Pinnacle West Capital Corporation
Q2 2011 Earnings Call Transcript

Published: 2 Aug 2011

[Operator:]

Greetings and welcome to the Pinnacle West Capital Corporation Second Quarter 2011 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Becky Hickman, Director of Investor Relations. Thank you. Ms. Hickman, you may now begin.

[Rebecca L. Hickman:]

Thank you, [Christine] and thank you everyone for participating in this conference call and webcast to review our second quarter earnings, recent developments and operating performance. Our speakers today will be our Chairman and CEO, Don Brandt; and our CFO, Jim Hatfield. Don Robinson, who is President and Chief Operating Officer of APS, is also here with us. Before I turn the call over to our speakers, I need to cover a few details with you. First, the slides we refer to today are available on our Investor Relations website along with our earnings release, supplemental information on our earnings variances and quarterly operating statistics, the webcast and the Form 8-K filed this morning. Please note that the slides contain reconciliations of certain non-GAAP financial information. Also all of our references to per share amount will be after income taxes and based on diluted shares outstanding. It is my responsibility to advise you that this call 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 of 2011 Form 10-Q was filed this morning. Please refer to that document for the forward-looking statements as well as the MD&A section, which identifies risks and uncertainties that could cause actual results to differ materially from those contained in our forward-looking statements. A replay of this call will be available on our website, for the next 30 days. It will also be available by telephone through August 9. At this point, I'll turn the call over to Jim.

[James R. Hatfield:]

Thank you, Becky and good morning everyone. The topics I will discuss today are outlined on slide four. First, I'll review the consolidated second quarter results and discuss the main variances from last year’s corresponding quarter. Second, I'll provide a brief update on the status and outlook for the Arizona economy. Third, I'll discuss our 2011 earnings guidance, and lastly, I will close with brief comments on our credit ratings, liquidity and financing activities. Slide five summarizes our reported and ongoing earnings for the quarter. On a GAAP basis for this year second quarter, we reported a consolidated net income attributable to common shareholders of $87 million or $0.79 per share compared with net income of $115 million or $1.7 per share for the prior year second quarter. Our on-going earnings decreased $0.04 per share. For the 2011 second quarter, we’ve consolidated ongoing earnings of $86 million or $0.78 per share versus ongoing earnings of $89 million or $0.82 per share for the comparable quarter a year ago. Slide six contains a reconciliation of our second quarter GAAP earnings per share to our ongoing earnings. The amounts for both quarters exclude the results related to our discontinued operations. The discontinued operations amounts relate primarily to APS energy services. My remaining comments on the quarter will focus on the ongoing results. Moving to slide seven, you see the variances that drove the change in quarterly ongoing earnings per share. First, an increase in our regulated electricity segment gross margin added $0.01 per share compared with the prior year second quarter. Several pluses and minuses comprise this net variance and I will cover those items in more detail on the next slide. Second, lower operations on maintenance expenses improved earnings by $0.03 per share. The decrease largely reflects lower generation cost related to the timing and scope of planned outages at our fossil-fueled generating plants. This change in O&M excludes expenses related to the renewable energy standard or RES energy efficiency, demand-side management and similar regulatory programs, which are offset by comparable revenue amounts. Third, higher infrastructure related costs decreased earnings by $0.07 per share, reflecting increases in property taxes of $0.05 per share and depreciation of $0.02 per share. The property tax increase relates to higher property tax rate in 2011 versus 2010, as Counties raised rates to adjust their lower residential assessed valuations. As Arizona’s largest property tax payer, APS has been significantly impacted by this property tax rate shift. Higher depreciation and amortization related to plant additions decreased earnings by $0.02 per share. And finally, the net impact of all other items decreased earnings by a penny per share. Just to comment on property taxes. Since 2008, we have seen assessed real estate values decline by approximately 20%. Therefore, counties increased tax rates to balance their budget. The net result to APS is a double-whammy of stable utility assessed values and higher rates. Also point out that property taxes are in 18 to 24 months lagging indicator and the declining real estate values of 2008 and 2009 are just now being reflected in property tax rates. Turning to slide eight, in the composition of net increase in our regulated electricity gross margin, total regulated segment gross margin was up $0.01 per share compared with the 2010 quarter. The components of that increase were as follows

