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UNS Energy Corporation (NYSE:UNS)

Q4 2012 Earnings Call

February 26, 2013, 11:00 am ET

Executives

Paul J. Bonavia - Chairman & CEO

Chris Norman - Manager, Investor Relations

Kevin Larson - SVP & CFO

Analysts

Kevin Cole - Credit Suisse

Paul Fremont - Jefferies & Company

Scott Senchak - Decade Capital

Brian Russo - Ladenburg Thalmann

Operator

Good morning and welcome to the UNS Energy Year-End 2012 Earnings Conference Call. Today’s call will be hosted by Paul J. Bonavia, UNS Energy’s Chairman and Chief Executive Officer. All lines have been placed on-mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions)

Now, I would now like to turn the call over to 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 financial results for 2012. Joining me on the call today are, Paul Bonavia, UNS Energy’s Chairman and CEO, and Kevin Larson, our 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’ll open up the call up for Q&A.

Now, I’ll turn it over to Paul.

Paul J. Bonavia

Thanks, Chris and thanks everybody for joining us today. This morning we reported that UNS Energy’s Board of Directors’ declared first quarter 2013 dividend of $0.435 per share. The Board also reiterated our long-term dividend payout ratio target of 60% to 70%. We also reported that US Energy’s net income for 2012 was $91 million or $2.20 per share on a fully diluted basis. By contrast, in 2011 we reported net income of $110 million or $2.75 per diluted share.

I would like to highlight a few items that affect the comparability of our 2012 and 2011 results. First, in July 2012, Springerville Unit 3 experienced an unplanned outage. TEP operates that unit on behalf of Tri-State, and we can earn operating fees and performance bonuses for doing so. That outage caused TEP to miss certain performance targets in 2012. As a result, 2012 earnings per share reflect a reduction of approximately $0.05 per diluted share.

In the fourth quarter of 2012, we partially wrote-off assets related to a proposed transmission project between Tucson and Nogales. The write-off was occasioned by the likelihood that we will abandon the project as well as a provision in TEP’s pending rate case settlement agreement regarding recovery of cost related to that project. The write-off reduced 2012 diluted earnings per share by approximately $0.07.

And finally, I would like to remind you that the results in 2011 included a gain of approximately $0.11 per diluted share related to the settlement of a transmission dispute with El Paso Electric. Excluding those items, earnings for 2012 were approximately $2.32 per diluted share compared with $2.64 in 2011.

Before we move past 2012, I do think it's important to summarize a few of our notable achievements. We once again delivered earnings within our stated guidance range. The effects of slow economic recovery, energy efficiency and distributed generation on our retail energy sales as well as an outdated retail rate structure and TEP created significant challenges in 2012. We responded to the ongoing pressure on margins by identifying operating efficiencies and process improvements.

Consolidated base O&M in 2012 was $266 million or $4 million below the target we set at the beginning of the year. And if you go back to 2009, the first full-year of TEP’s last retail rate increase, 2012 O&M was 1.5% or $4 million lower than it was in 2009.

Our track record of cross containment didn’t compromise safety or service reliability. Our continuing emphasis on safety led to a 19% reduction in our OSHA incident rate in 2012 versus 2011 and I should note that our 2012 incident rate was about half of what it was in 2008. Service reliability in 2012 was also excellent, as our average customer outage time fell by over 20% compared with 2011 and TEP’s power plant availability improved by three percentage points over 2011, reaching an average availability factor of nearly 90% in 2012.

We also took advantage of favourable capital market conditions during the year and entered into the market on three occasions issuing low cost, fixed rate debt. We use the proceeds to redeem higher cost debt and to repay outstanding revolver borrowings. The rating agencies took note of our gradual improvements in leveraged cash flow metrics and regular inventory environment. Earlier this year, Moody’s placed UNS Energy and TEP on positive outlook, while raising the ratings on UNS Gas and UNS Electric by one notch to Baa2.

On the regulatory front, we received a timely and constructive rate order for UNS Gas in April of 2012. The commission authorized the base rate increase of $2.7 million as well as a partial decoupling mechanism and in July of 2012 we filed an application for TEP’s first non-fuel base rate increase since 2008. That filing along with the testimony of ACC staff created a foundation that allowed several key stakeholder groups to enter into a settlement agreement.

One of our primary objectives for 2013 is to obtain commission approval of the settlement agreement during the second quarter. We believe the settlement fairly balances the interest of all our customers and stakeholders while also supporting TEP’s long-term financial strength. The proposed settlement provides several tangible and durable benefits including a non-fuel base rate increased of $76 million which provides TEP with an opportunity to earn a fair and reasonable return on its rate base including the $500 million of rate base additions between 2006, our last test year and 2011.

