William Currens – VP, IR Lynn Good – President and CEO Steven Young – EVP and CFO.
Julien Dumoulin Smith – UBS Greg Gordon – ISI Group Stephen Byrd – Morgan Stanley Jonathan Arnold – Deutsche Bank Michael Lapides – Goldman Sachs Hugh Wynne – Sanford Bernstein Ali Agha – SunTrust Robinson Humphrey Andy Levi – Avon Capital Advisors Greg Gordon – Evercore ISI.
Good day, and welcome to the Duke Energy’s Third Quarterly Earnings Conference Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Bill Currens. Please go ahead..
Thank you, Tracy. Good morning, everyone, and 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 2 presents the Safe Harbor statement which accompanies our presentation materials.
A reconciliation of non-GAAP financial measures can be found on duke-energy.com and in today’s materials. Please note that the appendix to today’s presentation includes supplemental information and additional disclosures to help you analyze the company’s performance.
Leading our call today is Lynn Good, President and CEO, along with Steve Young, Executive Vice President and Chief Financial Officer. After our prepared we will take your questions. Other members of the executive team will be available during this portion of the call. With that, I’ll turn the call over to Lynn..
Good morning, everyone and thanks for joining us. Earlier today, we released third quarter adjusted earnings results of $1.40 per share. These results are 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, and we remain on track to achieve a revised 2014 adjusted EPS guidance range of $4.50 per share to $4.65 per share. Steve will provide more about the financials in a moment. Let me spend a few minutes on operational performance and progress and 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 80% capacity factor at eight of our nine combined cycle plans in the Carolinas and Florida. We also continued to deliver significant benefit from the 2012 merger with Progress Energy.
Through the third quarter, we generated about $360 million of cumulative fuel and joint dispatch savings for our Carolinas customers. We are on track to achieve to 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 4, 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 40% ownership interest in this project through our commercial business. The pipeline has a total construction cost estimates of between $4.5 billion 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 a 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 regions voicing support for the pipeline. An independent study estimates that the project can generate a total of $2.7 billion, an economic impact by 2019, supporting over17,000 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 the 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’s cities to reduce their customers’ rate 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-requirement 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 increasingly diverse generation portfolio, as well as providing a solid foundation for our long-term earnings growth rate of 4% to 6%.
Now let me turn to Slide 5, which summarizes our new generation projects in the Carolinas and Florida. Overall, these projects will replace generating capacity that has or will be retired. And will help us meet the long-term load growth in our service territory.
These projects represent around 3,000 megawatts of capacity and almost $3 billion of investments through 2018..
Site certification approval for Citrus County is expected in late 2015. We continued 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’re 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 6, I’ll provide an update on coal ash management activities during the third quarter. In August the North Carolina legislation 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 the nine member of 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 wash basins as either high, intermediate or low risk by the end of 2015.
The law designates the ash basins of 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 NC DENR 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 the new centralized internal organization to manage all coal combustion products.
We also announced the formation of the National Coal 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 base enclosure.
Before, updating you on Edwardsport, let me provide some comments, on the EPA’s proposed rule for regulating carbon-dioxide emission 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 rule making as it evolves over the coming months. Next, let’s turn to Slide 7, in our Edwardsport plant in Indiana, which achieved commercial and 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 of the contract with the GE, we are finalizing the plants ramp rate performance, which we expect to complete later this year.
Planned 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 to begin 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 IGCC-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 semi-annual writer filings. Any Edwardsport IGCC-related fuel costs are reviewed in connection with the quarterly fuel costs proceeding.
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 8, 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. The 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 in our progress in the coming months. Overall, in looking back at everything we have accomplished so far this year, I am 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..
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; and finally, I will close with our financial objectives including the status of our 2014 adjusted earnings guidance range.
Let’s start with the major earnings drivers for the quarter, as outlined on Slide 9. Our quarterly adjusted diluted EPS $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 a $1.80 during the quarter compared to $1.42 last year.