[Donald E. Brandt:]

Thanks Jim and thank you all for taking the time to join us this morning. Since our last earnings call, we made distinct progress in key areas and continued our track record of operation excellence. Today, I'll update you on the following topics. One, Arizona regulatory developments. Two, our renewable and other generation investments. And three, our recent operating performance. We know Arizona regulations and APS recently filed retail rate case are top of mind for investors and analyst. So I’ll start with those topics. Progress is been made in Arizona’s regulatory environment, and we appreciate the opportunity to continue working with the Arizona Corporation Commission and various stakeholders to further enhance the states regulatory framework to address several regulatory and operational issues and find solutions that balance the interest of customers, shareholders and other stakeholders alike. With this goal in mind, we look forward to continuing this dialogue in our ongoing state regulatory proceedings. On June 1, APS filed the general retail rate case; the key provisions of the case were in line with expectations set for stakeholders through APS’s 120 day notice filed back in February. Today I’ll highlight the key request of the case and their benefits. For your reference these items as well as key underlying assumptions are summarized in the appendix to today’s slide [deck]. The rate case provisions contain a number of benefits for our customers, the communities we serve and our shareholders. The requested regulatory treatment would build upon the constructive regulatory framework established in the 2009 settlement and would provide the financial support APS needs to achieve Arizona’s ambitious energy goals. Through the rate application, APS has requested a $95 million net base rate increase effective July 1 of 2012. The proposed rate changes include, a non-fuel base rate increase of $194 million, a fuel related base rate decrease of $144 million attributable to the transfer of lower commodity costs from the power supply adjustor to base rates, and a $45 million base rate increase attributable to the transfer of revenues from the Renewable Energy Surcharge to base rates. This change relates primarily to AZ Sun projects that will be placed in service prior to new base rates becoming effective. The net effect of these proposed changes on the average retail customer bill would be an increase of approximately 6.6%. Slide 17 in the appendix shows the key financial assumptions underpinning the rate request, including updated rate base, cost of capital and fuel prices. Other key provisions of the rate case request would continue constructive regulatory treatment and mitigate regulatory lag. Post test-year plant additions would be added to rate base through the date new rates would become effective. These additions totaled $250 million for AZ Sun and other solar projects, and $161 million for all other projects. This 18-month catch up is consistent with the methodology used in the 2009 settlement. APS also proposes to implement two new recovery mechanisms that would modernize the rate-setting process and adjust electricity rates between general base rate applications. The first of these is a decoupling mechanism using a revenue-per-customer method. This mechanism would update APS's rates to address recovery of the company's fixed costs in an environment of lower energy sales caused by energy efficiency programs and renewable distributed generation. The second mechanism proposed is a generation and environmental infrastructure tracker. This mechanism would update APS's rates for costs associated with environmental compliance investments, as well as generation additions and generation efficiency projects needed to serve APS's customers' expanding energy needs. APS has requested its power supply adjustor be modified to allow full pass-through of all fuel and purchase power changes, increases and decreases instead of the current 90/10 sharing provisions. In addition, APS requested that the second 50 Megawatts of the AZ Sun program be recovered through the RES until it's included in base rates. This request is consistent with the 2009 regulatory settlement and was the approved treatment for the first 50 Megawatts of the program. The Commission Administrative Law Judge has set a procedural schedule for the rate case proceedings. In short, the schedule provides two possible tracks for processing the request. Under both tracks, the ACC staff and interveners would file their direct testimony on November 18, on all matters except cost of service and rate design, and then on December 2 on those typical topics, and the hearing would begin on January 16. However, the details of the tracks are different. One track assumes APS and the Commission staff