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NextEra Energy (NYSE:NEE)

Q2 2014 Earnings Call

July 29, 2014 9:00 am ET

Executives

Amanda Finnis -

Moray P. Dewhurst - Vice Chairman, Chief Financial Officer and Executive Vice President - Finance

James L. Robo - Chairman of The Board, Chief Executive Officer, President, Chairman of Executive Committee, Chairman of FPL and Chief Executive Officer of FPL

Armando Pimentel - Chief Executive Officer of Nextera Energy Resources, LLC and President of Nextera Energy Resources, LLC

Eric E. Silagy - President and Director

Analysts

Stephen Byrd - Morgan Stanley, Research Division

Daniel L. Eggers - Crédit Suisse AG, Research Division

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Paul Patterson - Glenrock Associates LLC

Steven I. Fleishman - Wolfe Research, LLC

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Greg Gordon - ISI Group Inc., Research Division

Operator

Good day, everyone, and welcome to the NextEra Energy and NextEra Energy Partners' 2014 Second Quarter Earnings Conference Call. Today's conference is being recorded.

At this time for opening remarks, I would like to turn the call over to Amanda Finnis. Please go ahead, ma'am.

Amanda Finnis

Thank you, Chanel. Good morning, everyone, and welcome to the second quarter 2014 combined earnings conference call for NextEra Energy and for NextEra Energy Partners.

With me this morning are Jim Robo, Chairman and Chief Executive Officer of NextEra Energy; Moray Dewhurst, Vice Chairman and Chief Financial Officer of NextEra Energy; Armando Pimentel, President and Chief Executive Officer of NextEra Energy Resources, all of whom are also officers of NextEra Energy Partners; as well as Eric Silagy, President and Chief Executive Officer of Florida Power & Light Company.

Moray will provide an overview of our results and our executive team will then be available to answer your questions.

We will be making forward-looking statements during this call based on current expectations and assumptions which are subject to risks and uncertainties.

Actual results could differ materially from our forward-looking statements if any of our key assumptions are incorrect or because of other factors discussed in today's earnings news release, in the comments made during this conference call, in the Risk Factor section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our websites, www.nexteraenergy.com and www.nexteraenergypartners.com. We do not undertake any duty to update any forward-looking statements.

Today's presentation also includes references to adjusted earnings, which is a non-GAAP financial measure. You should refer to the information contained in the slides accompanying today's presentation for definitional information and reconciliations of the non-GAAP measure to the closest GAAP financial measure.

With that, I will turn the call over to Moray.

Moray P. Dewhurst

Thank you, Amanda. Good morning, everyone.

NextEra Energy had an excellent quarter, capped off by the successful launch of NextEra Energy Partners. All parts of the NextEra portfolio performed well, and both NEE and NEP remain on track to deliver the financial expectations, including cash flow and credit metrics, that we have previously disclosed. I will provide more detail on expectations later in the call.

At Florida Power & Light, we have invested roughly $1.6 billion of capital year-to-date, consistent with our strategy of improving the long-term value we offer our customers. Our major capital projects remain on track, and we continue to expect the last of our 3 generation modernization projects at Port Everglades to come online in mid-2016. Our reliability and storm hardening initiatives are also progressing well.

In addition to these efforts to improve our electric delivery system, we are now exploring opportunities to help us deliver lower and more stable natural gas costs for our customers.

Last month, FPL announced an innovative plan to invest in long-term natural gas supplies, which I will talk about more in a moment. And we were particularly pleased to learn that FPL was named the most trusted utility in the nation based on a large nationwide sample of utility customers.

At Energy Resources, our development and construction programs remain on track, and our backlog of contracted renewables projects continues to development, with a PPA for another roughly 100 megawatts of U.S. wind signed since the last call. Earnings growth was driven by new contracted renewals projects, as well as strong results in our customer supply and trading business.

At NextEra Energy Partners, the assets operated well and delivered financial results in line with expectations. In addition, just after the close of the quarter, the last of the projects in the initial portfolio became operational.

Now let's look at the results for FPL. For the second quarter of 2014, FPL reported net income of $423 million or $0.96 per share, up $0.04 per share year-over-year.

The principal drivers of FPL's earnings growth in the quarter were continued investment in the business and an increase in wholesale operations. FPL's capital expenditures were approximately $570 million in the quarter, and we expect our full year capital investments to be roughly $3.2 billion. Regulatory capital employed grew 6.2% over the same quarter last year, and net income grew 8.2%.

Our reported ROE for regulatory purposes for the 12 months ended June 2014 will be approximately 11.3%. Similar to last quarter, this includes the impact of transition costs associated with our enterprise-wide productivity initiative, Project Momentum, that we incurred over the 12-month period, all of which were incurred in 2013.

Absent these costs, regulatory ROE would have been 11.5%, which remains our target for the full year 2014. As a reminder, the impact of the 2013 transition costs will roll off our reported regulatory ROE as we move through the year, since the regulatory ROE is measured on a 12-month trailing basis.

We utilized $6 million of reserve amortization during the quarter in order to achieve this predetermined ROE, bringing our year-to-date utilization reserve amortization to $131 million. Under the current rate agreement, we record reserve amortization entries to achieve a predetermined regulatory ROE for each 12-month trailing period, in this case, the 11.5% that I previously mentioned, excluding special charges such as the Project Momentum transition costs.

