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UNS Energy Corporation (NYSE:UNS)

Q2 2013 Earnings Call

July 30, 2013 12:00 PM ET

Executives

Chris Norman - Manager, IR

Paul Bonavia - Chairman and CEO

Kevin Larson - SVP and CFO

Analysts

Kevin Cole - Credit Suisse

Paul Freeman - Jeffries & Company

Chris Ellinghaus - Williams Capital

Brian Russo - Ladenburg Thalmann

Operator

Good morning, and welcome to the UNS Energy Second Quarter 2013 Earnings Conference Call. Today’s call will be hosted by Paul J. Bonavia, UNS Energy Chairman and Chief Executive Officer. All lines have been placed on-mute to prevent any background noise. After the speakers’ remark, there will be a question-and-answer session. (Operator Instructions)

As a reminder, this conference is being recorded, Tuesday, July 30, 2013. Now, I’d like to turn the call over to Mr. Chris Norman, Manager of Investor Relations. Please go ahead, sir.

Chris Norman

Thank you all for joining us today as we review UNS Energy’s second quarter financial results. Joining me on the call today are, Paul Bonavia, UNS Energy’s Chairman and Chief Executive Officer; and Kevin Larson, Senior Vice President and Chief Financial Officer.

Before I turn the call over to Paul and Kevin, I would like to point out that our earnings release, supplemental materials and webcast slides are available on our website. Please refer to these materials for a reconciliation of non-GAAP measures.

In addition, it’s my responsibility to advise you that forward-looking statements made on this call are based on current expectations and may contain risks and uncertainties. Significant factors that could cause actual events and results to differ materially from expectations are described in our earnings release and in our 10-K and 10-Q filings. All forward-looking statements are made as of today based on the information available to us today and except as required by law, we assume no obligation to update any such statements.

A replay of this call will be available on our website as well as by phone. At the end of Paul and Kevin’s remarks, we will open the call for Q&A

Now, I’d like to turn the call over to Paul.

Paul Bonavia

Thank you, Chris, and thanks to everyone for joining us today. This morning we reported that UNS Energy's net income for the second quarter 2013 was $34.6 million or $0.83 per share on a fully diluted basis. By contrast in the second quarter of 2012, we reported net income of $26.3 million or $0.64 per diluted share. Our second quarter results reflect an adjustment to income tax expense as well as a onetime credit to fuel expense related to TEP’s rate settlement. The net effect of those two items positively contributed to our second quarter results by approximately $0.22 per diluted share.

Excluding those two items UNS Energy's second quarter diluted earnings per share were $0.61 or $0.03 below last year. I am pleased with these results given that the second quarter marks the end of TEP’s base rate freeze that started over four and a half years ago. Our employees and our management team are to be commended for consistently delivering strong operating results despite facing the economic challenges of the financial crisis, the ensuing recession and a protracted recovery.

The approval of TEP’s new rates by the Arizona Corporation Commission in June, fairly balances the needs of our customers with the long term financial stability of TEP. TEP’s new rate structure which became effective July 1, contains a modest increase of less than $4 per months for the average residential customer. It has new cost recovery mechanisms that help to mitigate regulatory lag, and our reiteration and rate design changes that give customers easier to understand rate options and stabilize our ability to recover fixed cost.

With TEP’s rate case behind us; our immediate regulatory focus is on two fronts. First the Commissions’ enquiry concerning retail competition, and second the settlement discussions in UNS Electric’s pending rate proceedings.

As many of you are aware, on May 15, the Commission opened the generic docket to begin their enquiry into retail competition. On July 15, TEP and UNS Electric along with several other parties filed responses to questions posed by ACC staff. Our underlying position is that the current regulatory model in Arizona is proven and sustainable. The utilities in this state consistently provide safe, portable and reliable services to our residence. While we appreciate the Commissions’ diligence in reviewing the issues raised in this proceeding; we strongly urge them to act promptly in this docket by declaring the retail competition is not at a public interest.

The second round of comments is due on August 16. We are hopeful that the Commission will schedule an open meeting in September or October followed by a definitive decision on this matter. Yesterday settlement discussions began in UNS Electrics rate proceeding, and those discussions continue today. Our initial request included a non-fuel base rate increase of $7.5 million or 4.6% which assumed in original cost rate base of $217 million, an ROE of 10.5% and a capital structure of about 53% equity and 47% debt.

