Pinnacle West Capital Corp (PNW) 2015 Q4 法說會逐字稿

Greetings and welcome to the Pinnacle West Capital Corporation 2015 fourth-quarter earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Paul Mountain, Director of Investor Relations. Thank you, sir. You may begin.

Thank you, Christine. I'd like to thank everyone for participating in this conference call and webcast to review our fourth-quarter and full-year 2015 earnings, recent developments, and operating performance. Our speakers today will be our Chairman and CEO, Don Brandt, and our CFO, Jim Hatfield. Jeff Guldner, APS's Senior Vice President of Public Policy, and Mark Schiavoni, APS's Chief Operating Officer, are also here with us.

First I need to cover a few details with you. The slides that we will be using are available on our Investor Relations website along with our earnings release and related information. Note that the slides contain reconciliations of certain non-GAAP financial information.

Today's comments and our slides contain forward-looking statements based on current expectations, and the Company assumes no obligation to update these statements. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements.

Our 2015 Form 10-K was filed this morning. Please refer to that document for forward-looking statements cautionary language, as well as the Risk Factors and MD&A sections, which identify risks and uncertainties that could cause actual results to differ materially from those contained in our disclosures.

A replay of this call will be available shortly on our website for the next 30 days. It will also be available by telephone through February 26.

I will now turn the call over to Don.

Thanks, Paul, and thank you all for joining us today. Pinnacle West delivered a solid 2015, with earnings near the high end of our guidance range, with Palo Verde Nuclear Generating Station having a record year, and with a balance sheet that remains one of the strongest in the industry.

Jim will discuss the financial results and outlook. My comments will focus mostly on the year ahead.

Our fleet performed very well in 2015, highlighted by Palo Verde Nuclear Generating Station's highest output ever, equating to a capacity factor of 94.3%. One of Palo Verde's key strengths is the ability of the team to perform at an excellent level, but to also drive continuous improvement each year.

2016 marks the beginning of a new period for our fleet. In total, we are planning to invest over $3.6 billion in capital over the next three years. We're investing in two large projects in our fossil fleet as well as a few innovative investments and some IT systems to prepare our operations for the long-term.

The two large fossil projects are the Ocotillo modernization project and the selective catalytic reduction pollution controls, or SCRs as they're called, at the Four Corners Generating Plant. Four Corners unit 5 entered a major outage in January to make several upgrades and begin laying the groundwork for the SCR installations.

The innovative investments I will outline are designed to increase customer and system reliability and meet future resource needs. In November, we announced a partnership with the Department of the Navy to develop a 25-megawatt micro-grid project at Marine Corps Air Station Yuma. This is APS's first micro-grid project and the first military base to secure 100% backup power.

We also plan to install a 40-megawatt solar facility this year on behalf of some of our larger customers. This amount has been reflected in our 2016 CapEx budget.

The Solar Partner program, which is planned for 1,500 APS-owned rooftop solar installations, is on track to be fully installed and operational by mid-2016. And just this month we officially launched our Solar Innovation Study, a 75-home demand rate laboratory here in the Metro Phoenix area which will determine how customers can use various combinations of distributed energy resources such as solar panels, battery storage, smart thermostats, and high-efficiency HVAC systems to better manage their energy environments. These customers will also be placed on our existing residential demand rate, and the study will provide valuable information on a customer's ability to use technology to manage peak demand and lower their bills.

In addition to generation investments, we are upgrading several IT systems to improve our customer interface, facilitate active operation of our transmission and distribution systems, and enable participation in the California ISO Energy Imbalance Market. These investments, along with our advanced meter program, which is fully deployed, are enabling integration of advanced technologies while also allowing us to maintain grid stability.

2016 also represents an important year on the regulatory calendar, with the APS rate case set to be filed on June 1. APS submitted the Notice of Intent to File on January 29, which gives notice to the ACC and stakeholders and outlines the primary topics we will propose in the June rate filing.

APS will propose the new rates go into effect July 1, 2017, based on the test year ended December 31, 2015, with certain adjustments. To help achieve this outcome we have held a series of stakeholder meetings to provide clarity and transparency with the stakeholders. We're also planning to submit an extensive list of standard discovery questions and responses with the June 1 filing.

Let me outline a few of the central topics from the Notice of Intent to Filing. Residential rate design is an area where we will propose changes to better align costs with prices and incentivize cost-reducing technologies. We will be proposing universal demand rates as well as shifting our time-of-use periods to later in the day.