As we've mentioned before, we always expect to use more reserve amortization in the first half of the year than the second half, given the pattern of our underlying revenues and expenses.

Over the remainder of the year, assuming normal weather and operating conditions, we expect to reverse the reserve amortization taken in the first half of the year and end the year with a balance roughly equal to where we started or possibly even a little better.

Looking beyond 2014, we continue to believe that our reserve balance, when combined with our weather-normalized sales growth forecast of 1.5% to 2% per year and our current O&M expectations, as well as the commitment of a total of roughly $7 billion in infrastructure CapEx for the period 2013 to 2016, will allow us to support regulatory ROEs in the upper half of the allowed band of 9.5% to 11.5% for the remaining period of the current rate agreement. We expect that we can do so in ways that will further improve our already outstanding customer value proposition and will position us well for 2017 and beyond.

In Florida, most economic indicators we follow continue to show improvement year-over-year, while some appear to have recently stabilized. Most notably, Florida's focus on economic development and an overall improvement in the business climate continue to encourage business expansion and additional hiring, while measures of confidence in the state of the economy have generally improved. As a result, Florida labor force participation rate has increased in recent months, even while the U.S. rate continues to drift downward.

Clearly, the return of previously discouraged workers into the labor force is positive, although it will naturally mean that further reductions in Florida's unemployment rate will come at a slower rate. Florida's seasonally adjusted unemployment rate in June was 6.2%, down 1.2 percentage points from a year ago. The number of jobs in Florida was up 237,500, an increase of 3.1% compared to a year earlier, and June was the 47th consecutive month with positive job growth in Florida, following more than 3 years of job losses. Nationally, the number of jobs was up 1.8% over the year.

Florida's annual job growth rate has exceeded the nation's rate since April 2012. Florida's private sector continues to drive the state's job growth, and more than 620,000 private sector jobs have been added since December 2010.

Turning to the Florida housing market. Recent data appear to show indicators settling into a steadier and hopefully more sustainable pace. As the accompanying chart shows, new building permits have stabilized and remain at comparatively healthy levels as Florida ranked second-highest in the U.S. in new housing permits. Mortgage delinquency rates continue to decline, and the Case-Shiller Index for South Florida shows home prices up 14.6% from the prior year. Other positive economic data across the state include continued improvement in retail taxable sales, as well as the consumer confidence index. Overall, Florida's economy continues to progress well.

Our customer and usage metrics at FPL this quarter show mixed results. We saw the largest average increase of customers since the second quarter of 2007, with approximately 91,000 more customers than in the comparable quarter of 2013 representing growth of 2%. Roughly half of the increase can be attributed to the rollout of our remote connect and disconnect capability, enabled by our smart meter program that we highlighted last year.

As a reminder, these new customers, which are disproportionately low usage and residential, have a lower impact on our sales. Taking this into account, we estimate that customer growth accounted for about 1% of the increase in sales during the quarter.

Overall usage grew by 0.6%, driven by favorable weather comparison. Underlying usage per customer, however, decreased 1.3% compared to the same quarter last year.

As you may recall, usage was in line with our long-term expectations during the first quarter, and as we have often pointed out, this metric can be somewhat volatile on a quarterly basis. Our long-term expectation of underlying usage growth continues to be approximately 0.5% per year, net of the impact of efficiency and conservation programs, at least through the period of the rate agreement.

The 12-month average of low-usage customers fell to 8.1%, its lowest level in 7 years, while the average number of inactive accounts for the quarter declined to levels not seen since early 2004.

As I mentioned earlier, FPL has announced a plan to invest in long-term natural gas supplies and has filed a petition with the Florida Public Service Commission seeking approval. As a first step in the plan, FPL will partner with PetroQuest Energy to develop natural gas production wells in the Woodford Shale region in southeastern Oklahoma. While a proposed initial program of up to roughly $200 million of capital investment is modest in size relative to FPL's overall natural gas needs, we view the transaction as an important first step in what we hope will be a larger program that will improve the value we deliver to our customers even further.

Acquiring an interest in natural gas reserves is expected to lower long-term fuel costs and provide a long-term hedge against potential volatility in the market price for natural gas, which is a large component of the price of electricity, and would thereby address a concern that a number of policymakers have raised.

In addition to the initial proposal, FPL has also requested that the PSC approve a set of guidelines for subsequent natural gas production projects to allow the company, and in turn its customers, to take advantage of future beneficial natural gas investment opportunities. FPL expects a PSC decision by the end of 2014 or early 2015.

Let me now turn to Energy Resources, which reported second quarter 2014 GAAP earnings of $81 million or $0.18 per share. Adjusted earnings for the second quarter were $213 million or $0.48 per share. These adjusted results include 2 unusual items, both associated with the launch of NextEra Energy Partners: first, a negative impact of $0.05 per share from restructuring and direct transaction costs associated with the creation of NEP; second, a negative impact of $0.10 per share, which represents an income tax charge driven by separating our Canadian projects to enable them to fit into the overall NEP structure. This is a noncash item, and any real cash tax impact -- if there were to be any -- would occur many years in the future. In fact, there may never be any cash impact as we believe this item may be reversed in future periods pending discussions with Canadian tax authorities.