ACC staff recommended a non-fuel base rate increase of $1.4 million, and they used the same capital structure but made downward adjustments to ROE and adjustment to rate base, to take out some of the posttest year rate based items we had included. Despite these differences we're hopeful the parties can reach common ground the settlement discussions have been constructive, neither staff nor RUCO opposed our proposed transmission cost adjustment mechanism, which would allow retail rates to include transmission costs reflected the approved (inaudible) rate. We requested that these new rate to be in effect January 1, 2014.

Moving to our long term resource strategy, TEP's purchase options for Springerville 1 expire on August 31. As a reminder the appraisal process conducted last year determined the purchase price at $478 per kilowatt, or $159 million for the 86% of the unit TEP currently does not own. We're still evaluating various scenarios ranging from the purchase of the entire unit or a portion of the unit down to maintaining our current 14% ownership and letting the options expire. We'll provide more information to you in late August or early September.

Another important component of our resource strategy is San Juan. We do have any new updates at this time; the work is proceeding as planned. Our recourse plan and associated capital budget assumes that the non-binding agreement which would retire Units 2 and 3 and require the plant to install selected non-catalytic reduction on Units 1 and 4 will eventually receive all necessary approvals from federal and state agency.

The book value of TEP shares of Unit 2 the unit that would be shutdown was $115 million as of June 30, 2013. TEP estimates our share of capital to install selective non catalytic reduction on Unit 1 would be approximately $25 million.

Finally I would like to touch briefly on our local economy. Earlier this month Augusta Resources announced that it's in the final permitting stages for the Rosemont Copper mine. The remaining permits include getting the final environmental impacts statement and record of decision from the U.S. force service as well as a section 404 water permit from the army core of engineers. Augusta estimates that it can start mine construction later this year and begin production in 2015.

Once in full production Rosemont would become based on current estimates TEP's largest customer with an estimated load of 85 megawatts. Turning to Tucson housing market, June closings were 9% above last year, the median price of homes sold increased by 15%. In June university of Arizona's economic research center updated their economic forecast for Tucson, they still call for the recovery to gain traction later in 2013 and for accelerated growth in 2014 and '15. I would like to turn the call over to Kevin who will provide more details on our second quarter results. Kevin?

Kevin Larson

I will cover a few key drivers for UNS Energy's second quarter and year-to-date results before we get into our Q&A. If you would to follow along please refer to slide two of the presentation that was furnished in an 8-K this morning and posted on our website. The slide shows the factors that impacted earnings between the second quarter 2012 level of $0.64 per share and the second quarter 2013 level of $0.83 per share. And slide three shows the change in earnings on a year-to-date basis from $0.81 per share in 2012 to $1.10 per share in 2013.

In the second quarter of 2013 TEP's total retail sales were 2,409 gigawatt hours, that's 1.3% below the second quarter of 2012, despite a hot June mild weather in April and May reduced the customer usage in the second quarter relative to 2012.

TEP's second quarter retail margin of 145 million was 1 million or approximately $0.02 per share below the second quarter of 2012. Compared to a normalized weather pattern we estimate the second quarter weather to be approximately $5 million.

Turning to our long term wholesale contracts; second quarter margins on our two wholesale contracts were in line with our expectations of $1 million. These margins were 1 million or $0.02 per share higher than the second quarter of 2012 due to higher wholesale power prices. Prices in the second quarter 2013 for on-peak power averaged $38 hours per megawatt hour, and off-peak averaged $27 per megawatt hour.

So the other quarter-over-quarter drivers were TEPs' based O&M was 1.7 million or $0.02 per share higher in the second quarter of '13, than the same period in 2012, due in part to an unscheduled plant outage, and the finally the resolution TV's rate case caused us to record two items to the income statement, first as part of a settlement agreement they agreed to a field credit of 3 million to customers related to sell for credits, by doing so fuel expense increased for the period, this translates to a $0.04 charge per diluted share, second we received a current year non cash income tax benefit relating to the establishment of a regulatory asset, this asset allows us to recover previously recorded income tax expense through future rates, this benefit is equal to $0.26 per diluted share and this adjustment arose because we invest in many renewable energy projects on which we earn investment tax credit, SITC benefit reduces tax depreciation for a small piece of the asset, under our prior order we recognize this tax loss up front. Under our rate order we amortize this tax loss over the life of the renewal project. Excluding these two items UNS earned $0.61 per diluted share in its second quarter compared to $0.64 in 2012.

