.4 billion is expected to be spent to expand our distribution system as we connect additional customers and increase our revenue base. Finally, we will invest and maintain the reliability and performance of our system. From 2014 to 2016, we expect to spend approximately $9 billion on maintenance of our system, principally offsetting our annual depreciation.

In our nonregulated businesses, we expect to spend approximately $1.5 billion over the three-year period from 2014 to 2016, an average of around $500 million. This consists of a growth capital of $1.2 billion for our renewables business, as well as an additional $300 million in maintenance capital for our Midwest generation and international business. Our range includes the level of discretionary capital, up to $2 billion from 2014 to 2016, giving us flexibility to pursue opportunities for incremental growth projects in both our regulated and nonregulated business.

In a moment, I will discuss some potential opportunities we are evaluating. In 2016, we began construction of new generation plants to be in service in 2017 and 2018, principally in the Carolinas and Florida. This will cause the range of our CapEx investments to accelerate in 2016 and beyond.

Next, I'll provide details on incremental investment projects I mentioned previously. First, as we announced earlier this month, we have been in exclusive discussions with the North Carolina Eastern Municipal Power Agency regarding the potential to purchase their minority ownership interest in certain existing Duke Energy Progress plants, a total of 700 megawatts of coal and nuclear generation. If an agreement is reached, there are several approvals we would need to obtain for this transaction.

Potential next steps would include a filing with the FERC, a request for the NRC to approve the transfer of the nuclear licenses, DOJ antitrust approval, as well as approvals from the Carolinas Commissions. It is too early to speculate on the timing needed to complete the transaction as negotiations are still ongoing. If we are able to reach an agreement, we would enter into a long-term wholesale power contract with NCEMPA. We will keep you updated.

An additional growth opportunity is the potential for gas infrastructure investments across our regulated jurisdictions. We were reminded of the importance of robust gas infrastructure during the recent extreme cold January weather. We intend to explore the viability of additional pipeline capacity into various jurisdictions to expand the infrastructure necessary to continue to support an expanding gas-fired generation fleet.

We also have the potential to invest in additional nonregulated renewable projects above our annual capital budget of approximately $400 million. Additionally, we continue to evaluate growth investment opportunities in projects at International that meet our risk-adjusted return expectations.

Next, let me discuss the dividend payment to our shareholders, the cornerstone of our investment value proposition. As you can see on slide 19, we have consistently increased the dividend an average of 2% annually over the last several years. The Board ultimately has final say about the dividend. We believe the Board has the flexibility to increase the growth in the dividend to be more consistent with our earnings-per-share growth once we have achieved our targeted payout ratio of 65% to 70%. Based on the midpoint of our 2014 guidance range, we expect our payout ratio this year to be at the top end of the range, at around 70%.

I will close on slide 20 with a discussion of our financial objectives. We have a strong track record of meeting these objectives. In addition to being well-positioned to achieve our 2014 EPS guidance range, we have a solid plan to deliver longer-term EPS growth of 4% to 6% through 2016. While growing earnings, we will continue to support the dividend payment to shareholders while maintaining a strong balance sheet.

In summary, I am very pleased with our financial performance for the year and how we are positioned for the future. We will maintain our strong growth platform through investment opportunities in both our regulated utilities and our commercial businesses. We will continue to focus on providing our customers with low-cost and reliable service while we drive efficiencies across the entire business.

Now, I will turn the call back over to Lynn.

Thank you, Steve. Let me briefly close with our priorities for 2014 and beyond, as outlined on slide 21. Simply stated, we will focus on achieving our financial objectives, including our earnings per share guidance range for 2014, as well as growing the dividend and maintaining a strong balance sheet.

We will also focus on driving further productivity in our businesses and deploying capital for the benefit of our customers and shareholders. As I mentioned, we will also turn our attention to enhance value from our commercial businesses, including advancing our process to exit the Midwest generation business. We will maintain our focus on strong outreach to our important state and federal stakeholders, as overall industry trends and regulations continue to evolve.

Duke Energy is a low risk, long-term holding with an excellent track record of performance. I am honored to lead this Company and work with an extremely talented team. I am very pleased with what we have accomplished in 2013 and our platform gives us many opportunities to grow the Company and create value for our customers, investors, and communities.

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

(Operator Instructions). Shahr Pourreza, Citigroup.