We will also propose a revenue per customer decoupling mechanism that will be adjusted annually to replace the existing lost fixed cost recovery mechanism. The decoupling mechanism will be proposed on a trial basis until the next rate case, to act as a rate-stabilizing mechanism during the transition period to the new rate structure.

The last item I'll mention is we will request the deferral of costs related to two large CapEx projects we're investing in: the SCRs at Four Corners, and the fast-ramping natural gas modernization project at Ocotillo. These investments total of over $900 million over the next few years with in-service dates of 2018 and 2019, respectively.

In the case of the SCRs, since the timing of installations will be close to the end of this rate case, we'll also propose a step mechanism to reflect the deferred SCR costs, similar to the treatment of the Four Corners acquisition.

The docket on value and cost of distributed generation has testimony due on February 25. There are also four other electric rate cases in process.

UNS Electric is the first in line, with hearings set to begin on March 1 in Tucson. We are an active intervener in the UNS case, since it is an important forum to discuss rate design.

The testimony we filed supports the concept of three-part rate design which incorporates a fixed service charge, an energy charge, and a demand charge. This concept was also proposed and supported by UNS Electric and the ACC staff. Related topics, including methodologies for determining the cost to serve customers with solar and the value of solar, will be a central focus in the value and cost of distributed generation docket.

In closing, we delivered on our commitments in 2015, and we are well positioned for 2016 and the long term, with a clear plan and a strong leadership team in place to deliver on the plan. I'll now turn the call over to Jim.

Thank you, Don, and thank you, everyone, for joining us on the call. This morning, we reported our financial results for the fourth-quarter and full-year 2015. As you can see on slide 3 of the materials we had a solid year and ended on a strong note.

Before I review the details of our 2015 results, let me touch on a few highlights from the quarter. For the fourth quarter of 2015, we earned $0.37 per share, compared to $0.05 in the fourth quarter of 2014.

Slide 4 outlines the variances which drove the increase in our quarterly earnings per share. Looking at gross margin, higher retail sales, favorable weather, and the adjustment mechanisms were all positive contributors. Also, as we anticipated, lower operations and maintenance expenses in the fourth quarter of 2015 compared to 2014 improved earnings, largely due to lower planned fossil outages.

Now turning to slide 5, let's review some of the details of our full-year results. We delivered positive results in the top end of our guidance range, earning $3.92 per share compared to $3.58 per share in 2014, and earned a consolidated ROE of 9.77%, which was in line with our goal of achieving more than 9.5%.

Gross margin was a positive driver for the year, including favorable year-over-year weather. The adjustment mechanisms were also earnings accretive in 2015, including the lost fixed cost recovery mechanism, transmission, and our Arizona Sun program.

The Four Corners rate change that went into effect on January 1, 2015, was the largest driver in gross margin. However, keep in mind that the Four Corners rate change was largely offset in D&A.

Higher usage by APS customers in 2015 versus 2014 contributed to earnings. Weather-normalized retail kilowatt hour sales, after the effects of energy efficiency, customer behavior, and distributed generation, were up 7/10 of 1% year-over-year. 2015 was our strongest year for retail sales growth since 2008, including three out of four quarters in which combined customer and usage growth outweighed the impacts of energy efficiency and distributed generation.

Operations and maintenance expense lower in 2015 compared to 2014 due in part to our ongoing cost-management efforts. The largest reductions included a decrease in employee benefit costs and lower costs related to fossil planned outages.

Lower interest expense, net of AFUDC, was another benefit to earnings in 2015 compared to 2014. The decrease included reduced interest charges resulting from refinancing long-term debt at a lower rate, and higher construction and work-in-progress balances benefiting AFUDC.

Higher depreciation and amortization expense was a primary headwind to 2015 earnings as compared to 2014. As we reported all year, higher D&A decreased earnings due in part to the absence of the 2014 Four Corners cost deferrals and related 2015 amortization of the deferrals and the costs associated with the Four Corners acquisition in 2013.

Additional plant in service also reduced year-over-year earnings.

Because Arizona's economy is an integral part of our business story, let me highlight for you the trends we are seeing in our local economy, and in particular the Phoenix Metro Phoenix area. By and large, what you see on slide 6 is the continuation of the consistent growth trends we have been describing for you the last couple of years.