Together, these 2 items reduced Energy Resources' adjusted results by about $0.15 per share. So the underlying operating results were very strong and, in fact, exceeded our expectations with excellent performance in virtually all parts of the portfolio.

As you know, the launch of NEP came at the end of the quarter and NEP was not operational in the second quarter. As a result, Energy Resources' second quarter results do not reflect any deduction for noncontrolling interest. Going forward, Energy Resources will continue to consolidate NEP for accounting purposes, and you should expect to see a deduction from income representing the NEP LP unitholders' interest in Energy Resources results.

Our investor relations team will be ready to address any questions you may have about the interrelationships between Energy Resources and NEP.

Energy Resources' contribution to adjusted EPS decreased by $0.08 year-over-year. Setting aside the combined negative impact of $0.15 per share from the unusual items associated with establishing and launching NEP that I discussed earlier, the core business delivered great results.

Strong contributions from growth in our contracted renewables portfolio added $0.05 per share, reflecting new wind and solar investments placed into service during or after the second quarter of 2013. Consistent with our commitment to recycling capital, asset sales collectively added $0.06 per share, including $0.03 per share due to a gain on a sale of wells in our gas infrastructure business. We expect to continue to recycle capital from time to time within the gas infrastructure business, keeping our overall commitment of capital to this business to a small fraction of the total.

The customer supply and trading business added $0.07 per share, primarily reflecting structured transactions tailored to meet specific customer needs.

The contributions from existing assets declined by $0.05 per share, driven primarily by the planned refueling outage at Seabrook. However, this was better than we had anticipated as Seabrook's outage was the best ever for the facility at just over 23 days. In addition, wind resource, overall, was strong during the quarter, although the year-over-year impact was small, as the second quarter of 2013 was also well above average.

All other factors reduced results by $0.06 per share, including $0.02 of higher interest expense associated with the growing portfolio and $0.02 of dilution.

For the full year, we continue to expect to elect CITCs on roughly 265 megawatts for our Mountain View Solar project and the portions of Genesis and Desert Sunlight solar projects that are expected to enter service in 2014. This equates to roughly $60 million in adjusted earnings, down from roughly $70 million in 2013 on 280 megawatts of solar projects.

Let me now turn to NEP. As I just noted, NEP was not operational during the second quarter, and therefore, while it has released results and will file a Form 10-Q, the presentation of results follows what is known as predecessor format, which is the same basis as was presented in the S-1. I must caution you that this is likely to be different from what you will see going forward, in particular, because the tax treatment of the NEP assets will be different under the NEP structure.

As a consequence, analysis of NEP second quarter reported results is not particularly meaningful. Moreover, we recognize that most NEP investors will be focused on EBITDA and cash available for distribution, and we expect to provide analysis of these variables for the third quarter and beyond.

During the second quarter, the NEP assets performed in line with our expectations. Consequently, the EBITDA and cash flow of the portfolio were also consistent with our expectations. The second unit at our Genesis project entered commercial operations late in the first quarter and operated well throughout the second quarter, while the last of the initial portfolio assets, our Bluewater wind project in Ontario, started commercial operations just after the end of the quarter.

Overall, we were very pleased with the performance of the NEP portfolio during the second quarter.

Shifting back to the broader Energy Resources portfolio, the team continues to execute on our backlog and pursue additional contracted renewable development opportunities. In Canada, we continue to expect the remaining approximately 400 megawatts of wind in our backlog to enter service by the end of 2015, with the majority expected to come into service by the end of this year.

Our solar backlog remains on track and during the quarter we brought 13 megawatts of solar into service with the partial commissioning of Desert Sunlight. We continue to expect to bring the remaining roughly 635 megawatts of our backlog into service by the end of 2016. In addition to our existing contracted backlog, we continue to pursue additional solar opportunities that could come online by the end of 2016.

Turning to our U.S. wind program. The team recently signed a PPA for a roughly 100-megawatt project, which is expected to come into service in 2015, bringing our total contracted U.S. wind development program for 2013 through 2015 to approximately 1,770 megawatts.

Based on everything we see at the moment, we continue to believe our total 2013 to 2015 U.S. wind program could be 2,000 to 2,500 megawatts. In the appendix of our earnings presentation, we have provided a reconciliation of all anticipated megawatts at Energy Resources through the end of 2016, which may be helpful to NEP investors as well.

Turning now to the consolidated results for NextEra Energy. For the second quarter of 2014, NextEra Energy's GAAP net income was $492 million or $1.12 per share. NextEra Energy's 2014 second quarter adjusted earnings and adjusted EPS was $630 million and $1.43, respectively.

Adjusted earnings from the Corporate & Other segment increased $0.01 per share compared to the second quarter of 2013.

You may recall that when discussing the possible creation of NEP, we indicated that an important factor in our decision-making would be the impact it might have on credit. We are pleased to note that S&P, Moody's and Fitch all affirmed our ratings and stable outlook. Looking forward, as NEP grows, we will continue to focus on ensuring that we sustain our strong credit position, both in terms of our credit metrics, as well as in our focus on portfolio mix and business composition.

