Pinnacle West Capital Corporation (PNW) Q2 2015 Earnings Report, Transcript and Summary

Greetings, and welcome to the Pinnacle West Capital Corporation 2015 Second-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 for Pinnacle West Capital Corporation. Thank you Mr. Mountain, you may begin.

Thank you, Jerry. I would like to thank everyone for participating in this conference call and Webcast to review our second-quarter 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 using are available on our Investor Relations Web site, 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 second-quarter Form 10-Q 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 the contained in our disclosures. A replay of this call will be available shortly on our Web site, and it will also be available by telephone through August 6. I'll now turn the call over to Don.

Thanks Paul, and thank you all for joining us today. Before Jim discusses the second-quarter results, and our updated financial outlook, I'll provide a few operational and regulatory developments. Our operations continued to be strong this summer, despite a couple of short-lived but powerful storms here in Arizona. On the regulatory front, we are focused on rate modernization, and exploring technologies that may improve customer options while maintaining the reliability of our system. The Palo Verde Nuclear Generating Station had a solid first half of the year. In early May, Palo Verde completed the Unit 3 planned refueling outage in less than 30 days. This is the third time that Palo Verde has completed a planned outage in less than 30 days, and the first time for Unit 3. We have two transmission projects to update you on. First as we call it, Hang 2, or the Hassayampa to North Gila 2 line, a 500 KV transmission line was energized in late May, as we planned. This 112-mile line is an important project for reliability in southwest Arizona. Second, the Cal ISO announced the winner of the bidding process for the Delaney to Colorado River transmission line earlier this month. Our bid, submitted by TransCanyon, was not selected. The winning bid was cited by the Cal ISO as having the lowest revenue requirement of the five bids received. We are analyzing the process to inform our bids on other projects, but we were comfortable with the discipline our team demonstrated on the DCR bid. We did not have CapEx for this project in our projections. We will continue to pursue transmission development opportunities in the Western United States consistent with our strategy, and look forward to future successes with this team and our counterparts at BHE US transmission. Solar also continues to be an important area of investment and research. Our utility scale program, AZ Sun has two 10-megawatt projects in the Phoenix metropolitan area that are expected online in the third quarter. These two projects will bring the program total to 170 megawatts. Our APS solar partner program, where APS will be installing and owning residential rooftop solar on 1,500 homes, equal to 10 megawatts, is now being rolled out. We had our first installation earlier this month, completed by one of the local Arizona installers who is also a member of the Arizona Solar Deployment Alliance. Our team continues to sign up customers on the selected feeders we've chosen for this program. This innovative program allows us to conduct research in collaboration with EPRI, the Electric Power Research Institute, on maximizing the efficiency and effectiveness of distributed solar generation, and its interaction with the grid. Our understanding in this area will better inform our efforts to create a modernized rate structure tailored to our customers' energy needs. On a related note, we are in the early stages of a 200-home rate study intended to provide insights on how solar, storage, and other technologies interact with demand rates, aimed at reducing electricity used during peak periods. Similar to our 10-megawatt program, we will work with local Arizona installers on this program. APS will own 75 of the systems, while another 125 systems will be customer-owned, with those customers receiving an incentive for their participation in the research project. This is an exciting new program that will allow us to realize several benefits. First, customers can take charge of their energy envelope by learning how to manage their energy use during peak times. Next, local installers can remain viable in our economy, and evolve as the market and new technologies evolve. And here at APS, we can better learn how to manage these advanced technologies, and the demands they place on our system, all of which will enable us to continue to safely provide our customers with the reliable electricity they've come to expect. Both of these programs are leading edge in our industry and will be the first time a utility has had full control of a large number of advanced inverters in the field to perform testing. APS is partnering with several providers to drive this technology in a direction that makes it easier to integrate and results in greater benefits for both customers and grid reliability. On a related note, in the recent JD Power residential survey, APS improved its score in all six of the study's categories, and ranked in the top quartile among 54 large investor-owned utilities. On the regulatory front, we're focused on advocating for rate modernization and laying the groundwork for our rate case filing, which we still expect to file next year. Rate design continues to be an important priority across the country. Other Arizona utilities have made filings to modernize their rates, and California has taken steps to begin modernizing their rate structure. UniSource Electric followed a rate application on May 5, which includes several proposed changes to rate design in line with what we have advocated for, and similar to what Salt River Project implemented this past spring. Tucson Electric and Trico are expected to file a rate application later this year, so both of them recently withdrew their net metering specific filings. The proceedings at each of these companies will be interesting to monitor; however, our grid access charge filing is based on a precedent we have from the 2013 net metering decision. Since then, we have seen steady growth in rooftop solar applications and installations, with May and June showing record levels. Our proposal would not fully resolve the cost shift, but rather is intended to be an interim solution until the issue is more fully addressed in the next rate case. Other components of the future rate design would include use of the demand charge on a broader scale, and sending better price signals to customers by modifying the time of use rate structure. Let me conclude by saying we're excited about the opportunities ahead for our customers, our employees and our shareholders. We have a clear investment plan which gives me confidence in our rate base growth. Given the unique strength of our balance sheet, we are well-positioned to execute on our plan and also return capital to shareholders in a predictable and sustainable manner. I'll now turn the call over to Jim.