and other parties pursue settlement discussions and settle the case. Under this schedule, the parties would enter into settlement discussions at November 30, with the goal of filing a settlement agreement with the Commission by late December. Testimony supporting or opposing the settlement would be filed on January 11. The other track assumes that no settlement is reached and the parties proceed to litigation. Under that scenario APS would file rebuttal testimony on December 23. The schedules are noteworthy in that they demonstrate support for collaboration among the parties, and improve streamlining and efficiency of the regulatory process. They also are noteworthy in that they are designed to allow for final ACC decision by July 1 of 2012, consistent with APS's 2009 regulatory settlement. In a separate application filed with the commission on May 20, APS requested changes to its line extension policy to a lot – line extension policy to allow a new customers and opportunity to avoid certain new construction costs. As requested the policy change would be effective with the decision on the general retail rate case. A procedural schedule for ACC consideration of this request has yet to be established. As I discussed during our last conference call, in April, we made our 2011 filings for rate changes related to transmission services. The total adjustment to our annual transmission rates effective this year is a $44 million increase, calculated pursuant to the formula rate making procedures, previously approved by the Federal Energy Regulatory Commission. Of this amount $6 million relates to wholesale transactions with other utilities and that became effective June 1. On June 21, the Arizona Commission approved our request to allow the $38 million balance of the adjustment related to transmission services for APS's retail customers to pass-through the company's transmission cost adjustor, effective July 1. Turning to renewable resources and our AZ Sun development activities. We're on track with plans to significantly increase the amount of renewable energy APS provides. Investing in these resources makes sense for our customers, our communities, the environment and our shareholders. We play strong emphasis on solar power because Arizona has some of the best solar conditions in the world. Solid progress continues on APS’s AZ Sun program, the company’s plan to develop and own utility-scale photovoltaic plants in Arizona. We now propose that there will be two phases to this program. The first 100 megawatt phase, which was approved in 2010 by the commission, and a second, 100 megawatt phase, which was proposed as part of the APS’s 2012 RES implementation plan, that was filed with the Arizona Commission on July 1. I'll provide an update on phase one. Then I’ll outline what we have proposed for phase two. For your reference, the appendix to our slides today contains summaries of both phases of the AZ Sun Program. For phase one, to-date we've announced projects for the total capacity of 83 megawatts and an estimated capital investment of $384 million. Construction and other development activities are progressing as planned, and we expect to place the first 45 megawatts of the AZ Sun Program in service for customers later this year. One of the plants has begun delivering energy to the gird as portions of the plant are wired and tested, and a second facility has nearly all the solar modules in place, as crews continue to wire the collection system. Procurement initiatives are underway to fill out the last 17 megawatts of phase one. We expect projects for the remainder of phase one to come on line in 2012 and 2013. Based on our success to-date with the first 100 megawatts of AZ Sun. APS has requested that the commission approve phase two of AZ Sun is part of the company's 2012 RES implementation plan. Phase two includes an additional 100 megawatts of utility-scale photovoltaic plants representing a potential capital investment about to $475 million. We estimate the facilities would be placed in service in the 2013 through 2015 timeframe. Further, we have requested regulatory treatment for the facilities through the Renewable Energy Surcharge until the plants are recovered through base rates. This approach is consistent with the first 50 megawatts of Phase I. Assuming the ACC's consideration follows the timing of previous year's RES Implementation plans; we expect a decision from the commission on the 2012 plan around the end of this year. We're excited about the AZ Sun Program and our other renewable energy initiatives. They are important steps towards advancing Arizona's sustainable energy future. Now turning to the status of our Four Corners plan. During our last two conference calls, we discussed our multipart plan to address several challenges facing our Four Corners