The development of both Sabal Trail Transmission and Florida Southeast Connection continue to progress well through their respective processes, and we continue to expect to submit necessary filings with FERC later this year.

During the quarter, we also announced a nonbinding open season for a 330-mile natural gas pipeline project called Mountain Valley Pipeline, partnering with EQT Corporation. The project is designed to connect the Marcellus and Utica Shales with markets in the southeast region of the U.S. in order to support growing demand and improvements in reliability.

The results of the open season, the details of which we are currently evaluating, were very strong and confirm our view that the Mountain Valley project is very attractive to a wide range of potential shippers. The next step towards firming up a commercially viable project is to convert these strong expressions of interest into binding economic commitments. We look forward to providing more details at a later date.

Before turning to our expectations for 2014 and beyond, I would like to say a few words about our involvement with the Energy Future Holdings bankruptcy case. While our general policy is not to comment on individual transactions, whether real or potential, obviously, a number of documents have been publicly filed in this case and various parties have commented and speculated on our involvement.

We have, on many occasions, articulated our view that we believe we have the necessary skills to effectively manage large, regulated utility businesses in a fashion that delivers value to both customers and investors.

We have also indicated that we would be open to expanding our portfolio of regulated utility assets through acquisition if we can do so within acceptable financial and risk parameters and if we can see a reasonable path to all necessary regulatory approvals.

With that in mind, it is no secret that we have made a tangible revised proposal to EFH in the bankruptcy court. Our commitment to Texas runs deep, having invested more than $7 billion in transmission, power generation and other operations in the Lone Star state.

We also bring to the table a proven track record in the utilities industry, highlighted by strong performance in the areas of reliability, affordability and customer focus. And I will simply reiterate our belief that our revised proposal would provide substantial value to all stakeholders, including Oncor's customers.

Our performance in the second quarter was stronger than we expected, and our expectations for the second half of the year have not changed significantly. Based on these observations, we now believe it is reasonable to expect our full year results to be somewhere in the range of $5.15 to $5.35 per share, even including the $0.15 of onetime effects from the launch of NEP, which, of course, were not anticipated when we originally shared with you our 2014 view back in the summer of last year.

While we're very pleased with our progress so far this year, it remains to be seen how much of the "goodness of this year" will carry over into 2015 and beyond.

Accordingly, at least for now, we are not changing our view of 2016 with an adjusted earnings per share range of $5.50 to $6, or 5% to 7% compound annual growth rate off a 2012 base. However, we do expect to update our view of the 2016 time frame later in the year or early in 2015 when we will have more clarity around a few important uncertainties.

As always, our expectations are subject to the usual caveats we provide, including normal weather and operating conditions.

Last year, we shared with you our expectations for improvements in our credit metrics for both 2013 and 2014, and we continue to be on track in terms of cash flow and leverage to meet those targets, which are fully consistent with our current ratings.

Turning now to expectations for NEP. We remain confident in the forecast we presented in the S-1. We expect the initial portfolio to yield EBITDA of about $250 million and cash available for distribution of about $87 million for the 12 months through the end of June 2015, and these results should support an initial distribution at an annualized rate of $0.75 per unit. Our expectations assume normal weather and operating conditions.

Looking beyond the first year, we expect unit distributions to grow about 12% to 15% per year for at least 3 years, and we believe this is achievable with the acquisition only of assets from the ROFO portfolio, assuming current market conditions.

On average, we expect the ROFO portfolio to look fairly similar to the initial portfolio on a per-megawatt basis, with annual EBITDA expectations of $250,000 to $260,000 per megawatt and cash available for distribution of about $85,000 to $95,000 per megawatt, once all ROFO assets have entered into commercial operations. The last of the ROFO assets are not expected to enter service until late in 2016.

While NEP has no special contractual rights to support further acquisitions, we believe it is reasonable to expect that Energy Resources will want to make available additional projects from its existing portfolio, as well as some of those currently under development.

As of the end of last year, Energy Resources had another roughly 7,000-or-so megawatts of contracted renewables projects in its operating portfolio. And while not all of these projects would be suitable immediately for NEP, many or all of them could become eligible over time.

In addition, we expect to have a further 1,800 to 2,300 megawatts of additional contracted renewable capacity, entering service prior to the end of 2016. And finally, beyond contracted renewables, Energy Resources has other projects that may perhaps be suitable for NEP over time.

Overall, we continue to believe that NEP offers investors, by far, the largest and highest overall quality portfolio of potential assets that can help drive growth and distributions for many years to come. We expect to be in a position to provide additional ongoing, forward-looking disclosures with our third quarter conference call.

With that, we will now open the line for questions. Since this is our first combined conference call for NextEra Energy and NextEra Energy Partners, it will be helpful if you can be clear which entity you are referring to in your questions. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Stephen Byrd with Morgan Stanley.

Stephen Byrd - Morgan Stanley, Research Division

I wanted to touch on Mountain Valley. And just to understand -- I understand the feedback you gave on the expressions of interest, could you speak a bit to the timing that we might expect as you assess what you received? And just better help us understand what sort of milestones we should be looking for.

James L. Robo

Sure, let me ask Armando to address that.