Thank you, Don. The topics I will cover today include a discussion of our second-quarter financial results, an update on the Arizona economy, and a review of our financial outlook. Slide 3 summarizes our GAAP net income and ongoing earnings. For the second quarter of 2015, we reported consolidated ongoing earnings of $123 million, or $1.10 per share, compared with ongoing earnings of $132 million, or $1.19 per share for the second quarter of 2014. Slide 4 outlines the variances in our quarterly ongoing earnings per share. I'll highlight a few of the more significant drivers. Lower gross margin decreased earnings by $0.02 per share. I'll cover the drivers of our gross margin variance on the next slide. Higher depreciation and amortization expenses decreased earnings by $0.07 per share. Similar to the first quarter, this variance includes the absence of the 2014 Four Corners cost deferrals and related 2015 amortization of the deferrals and costs associated with the acquisition price. G&A expenses were also higher due to additional plant in service. Lower interest expense, net of AFUDC, benefited earnings by $0.04 per share. The decrease largely reflects reduced interest charges resulting from refinancing long-term debt at a lower rate. There is not an operations and maintenance expense variance on this slide, since it is flat year-over-year, as higher generation expenses, primarily due to the effects of planned maintenance, were offset by lower employee benefit costs. Turning to Slide 5, I'll cover a few of the key components of net decrease of $0.02 in our gross margin. Weather-normalized retail kilowatt hour sales, after the effects of energy efficiency, customer conservation, and distributed generation increased 0.3% in the second quarter of 2015 versus 2014, although the earnings impact was immaterial. Collectively, the adjuster mechanisms continued to add incremental growth to our gross margin as designed, contributing $0.10 per share primarily to the Four Corners adjuster that went into effect on January 1. Offsetting Four Corners expenses are included in the other drivers, primarily D&A, which I mentioned earlier. The effect of weather variations decreased earnings by $0.06 per share. This year's second quarter was milder or less favorable than normal, while the second quarter of 2014 was warmer, or more favorable compared to normal conditions. In total for the quarter, cooling degree days on an 80-degree base were on par with normal conditions, but this one statistic does not do justice to the variance in daily weather we experienced throughout the quarter. In particular, the entire month of May and the first half of June were quite mild, followed by a snap to high temperatures in the second half of June. While we saw usage behavior very much in line with expectations, once the hot weather arrived in mid-June, prior to that period, weather-sensitive usage remained well below where our models would have predicted, an indication that our customers took advantage of the mild conditions to essentially not use much air conditioning at all. With 21 days in May below 95 degrees for the high temperature, and most overnight lows in the low 70s or 60s, the typical heat buildup we would expect to see did not materialize, and allowed customers to ignore a handful of warm days that did occur during the month. The net effect of lower transmission revenues decreased quarterly results by $0.04, driven by a formula rate true-up in the second quarter of this year, included in our annual filing in May. We anticipate transmission revenues will be a positive driver for the full year. As a reminder, both the O&M and gross margin variances exclude expenses related to the renewable energy standard. Energy efficiency and similar regulatory programs, all of which are offset by comparable revenue amounts under adjustment mechanisms. Also, the impacts of our non-controlling interest for the Palo Verde lease extensions are treated in a similar manner. The drivers I discussed exclude these items, so there was no net impact on second-quarter results. Slide 6 presents a look at the Arizona economy, and our fundamental growth outlook. Arizona's economy continues to grow, much like it has in the past several quarters. Job growth in the second quarter in Arizona in the Phoenix Metro area remain data were above the national average, as they have for 14 of the last 16 quarters. As seen in the lower right-hand side of slide 6, Arizona added jobs at a 2.2% year-over-year rate. For the first six months of 2015, Arizona has added jobs at the fastest rate since the first half of 2007. As I've mentioned before, business services, healthcare, tourism, and consumer services are the sectors with the strongest job growth. Each of these sectors is adding jobs at a rate of between 3% and 7% over the prior year, and is helping to fuel continued demand for office and retail space in metro Phoenix and elsewhere. Absorption of vacant office space in Metro Phoenix has averaged between two million and three million square feet per year since 2011, and similarly, absorption of vacant retail space has run at about two million square feet per year. As seen in the upper right-hand side of Slide 6, vacancy rates in these sectors continue to work their way down from their highs in 2010, and new investment activity in these sectors has picked up. Almost four million square feet of office space is currently under construction, virtually