Reported results include an approximate $475 million pre-tax reversal of a first quarter impairment charge related to the sale of our Midwest generation business. This impairment reversal is 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 normal 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 and amortization expense and interest expense primarily associated with the new assets in the 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 purchased power cost in Brazil resulting from core 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 draught Brazil’s regulatory authorities are dispatching thermal generation at full capacity. In anticipation of below normal rainfall and challenging hydrological conditions we’ve 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 up $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 low 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 remained 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 sub-sectors. 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 effect 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 multi-family housing. Overall, we continue to be cautiously optimistic about the future based upon the broad trends in the economy.
The 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-foreign 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 but 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 those are regulatory [assets] for retire 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 sites specific risk classifications and closure methodologies approved by Dinah 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’ve 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 is 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 reported 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 the 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 the 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 average cost levelization in late 2013. You might recall we realized $0.11 of favorable earnings per share in 2013 mostly in the fourth quarter as well implemented this accounting treatment.
This year we expect about $0.05 to $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 condition in Brazil and unfavorable foreign currency exchange rates. Finally we expect a higher effective tax rate in the fourth quarter than the 31% we recognize last year.
We anticipate the full year adjusted effective tax rate of 32% to 33%. Slide 14 highlights the building blocks of our long term adjusted earnings growth objectives of between 4% to 6% through 2016. The left side of these slides 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 investment and assumes modest retail and wholesale loan 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 [low] growth in excess of 0.5% and optimization of our commercial portfolio give us confidence in our ability to achieve our targeted 4% to 6% adjusted earnings per share growth objective through 2016. Slide 15 outlines our financial objectives for 2014 and beyond.
These objectives have remained consistent overtime and we have an established track record in 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% to 70% this year providing additional flexibility going forward.
Our balance sheet and credit ratings remain strong allowing us to invest in our business without the need for new equity issuances through 2016. As we normally do in February we will provide our updated financial plans to 2015 and beyond. Now I will 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 are laying a strong groundwork and foundation for the future. Now we welcome your questions..
(Operator Instructions). We’ll go first to Julien Dumoulin Smith from UBS..
Hi, Good morning..
Hi, good morning..
Good morning, Julien..
Thanks, first question on the ARO and the overall CapEx OpEx composition of potential spend with the coal ash, could you just give a little bit of flavor around how much this could turn into an earnings opportunity in whatever parameters you can describe?.
Well, we have recorded at this point the ARO liability and while we have not begun to spend any significant funds we will begin spending that money in 2015 as we identify four plans that we are going 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 Dinah and the coal ash commission regarding many of the sites. Ultimately the cost recovery aspect has been kicked to the Utilities Commission. We have made no application for recovery because we haven’t incurred any cost.
So ultimately the dispositions of that into customer rates is yet to be decided..
Fair enough.
Then turning to the international business I’d be curious where do you stand in the strategic review and specifically does the latest hydrological developments in Brazil impacts that review in any sense and really what’s on the table at this point as the process continues?.
So we are continuing to review all options and had set an internal timeline of late ‘14 early ‘15 for our review and we are on pace for that Julien.
I wouldn’t say specifically that the hydrology in the year of 2014 is impacting that review, but certainly hydrologic risk, regulatory risk, market risk and opportunities are part of what we are assessing.
So when we reach any important milestone in that review we will certainly update you but at this point Julien I don’t have anything further to discuss..
Great and then if you will, just turning to Florida quickly, [Necter] 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 states that we are focused as we remarked in our comments on combined cycle upgrades and adding additional capacity.
We certainly believe that solar represents an opportunity for the State of Florida as it makes sense for public policy and requirements of our customers and we will pursue that at the right time but I would say our focus at this point is on the gas capacity..
Great, well thank you very much..
Thank you..
Thank you..
We will take our next question from Greg Gordon from Evercore ISI..
Good morning..
Good morning, Greg..
Good 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 f the commission were to decide that you weren’t performing up to their expectations?.
Greg, I think, we can take you offline on the specific dollars in each of the filings and the team would be ready to do that as soon as the call over. Let me just give you some color generally about the proceeding. So the commission would be taking up IGCC-12 and 13 in February. They will 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 degree normal in Indiana we would expect the commission to be reviewing operating activities during that period.