coal-fired plant in Northwestern Mexico. The plant presents a creative solution to address new environmental regulations and maintains our well-balanced resource portfolio. A summary of the plan is included in the appendix to our slides. To recap the plan, APS has agreed to buy Southern California Edison's 739 megawatt interest in Units 4 to 5 for $294 million. The parties target closing the transaction in late 2012. If the purchase transaction moves forward as planned, we intend to shut down Four Corners Units 1, 2 and 3, which total 560 megawatts in size and are wholly owned by APS. These units are smaller and less efficient than Units 4 and 5 and are not as well situated as the two larger units to bear the compliance costs associated with new regulations issued by the U.S. EPA. The net result of the anticipated acquisition enclosure is a 179 megawatt increase in the APS's share of Four Corners. We estimate APS's capital expenditures for environmental compliance for our revised share of the plant would be about $300 million. These expenditures would be far less than the estimated $620 million APS would need to spend if instead it were to bring our existing interests in all five plants, units into compliance with the proposed EPA rules. The acquisition requires approval by Arizona, California and federal regulators and other government agencies. It also is contingent upon extensions of the land lease with the Navajo Nation and the coal supply contract. We've made progress on our plan on several fronts. First, the land lease extension through 2041 has been approved by the Navajo Nation. Second, the Arizona Corporation Commission began a hearing on the matter on July 14th and 15th and the hearing will resume on August 8th. And third, coal contract negotiations are underway. We feel, we believe our plan has substantial merits economically, environmentally and socially. Our proposal clearly provide significant savings, given that the combined purchase price and environmental compliance costs for APS’s revised share would be less than environmental compliance cost per APS’s existing ownership in the plan. Our plan has substantial benefits in other important areas as well. We remain optimistic that APS and Southern California Edison will obtain the requisite approvals in a timely manner. Now turning to our power plant performance for a few moments. Our base load coal and nuclear fleet continues to perform well. Our coal-fired plants continued their top tier performance. In the second quarter, our coal fleet posted a capacity factor 78%, which is well above the most recently available industry average of 68%. During the second quarter, our Palo Verde nuclear facility operated at an 87% capacity factor, reflecting the plan Unit 2 refueling outage during that timeframe, which was completed in 35 days as planned. We have another refueling outage scheduled for this fall in Unit 1, which we expect to be completed in about the same amount of time. These refueling outage durations reflect sound planning and execution, the benefits of our work over the past couple of years, improving outage management and installing rapid refueling packages and replacing reactor vessel heads in each of the plan’s three units. Now turning to the quality of our customer service. Last month, J.D. Power and Associates released the results of its 2011 residential customer survey. I am pleased that APS continues its record of excellent performance and overall customer satisfaction. In eight of the last nine years, APS has been ranked by residential, our business customers in the top 10 nationally among all large segment utilities in overall customer satisfaction. In the most recent results, APS ranked fourth nationally among 55 large investor-owned electric utilities. More specific to our region, we were rated third among the 10 investor-owned utilities in the West. In addition to the overall customer satisfaction index, APS ranked in the top 10 nationally on five of the six components of customer satisfaction as defined by J.D. Power. Finally regarding our non-utility operations, we continue to focus on our core utility operations and streamlining the company. Toward that end, Pinnacle West is negotiating the potential sale of our competitive energy services subsidiary, APS Energy Services. As a result, APS Energy Services was classified as a discontinued operation as of June 30th. In summary, our company's goal is to achieve top-tier performance and we constantly work toward that objective in every facet of our business. Going forward, we are committed to maintaining operational excellence and achieving superior financial results by concentrating on our core electric utility business. This concludes our prepared remarks. Operator, at this time, we would be pleased to take any questions.