Job growth in the fourth quarter in the Metro Phoenix area remained above the national average, as it has for the past 18 quarters. As seen on the upper panel, Metro Phoenix added jobs at a 2.8% year-over-year rate. This job growth is broad-based, with the construction, healthcare, tourism, financial, business sectors, consumer services sectors each adding jobs at a rate above 3%. Notably the construction sector has been adding jobs in the last two quarters at a rate of above 7%.

Growth in consumer spending remains robust, and the housing market continues to strengthen. Our expectation for the Metro Phoenix housing permits can be seen in the lower panel.

In 2015, the housing market recorded its best year since 2007 for both total permits and the single-family sector by itself, with almost 22,000 permits and 15,000 permits, respectively. This level of single-family permit activity represents an increase over the prior year of almost 50%. As you can see on the slide, we expect the housing market to improve in 2016, with total housing permits within a range of 25,000 to 32,000.

In summary, the Metro Phoenix economy continues to grow steadily and is positioned for stronger growth in the next couple of years. As I have mentioned before,, Arizona and the Metro Phoenix remain attractive places to live and do business, especially as it is situated relative to the high-cost California market. 2015 was better than in 2014 in terms of job growth, income growth, consumer spending, and new construction; and we expect to see in 2016 to be better than 2015.

Reflecting this steady improvement in economic conditions, APS's retail customer base grew 1.3% compared with the fourth quarter last year, and 1.2% year-over-year. We expect that this growth rate will gradually accelerate in response to the economic growth trends I just discussed. Importantly, the long-term fundamentals supporting future population, job growth, and economic development in Arizona appear to be in place.

Now I'll review our earnings guidance and financial outlook. Last quarter we issued Pinnacle West's consolidated ongoing earnings for 2016, which we continue to expect to be in the range of $3.90 to $4.10 per share. The adjustment mechanisms, particularly transmission and the LFCR, along with modest sales growth and normal weather remain the key gross margin drivers.

O&M is above-trend in 2016. However, non-outage O&M spend remains flat.

As you may recall, last year we reported that we had moved a planned Four Corners unit outage from 2015 to 2016. 2016 includes major planned outages at both Four Corners and Cholla.

The planned 82-day major overhaul at Four Corners Unit 5 started in January, which creates a Q1 2016 earnings headwind of about $0.13 quarter-over-quarter. Keep in mind, this was factored into our guidance.

Overall our focus remains on our cost-management efforts as we look through 2016 and beyond. But the outages are a priority for us this year.

One other comment on O&M: the funded status of our pension plan remains strong at 88% as of year-end 2015. The continued implementation of our liability-driven investment strategy has helped us keep costs down. There is a slide in the appendix with additional details on our pension plan.

You will find a complete list of factors and assumptions underlying our guidance in the appendix to our slides, which are unchanged.

As Don mentioned, our balance sheet remains strong. I will outline our financing plan and how the impact of bonus depreciation is factored in.

We had already assumed a two-year extension of bonus depreciation that was incorporated into our rate base disclosures in the last earnings call. Our updated estimates can be found in the appendix, which show an incremental reduction in rate base of approximately $200 million in 2018 as a result of the bonus depreciation. However, the extension also results in approximately $550 million of total cash benefits to 2019, which provides financing flexibility over that time horizon.

In terms of capital expenditures, we anticipate APS's spend to average around $1.2 billion annually from 2016 to 2018, which will be primarily funded through internally generated cash flow. With this capital spending level, taking into account the bonus depreciation, we continue to expect our rate base to grow at an average annual rate of 6% to 7% through 2018.

Turning to 2016 financing, we plan to refinance a $250 million maturity in August and anticipate issuing of a quarter million (sic - see slide 14, "issuance to refinance $250 million") of additional long-term debt. Overall, liquidity remains very strong. At the end of 2015, neither Pinnacle West nor APS had any short-term debt outstanding.

In summary, given the strength of our balance sheet, coupled with the extension of bonus depreciation, we no longer forecast the need for additional equity. The net effect of bonus depreciation and the removal of equity leaves us relatively neutral from an earnings perspective. We will continue to review our capital forecast to identify additional investment opportunities as we move forward.

This concludes our prepared remarks. I'll now turn the call back over to the operator for questions.

(Operator Instructions) Dan Eggers, Credit Suisse.

Hey, good morning, guys. Don, just on the revenue per customer decoupling mechanism you talked about in your opening remarks, you said there were going to be some adjuster mechanisms as you go, to try to rebalance, to keep you guys whole. Can you just explain to me how that's going to work and how you propose for that to work going forward?