Armando Pimentel

Stephen, we're in the middle of going back and looking at all the expressions of interest that we received and having individual discussions to make sure that we can enter into agreements with all of the interested parties. My expectation is that by the end of this year, we will be in a position to understand whether to -- whether we're going to move forward or not with the project.

Stephen Byrd - Morgan Stanley, Research Division

Okay. So we should -- we -- you'd be communicating that back by the end of the year, it sounds like is the general time frame you're thinking? Okay.

Armando Pimentel

Yes. I'd expect it to be no later than then. We might have updates before then, but I think for investors and analysts, they should expect that by the end of the year, we should know whether we're moving forward.

Stephen Byrd - Morgan Stanley, Research Division

Okay, great. And just over for NextEra, not NEP, but just thinking about equity needs in the future and what's -- as you think about further drop-downs into NEP. Can you talk, at least, broadly about how having NEP impacts your need for equity funding? How you think about that? Does it largely eliminate external equity requirements or -- just a little bit more color on equity needs?

Moray P. Dewhurst

Sure. The way to think about the contributions coming up from NEP from a financing perspective is to expect that they will get rolled into our overall financing plan at Capital Holdings. So obviously, that implies that at the margin, there's some implicit reduction in what are the other -- the equity -- otherwise would be. Having said that, I would just remind you what we've said previously, which is with the equity issuance last year and the forward that comes in this year, unless we see significant additional incremental CapEx, we would not expect to be coming back to the market for incremental equity.

Operator

And we'll take our next question from Dan Eggers with Crédit Suisse.

Daniel L. Eggers - Crédit Suisse AG, Research Division

Can you just give -- maybe a little more commentary on adding the natural gas reserves into rate base, kind of how the process will work with Phase 1 and then how you're thinking about layering in additional reserve additions over time? And what the commission is going to view as a successful implementation in this program?

Moray P. Dewhurst

Sure. It's pretty straightforward. We have a tangible proposition on the table right now, which we are asking the commission to approve. It has good economics for our customers. We think it makes a lot of sense from fundamentals and fundamental policy reasons. But it's just one transaction, and it's obviously very small in the context of FPL's overall gas needs. So what we are also asking for is approval of a set of guidelines, which would allow us to move forward with the potential to execute additional deals on a time frame that's consistent with the commercial realities of doing business in that upstream space. Obviously, the decision-making time frame commercially for the plans in that sector is fairly rapid and we would want to have agreement and essentially the blessing of the PSC that within certain parameters, we would be okay to go ahead with additional deals. Having said that, all deals, even if they're executed, are going to be subject to annual review through the fuel clause filings, so the commission would still maintain oversight over the specifics of each transaction.

Daniel L. Eggers - Crédit Suisse AG, Research Division

And how comfortable do you guys feel about the scaling of those projects? And how much fuel would you like to ultimately have from controlled reserves versus buying in the market?

Moray P. Dewhurst

Well, we haven't set an ultimate target yet. Obviously, it could be very significant over time. Our main focus is on establishing the framework and getting started on the program, but clearly, we think there are plenty of other potential opportunities over time. They may not come in a smooth, steady stream. Obviously, that's going to depend upon the commercial realities in the upstream space. But it's very clear that from a customer perspective, if we can convert what is today a variable and uncontrolled cost into something that's much more predictable, there's real value to customers in doing that.

Operator

We'll take our next question from Paul Ridzon with KeyBanc.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Can you kind of just think about your rationale of not stripping out that $0.15 and kind of given that we are incurring that now and guidance is unchanged, where the upside came from to maintain guidance?

Moray P. Dewhurst

Well, there's a number of areas. As we said, the wind resource was strong, so that was our expectations are always around this average wind resource. We had that. The Seabrook outage was shorter than we'd expected. Some of the customer supply transactions that we closed this quarter pushed us a little bit above where we had otherwise expected to be. We were a little bit better on our interest rates. There was a whole variety of areas, but when you put them all together -- there was also a little bit on the FPL side. The wholesale results were a little bit stronger there, so there was a number of areas that have pushed us up.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Okay. And then in a couple of places in your slide deck, on the one hand, we had 109% of normal wind. But then when you're talking about NEP, you said the wind and solar resources was very slightly above normal. Is this just the different geographies of the assets?

Moray P. Dewhurst

It's probably the different geographies and probably, the solar was actually below expectations.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

And then -- I'm sorry, just got -- do you have a pro forma of what NextEra Energy Resources would have looked like under the new NEP accounting?

Moray P. Dewhurst

No, we don't.

Operator

We will take our next question from Julien Dumoulin-Smith with UBS.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

So kind of a twin question relating to the parent company. Can you talk a little bit about how to minimize dilution from the sell-downs to NEP and the roll-down of the ROFOs. And perhaps, coupled with that, discuss the 2016 outlook. You mentioned that you're looking for clarity on a few caveats later this year to perhaps provide an update. What are those key moving variables that limit you from providing that update today as you think about it?