Moving on and looking at some of the other additional year-to-date drivers, colder than normal weather in TEP service territory during the first quarter of 2013, drove higher sales and margins relative to 2012 on a year to date basis through June TEP's retail margins were 3.4 million or $0.05 per diluted share higher than 2012.

TEP also benefited as expected from lower interest expense and its declining capital lease obligation balances. Total interest expense in the first six months of 2013 was 3.7 million, lower than 2012. This translates to $0.05 per diluted share. And on a year to date basis excluding the fuel credit and income tax benefit mentioned previously, UNS earned $0.88 per diluted share compared to $0.81 per diluted share in '12.

Now I’d like to mention a few last items, in June, Moody's Credit Rating Agency upgraded TEP secured and unsecured ratings by one notch and the UNS parent secured rating by one notch as well. Moody's indicated the upgrade reflects there's only improving regulatory environment and a favorable result in TEP's rate case, and back in April S&P put TEP on par with outlook. this outlook originally was based upon an improved regulatory environment and at that point the rate case settlement agreement.

Finally I'd like to just point out that on our next investor call to discuss the third quarter results late October, early November, we intend to provide our earnings outlook for 2014. With that I'll turn it back over to Paul for Q&A.

Paul Bonavia

Thank you, Kevin, do we have questions?

Question-and-Answer Session

Operator

Thank you, (Operator Instructions). Our first question comes from the line of Kevin Cole with Credit Suisse, please begin with your question.

Kevin Cole - Credit Suisse

On the deregulation, can you provide a little perspective on why Arizona is going down this path again and could you remind me what happened the last time they did this exercise and then also given the complication of this issue I guess what gives you the confidence that this can be resolved in one open meeting.

Paul Bonavia

Well, what if we start with the history, and I'm in an unenviable position of an historian who wasn't here when it happened the last time but you know that Arizona vote with commission rules and legislation moved on a path toward instituting retail competition and got right up to the point of having several legal disputes that got to court that define some of the baseline rules and I think the combination of impediments that come directly from the way the Arizona constitution requires the Arizona Corporation Commission to regulate retail electric sales, the combination of those rulings which create some real barriers to having anything like a competitive market as some envision it, that combination plus the California experience and the general experience with wholesale power markets and retail competition caused the state to pull back. And not much has happened in 10 years or, since then.

Why it's coming back now, you know it's, I think the commission has over those years asked their staff to update periodically the commission on how retail competition or some form of deregulation which is probably a more accurate term would affect the Arizona customers, so they've continued to monitor the policy environment of that. Three years ago the staff put out a report going through pros and cons of deregulation and essentially saying there are some pros, there are some cons this is probably not the time. So no action was taken in 2010. Now we’ve got some new commissioners. They are commissioners who believe in business, believe in competitive free markets, for that we applaud them. But the resumption of this inquiry taking it up again and asking the questions again at this time are a logical enough step for that group to take.

So, Kevin, have I missed anything critical in the history. You got to live…

Kevin Cole - Credit Suisse

Paul, I think that does pick up the key issues historically. I mean the ACC looked at it pretty extensively at the time, began to implement it and concluded through that process so that wasn’t the right path.

Paul Bonavia

As to what makes us think or what gives us confidence that this can be resolved without a drawn-out proceeding. I guess the thing that gives me the most confidence that the commission will be decisive and prompt in its discussions and decision making is the statements from the commissioners. We’ve had several public statements on the record from commissioners saying that they’re very mindful of the need to look after retail customers, particularly residential and small commercial and they are not interested in doing anything that would harm those customers.

And at the staff meeting that they held a month or so ago, and those are public meetings. Several commissioners took note of the reaction from some analysts and spokespersons for capital markets that they’re inquiry created a sense of uncertainty and a number of the commissioners commented that whatever we do, we’re going to do it promptly, we’re going to stay on task and we’re going to not leave this uncertainty hanging out there for a long period of time.

So we take that as very constructive. Kevin, they’ve got a good track record in the last couple of years of keeping their promises regarding scheduling Commissioner Pierce and others made comments about the need to get rate cases done in a year, and they’ve been getting their rate cases done in a year, for us and for the other utilities.

So, that gives us some confidence that this commission is serious and thoughtful that they appreciate that uncertainty is the least favorable state for the industry to be in and that they’ll move it right along. And from our point of view, I’ve been down this path myself in other states and a move toward a more de-regulated market or differently regulated market for the utility can be a pretty good thing. It can be a bad thing. It all depends on how the rules gets set. As I look at where we are, first of all, economically, our fleet’s competitive. We do not have a fleet that is going to create a lot of huge potential risk in liabilities here. It dispatches very well in this market and it’s very competitive viz-a-viz places like California.