You sort of reiterated your EPS growth trajectory of 4% to 6% off the 2013. Looking at slide 17, it looks like your CapEx profile looks flat beyond 2016. Is that a placeholder, and how should we think about the EPS growth trajectory if you were to exit the Ohio business, given the fact it could be accretive?

I think our CapEx profile does grow beyond 2016. I think back in our appendices we showed that our rate base growth moves in the range of 6% beyond 2016. As we ramp up, the Lee combined-cycle plants, the potential for the Florida combined cycle, and also we will see a change in 2016 and beyond as we become a significant taxpayer and a decrease in deferred taxes. And that will put an upward push on our rate base as well, Shahr. So I think we do have growth in earnings base.

Got you. Very helpful. And just when you think about potential uses of cash as you exit Ohio generation, is there any areas that we should be not thinking about as far as the source of cash? Or I think, Lynn, you were maybe potentially quoted in media as a source of cash could be buybacks. Is there anything we should focus on or what we could rule out?

You know, Shahr, we haven't made a decision on use of proceeds. We'd like this process to mature over the course of 2014, and we will look at incremental investment opportunities that may be ripe and what I would also say is we would not rule out a share buyback. But those decisions will be made down the road as we complete the process.

Okay, appreciate it. Thank you very much.

Dan Eggers, Credit Suisse.

I'm glad you guys feel like you had a determination on commercial operations. Can you just clarify when that earnings contribution is included in guidance, for both the 2014 number and the growth rate? And then if it comes out, what are you using for substitution to help sustain the growth rate beyond 2014?

You know, Dan, the earnings contributions of the Midwest generation is in 2014. And then as we think about the buildup for growth over the 2014 to 2016 period, we believe that redeployment of the proceeds will be accretive and be a strong contributor to the 4% to 6% growth rate.

So you have a placeholder beyond 2014 for using some assumption of cash for debt paydown or some other reinvestment to support the growth rate? Is that the right way to think that it?

That is correct.

That's correct.

And then on the international, if I look at the contribution of growth rate drivers by business line out through 2016, international looks like you had it at a zero contribution to the growth rate, which was kind of treading water over those years. How does that slow -- the flat-looking outlook affect the strategic review you guys are going through right now?

Dan, I would say it's been a catalyst for the review. We looked at a strategic review of international probably five or six years ago. We think it's appropriate to do so again. We do this periodically for all of our businesses. We are pleased with the international business, the contribution that they've made over time, but we'd like to explore positioning for better growth and for optimization of cash flow, and so that will be our focus in 2014.

Does the impairment you guys took on commercial or the one you will take, given that extra cash surplus, does that make it easier to think about monetizing international because you have a better offset to maybe any repatriation cash you'd have to deal with?

Dan, I wouldn't jump to monetization of international. What I would suggest is let us work through the process and evaluate a range of options, and as we complete our review, we'll be in a position to talk further about it.

Okay, great. Thank you, guys.

Jonathan Arnold, Deutsche Bank.

A couple of quick questions just to clarify on things that you've already just answered, I'm afraid. On the Midwest, and you say the use of proceeds will be accretive, is that a statement net of losing the earnings of the business and the --?

Yes.

Okay. So it's in an aggregate state? It's not just that you'll have an accretive offset?

That's right.

That's correct.

Okay, thank you. Sorry to go back to that. And then on the international, you talked about a 6% CAGR, I think somewhere in the slides, for the pricing assumption in Brazil. Is that something you have a clear line of sight on currently? How much of that is already priced and how much of that is an assumption?

We have pretty good line of sight to that, Jonathan. Our revenue pricing in our current tracks in Brazil is tagged to inflation indices that have been pretty consistent. And they're on the lagging indices, so we've already seen some of those metrics come through. And the forecast for inflation in Brazil and so forth are pretty stable, and so we feel pretty good about those pricing metrics.

So that's not -- you don't have re-contracting embedded in that assumption? That's just the current contracts inflate?

That's correct.

Great. Thank you, guys.

Julien Dumoulin-Smith, UBS Investments.

So, a quick question following up on the international strategic review. Could you elaborate perhaps on what those options are more specifically?

You know, Julien, I think it's premature to talk about the range of options. What I would say is just emphasizing we'll be looking at ways to position the business to grow and also ways to further optimize cash flow. The fact that we were able to identify an opportunity to bring $750 million home I think is a good indication of work that we put underway in 2013. And we'll just continue that strategic focus in 2014. As we have more information, we'll of course share it.