Jeff is sitting right here, Dan. I'll let him try on that one.

Sure. Dan, there was an extensive discussion in Arizona a few years ago around decoupling mechanisms in general. In our last rate case we had proposed that LFCR mechanism essentially from the settlement process.

But the way a revenue per customer mechanism would work is it takes into account all of the different adjustments: so weather, sales, as well as just other changes to -- essentially changes to the normal revenue requirement process. But what it does is it looks at it to accommodate customer growth, right?

So as customers grow and we're making additional investments into the system, we need to be able to pick up the additional costs that come from that growth. Does that make sense?

I got it. Yes, that makes sense. Okay.

Don, you also said you guys are going to change the peak period from a demand charge perspective or a pricing perspective. What hours are you looking to move that to?

Have we arrived at those yet, Jim?

Still working through, obviously, the stakeholder process, but pushing it more towards later in the day, because that's where you see the need to essentially focus on the peak.

Okay, so the evening, early evening hours, I guess. Is that what (multiple speakers)?

Yes, early evening. We've got at current rates the primary time use rate is a 12 to 7 peak period, and so it both shorten that up and then move it out later in the day.

That's partly responding to the duck curve, what you see in the wholesale market out here from the overgeneration that happens in the middle of the day.

As our summer peak, this last year was 5:00 to 6:00 in the afternoon, early evening, and that's been typically the time of hitting our peak.

Okay, got it. I guess, how do you guys see this working, I guess, with all the parties involved? Obviously the Nevada process has gotten challenged and maybe a little bit sloppy, in retrospect.

Do you see common ground where this works to get to a fair conclusion all the way around? Or this is probably going to be another contentious process?

Well, I think there will be some additional element in this than is typical. But the last few cases have been very well organized and executed by all 22, 23 parties. That's certainly, I think, the direction we, the staff, [BRUCO], and the vast majority of the parties would intend to proceed.

Should we be watching the UniSource case as indicative of what you guys will try and accomplish as well?

UniSource is going to be an important discussion. That's the first case in a state that's really focused on the changes to residential rate design. That's why we've got four witnesses in that case. So obviously that's probably a case to watch.

Got it. Thank you, guys.

Shar Pourreza, Guggenheim.

Good morning, everyone. Just on the shifting of the demand rates to later in the day, is there any potential impact if we get a successful launch of the EIM? Can that peak demand period smooth out a little bit?

No, Shar; this is Jeff. The EIM helps balance really inter-hour. It's not affecting the underlying wholesale markets.

So what you see in that shift -- and it's not the shift of demand rates, but that shift of the time-of-use period, the peak period, out to later in the day is reflecting that ramp that comes later in the day from the duck curve.

Got it; okay. That's helpful. Then just thinking about -- have you -- are we anywhere in the process as far as looking at gas storage opportunities right now around APS?

No, nothing in the process.

Got it; okay. Then lastly, the toll does expire I think next year. Any updates there, far as looking at newbuild or acquiring in-state generation or another toll?

Well, we will be going out next month, I believe, with a [tolls] resource RFP for -- with a beginning date later this decade. It's really designed not only the heat rate options, which are not flexible that have been -- or will expire; and then we have a toll in 2016 and a toll in 2019.

So this process -- and we'll get, being all-resource, I expect to see various resources in there; and we'll evaluate that, and evaluate where we are and what we need, and we'll move from there.

Okay, got it. But newbuild is still an option?

Yes, I think we have great optionality here. We can extend the tolls short-term, long-term. We could newbuild if it was the right thing to do. But right now we'll just see what comes into the RFP.

Excellent. Thanks, Jim and Dn.

Michael Weinstein, UBS.

Hi, guys. Hey, in regard to the shifting of the time-of-use rates to later in the day, how much value do you really see shifting or being shifted as a result of that change?

This is Jeff. What you're trying to do -- we have a fuel adjuster, right, which is going to pick up essentially the cost of the fuel burn. But what you're trying to do in shift that out later is to align the customer response with when we see the need for, essentially, conservation on the system.

So what it's trying -- go ahead.

No, I guess what I'm asking is: How much value is being lost right now by having the time-of-use rates peaking too early in the day?

It's a customer issue. If you have the time-of-use rates fixed, you don't have essentially -- for example, on the solar side you're not providing credit at noon at a peak rate when the wholesale market is negative.