Moray P. Dewhurst

Okay. On the first -- again, maybe I'm just repeating what I said earlier, but the way to think about the proceeds coming up as they get rolled into the overall financing program. So in the short term, if you have a particular transaction, an acquisition by NEP of Energy Resources' assets, there will be some temporary accounting dilutive aspect until you have moved forward and adjusted your financing structure, so that your credit metrics are back where they would be, but that's going to be a relatively small amount. So it shouldn't meaningfully move the numbers. It will make this year, for example, very -- well, maybe there's $0.01 of effective dilution from that affect, so -- but then going forward, we just integrate it into the overall financing plan. On the 2016 outlook, obviously, by the end of the year, we will know where we are on the election here in Florida. We'll have a much better insight into where we are on completing the portfolio, the backlog portfolio of renewables and projects, we're working on a number of things there that we are pretty optimistic will come to pass, but we'll know a lot more by the end of the year on that front. Of course, the other thing is we'll know a lot more where we are on the PTC.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Right, absolutely, and to that point, can you discuss real quickly, what is your -- you didn't change your outlook per se, but I'm curious, is the potential for PTC extension delaying PPA sign-ups? And then coupled with that also, are you -- what is the outlook for third-party acquisitions? And has your view on third-party acquisitions down at the NEP level changed in light of the relative currency that you have in hand?

Armando Pimentel

Julien, it's Armando. I think the uncertainty about the PTC and when it would be extended this year certainly caused a lull, in our view, in

[Audio Gap]

towards the very end of the session this year. I'll let Moray answer the NEP question.

Moray P. Dewhurst

So in terms of outlook for third-party acquisitions, I don't think the existence of NEP has fundamentally changed our view. We've always been very active in the market for third-party acquisitions. We'll continue to be, but we've also historically been disciplined in our pricing there, and we expect to continue to be disciplined. I do think it gives us a different vehicle. So depending upon the nature of the potential acquisition, it might fit better in NEP, or it might fit better in Energy Resources. In general, I think that if we see something that requires what I'll call a fair degree of cleanup, for example, perhaps a project that hypothetically we see having some operational improvement potential or requiring a contract restructuring, something of that nature. Other things equal, it would seem logical that we would start with that at the Energy Resources level, work on making those improvements and then make it available to Energy Partners because the key part of the strategy at NEP is to have clean and derisked projects because those are clearly what the investors in NEP value very highly. So to the extent to which the potential asset was already very clean in that sense, it might be a suitable candidate for direct acquisition by Energy Partners. But those are just kind of a conceptual guidelines obviously that we'd have to see in any practical situation. But I think we'll continue to be very competitive.

Operator

We will take our next question with Paul Patterson with Glenrock Associates.

Paul Patterson - Glenrock Associates LLC

Sort of quickly on Slide 7, the load growth -- I'm sorry if I missed -- what caused the 1.3% nonweather-related decrease?

Moray P. Dewhurst

Well, I guess the bottom line is we're not sure. That's the underlying usage growth and other is essentially a residual from our calculations. So we apply our regular forecasting model which says, okay, given what happened with temperature, given what happened with the economy, given what happened with relative pricing, here is what we should have expect and so this is really measured relative to that, which is one of the reasons that it is often volatile from quarter-to-quarter. Having said that, I think what we're seeing in here, although I can't be sure of the exact reasons, is some reduction in usage or lower-than-expected usage among the higher volume customers because the lower volume customers, the metrics associated with them, all look pretty good. So I think what we're seeing is some -- among higher-volume customers, whether that is deliberate conservation efforts, whether it's the effect of more energy efficiency than we have anticipated, we're not sure. So we're going to be digging into those numbers to figure out what we can about what's going on there. But do recognize that from quarter-to-quarter, just mix impacts within the customer base can have quite an impact, an indirect impact on that residual usage.

Paul Patterson - Glenrock Associates LLC

Okay. And then on Oncor, looking at the legislation that was 13-64 [ph] last year regarding the sort of standalone tax concept and what-have-you, how should one think about -- or what can you share with us the potential use of leverage in an acquisition such as Oncor? I mean, one might think that it could be substantial. I'm just wondering if...

Moray P. Dewhurst

Yes. I really can't say anything more than we shared in the prepared remarks.

Paul Patterson - Glenrock Associates LLC

Okay. Fair enough, but I tried though. Okay, so then -- and then finally, on the structured transactions in the trading and marketing of $0.07, could you give us a little bit of flavor for what happened there? What the nature of that is, I guess?

Moray P. Dewhurst

Sure. We've, for a long time, been in the business of tailoring power and gas products to meet particular customers' needs. Commonly, these customers are munis and co-ops in different parts of the country, who don't necessarily have the capability to manage all their varying energy needs directly. And typically, these will be for kind of nonstandard amounts of power varying over the course of the year or varying over years. So they're sort of customized products in that way, but they're still relatively straightforward in that they're power and gas delivered to particular locations. And so we will customize the product to meet that need and then essentially back-to-back it, hedge out the components in the regular market. And there's obviously a spread to be made on that. I would say that with the pullback of some of the major financial services firms from the physical commodity world, we've been seeing perhaps a few more of those kinds of opportunities more recently. So it's good business, it maintains relationships with the folks who are often customers of ours on the wind side. So it provides a nice extra portion of the mix.