So we think the underlying economics that we start with, they’re pretty good if we go down a path of making rules for a transition. And secondly in Arizona, you do have the legal basis which does place considerable restrictions on commission and legislature and how they could proceed. And even though this would be a very complex process there is also permutations we think the starting point in the existing law plus more importantly the starting point for us with the fundamental economics of our fleet put us in a pretty good position.

And so now the commission’s got to decide what problem they’re trying to solve. We’ve got low rates in Arizona, high reliability, good customer satisfaction, and we’re also a state that does not have all the embedded infrastructure of a wholesale market to fall back on, is this really the time? Is it favorable to consumers to go down this path? That’s what’s the commission is going to decide.

Kevin Cole - Credit Suisse

And then this turns out to be more of a complicated issue and kind of believes into next year. How does that impact how you run your business? And what I mean by that is you have this one, I guess, indication coming out in August-September timeframe. You have two pending RFPs. How do you do that if this issue lingers and (inaudible) year?

Paul Bonavia

And the issue will certainly linger beyond the exploration period for our option exercises on Springerville one. So, that uncertainty is part of our decision making process, and along with all the other uncertainties in the market. And Kevin what we will try to do is the good portfolio managers here with respect to the underlying economics of the fleet, with respect to the risk embedded to few risk technology risk environmental risk inherent in the fleet and we’re going to put together a fleet of resources here that’s as competitive as we can make it because whether the commission goes down or deregulation pay after, whether the commission decides it has over the last 10 years that this isn’t the time, we’re going to nevertheless want to have the lowest cost, lowest risk fleet that we can and the other thing that I know you commented on before there is some excess capacity in Arizona but we don’t have excess capacity. Our resource position is actually a little bit short, we already benefit from merchant plants in the (inaudible) area and our intention would be to put together a fleet that remains as competitive as possible and doesn’t have a big standard cost overhang.

Kevin Cole - Credit Suisse

And just so I am clear, so you believe execution on either one success strategy.

Paul Bonavia

We haven’t made a final decision but remember, the range on unit one, this is Springerville one, is all the way, we already own 14% of it. So, it’s the ownership past year that we would come out of this decision with is somewhere between continuing at 14% or going all the way to a 100% and remember that there are I believe seven separate leases. So, we can exercise options with respect to each of those seven components of the overall ownership separately. We don’t have to either buy all of it or none of it. So, we might look, we clearly we are going to look as an option at some portfolio mix that would blend some natural gas capacity that would emerge from the RFP process that we’re in and perhaps some coal capacity at Springerville one, keeping in mind that we’re blending down coal capacity at San Juan, if that settlement proceeds as we expect it to and that some of the other coal units might also see reduced capacity. So, we’re looking to have the lowest cost most competitive lowest risk fleet we can and we’ve got a pretty wide range of option.

Operator

Our next question comes from the line of Paul Freeman with Jeffries. Please proceed with your questions.

Paul Freeman - Jeffries & Company

I guess the first question has to do with, it looks like the cooling degree days were actually higher this year but the level of sales was lower and you talked about sort of the timing of which months those days fell in, was that the sort of the explanation as to why the sales were lower actually this year?

Paul Bonavia

Yes. It’s part of the necromancy of figuring out correlations better weather and sales. The months of April and May were very tempered, very cool so our sales mix was low and in fact one of the things we look at, our analyst look at is whether we spike a 100% day early in the season and there were no 100 degree days in our service territory and TEP service territory in April and May. And having those 100 degree days sort of accelerates customer behavior as we go into the season, then again very hot in June but although the temperatures were high, the humidity was very low and that affects the efficiency of cooling technologies that people use.

So, it’s more complicated that just how many cooling degree days did we have, it’s when did they occur and as what was accompanying humidity. All in all pretty strong sales quarter but just a little bit less sold than last year that for those weather factors.

Paul Freeman - Jeffries & Company

And whether normalized, what was the growth?

Paul Bonavia

It’s pretty much flat, whether normalized, you kind of insight the noise of the weather nominalization. Customer count was up, sales year-to-date are up but for the quarter it’s pretty flat.

Paul Freeman - Jeffries & Company

You guys had law outstanding to try and get affirmation of the 159 million value for Springerville. Are the courts going to rule in time before you actually have to exercise the option and if not, what’s the implication there?