Oh, I see. So this is -- I guess what I'm trying to find out is how much money is the utility losing by providing peak pricing at times of nonpeak usage.

Yes, Michael, there is no money lost for APS. It's really a shifting and sending the right price signals to -- what was done they were put in before to what we're seeing in today's marketplace. It's an alignment issue.

Do you have any sense of how much of the shift -- how much in dollar terms that shift is?

It's really a rate design issue, so it's part of the rate design process. We're trying to align the retail rates with the wholesale market.

Okay. Also, Doug -- yes, I was just going to shift to another question. But we can talk more about that outline.

Yes, I was just going to say the issue is its rate design, so it's revenue neutral.

I understand it's revenue neutral. I'm just trying to get at what's the impact on solar, on the third-party solar in the state and how -- what's the impact on them in terms of cost shifting?

What kind of rate shift will they see as a result? How is this going to impact adoption rates?

On a separate topic, Doug Little was recently in New York City and he was talking about reducing regulatory lag, as a high priority. This goes along the lines of you applying for a decoupling mechanism. I'm just wondering, are there other forms of rate lag, structural rate lag, that you could seek to eliminate under the new Commission makeup?

We've made a fair number of changes really over the last probably two or three rate cases that have picked that up. A lot of it comes in the time to process the case and trying to get that processing time down to the year or so.

Things we've done with that are, for example, prefiling the discovery. So we don't wait, file the case, wait for three or four months, and then begin the discovery process. So a lot of that's been worked out.

Obviously, adjuster mechanisms and how you can work on adjustment mechanisms can help smooth that even further. So that's probably going to be some of the discussion you'll see, and that's part of what we've been talking about with stakeholders.

Are there any important differences between your rate design and the UNS case, the UNS rate design, that we should be looking for as we watch that case?

I think the general issue that's coming up in UNS is how it's going to apply broadly across the customer base. The Commission staff have proposed that the three-part rate design be applied to all residential customers, and that's one of the key issues to look at, I think.

Okay, thank you.

Ali Agha, SunTrust.

Jim, first I wanted to clarify your comment when you said with bonus depreciation extension equity needs have been taken out of the equation. Does that mean through this 2018 period? Or when at the earliest do you now see any need for equity?

I don't see any equity needs, Ali, through the planning horizon.

And that runs through 2018?

Yes. Well, through the end of this decade, frankly.

End of this decade? Okay. Then secondly, given that fact, if I look at your updated rate base numbers, if I take 2015 as the starting point, the 2015 through 2018 CAGR is about 6%. So should we assume EPS should pretty much follow that, since there is no equity dilution to factor in? Or how should we think about the EPS CAGR there?

I think as we've said in the past, EPS CAGR is somewhere between rate base growth and dividend growth, as we think about those as your two boundaries.

Dividend growth you've talked about 4% annually, if I correct recall correctly.

5% was the last dividend increase.

Okay, okay. Then a question to you, Don. Wanted to get your view. We've seen a pickup in consolidation in the utility space. We've seen very large premiums being paid out there.

Just wondering what your perspective is. Do you see a role for Pinnacle West in that consolidation process we're seeing out there?

Well, you're right, there's a lot going on out there. But we don't really comment on M&A.

I will say we're focused on our excellent operations and continuing that. We believe growing earnings will provide shareholder value without combining operations with another entity.

But would you agree with the assessment that valuations that are being paid appear excessive? Or do you think those are reasonable out there?

I think each one of them is unique to the specific transaction.

Fair enough. Thank you.

Charles Fishman, Morningstar.

Thank you. Jim, I just want to confirm. ROE for 2015, you said 9.77%; and I'm assuming that's weather-normalized?

No, that's based on the $3.92.

Oh, okay.

And that's at the Pinnacle level.

Okay, okay. So it's a book level?

Yes.

Okay. Do you have it for -- well, I'm looking at my model and I have 9.6% last year. Am I comparing apples to apples?

I think that's pretty close, yes.

Okay. That's all I had. Thank you.

Andy Levi, Avon Capital.

Actually all my questions have been answered. But it's nice to hear a call where there are no -- where you make your numbers and that your forecast is good. That there is no, like, pension plugs or anything like that.

So that's it. All my questions have been answered. Thank you.

Thanks, Andy. We like it that way, too.

We have no further questions at this time. I would now like to turn the floor back over to management for closing or additional comments.

Thank you, Christine, and thanks, everybody, for joining us today. We will talk to you soon. That concludes our call.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.