And, just to be clear, anything you would do would need to be accretive?

I think that's a good starting point.

All right. Just to be clear. And then perhaps looking at the earned ROE assumption, in the buildup if you will of the 4% to 6%, you have a regulatory lag/depreciation of minus 3%. What kind of earned ROE degradation or what have you are you assuming as you think about the near year period -- the three year?

We project that we're going to be earning very close to our allowed returns in all of our jurisdictions. You do have regulatory lag, but you've also got new investments that are going into riders and accruing AFUDC and earnings and so forth. Additionally, one of the big key elements that gets us through a rate freeze period is being able to eliminate rate lag due to O&M increases. Keeping O&M flat is very significant here. It should help us to earn our allowed returns.

And then, lastly, quick question on the 2014 assumption on our guidance, there's a big Other jump from minus 128 to minus 215. Could you talk about that quickly?

Yes. In the Other area, we're looking at two things that occur there. You've got HoldCo interest expense, which goes up as you issue HoldCo debt to fund some of the growth in the business. And then we do expect our effective tax rate to jump and increased by roughly 1%, and the effective tax rate goes up for a couple of reasons. One is that as you move forward, the progress entity has less permanent differences, less tax benefits. So when it's mixed into the Duke entity as a whole, which has renewables and international, it pushes the effective tax rate up a bit. Also, we are seeing that we have less AFUDC equity impacts in the tax rate, so that drives the effective tax rate up a bit as well.

Great. Thank you.

Brian Chin, Merrill Lynch.

For your comments on slide 18 on transmission and gas infrastructure, could you talk a little bit more about what opportunities might manifest themselves as you complete your evaluations?

Brian, this is an early-stage evaluation of infrastructure in the Southeast. As we continue to look at adding gas-fired generation in the Carolinas in particular, we have some dependency here on a pipeline infrastructure that we'd like to explore other options. And so this is something that is on our radar screen for strategic growth and objectives that we'd like to achieve. We also think it's important for reliability for customers, and so we'll be exploring that over the next year or two to see if an investment makes sense.

Should we be thinking about that in the terms of gas or pipeline investments potentially that connect to your gas-fired generation? Is that the primary thrust of where that thought process is going?

Yes.

Great. And then just one other question on this slide. For commercial solar and your wind assets in general, just how do you think about the opportunity to construct a YieldCo like some of your peers?

We've looked at YieldCos, Brian, and we'll continue to keep an eye on those types of financing vehicles. But a couple of things to keep in mind on a YieldCo that we're looking at. One is that we trailed as a -- we trade as a YieldCo already, and so isolating assets there may not have as much incremental benefit for our shareholders. Another thing you have to keep an eye on with YieldCos is they require very disciplined investment profile. You typically have to match up the investments with tax benefits that roll off under accelerated depreciation. And it requires quite a disciplined investment in capital and that flexibility in our capital planning may be a hurdle in setting up a YieldCo.

Great. Thank you very much.

Hugh Wynne, Sanford Bernstein.

My question goes to the ash pond cleanup issue. You've been under some -- you've been fighting some legal suits in the Carolinas regarding supposed groundwater contamination, if I remember correctly. And now we have the Dan River break, and at the end of this year I think EPA will come out with its coal ash regulations. What is the long-term thinking regarding how you're going to handle that? Are those costs included in your environmental CapEx? And what would be the prospects for recovery?

Let me break that question down. I'll speak first of all about Dan River. We have been very focused over the last two weeks for the 24 by 7 operation to put a permanent solution in place and to begin remediation. We will take the learnings from this experience and look for ways that we can improve overall management of our ash ponds and we are very focused on ensuring the integrity of our basins throughout our system. And so that's efforts that will continue.

If I transition to the broader level about ash pond remediation and the implications of the Coal Combustion Residuals Rule, we do expect those rules by the end of this year. And when Steve talked about the $4.5 billion to $5.5 billion, that does include ash pond closures. It also includes conversion to dry handling, and so those estimates will continue to be updated and evolve as those regulations are finalized.

Good. Okay. And is recovery ordinarily available to you in the states where the plants are located?

Yes, yes. We've had a good history of environmental recovery and I think 85% of our environmental costs are in Indiana and the Carolinas. And we have demonstrated recovery of environmental costs in both of those jurisdictions.