Paul Bonavia

No. We’re in the court of the appeal with that, it will not rule before we have to exercise the option. We filed that lawsuit because we’re a utility company, we have regulators out there and we like to have certainty when we make decisions so that we can communicate that to regulators, we’re always asking them to give us as much certainty as we can, we wanted to follow on the same thing. That’s why we filed a law so it was just confirm the arbitration award. The trial court, United States District Court dismissed it for lack of jurisdiction over the subject matter which is not a ruling on the merits and so that’s what the appeal was about it, it’s mainly a technical point of jurisdiction under the relevant statue. We still think the price set by the appraisal process is $159 million, $478 per kilowatt irrespective of what happens with this appeal over the jurisdictional issue, we would expect that’s the purchase price. We were just trying to nail it down as strongly as we could.

Paul Freeman - Jeffries & Company

Okay so if you would exercise either a portion or all you would assume it would be at that price and there may be a challenge on the part of less or after the fact, right?

Paul Bonavia

There may be, yes. They’re going to try and push the price up as much as they can that is no surprise to us, our assumption is it would be $478 a kilowatt, should we allow the option to purchase to expire, now you’re back to what’s the market post September 1, 2013, because those megawatts will still be there and discussions could still ensue, we have no idea what their pleasure will be but if the option expires, then so does the $478 per kilowatt price, it would then be negotiated.

Paul Freeman - Jeffries & Company

Okay and then the income tax benefit that you booked in the quarter, what is going to be the effect on a going forward basis either by quarter by year, I assume you’re going to have now incur higher tax expense on a going forward basis?

Kevin Larson

Yes, Paul, that is correct, this is Kevin. I mean the onetime asset write up was about $11 million and so that will be amortized or expensed over the next 16 years between now and 2013, I believe it is, so I guess on an annual basis what’s that maybe $600,000 or $700,000 on annual basis.

Paul Freeman - Jeffries & Company

Kevin, what’s the effect in the next couple of years?

Kevin Larson

Yes that's on that particular write up. because we anticipate even other renewable investments and we’ll benefit from the ITC and the taxes at that point in time as investments are made, we could see some net benefit if maybe $0.02, $0.03, $0.04 when you consider the new investments load alone or in addition to just onetime adjustment that we just made in this quarter and that will continue on probably for the next two to three years and then it will trend more on the expense side as I initially indicated.

Paul Freeman - Jeffries & Company

So in the next couple of years, the benefit is going to be positive or is that $0.02 to $0.04 in offset to the 600,000 to 700,000 of incremental expense?

Kevin Larson

Yes, I would expect that the next benefit over the next two to three years, if we make the renewable investments that we currently have in our capital budget that should be favorable $0.02 to $0.03, it’s basically just kind of noise, we’re in a situation now where we get recovery of that tax expense through rates whereas before we did not.

Paul Freeman - Jeffries & Company

And then last question for me, you’ve talked about an 85 megawatt load benefit from Rosemont, I think in the past you’ve talked about 100, is that just a refinement based on sort of updated information or did something change or?

Kevin Larson

Yes, it’s a refinement and it’s really based on the changes they’ve made to their mining plan of operation to comply with the various requirements that they have to meet to get final environment impact statements, so they’ve changed their operating mode a little bit.

Operator

Our next question comes from line of Chris Ellinghaus with Williams Capital. Please go ahead with your question.

Chris Ellinghaus - Williams Capital

Kevin could you just remind us what the Springerville outage impacts were in third and fourth quarter last year?

Kevin Larson

Of last year?

Chris Ellinghaus - Williams Capital

Yes.

Kevin Larson

Well, I’m sorry I’ve mentioned earlier that we had some additional O&M expense this year in the second quarter that was related to unplanned outage and that happened to be the Springerville plant and that was approximately $2 million to $3 million, as your question you’re referring to prior period look into Chris.

Chris Ellinghaus - Williams Capital

As you’re probably unit 3 I’d say a year ago.

Kevin Larson

Okay that’s right.

Chris Ellinghaus - Williams Capital

Where the operator firm in the unit 3 and there was an unplanned outage there.

Kevin Larson

Yes and then Chris said there’s really impact our own expense so that was Springerville unit 3 which was owned by a different entity.

Chris Ellinghaus - Williams Capital

It did impact you operating revenues or did not?

Kevin Larson

Yes, it did, there was approximately about $2 million.

Chris Ellinghaus - Williams Capital

Okay and was that sort of evenly spread out in the third and fourth quarters?