So I think between the IGCC filing as well as fuel there will be a comprehensive review of operations and our focus has been on continuing to improve performance and I think the demonstrated results that we shared on the call with 90% availability for the gas supplier in July and August and the overall capacity factors demonstrate that we’re moving in the right direction..
Thanks I will get them offline. That’s all I got, thanks..
Thank you..
And we will go next to Steven Byrd from Morgan Stanley..
Good morning..
Good morning, Steve..
I wanted to discuss your tax position and your Latin American assets.
Apparently we don’t know where you’ll ultimately come out in terms of your strategic review but if you were to think about selling assets and repatriating the money back to the US, can you discuss your tax position at a high level, I know you have a large US 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. We’ve got about $1.6 million 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 to $350 million. We have not accrued any U.S.
taxes on the international operations, but if we said all the past earnings were 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 tax payer until 2016 or 2017. So the actual cash outlays related to income taxes on our international operations wouldn’t be made for a few years down the road..
Okay.
So you do essentially, Steve, get some benefit from that tax loss position that you had when you think about bringing capital back, but there is still an accrual, there is still some degree of cash costs when you bring that money back?.
Yes, that’s correct. We have both the accrual to catch-up taxes on all the previous earnings, and then the actual cash outlays would be a bit later..
And so the GAAP accounting or the generally accepted accounting principles require recognition of 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.
But if you were to try to bring the 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, but I believe there would be some tax shield there for a period of time, couple of years perhaps..
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 number of other moving pieces that could impact that assessment as well, that you may want to consider..
That’s a good point. 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, it’s sort of – is the cost of the pipeline kind of in your mind, the sum cost, and then you pay for billing Henry Hub rates, or does that transport need to factor in, and therefore you would be paying a lower price for gas essentially than what we might see in the Gulf of Mexico?.
So I think the combination of things that you’re talking about are still under evaluation on specifics, Stephen, so we don’t have a specific price of natural gas that we’ve locked into in Marcellus.
We will have a price that’s implying the transport as we look at making that multiyear commitment for the utilities, but as we stand back and look at the diversity of supply, look at the pricing out of Marcellus, look at the pricing of this additional transport facility into the Carolinas, we think there is a very compelling business case for our customers to have access to low-price diverse sources of gas.
And so that’s exactly the business case that we believe excess 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..
Yes, good morning..
Good morning..
Good morning, Jonathan..
Just on last – this might be – I might be reading too much into this, but last slide – last quarter on your 4% to 6% growth build-up slide, you said finalizing international strategic review and now you just 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 is the way do you communicating anything that?.
I think you’re reading more into it. And we should use you as part of finalizing our slide, 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.
And I would love to tell you that analyzing international tax is something that can be done quickly, but there are a variety of complexities and analysis. We’re taking our time. This is an important part of our business that has contributed well for a long period.
And so when we have an update on that, we will certainly share it but we’re on target to complete our work late ‘14, early 2015..
So you’re fairly confident then that you’ll know the outcome on that by the time you give your ‘15 outlook, I guess with the year-end call?.
So that’s certainly our target, Jonathan. And just to step back for a moment, when we undertook this review, we were looking at several dimensions.
One dimension is, how do we optimize cash? We’ve had opportunities to bring home cash in a couple of large transactions over the last several years but we would love to solve cash in a way that was more predictable and more consistent with funding in the dividend.
And then secondly, we’re evaluating is there a way to improve the growth profile of the business in light of what we see as near-term to mid-term headwinds, currency, pricing, etcetera.
So our intent as we finish, our review would be to share our perspectives on both of those objectives, and the work we’ve completed that could accomplished some or all of this objectives as we complete our work..
Okay, thank you. And then just somewhat similar question I’m afraid, but when you first announced the Midwest generation sale, you sounded more robust about the idea that it would be accretive.
Now you are saying that it depends on the timing and the ultimate use of proceeds [indiscernible] 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 ‘14. We think it’s probably more early ‘15. And so we’re just kind of talking about that timing as we share that perspective..
But ultimately we do see this as an accretive transaction certainly..
All right, great. Well, thank you very much..
Thanks so much..
We’ll take our next question from Michael Lapides from Goldman Sachs..