all of which is scheduled to come online in late 2015 or 2016. A multi-building development by State Farm Insurance at Tempe Town Lake accounts for half of this activity. At only half a million square feet, retail construction can be considered soft at the moment, but with the vacancy rate below 8% in several sub-regions within the metro area and strengthening single-family home market, we expect retail construction to accelerate in the coming quarters. Finally, as I have described before, the industrial building sector remains a source of strength for the Valley. Over the last couple of years, the amount of new industrial space added to the market has ranged from four million to eight million square feet per year, all of which has been absorbed. At 11%, the industrial vacancy rate is at its lowest level since the beginning of 2008. Only two million square feet of industrial space is under construction currently, so we fully expect industrial vacancies to continue to decline and motivate additional construction in the coming quarters. Turning to the residential sector, metro Phoenix housing permits were relatively flat for the first six months of 2015 on a year-over-year basis. However, there were some sizable shift between the single-family and multi-family sectors. Single-family sales and permit activity were up about 35% over the prior year, while new development in the apartment sector slowed considerably. Our expectation for year-end housing market permit activity can be seen in the panel at lower left. The dynamics we are seeing in the residential housing market today are influenced by incredibly tight vacancy levels in apartments, rapidly increasing apartment role rates, continued low interest rates maintaining a higher level of single-family home affordability, and the expiration of the mortgage blackout period for the first substantial wave of foreclosed homeowners. Back in 2008, 37,000 homeowners lost their homes to foreclosure in metro Phoenix alone. In 2009, 43,000 homes were foreclosed upon. After seven years, these families will now have much more accessibility to owning a home while homes remain quite affordable. In addition to the favorable trends in job growth and the prospects for new construction, Arizona consumers are also participating in the recovery. Real consumer spending on retail and restaurant and bar sales increased by 10% in the second quarter, the best rate in 10 years. Purchases were led by home and garden sector, and new auto sales. Steady income growth, improving consumer confidence, and lower gas prices are all contributors to this most recent surge. In summary, we can see continued healthy job growth, especially in certain sectors, providing the momentum for absorption of commercial space in vacant housing, which in turn is providing for an environment of increased investment and new development. As I have mentioned before, Arizona and metro Phoenix remain attractive places to live and do business, especially as it is positioned relative to the high-cost California market. We expect 2015 to be better than 2014 in terms of job growth, income growth, consumer spending, and new construction. Reflecting the steady improvement in economic conditions, APS's retail customer base grew 1.2% compared with the second quarter last 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. Slide 7 outlines our financing activities. Our balance sheet continues to be one of the strongest in the industry. We are now rated A-minus or better at all three rating agencies. In May, Fitch announced its upgrade to APS's senior unsecured rating to A from A-minus, as well as similar upgrades to Pinnacle West and APS's corporate credit rating. Additionally in June, Moody's upgraded APS's senior unsecured and corporate ratings to A2 and Pinnacle West's corporate credit rating to A3. In connection with these rating actions, the rating agencies cited the Company's strong financial and credit profile, as well as increasingly constructive and supportive regulatory environment in Arizona. In terms of our recent financings, on May 19 APS, issued $300 million of 10-year, 3.15% senior unsecured notes. The proceeds from this sale were used to refinance the $300 million 4.65% May maturity. Also in May, APS purchased all $32 million of the Maricopa County 2009 Series B Pollution Control Bonds which we may later remarket. Overall, liquidity remains very strong. At the end of the second quarter, the parent Company had no short-term debt outstanding, and APS had $158 million of commercial paper outstanding. Finally, I will review our earnings guidance and financial outlook. We continued to expect Pinnacle West's consolidated ongoing earnings for 2015 will be in the range of $3.75 to $3.95 per share. A complete list of factors and assumptions underlying our guidance is included on Slide 8. The adjuster mechanisms and cost management remain important drivers, particularly in the second half of the year. We have maintained our earnings per share guidance but adjusted certain line items, primarily due to what we have realized year-to-date for gross margin and interest savings, while moving planned coal unit outage from 2015 into 2016. Our guidance assumes normal weather. Our rate base growth outlook remains 6% to 7% through 2018, and we continue to forecast that we will not need additional equity until 2017, at the earliest. This concludes our prepared remarks. Operator, we'll now take questions.