Paul Patterson - Glenrock Associates LLC

Okay. Is it sort of like a gain-on-sale, though, when you do these transactions? Or is this sort of an accrual kind of -- how should we think about sort of the ongoing nature of something like this sort of structured transaction, in other words, do you take a gain as you do these transactions or is there more like an annuity stream? How should we think about that?

Moray P. Dewhurst

It's a little bit of both, and it depends on the nature of the transaction. Mostly, they are an accrual transaction; occasionally, they may have an element of mark-to-market upfront. We try and minimize that portion for obvious reasons. It's better to spread them out over time. But depending upon the specific nature of the deal, the accounting may require you to take a day 1 gain, so to speak.

Paul Patterson - Glenrock Associates LLC

So that $0. 07 just sort of -- the flavor of that would you say is mostly accrual or mostly sort of mark-to-market? Onetime-ish? How should we sort of think about that?

Moray P. Dewhurst

I would say it's mostly stuff that continues on.

Operator

And we'll take our next question from Steven Fleishman with Wolfe Research.

Steven I. Fleishman - Wolfe Research, LLC

Just a couple of things. First, do you an official schedule for the EMP [ph] approval?

Moray P. Dewhurst

I'm going to turn to Eric. I'm not sure that the PSC has formally scheduled it. We're certainly hoping to have a decision by at least the early part of next year.

Eric E. Silagy

Steve, this is Eric. So we're right now working with the staff of the PSC and other interested parties on schedule. We're hoping for hearings in October, and then we're still hoping for a decision by the PSC sometime by the end of the year, beginning of next year at the latest.

Steven I. Fleishman - Wolfe Research, LLC

Okay. And then just a question on NEP. We never really, because of the filing and your kind of inability to comment once you file the S-1. We never really got the kind of story on why this is good for NextEra and how you made the decision and the like. And I don't know, if you could just spend a short bit of time on how this is -- how you see the value of this to NextEra?

Moray P. Dewhurst

Sure. Obviously, there's different ways of looking at it -- and I think different individuals look at it somewhat differently -- for myself, I view it very much as a way to highlight the value of a very attractive portion of the portfolio that arguably wasn't receiving full value in the existing structure. As I had sort of hinted at in the response to an earlier question, a lot of what we are really doing in separating out the assets that are part of NEP is segregating 2 distinct aspects of the business in Energy Resources. There is the development construction early stage operations, getting a project to the point where it is, as I referred to it earlier, clean and derisked. And then there's the long-term ownership of the financial interest in those assets. Those 2 aspects of the business are really quite different. They have different risk profiles, and they can certainly appeal in differing degrees to different sets of investors. And what we've done through creating NEP is we've really created a vehicle that allows us to segregate those activities. And in so doing, I think we've highlighted, begun to highlight the real value of those -- of that long-term financial interest in those projects. So to me, it's mostly about highlighting of the value, but we've done so in a fashion that I believe promotes alignment of interests, and that speaks to obviously the structural characteristics of NEP. Other people are going to see it somewhat differently. So a common way, but certainly a number of investors have expressed it and folks internally just see it as accessing a lower-cost source of capital. So I think there's a number of ways, in a sense, different sides of the same coin, but I see it as really highlighting the value.

Operator

We will take our next question from Michael Lapides with Goldman Sachs.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

One or 2 nuts-or-bolts questions. Florida Power & Light O&M for the quarter and year-to-date, basically flat year-over-year. Just curious, is there anything unusual in kind of the quarters for 2014? Do you still expect kind of flattish O&M in '14? Anything that could make second half of 2014 higher or lower than second half of 2013?

Moray P. Dewhurst

Well, recall that we undertook this initiative that we call Project Momentum last year. And that produced a great many ideas that, in FPL's case, will deliver O&M savings over time. Not surprisingly, those savings tend to build over time. So we would expect the full year for 2014 O&M at FPL actually to be down relative to 2013. So you should definitely expect the second half to be down. But there's nothing particular that I can point to there because the gains from Project Momentum were very widely shared across different parts of the organization. So it's really progress in all areas. We're very pleased with the way the implementation of those initiatives have been going. We're actually a little bit ahead of where we had expected to be. Recall, of course, that those don't directly affect FPL earnings because of the nature of the settlement agreement. So if we do better than we expect on O&M, that simply gets reflected in the amount of [indiscernible] depreciation that we adjust. But that's really what's going on there.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Okay. And then when thinking about NEP's portfolio over time, and when I say over time, I mean multiple, multiple years, and the risk profile of NEP. Just curious for your thoughts, it's one thing we've got renewable assets in there that honestly have very, very, very low maintenance CapEx or even kind of onetime CapEx requirements and have 25- or 30-year contracts. How do you think about what adding other types of assets whether it's gas fire, power play [ph] typically have shorter-term contracts or whether it's nuclear, where they may have longer-term arrangement, but there's also, I don't know, kind of binary capital spending risks? Meaning, Crystal River 3 or Songs [ph] or Davis Besse-related risks that just kind of don't exist with a lot of other type of power plants. How do you think about the pros and cons of adding to the EBITDA and the cafte [ph] for NextEra Energy Partners by putting nonrenewable assets? Even something like a T&D utility in there versus the potential impact on maybe valuation or multiples or CapEx, given kind of what the CapEx risk looks likes for those other types of assets versus the CapEx risk of a renewable plant?