Kevin Larson

That was pretty much all in the third quarter the adjustment occurred.

Chris Ellinghaus - Williams Capital

It sounds like you’re little more optimistic on Rosemont, can you just give us a little color on your thinking, that’s going to be a major contributors assuming all goes well, how does that impact in the absence of say a big acquisition of RSP or what not of your rate making strategy particularly since you got some new mechanisms that will help the attrition, what are your thoughts on that?

Kevin Larson

Yes, if they come on line and start coming into service in 2015, obviously that's going to increase our revenues. That time is up pretty well with the expiration of some wholesale contracts or one wholesale contract in particular. So as I know we've talked about before, we've got capacity to serve Rosemont, we don't have to go build something or buy something, so the revenue effect kicks right in without an offsetting CapEx program.

In terms of how it affects our rate making strategy, I think it helps us make the decision to stay out of rate case just that much easier. It's a revenue stream to help offset increasing costs and the effective increasing rate base over those years. It has a very positive effect on the overall economics of the company, again helping us stay out of the rate case but also improving our asset utilization very much, because it's around the clock 365 day a year customer. So if it pushes back the next rate case a year or two conceivably that would be a very nice thing.

Chris Ellinghaus - Williams Capital

Can you also remind me who was the lost customer at UNS Electric and did that also impact the first quarter?

Kevin Larson

It was a fiber glass manufacturer and they just closed their plant.

Unidentified Company Representative

They provide on a full year basis about $800,000 of margin, so that customer is no longer with us.

Chris Ellinghaus - Williams Capital

Can you give us a little update on the RFP and when should we be looking for something?

Kevin Larson

We've got responses to the RFP for reviewing them right now and again as I mentioned in response to previous questions, we'll make a decision about those bids, one or more of them at the same time we make a decision about what to do with Springerville, it's all one integrated resource portfolio exercise. So right now the bids are confidential, we have a confidentiality undertaking for the process. But we'll be making some announcement it will probably be certainly after September 1 as to what resource options we are going to be going down.

So you probably hear about Springerville first that if we enter into any agreements or shortlist in a way that we're going to publically disclose some of the other bidders that will probably be coming along pretty promptly after that.

Chris Ellinghaus - Williams Capital

And have you made it abundantly clear to the commission that you sort of would love to have some information on the competitive investigation before you have to make all these decisions.

Kevin Larson

We would, we have, we absolutely have, and we told them, we don't expect that they are going to come out with some definitive announcement before August 31, which is when we would have to elect a Springerville option. So don't expect to have the clarity by then, but again the process isn't over on August 31, where we will still be negotiating with the RFP submitters and we might well still be negotiating with some of the Springerville owners. So we have made it very clear that a decision is important here because it effects our resource planning and it's going to affect cost of customers for years to come. And I will say, the commission understands that, they have been very clear that they hear us and they hear some of the comments from rating agencies and equity analysts as well.

Chris Ellinghaus - Williams Capital

One last thing Kevin. We had some discussion before about how you saw seasonality in the backend of the year. Can you just refresh our memory what you had said previously. And was there anything in the TEP case that would change how we think about the seasonality of earnings in terms of the rate design or anything?

Kevin Larson

We did change; I guess there are two things that changed. I think we changed the summer months, I think previously the summer included October, but now under the new rate structure I believe it only goes through September. And I think there are also the difference between the two rates, the summer rate and winter rate has gotten to be a little bit tighter. So I think that you probably see a little bit more benefit I guess overall on a relative basis in the winter months than you did previously.

Operator

Our next question comes from the line of Brian Russo with Ladenburg Thalmann. Please proceed with your question.

Brian Russo - Ladenburg Thalmann

Just the Springerville one purchase option is another scenario you don’t exercise it and you possibly accelerate an acquisition of emerging gas plant to satisfy your needs in 2015?

Paul Bonavia

That is a scenario, or that we do some combination of the two.

Brian Russo - Ladenburg Thalmann

Because you’ve got multiple leases, you can increase your ownership above 60% but own less than 100% and fill in that delta with some merchant generation?

Paul Bonavia

That’s correct. And the merchant generators, they’re out there. We’re in contact with them. We know them. They know us. So those discussions are there to be had.

Brian Russo - Ladenburg Thalmann

I realize the bidding process is confidential. But, have there been any recent transactions to compare the dollar per KW on a gas plant sale versus the $470 KW that would buy Springerville for?