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] The first question is from Shahriar Pourreza, Guggenheim Partners. Please go ahead.

Good morning.

Good morning, Shahriar.

On the rate design changes that you're seeking, how should we think about that from a timing perspective, with a potential filing for GRC next year? And is there an opportunity to reach a conclusion with the rate design prior to you filing?

This is Jeff. So part of the discussion that has happened out here, is when you make a more structural change in rate design to be more sustainable, you do that in a general rate case filing. And so that would be part of, normally you go through revenue requirement phase and then rate design is the second phase of the filing. And so I think that's what we're expecting to happen right now.

Next question

The next question is from Dan Eggers, Credit Suisse

Hey. Good morning, guys.

Good morning, Dan.

Hey, just on the housing outlook and the home builders have been pretty constructive on the Phoenix market, what do you think is the follow-through if you look at what's queuing up for this year and for next year? Is that having an effect on moving up the distribution CapEx for next year, just you're seeing more pull through or what's the linkage of those two right now?

We're not, Dan, seeing a big increase in distribution spend currently as we are queuing up for the market, but keep in mind that there are lots out there that are already improved, meaning they have basic services already installed. We think that the beginning of the customer growth will take relatively less capital, although as the inventory builds, we will have to move up distribution capital, and hope to capture as much of that in the next rate case as we can.

Okay. And on guidance for this year, that's taking -- that's excluding the $0.09 of negative weather that you have incurred this year. Is that correct?

In terms of the guidance for this year, I really see four key elements of driving growth in the second half. First of all, our adjuster mechanisms, so we'll see a higher benefit year-over-year from LFCR. Obviously, Four Corners came in this year, Arizona Sun, as we complete projects in metro Phoenix, and then the TCA will be higher as we look toward accruing a FY16 filing. We expect to see positive usage in the second half, year over year. We are, as I said in my remarks, we have moved a fossil outage so we expect O&M to be down, as we have less planned maintenance in the fossil fleet this year. And then, we expect the interest savings to continue throughout the year. So that's really what's driving the second half of the year. In terms of weather, I'd say this. If you remember 2011, we were $30 million other under on weather in the second quarter. We reduced guidance, and we made it all back in the third quarter. So weather is what it is. We'll continue to manage those factors I just mentioned.

Okay. Got it. Jim, can you explain the transmission adjustment, the $0.04 negative? What caused that true-up to go negative on you this year?

Well, I think if you remember, as we file every year at FERC, we plan what the next fiscal year is, and we can accruing that increase as we're earning it throughout the year. The big issue in the May true up was really the late passage of the deferred tax which reduced rate base and reduced our ask, so that was a catch-up adjustment. Every year we've had catch-up adjustments, most of the time, they're very minimal. This just happened to be a bigger adjustment than we normally have.

Okay. Very good. Thank you, guys.

The next question is from Julien Dumoulin-Smith, UBS. Please go ahead.

Hi, good morning.

Good morning, Dan.

I suppose first question, just in terms of the grid access charge, what kind of a decision are we looking for here? Are we going to get tangible numbers? A - Jeff Guldner Julian, this is Jeff. The next step in that proceeding is going to be a recommended opinion order from the administrative law judge. And the issue that's teed up right now is procedural. So it's do we move forward with a substantive proceeding on increasing the grid access charge from its current level, or do we wait until the next rate case and do it through rate design? And so we haven't seen, we're expecting it soon, but we haven't seen anything yet from the judge.