Moray P. Dewhurst

Okay. Let me try and address that in a number of pieces because I think there's a lot of things in there. I think the short answer is, we are going to evaluate all those issues that you've just talked about over time, and we're going to receive, I suspect, a lot of investor feedback, and that will help us in our evaluation. One of the great things you pointed out, but you're talking many years down the road -- one of the great things about the NEP position is it can look to long-term sustained growth simply through adding contracted renewable projects, which it may hope to acquire from the sponsor, so long before you have to even consider some of the things that you've just raised in your question. Having said that, let me take the [indiscernible] assets, clearly, there are examples in the market where those assets have been added to a yieldco-type portfolio, so it clearly can be done. I think there are a couple of issues that go different ways. On the one hand, you get an extra dimension of diversity, so that should be attractive to an NEP investor. But as you pointed out, they do have different characteristics. So I think we're just going to have to evaluate the relative weight of those -- broadly speaking, those 2 factors and see what investor reactions are. And the same general criteria apply as you start thinking about extending the universe of assets more broadly, although introducing even more complexities. So for example in the nuclear assets, obviously, the binary nature of an event risk that you're implicitly referring to would need to be taken into account. I don't know, but I suspect that, that's not a kind of risk profile that most of the NEP investors would be particularly -- would be pricing into their valuation today. So we need to see what the reaction is. So there might be structures that you would need to put in place to isolate that portion of the risk. In a sense, it goes back to the response of a couple of earlier questions, which is one of the nice things about the NEP platform, is that it enables us to segregate out different types of activities and focus them in the 2 different companies. And in particular, I suspect that means there will be -- we will take on specific types of risks within Energy Resources and NextEra Energy that we would not take on within NextEra Energy Partners.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. Last question, any update on transmission investment opportunities -- electric transmission investment opportunities outside of Florida?

Moray P. Dewhurst

Not a lot new to report. As I've said on a number of occasions to many folks, the transmission development business is long-term in nature. The decision-making time frame for a lot of these projects, particularly the ones that go through the regional, the ISOs, the ITOs, tends to be fairly long. And so nothing in particular, the project, the development project in Canada is moving along as we would expect. We continue to have a very healthy portfolio of initiatives that we're working on. But as I've also said many times before, all of these things are long-term in nature. So things that would not begin to contribute before 2018 or 2019 in most cases.

Operator

We will take our next question from Greg Gordon with ISI Group.

Greg Gordon - ISI Group Inc., Research Division

So 2 questions. First on the TXU transaction. I know you can't comment specifically on it, but can I ask a broader question with regard to your philosophy on acquiring regulated assets? So when you talk -- when you think about what acceptable financial and risk parameters are, in any, like, acquisitions with any, regulated utility, what are the cornerstones sort of financial pillars of your decision-making? For instance, with the Wisconsin acquisition of TEG, they had never commented explicitly on any transaction but always had said had to be accretive in the first full year, not too dilutive to growth rate, not too dilutive to credit. So can you sort of give a comparable set of characteristics that you look for when you think about the price you're willing to pay and the risk you're willing to take in acquiring an additional regulated asset?

Moray P. Dewhurst

I'm not sure I can give a comprehensive list, but let me just try and provide some color at least around that. Recognize that your ability to add value in these situations depends upon your ability to develop synergies across 2 platforms, to improve operations in a platform that you may acquire or to find other ways of delivering incremental value on which the shareholder may hope to earn a regulated rate of return. So you have to look at what is the realistic potential to create value. And while that can be quite meaningful in this industry, it is typically not as large when expressed as a percentage of the existing market value as you will see in many other industries.

So you've got to make sure that you can retain significant portion of the value that you create for your investors; otherwise, there's no point in doing the transaction. And that obviously, in turn, depends upon the terms on which you can expect to get regulatory approval. We would certainly want to make sure that anything that we do is supportive of our existing credit position. As we said on many occasions, we're very comfortable with our credit position, it's an important, competitive weapon to us. So we certainly would not want it to be dilutive to credit. We have traditionally said that with respect to accretion, dilution, while we don't have any absolute hard-and-fast rules, if a transaction is significantly dilutive in the first couple of years, that's usually a warning sign about its fundamental economics. So there can be some particular accounting reasons why an individual transaction might be dilutive in the first year, but normally, that should be a red flag.

Greg Gordon - ISI Group Inc., Research Division

The final question is circling back to the opportunity to create value by hedging out your risk through reverse integrating into natural gas. Someone asked you that question earlier. You indicated that the request that you're making is only to sort of hedge out about 2.9% of your expected 2015 gas burn, and your gas burn is likely to rise in the future by a fair amount. If we want to sort of size up the potential expenditures, if you were to fully hedge, and I understand you'd never do that, is it fair to just take the $70 million to $190 million range and sort of gross that up, so that hypothetically, if the regulator were to say, look, we'd like you to hedge it all, that the range of the potential spending would be sort of $2.4 billion to $6.5 billion? Or is that way over simplifying the math?

Moray P. Dewhurst

Yes. I'm not sure that it's going to scale linearly, certainly as you get up higher and higher, but for the first few percent, it probably is not far off.

Operator

That does conclude today's conference. Thank you for your participation.

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