Hi guys. Just curious, did anything change in terms of your thought process regarding rate case timelines, if any, in Carolinas.
The only reason why I asked 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’re looking at our cost structure as we move forward. Typically when you try to play on rate case as I think about data points on rate cases, you look at when a base load plant moves into service, because your cost structure changes at that time.
Lee has been scheduled for late ‘17 or during 2018 for commercial operation for the Carolinas. So that might be a point that you’d look at there. Shortly following that or plant additions for DE progress as well. So that’s kind of your starting point. But we’re looking at our cost structure between now and then, in light of other factors.
And that could compel us to move earlier or it could push us back later if other events occur..
And can you give us – change in topics a little bit, when thinking about the Indiana smart grid rollout, what the annual – kind of the average annual revenue increase tied to that would be?.
So it’s about less than 1% to around 1%, lower for industrial. The industrial class will not participate in all of investment. And we’re targeting somewhere around $250 million of spending a year around over the seven-year period..
Got it. Thank you, Lynn. Thanks Steve. Much appreciate it..
Thanks so much..
We will go next to Hugh Wynne from Sanford Bernstein..
Thank you. I have a couple of questions. My question goes to Slide 14, where you outlined your sort of 4% to 6% EPS growth trajectory and the drivers that will get you there.
4% growth over ‘15 and ‘16 in earnings is kind of an 8% increase against a 1% increase in retail load over that period, 6% growth over ‘15, ‘16 would be a 12% increase in earnings against maybe slightly more than 1% growth in retail load.
I was just wondering, if you could help me understand, how you’re going to close that gap in a way that’s tolerable to rate payers.
I understand that 4% range we’re hoping to do with wholesale growth and cost control and the 7% range we’re hoping to do it with accretive acquisitions, but I wonder if you just might give more color on how you close that gap? And secondly, what the long-term implications for EPS growth of 5% load growth are beyond 2016?.
Yes so – and 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 to Senate Bill 560 during the three to five year period we will start to produce some earnings as well.
So we feel confident about the earnings growth rate on a longer term basis. When you look year-to-year, some of the drivers to think about, you’ve got weather normalized customer growth and that’s modestly forecasted at 1%. We also have wholesale sales growth 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 approve 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.
So 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 [indiscernible] in Brazil.
What are the earnings implications of that beyond the quarter? Are you expecting that a year of depressed earnings, or will it take even longer to reestablish a reservoir from Brazil?.
I think when you’re thinking about Brazil hydrology, one of the – probably the key factor to think about is the upcoming rainy season, which typically runs November/December through March/April. And I think the results of that rainy season will be critical to decisions made in 2015.
I wouldn’t try to guess at what that rainy season would look like, but I don’t think that you’d see any rationing occur unless there was a third consecutive core rainy season, and it’s the force rationing that really has an impact on earnings..
Great. Thanks a lot..
Thank you..
(Operator Instructions) We’ll go next to Ali Agha from SunTrust..
Thank you. Good morning..
Good morning..
Good morning..
Steve, I wanted to be clear on the growth rate targets you had talked about, the 4% to 6%. So as you pointed out, some of your growth initiatives like the pipelines and the additional buyback of the assets from the municipalities etcetera, those are going to start really contributing to you more in the timeframe beyond ‘16.
So if I am hearing you right, should we assume that, that contribution keeps you on the 4% to 6% growth rate beyond ‘16, or should we think of those actually taking you above the range? How should we think about these growth initiatives relative to the 4% to 6%?.
Yes, we will be rolling out beyond ‘16 in February, as we’ve traditionally done. And that’s the point which we’ll be discussing the longer term projections of earnings, but right now we feel comfortable through ‘16 with the 4% to 6% earnings growth rate..
Okay.
But in a high-level sense, is it fair to say that this keeps you on-track, that kind of run rate?.
Ali, I’ll jump in. 4% to 6% is our long-term growth aspiration. We spend a lot of time in 2014 laying the foundation and groundwork for that, by putting projects in place that will give us an opportunity to deploy the capital necessary to achieve that growth rate. And so we are on track to do that.