Got it. All right. Excellent. And second, moving back to transmission here for a second, I'd be curious what kind of complementary opportunities do you see this latest large-scale line back to California, as well as can you elaborate a little bit more on the other opportunities inside the context of your partnership here in the Western US, that you're evaluating?

I would comment on pipeline in terms of our partnership with Berkshire. Much like DCR, which we're very disappointed we didn't win after working four years on that development, on that subject I would say that us and our partners are very proud of our disciplined approach, but there's other opportunities in the pipeline much like DCR. DCR was an economic project. Much of the other we're pursuing at this point will be reliability type projects. And so I would say our partnership continues, and we're pursuing other types of transactions.

Got it. Are there any complementary opportunities arising out of DCR?

Not for us. No.

Okay. Great. And then lastly on the solar front, you all have obviously had a pilot going on for a little bit here. I'd be curious, either outside of the context for a rate case or in the context of the subsequent rate case, is there a thought to scaling up your pilot to a full-scale deployment of a rooftop program at APS?

We'll be looking at that as this pilot program folds out over the next couple months. Certainly a potential opportunity.

Got it. Although presumably that would necessarily need to be addressed in any more formal filing? IE the rate case?

Not necessarily. We'll get to that when we get to it.

Okay. All right. I won't belabor the point. Thank you very much.

The next question is from Greg Gordon, Evercore ISI. Please go ahead sir.

Thanks. A couple of my questions have been answered. I just had a few more. I just wanted to get a clarification, the earnings guidance, Dan asked a question, Eggers asked the question on earnings guidance. Your earnings guidance reflects what's happened with the weather year-to-date, and you still expect to be inside your guidance range; correct?

Correct.

Okay. The second question was, just looking at the detailed slide on page 16 of your CapEx forecast, it moves around every quarter, and it's moved around a little bit again this quarter, and distribution CapEx has moved and traditional generation CapEx has moved up a bit in 2016. Can you comment as to -- I'm sorry, distribution has moved up, and generation has moved down a bit. Can you comment on whether that's a pull forward or whether that's other factors?

Distribution, we pulled about -- a few million dollars from distribution into 2016 from 2017, and with the Ocotillo being delayed a year, we pushed back a little generation to 2017. All in all, I think if you look and those all up, the projection for the three years has not changed. It's really been cash flow between years.

Right. Great. And then on cost profile, notwithstanding just the deferral of an outage into next year from this year, you still have a bunch of programs in place to try to keep O&M flat relative to kilowatt hour sales growth. Correct? So if you were to have some fluctuation either up or down in expected economic demand for power, you feel like you have the ability to flex your O&M to maintain your margins?

Yes, we do, Greg.

And then finally going into next year, and up until the next base rate case is finalized, you still do have some significant cost saves that you'll be able to capture from the Palo Verde lease refinancing; correct?

Right.

Okay. Thank you very much.

Thanks Greg.

We have a question from Charles Fishman, Morningstar.

Hi, Thanks Don, you mentioned the UNS Tucson filing. How good of a proxy is that for any kind of change in rate design? As far as similarities of solar penetration, and things like that?

I don't think it's a very good proxy. Their service territories are very much different. The sources of generation and traditionally, the rate design has been significantly different in Tucson than across APS. Jeff may be able to add a little more color to that.

Charles, this is Jeff. Remember, we've got about half our customers on time use rates, and we're also one of the only utilities in the country that has a significant amount of residential customers on a demand rate, and so we've got about 10% of our customers today on a residential demand rate with time of use. And so we certainly are going to be involved in the proceeding in Tucson and watching that, but we have historically had different rate structures than both TEP and SRP. And so we'll watch it, and we'll see if -- there's obviously procedural things we'll want to be paying attention to, and conceptual stuff that we'll be talking about.

Okay. Thanks. That saves me some work looking at it. That's it.

We have a question from Ali Agha, SunTrust. Please go ahead sir.

Thank you. First off, I just wanted to clarify the timing on the interim fixed charge that you have applied for. I think I heard you say ALJ is to opine on just the logistics of when that should be looked at. I know you'd asked for an August implementation, so is that not realistic now or how should we look at the sequence of timing?