Paul Bonavia

With respect to the gas plant so I think Salt River project bought one of those units out in west to Phoenix and I think they paid about $600 a kilowatt for the combined cycle plan. But each of these plans is unique. They all have different operating characteristics, different vintage. And I don’t know what is behind that $600 number of the Salt River project paid. And when you look at the production cost, the all in production cost of the gas plant, the capital cost is important. But when you’re doing evaluation model, as you know Brian, fuel cost and the fuel forecast always drives that model considerably. And so, tell me what the price of natural gas is going to be for the next 20 years and I’ll tell you what the right unit is for our fleet.

We’re going to be making this decision based on trying to bring down the risk in our portfolio. We don’t want all of our eggs in the same basket. So some combination of assets and fuels is probably the right thing for us to do given the uncertainty of fuel prices, federal environmental policy and then we have this shorter term concern about the commissions de-regulation include.

So again we’re going to be looking at a risk adjusted portfolio balance here.

Brian Russo - Ladenburg Thalmann

And just to make sure I’ve got the timing correct. On August 31st or by August 31st you have to notify the lesser of your intent on Springerville, is that accurate?

Paul Bonavia

If we intent to exercise a purchase option or a lease extension option, we have to give notice of that exercise, not later I think than August 31.

Brian Russo - Ladenburg Thalmann

So will this be disclosed in an 8-K for the investment community?

Paul Bonavia

I would expect it would, yes.

Brian Russo - Ladenburg Thalmann

Okay. And if you pursued not, I mean, is there a scenario where you just do nothing?

Paul Bonavia

Yes, there is a scenario where we maintain the 14% ownership and decide not to elect to purchase option. And in that case, Brian, we certainly wouldn’t be doing nothing we would just be pursuing different assets for our generating portfolio. We have to have capacity for our customers and we’re not sitting on a whole bunch of excess capacity here, especially with the prospective Rosamond which will sort of take up the slack for a decision on our part to led a wholesale agreement expire. So we need capacity. We don’t want excess capacity. We’re a little bit short now. That’s not a place, bad place to be we think in this current market. So if we don’t exercise on one or all of the Springerville lease parcels, it doesn’t mean we’re doing nothing it just means we’re going down a different path.

Brian Russo - Ladenburg Thalmann

Understood, and then you mentioned early you’ve got the wholesale contract that’s expiring in ’15 and that would big time-well when Rosamond comes on. But, how would you get recovery of that? I mean, it will just look like a wholesale contract or, I mean, Rosamond in theory would be a retail customer?

Paul Bonavia

It’s a retail customer and there the revenues would be based on the currently existing retail rates. It would just fall into retail revenue and we just finished a rate case so we would expect the current rate still to be in effect.

Brian Russo - Ladenburg Thalmann

Right, okay. So you get the retail margin from the sales but in theory that capacity is not in rate base yet.

Paul Bonavia

When you have a wholesale retail allocation in the retail rate making process, they will take a certain amount of capacity investment, and allocate that to wholesale which reduces your retail rate base that too would remain in effect, that wouldn’t change until the next rate case then we would look to bring those assets into the retail rate base. So, the rates are based on a cost structure from the test year and on the elements of our negotiated settlement, those rates and the rate base supporting them would stay the same until the next rate case.

Brian Russo - Ladenburg Thalmann

And then just lastly just remind us of your dividend policy or what of the year is the divided reviewed for an increase?

Paul Bonavia

Normally, reviewed in February that’s what we expect it to do this time around you know our express policy has been 60% to 70% payout ratio range and Board reaffirmed that this past February that is in the policy, we reviewed in February but that’s what it is as we’re talking right now and Brian you can, and in deed I know you have done the math to see based on your forecast where we are in that payout ratio range for 2013 and then ’14 and beyond.

Operator

(Operator Instructions). Our next question comes from the line of (inaudible). Please proceed with your question.

Unidentified Analyst

Anyhow I have a big picture question for Paul and it’s really to discuss the earnings path going forward because there is a lot of moving parts in the UNS story or specifically the [Tusan] story and I just would ask you to summarize the path of earnings going forward. Starting with the second half of 2013, I guess you chosen not to give us guidance for 2013 and you give us 2014 guidance in the next conference call. If you could please sir, give us some summary of the earnings path going forward, the positives and the negatives for the second half of ’13 as well as next year and ’15 and ’16.