[Operator:]

Thank you. We will now be conducting a question-and-answer session. (Operator Instructions) Thank you. Our first question is from Greg Gordon with ISI Group. Please proceed with your question.

[Greg Gordon:]

Hey, gentlemen, good afternoon.

[Donald E. Brandt:]

Hi, Greg.

[Greg Gordon:]

The Phase II Arizona Sun, so this is your first disclosure of this opportunity, correct? So this is incremental to Four Corners and others sort of rate base growth drivers, should it be approved that we should think about sort of post 2012. Is that fair?

[Donald E. Brandt:]

That's right, Greg. We filed this annual filing on July 1 of this year. So this would be the first cycle where we’d be talking about it publicly.

[Greg Gordon:]

Okay. So should you be permitted to make these investments, it would obviously wrap into your assessment of your capital needs. But would it change the sort of statement you made earlier that you would need equity no sooner than 12 at the earliest?

[Donald E. Brandt:]

On the first point, yeah, this would be incremental capital. And I think it’s reflected, 12 is reflected in our QV Arizona Sun too, but it's not a change our statement on equity before 12.

[Greg Gordon:]

Great. Second question, you obviously had a relatively mild second quarter last year. I think street consensus presumed it would get better, it actually got a little bit worse. But in terms of what we should think about in terms of the revenue requirement that you’ve asked for in the rate case, that does presume normal weather next year, is that right?

[Donald E. Brandt:]

Yes, right.

[James R. Hatfield:]

Yes, Greg.

[Greg Gordon:]

And then on tax rate, I mean if I'm doing the math correctly, your – are you, these new tax rates just going affect in the second quarter? Is that the first, is it the first, if I look back at your comments on what your drivers were in Q1, you didn’t mention higher tax rates then, so.

[James R. Hatfield:]

You mean property tax?

[Greg Gordon:]

Yes.

[James R. Hatfield:]

Yes. I think when we came into the year, obviously we had a significant increase last year. We plan for a significant increase this year as well as we went through the budget process, we’re now beginning to get looks at the bills and we’re seeing rates that are higher than we thought.

[Greg Gordon:]

Okay. So there were sort of – you're getting the bills for the full-year, but you’re getting them now?

[James R. Hatfield:]

Yeah.

[Greg Gordon:]

I got you. That’s just like my call-up here in New York. And it looks like the run rate, am I right that the tax run rate looks like it’s $30 million to $40 million higher, pre-tax, just closing up the $0.05 on an annualized basis? Or is that not a fair assessment?

[James R. Hatfield:]

That’s not a fair assessment

[Greg Gordon:]

It is or it is not?

[James R. Hatfield:]

It is not, Greg

[Greg Gordon:]

Can you tell us what you think or is it sort of a work in progress?

[James R. Hatfield:]

No, no. If you look at sort of what we did with the ranges, we increased operating expenses by approximately $10 million to reflect the increased property tax at this point.

[Greg Gordon:]

Got you.

[James R. Hatfield:]

And we reduced interest expense by about $5 million, keep in mind these are ranges, to reflect lower interest expense for the year.

[Greg Gordon:]

And that lower interest expense is partly reflective of the borrowing cost savings you’ll be getting from being able to access the commercial paper market?

[James R. Hatfield:]

Yes, it's less need to borrow cheaper rate because of the change to A2 or P2, in that case, so.

[Greg Gordon:]

Great, great. And then final question, to the extent that these property taxes are running higher, are you going to be able to make post period adjustments to your rate case to reflect that?

[James R. Hatfield:]

Well, we always try to make post test year adjustments and we’ll certainly look at any operating expenses on a measurable and try to account for that.

[Greg Gordon:]

Okay. So we should assume that under normal course of business, these are recoverable expenses?

[James R. Hatfield:]

They are recoverable expenses.

[Greg Gordon:]

Thank you.

[Operator:]

Our next question comes from Daniel Eggers with Credit Suisse. Please proceed with your question.

[Daniel Eggers:]

Hey guys, just real quick on the rate case process. You guys does look comfortable with the schedule formerly out that you can get this done by July, worst case scenario?

[Donald E. Brandt:]

Yes, very much so, Dan.

[Daniel Eggers:]

And then from a settlement discussion perspective, nothing is going to open up until after Thanksgiving and there’s effectively a month long window basically to get something resolved?