Ali, it's Jeff. Originally, we had asked for an August implementation date. Now, the process would be if the ALJ issues a recommended decision that says -- and the commission decides based on that decision, the ALJ will issue a proposed decision, the commission will presumably hear it at an open meeting, and then the decision would be if you move forward, you're going to have a proceeding after that. So that's going to push it into later in the year, at least.

Okay. Got it. Separately, Jim, if you look at your results on an LTM basis, what's the earned ROE you'd be earning right now, based on the calculation, the way you look at ROE?

Weather normalized would be in excess of 9.5%.

Okay. But the weather impact in last couple of quarters will pull it down?

Yes. But again, you have to weather normalize the quarters. In both the first two years of this year and the last two quarters of this year, and last two quarters of last year.

Right. Okay. And then, you had mentioned that you expect, as you go through this year and beyond, customer growth, usage patterns, et cetera, to pick up. So far as you've been looking at the data, is there following that pattern, looking in July and into the rest of the year as well, I think 0% to 1% from a weather-normalized load growth perspective, you were looking at for electric sales, any more granularity in that? Should we think of midpoint of that or how is it's trending as you're looking for the rest of the year?

Well, as we build our forecast for 2015, we expected we'd see acceleration of customer growth and sales growth throughout the year. So as we look to the second half of the year, we would expect sales growth to be higher than the first half of the year. And what materializes, we'll wait and see, but we feel pretty confident that we'll be between 0% and 1% sales growth.

Okay. And then last question, I know you had mentioned it in your comments as well in terms of equity 2017 at the earliest. So is that going to be driven more by credit matrices and liquidity profile, as opposed to the regulatory needs that you've said before you don't need to equitize for the rate case filing? What would be the trigger in your mind, when it's the appropriate time to raise new equity?

We'll certainly look at our credit metrics. And we'll look at where we are in the regulatory cycle, obviously, with the rate case filing in 2016. But we're sitting here today with an equity ratio at APS of about 56%. Very strong balance sheet, so we have a lot of flexibility in financing our CapEx program with long-term debt.

All right. So given that, reiterating, you said before you don't need any equity for the timing around the rate case, basically?

Correct.

Thank you.

The next question is from Steve Fleishman, Wolfe Research. Please go ahead sir.

Just wanted to clarify, if you look at your slide on the factors and guidance for 2015, so, it looks like you lowered gross margin $30 million versus last quarter for the year. You, to the positive, lowered O&M by $20 million and to the positive lowered interest by $20 million. The $30 million on lower margin, is that just the weather impact year to date?

It's weather. It's also transmission. And keep in mind, we would have had originally all of the Four Corners rate increase that we got about $8 million less, so we incorporated that in this quarter as well.

Okay. And then the lower O&M of $20 million is that pretty much the delay in the outage to 2016?

That's correct.

And then the interest savings, is that just all refinancing benefits?

Yes. We've realized significant interest savings in the first half of the year net of AFUDC. So we expect that to continue.

Okay. And net interest savings is an ongoing benefit?

Until the next rate case.

Okay. Got it. That was it. Thank you.

The next question is from Michael Lapides, Goldman Sachs. Please go ahead sir.

Hey guys. Congrats on a pretty good quarter. Real quickly, looking at the transmission rate change, I'm looking at Slide 17, that $18 million, that, basically the best way to think about that is seven months of that in 2015, five months of that in 2016, but did you actually book the charge for all of that in this quarter, or will it flow through from an income statement impact over the next 11 months?

We booked the true-up adjustment in May. So I would think of it more as a one-time. In that regard, it will flow-through to FY16, but we're also booking on top of that reduction, the increase we expect to file in FY'16. So net-net, it's a positive for us.

I hate to respond this way, but I'm totally confused.

Okay. What we'll do, we'll take it off line and we'll have Paul call you after the call and walk you through the timing of our PPA.

That sounds fine. One other item. Any update, I know you've talked at length about the need for Ocotillo. But any update at all on either a process for a need for other gas-fired generation, whether it would be under PPA or whether it would be something you would actually go out in the market and buy and own, if you could get it at an attractive price, or do you feel that once Ocotillo's done, you're good through the end of the decade?

We have a couple of significant PPAs rolling off by 2020. We have the 515 megawatts at Gila River in 2016. And then we have a toll on Arlington through the summer of 2019. Obviously, we'll have to -- we'll look at how we replace those that capacity in the context of our reserve margin, and we feel like we have great optionality as we move forward, as it relates to a PPA or some other outcome.