Paul Bonavia

Yes. And you know we do expect to come out with ’14 guidance probably after the third quarter and it might be timed around the EEI financial conference somewhere in that ball part. As far as earnings prospect for the next few years and Kevin is here to launch in with learn guidance on what I might say here but, you know what’s in our rate case, if you make a reasonable and we’re pretty conservative about sales forecast, that are reasonable sales forecast and applied a new rate structure with the various adjusters and rate design modifications that we were able to negotiate that takes you down the path of earnings growth over the next couple of years. O&M for the next couple of years is going to be something we’re working on right now because a lot of the O&M impact is driven by schedule overall plant maintenance averages and we have fairly full schedule of plant maintenance for 2014 and 2015, so we’re in the process of reviewing the timing of that right now. But, we expect to be able to control O&M appropriate lead of level of sales as we’ve done for the several years.

Then you have the factor of (inaudible) mine coming in, if that happens in 2015 or beyond obviously that is going to be a boost to earnings and will help us offset, cost increases and increased depreciation from our rate base investment. You know what our investment path looks like, I like the way our curve looks as we’ve disclosed it in that, we are adding the rate base but we’re adding at a nice manageable moderate financeable pace and our rate base investment is spread across the value change that we don’t have single big investments that bring high risk or political controversy or for some other reason have a bull's eye painted on them.

So we have a nice measure but increasing rate base investment, we have a spread around the value chain which reduces the risk of rate base growth and then we have layered on top of that question of what asset mix we’re going to pick from Springerville one, from the RFP process to put together assets to serve our customers and that one is where the highest level of uncertainty is right now because we are right in the thick of those decisions today. So what does that translate into for an earnings path? We will give you the drivers and the sensitivity factors but it’s a pretty reasonably predictable operating path over the next few years. We expect some modest sales growth particularly if the economy behaves the way the economist say it will. We’ve got the TEP rate case in effect. We may well have new rates in effect for UNS Electric which will perhaps contribute some additional growth. We will keep you posted on that. We have the steady rate base growth and all the pieces are there.

Unidentified Analyst

What about the negatives to earnings, over the next several years? What do you see there?

Paul Bonavia

Well again rate based growth between rate cases always affects earnings. As you know it droves off depreciation and it requires financing expenses to be incurred. So that’s one thing but you can look at the sensitivities on that and track it in your modeling. What other negatives are out there, well, we and every other company in our industry are reassessing our long term sales growth forecast. No big surprise there. I think everybody is in the same position, because the underlying – you asked a big picture question. And the big picture response, the underlying correlation between GDP growth and electricity conception or natural gas consumption for that matter is different than it was a few years ago. Instead of being one plus correlation, it’s now less than a one-to-one correlation. So that’s the negative. Kevin, what am I missing here, that’s a big picture item that Maurice is calling for.

Kevin Larson

Yes Paul, you have touched on all of them, and just the O&M. I mean that’s always an issue, Maurice, and we’ve been very fortunate, and closely managed our O&M and mobilized two, three, four years, but there is always cost pressure. Where there is additional regulation, additional scope changes in terms of our business, something that we have to manage around, that put pressure on O&M. So certainly if we anticipate that sales growth will start to pick up and if it doesn’t, it will make it even more difficult for us to manage and contain that O&M expense. I think we are able to do it. But I think that’s always a big focus, I mean certainly from the big picture standpoint has been to manage O&M.

Unidentified Analyst

Yes, what about the lease payments? You get the kind of capacity payments on these leases, and they go away with the leases, do they not? But do they not go away if you continue part of these leases?

Kevin Larson

Yes, there is a lease expense that the company incurs under the very three different leases that the company has and certainly the largest one relates to Springerville unit 1, and we anticipate to the extent that we didn’t, if we bought the asset, or didn’t buy it at all, and did not continue with the lease structure, that lease expense will disappear. And the lease expense related to Springerville unit 1 that currently go through our income statement is probably right around $30 million on an annual basis. But that’s declining overtime.

Operator

Ladies and gentlemen, there are no further questions at this time. I will now turn the call back to you.

Paul Bonavia

Thank you so much for joining us and thanks for your patience. As we said earlier, we are in the thick of resource decisions. We'll keep you posted on that but we see a lot of alternatives available to us and we are working very hard to pick the right balance. We want to manage down the coal risk in our portfolio. We want to broaden the balance. But we are going to do so at the lowest cost possible, given all the alternatives. We’ve had a commission that is supportive of coal and we’re mindful of that as well. So please stay tuned. We will keep you posted. And in the meantime it’s hot and too sunny. Thanks so much.

Operator

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation, as you please disconnect your lines. Have a great day.

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