[Donald E. Brandt:]

Yes.

[Daniel Eggers:]

Okay. And then whether have you guys seen any sort of turnabout in – as July has moved on, if you look at the forecasts as far as August is concerned, set the reduction for the third quarter is already captured in the books or have you guys put more question in for what things are better?

[Donald E. Brandt:]

We’ve taken account of whether, kind of like right up to yesterday and we're seeing a little bit of a rebound. I think for today and tomorrow we're supposed to hit 110 or 111 but then it start cooling down. After this week, it's anybody's guess.

[James R. Hatfield:]

And Dan, I'll say that you keep in mind that May, June, July all big summer months for us. We are sort of down and not a whole lot of time left to offset this.

[Daniel Eggers:]

Okay. And now I guess on Four Corners read something about the Department of Interior kind of preempting EPA action and then the need for investment. Do you see that change in perspective to the plants at Navajo or do you see upgrades ultimately going to be required?

[Donald E. Brandt:]

Well, I think it's premature to talk about Navajo. We and the other partners are still in early stages of discussions with EPA and other parties.

[Daniel Eggers:]

Okay. Thank you.

[Operator:]

Our next question comes from Brian Russo with Ladenburg Thalmann.

[Brian Russo:]

Just a follow-up on the revised 2011 guidance. It looks like the gross margin is down about $40 million and I would imagine that's almost entirely related to weather.

[James R. Hatfield:]

Correct.

[Brian Russo:]

And then it looks like for the first half of 2011 the weather impact was negative 27 million versus normal which I assume your previous guidance was based on.

[James R. Hatfield:]

Correct.

[Brian Russo:]

So given that, and since the revision is for the first seven months, does that kind of imply that July mild weather impacted margins by negative 13 million?

[James R. Hatfield:]

Well, I don't think you can just try to add the two together and get exactly the seven-month impact. But the implication of it is, July was below normal. I don't have the stats yet but we do get daily weather statistics – or sales statistics and we know we're under from what would be normal weather.

[Brian Russo:]

Okay, and Phase 2 of the Arizona AZ Sun program that you laid out, is that needed to get to your RPS standard by 2015 or is some of that incremental?

[James R. Hatfield:]

The Arizona Sun 2 is a piece of the incremental renewable power we need to meet the standard we agreed to on 2015.

[Brian Russo:]

Okay. Thank you very much.

[Operator:]

Our next question comes from Paul Ridzon with KeyBanc Capital Markets.

[Paul Ridzon:]

I had a follow-up on the property tax question.

[James R. Hatfield:]

Sure.

[Paul Ridzon:]

Jim, you talked about a lag effect, how should we think about that in the form of lag in 2012 once you’ve got new rates, I mean is this going to happen every year for a couple of years as these counties try to stake hold?

[James R. Hatfield:]

Well, I can’t predict what counties are going to do in 2012. I think the implication is what we’re now seeing is the steep drop in ’08, ‘09 work its way through assessment ratios. The housing slide we showed shows EBIT fairly flat over the last 12 to 18 months and if that relationship solve, I would think property tax would be fairly flat next year.

[Paul Ridzon:]

Okay, so season capture this and post test, you should be (inaudible)?

[James R. Hatfield:]

Well, what we capture, I mean 20% reduction, which is pretty significant. So I can’t imagine we’re missing another big piece of property tax.

[Paul Ridzon:]

And just in 2011 where are line extension revenues tracking relative to plan?

[James R. Hatfield:]

They’re tracking pretty much on plan to the first six months of the year. Keep in mind, those things are very volatile, just because they’re based on builders’ schedule. So I mean we still expect to be where we thought we’d be, but we’ll see what happens throughout the year.

[Paul Ridzon:]

And then the two post tests, your planned additions, are those captured in your, I think, the $198 million, is that going to be incremental?

[James R. Hatfield:]

No, that's captured in our ask.