We think we’ve demonstrated that with tangible projects that will deliver earnings that are consistent with what we’re trying to accomplish, consistent with a strong dividend paying company. So we’ll, as Steve said, update more specifics in February, but we believe that we are putting the pieces in place to deliver a strong growth rate..
Okay. And then Lynn, can you remind us, the grand jury investigation around the coal ash spill.
What’s the status of that? Is that still ongoing, or what’s happening there?.
So the litigation continues Ali, and I can’t discuss any specifics on those matters, but 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, we’d provide updates when they are milestones met..
Okay. And my last question, as you talked about using the proceeds from the Midwest sales, one of the potentials for that is share buybacks, but if I put that in the context of these big mega projects, the pipeline and the acquisitions coming up, and put them in the equation, Steve you said, no equity issuance through ‘16.
Should we think of this as no equity issuance even beyond ‘16 when some of this big capital spend is going to be used on that ‘17, ‘18 period?.
Well, again right now I can’t project beyond ‘16. We’ll be finalizing our plans for beyond ‘16 and discuss that in February. But we’ll be looking at our various spend for coal ash, other investments such as the pipeline in NCEMPA as we make those decisions, and we’ll be firming up beyond ‘16 in February for you..
Okay, but conceptually you’re okay with buying back stock now if you think that makes sense, but then issuing equity in a year or 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. And our objective is to optimize proceeds and investments in the way that creates the greatest value for shareholders.
So I would say all options are on the table at this point and we’ll share more specifics as we move forward..
Fair enough. Thank you..
Thank you..
We’ll go next to Andy Levi from Avon Capital Advisors..
Hi guys, good morning. Just a very, very quick question. Just on the international, I guess with – again oil is up actually today, but with oil down so much, I just remember from your initial guidance that you gave back in February.
You had a sensitivity on Brent crude, I think it was $10 movement, it’s like $0.02, and never really paid a lot of attention to that. So as you get into next year, obviously we don’t know where Brent crude is going to be, but I guess it’s down about $30, $35 from the beginning of the year.
How should we think about that for National Methanol?.
Well, the sensitivity that we gave, Andy, is correct. About a $10 movement is $0.02 and that’s a $10 average movement on an annual basis, to make sure that’s clear. So that’s the sensitivity, and that relates to our National Methanol subsidiary, which is a portion roughly 25% of our international business.
So we will bake that into our forecast and keep an eye on where oil prices are moving as we make our projections in February..
And does slightly 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 they are pricing there. That doesn’t….
No. And Andy this correlation that we’re sharing with you is a rough correlation. We’re not actually in the oil business..
Right..
Okay. So the correlation has generally worked over time. We make more money when oil prices are high and less when oil prices are low, but it’s not a perfect correlation..
Okay. Thank you..
Thank you..
And we’ll take our next question from Greg Gordon, Evercore ISI..
Thanks. I have a follow-up question on the pipeline. Just maybe you can clarify a bit. Traditionally the shippers bear the costs of moving gas to where it’s been consumed.
And I guess the question is, whether or not because the cost of transportation on new pipes like this, especially given the negative basis that the Marcellus producers are already facing versus Henry Hub is so high might be prohibited for them to make it economic.
Is it likely that the transportation costs will be borne to some degree by the consumers?.
So we are entering into long-term transport contracts on the part of our utilities. That was what we put in front of the commission this, Greg, this quarter, so that we could enter into those multiyear transport contracts. And that’s part of the transaction. So the utility customers will bear the transport..
That’s right. And these costs are typically passed through the fuel cost mechanisms..
No, I completely understand it’s a non-traditional framework relative to what E&P analysts generally think about, in your pipeline as well as some others have gotten push back from E&P investors that, well, it just seems like a very expensive transportation cost.
And I pointed out to them that these are consumer-sponsored pipes and I just wanted to get some clarification on that..
That’s correct..
That’s a demand concept [ph] versus supply. So I think that key distinction, Greg, is 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 would like to turn the conference back over Lynn Good for any additional or closing remarks..
So thank you everyone, and thanks for your interest in Duke. We look forward to seeing many of you next week in Dallas at EEI. So thanks again..
This concludes today’s conference. We thank you for your participation..