Do you have to file and go through an RFP process to either replace either the Gila or the Arlington PPA?

No. So we don't follow the California process. That's not done here. We do an IRP, so there's an IRP where we talk about it. And then we follow essentially best practices when we're out doing procurement of power resources. But it's not like it's strictly regulated. It's like the California process.

Got it. Okay. Thanks. I'll follow up with Paul off-line. Much appreciated.

The next question is from Jim Von Riesling, Mizuho.

Hey guys, good afternoon.

Hi Jim.

Hey, two quick questions. The first one is, could you just talk about the cash flow impact an extension of bonus depreciation might have on you?

So what passed the Senate, which would be a two-year extension is approximately $200 million of cash, and you can think of about $100 million a year that we would realize from the extension of bonus depreciation.

Fair enough. And then second question is, given the fact that the interest expense is coming down so much, net of AFUDC, where do you think your embedded cost of debt is going to be at the end of the year?

I don't know. It will be roughly in the 5% range. Down from high-5s in the last case.

Okay. Appreciate it. Thank you.

The next question is from Paul Patterson, Glenrock Associates.

Hi. Good morning. Most of my stuff has been asked and answered, but I want to follow up on a few things. One was on Ali's question about the sales growth. I understood what you guys said about 2015, but I'm wondering with this 0.5% to 1.5% through 2017 as being a potential range, has that changed at all?

It has not changed from the prior guidance. Obviously this year, it's 0% to 1%, 0.5% to 1.5% by definition means just acceleration through 2017 of growth.

Okay. So what we've seen in terms of the weakness so far, you don't think that's going to -- there hasn't been any change, in terms of where you might see that range?

No.

Okay. And then on the DCR, it sounded that you were talking about the potential for reliability projects. But that seemed to indicate that perhaps because of your experience, and I just want to check on this, that you're not perhaps interested in the kind of opportunity that DCR had. And I'm just wondering if you could talk about what the takeaways from this process have been. Is it just basically Abengoa and Starwood? What would you say was their competitive advantage, was it simply cost of capital? What do you think is the dynamics in that, if you could share with us your thoughts about any…

I think the Cal ISO cited that Abengoa Starwood partnership would have the lowest revenue requirement over the life of the project. It's simply a cost and I guess as we look at what we did in the four years of development, we're very comfortable with our process, and our bid. And we are not going to go out and buy projects, just for the sake of buying projects. We're going to continue to focus on earning a strong return on a project that we can comfortably site and build in the timeframe and a dollar amount we bid.

I understand, but I guess what I'm trying to understand, I mean, I saw the Cal ISO report. What would you say was their competitive advantage? Obviously, they came in at a lower cost, but is that because their return requirement you think is less, or do you think in general that there was some deal in terms of the ability to construct these things or what have you? I'm just trying to get a sense as to what the competitive environment is, and whether what you saw happen there, and it's not just them, there are other competitors, whether you think that isn't going to be an area of interest going forward, in general? Do you follow what I'm saying, or is there something unique to that situation?

This is Mark Schiavoni. To answer your last question first, no, we're open to all projects. This is the first one that's gone through this type of process. So there's things to learn as a result of what happened, not just for us, but there were five finalists, as you may be aware of. And until we can look at the structure of what they did, it's very hard for us to sit here and really try to answer your first question, as far as what did they do that we didn't do or should be doing? That will come in due time. We've had conversations with Cal ISO. We've opened that door. We want to learn from it. And as Jim said, we're not going to increase our risk, just to get a project. We're going to do things the way we've always done it, measured risk. And then bids for it, for whether it's reliability or economic. It really doesn't matter to us. And our partner feels the same way. So we're confident that we'll continue to play in this space for the near-term.

Okay. That's great. I thought maybe you guys had more insight on what was going on there than I did. So I appreciate that. We'll find out maybe more later. Thanks.

Thanks. This is Don. Let me underscore what Mark said here, both we and our partner at Berkshire are very disciplined in this approach. And we're here to make thoughtful investment decisions, and not to buy a project. And this is one of many to come.

Okay. Thank you very much.

Mr. Mountain, at this time there are no further questions. I'd like to turn the floor back over to you.

Okay. Thank you, everyone. That concludes our call and we'll talk to you soon.