[Paul Ridzon:]

Great. Thank you very much.

[Donald E. Brandt:]

Thanks, Paul.

[Operator:]

Our next question comes from Ali Agha with Suntrust. Please proceed with your question.

[Ali Agha:]

Thank you. Jim, could you remind us in your revised guidance, what is the assumed utility earned ROV and just remind us what was the actual for ‘10?

[James R. Hatfield:]

The actual for ‘10 was 9.3 and we assume high eight in guidance.

[Ali Agha:]

Okay. And secondly also to clarify the rate case proceeding, is it fair to assume if you were to go the settlement route and that were to play out to the end, would the new rate still go into effect July 1 or could they change based on the settlement?

[James R. Hatfield:]

No, the assumption of all the parties with the 12-month cycle is they’d be affected July 1, ’12.

[Ali Agha:]

Okay, okay. So regardless of which path ultimately place out?

[James R. Hatfield:]

That's correct. And it's also consistent with our settlement, with set rates and affect no earlier than July 1, ’12.

[Ali Agha:]

Right, right, right. And the AZ Sun II Program, also just to be clear on that, I think I heard you on this, but just to be clear. So that CapEx that you would spend which you have not I guess budgeted today, would not offset some other spending, this would all be incremental and could be absorbed based on your liquidity and cash flows et cetera.

[Unidentified Company Representative:]

Ali, let’s clarify. We do have the twelfth portion in our 10-Q updated CapEx. Keep in mind this will probably be a later ‘11 approval, which means it’s hard to get a whole lot started in ‘12 or probably ‘13 and later, loaded it would be incremental the way we see it today. But I am very confident about our liquidity and ability to fund these projects.

[Ali Agha:]

Okay. And Jim, as you’ve said in the past, from the equity issuance point of view the key there still remains the timing of the future rate case filing and the texture that goes with that as opposed to the CapEx needs for the business. Is that still a fair way to think about it?

[James R. Hatfield:]

Yes.

[Ali Agha:]

Got it. Thank you.

[Operator:]

(Operator Instructions) Our next question is from Neil Mehta with Goldman Sachs. Please proceed with your question.

[Neil Mehta:]

Good afternoon.

[Unidentified Company Representative:]

Hi, Neil.

[Unidentified Company Representative:]

Hi, Neil.

[Neil Mehta:]

So, surplus gas and intervenors filed the settlement in Arizona last week in their base rate case. It looked good, there were some partial decoupling and more experienced timeline. What read over if any is there to the pending APS case?

[Unidentified Company Representative:]

I’ve said in the past it’s hard to look at a gas settlement and relate that to electric utility, just like it’s hard to look at electric utility settlement related to another company. I’d think from that perspective. Again, I think not been involved shows parties wanting to come together and settle cases and dialogue around decoupling and that’s really mildly read on that.

[Neil Mehta:]

And retail usage per customer increased again this quarter, we saw it last quarter as well. How does that impact the way you think about decoupling because you’d be given any upside from higher customer usage?

[Unidentified Company Representative:]

Well, I would say two things. One is, we’re seeing a rebound from absolute declines and so we don’t think that this big increase in customer usage is an ongoing pattern and we think it’s just that rebound effect going forward with flat sales being taken with decoupling and energy efficiency, decoupling is very important for us to have as a mechanism.

[Neil Mehta:]

All right and then final question on transmission projects, any new developments or key projects we should be keeping our eyes on?

[Unidentified Company Representative:]

No. Not this time.

[Neil Mehta:]

Okay. Great, thanks guys.

[Operator:]

Ms. Hickman there are no further questions at this time. I would now like to turn the floor back over to you for closing comments.

[Rebecca L. Hickman:]

Christine, thank you. And thank you again for joining us today. As always, if you need further information about our earnings or other information about our company, please contact me or Geoff Wendt. This concludes our call.

[Operator:]

Ladies and gentleman our teleconference has concluded. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.