Great. Just a quick follow-up on an earlier question regarding the Other segment. The significant decline in expense in that segment relative to expectations -- I think you were expecting something like -- was it $208 million? And you ended up incurring only -- you are expecting $205 million and you ended up incurring only $128 million. Is that also attributable to a favorable change in the effective tax rate or were there other factors at play?

Income taxes were a large portion of that. We found some state optimization tax benefit opportunities that we took advantage of. But also there were some lower costs in our captive insurance area as well.

Meaning that the losses from your insurance policies were not as high as you had anticipated?

That's correct.

Yes, okay. Thank you very much.

Michael Lapides, Goldman Sachs.

Good morning, you all, and again, congratulations, guys.

Thank you.

I want to ask about the dividend and dividend growth. At what point do you think you'll be at a stage where dividend growth is within the same range or close to earnings growth? And is there ever a stage coming for Duke where dividend growth is faster than earnings growth?

I'll take the first part of that question, Michael, because we're trending to 70% in 2014. And so we will look very closely at increasing the level of the dividends. Working with the Board, of course, because it is ultimately their decision. But our aspiration is to grow the dividend over time consistent with earnings growth.

I think the latter part of your question is probably something that's a few years out. If we look at the way the macrotrends in the business continue to evolve. So I think our objective is to always put together a combination of earnings growth and dividend that's attractive to our shareholders, and that objective won't change.

Okay. And then I had an environmental question. There's obviously lots of talk about potential carbon rules coming out this summer or a little later, but could talk a little bit about what's in your expectations in terms of what the rules for both coal ash and 316(b) could look like?

We have some specifics, and Keith Trent is here, Michael. Let me direct the question to Keith to give you a little bit of visibility and what's in our plans for the next three years, and then he can talk beyond that.

Sure. Michael, with respect to coal ash, we do expect that it would be designated as nonhazardous, so that's the general assumption that we're working with. In terms of specific investments, we have a very detailed plan. What I would tell you is the four largest categories of spend -- one is on SGRs at Cayuga, and then we have precipitator refurbishments at six plants.

We have dry ash conversion at multiple plants and then also ash pond closures. So those are the four biggest conversions -- biggest spends that we have in this category. But, again, in terms of CCR, we are expecting nonhazardous.

Got it. Last item, just a cash flow related question. What do you see? I noticed the guidance for commercial power and the commercial businesses, it seems like it's being driven largely by tax benefit. Am I interpreting that correctly? I think it's one of the slides in the appendix where you assume a 40% to 50% -- 50% to 60% tax benefit at that business.

At the renewables business, a great deal of the economics are driven by tax benefits, that's correct, Michael.

So is the assumption then the actual EBITDA of that business -- combined with Commercial Power is pretty low, but for the renewable business, the tax benefits drive the uptake in earnings power from the business?

That's correct, Michael.

Okay. Thanks, guys. Much appreciated.

Kit Konolige, BGC.

So, to get back for a second to the Midwest generation, can you elaborate a little bit on the discussion of your expectation for taking the charge on that business? If I wrote it down correctly, you said that you expected a charge of $1 billion to $2 billion in 2014, which, as I understood it, would be the difference between your projected fair market value versus the book value?

That's correct. That's correct, Kit.

And, Steve, what's the book value currently on that?

The net book value of the property, plant, and equipment net of accumulated depreciation is in the ballpark of $3.5 billion. There will be other items that could come into play in this calculation: inventories, deferred taxes, some of those kind of things. I don't want to be over-precise, but $3.5 billion is the property, plant, and equipment.

And do you -- you said you don't expect any transaction to close in 2014?

That's correct.

So can we understand from that, that the sale process might take something like, what? Six months or something like that?

Kit, this is Lynn. I think given the fact that our announcement was yesterday and we're getting advisors in place, I think we'll be in a position to give you more clarity on timing as we move into the first quarter call. But based on our present expectations, we think a 12 month period is probably a reasonable planning assumption.

That 12-month period, Lynn, from now until closing or now until an announcement of a sale?

Now until closing.

Okay, great. Okay, great. That's my questions. Thank you.

That concludes today's question-and-answer session. Mr. Currens, at this time, I will turn the conference back over to you for any additional or closing remarks.

Thank you, and thank you for your interest in Duke Energy. We look forward to seeing many of you in the weeks and months ahead. So thanks again.

This now concludes the presentation. Thank you for your participation.