Fuel cost adjustments are also in the settlement agreement they would mitigate the bill impact for our customers, if the settlement is improved, the average residential customer would experience an average increase of less than $3 on the monthly bill. They also have a partial decoupling mechanism in the settlement agreement it’s knows as a Lost Fixed Cost Recovery mechanism or LFCR. It would allow TEP to recover lost fixed cost resulting from the commission’s energy efficiency and distributed generation requirements. The LFCR would be subject to a cap limiting year-over-year rate increases to 1% of TEP’s retail revenues.

A plan for energy efficiency would treat expenditures on programs similar to other rate based resource investment allowing TEP to return on its investment in energy efficiency between rate cases. We have a rate mechanism also proposed called the Environmental Complaints Adjuster or ECA under which TEP would earn a return on and off qualifying environmental investments that are placed in service between rate cases and recover the associated operating expenses and taxes. The ECA would be subject to a cap of 0.25% of TEP’s retail revenues.

And finally, importantly to us we have rate design changes including the consolidation of a number of retail rates we offer customers as well as an increase in the fixed customer charge from $7 per month to $10 for most residential customers. I would like to take a moment to extend our thanks to the commission staff, the residential utility consumer office and the numerous other settling parties for finding common ground that led to the settlement agreement.

Hearings before our commission administrative law judge are scheduled to begin on March 6. Following the conclusion of the hearings, the judge will issue a recommendation which will then be subject to commission approval. The settlement agreement contains a provision under which the parties to the agreement will ask the commission to issue a decision so that new rates can be effective by July 1.

In other regulatory matters, UNS Electric as required in its last rate order filed a rate case application in December 2012. UNS Electric is requesting a non-fuel base rate increase of $7.5 million or 4.6% over adjusted last year revenues. The requested ROE is 10.5% with a capital structure of 53% equity and 47% debt.

UNS Electric also proposed a transmission cost adjustment mechanism that would adjust base rates to reflect the current transmission rate. The filing also proposes a lost fixed cost recovery mechanism and an energy efficiency resource plan similar to those in TEP’s pending settlement agreement.

Intervener testimony is due June 29, formal settlement discussions can begin on July 22 and ALJ hearings are scheduled to begin on September 3.

Moving to environmental matters, I'm sure many of you are following the ongoing discussions between the State of New Mexico, EPA and PNM regarding the San Juan generating station. As a reminder, TEP is a 50% owner of Units 1 and 2 for approximately 340 megawatts of capacity.

On February 15, the State of New Mexico, PNM and EPA reached a non-binding agreement to pursue a different course from the federal plan. As you recall, the federal implementation plan for regional haze would require the installation of selective catalytic reduction technology on all four San Juan units.

The revised plan would include among other things the retirement of San Juan Units 2 and 3 by December 31, 2017 and the installation of selective non-catalytic reduction or SNCR technology on San Juan Units 1 and 4 by January 2016.

TEP estimates its share of capital investment to install SNCR in Unit 1 would be approximately $25 million. The modified plan would require several actions by third parties before moving forward as well as approval by our board of directors and the Arizona Corporation Commission.

If San Juan Unit 2 is retired by December 31, 2017; TEP would request commission approval of a plan to replace that capacity including recovery over a reasonable time of all cost associated with the early retirement of that unit. At December, 2012; the book value of TEP’s share of San Juan Units 1 and 2 was $217 million.

Finally, I would like to touch briefly on our local economy. Tucson’s unemployment rate in December 2012 was 6.9%, down from 7.8% in December the year before. The economist at the University of Arizona believes Arizona’s economy recovery will gradually accelerate in 2013.

Current estimates point to 2014 and 2015 before Arizona experiences trend growth similar to long-term historic averages. Population growth in Tucson is expected to be just below 1% this year, increasing to 1.4% by 2015. In Tucson, housing market active inventories in January 2013, this year was 7% below January of the year ago, the month of inventory declined to 5.6 to 5.0 and the median prices sold homes increased by 17%.

Now, I would like to turn the call over the Kevin, who will provide more detail on our 2012 results and our outlook for 2013. Kevin?

Kevin Larson

Thank you, Paul and thanks to everyone again for joining us today. As Paul mentioned, our financial performance in 2012 was in line with our expectations in the guidance. First, I will explain some of the key drivers for UNS Energy 2012 performance and then I'll get into the factors of what will impact 2013 earnings.

If you’d like to follow along, please refer to slide two of the presentation that was furnished on our 8-K this morning and posted on our website. The slide shows the factors that impacted earnings between $2.75 per share earned in 2011 and $2.20 per share earned in 2012.

Moving in first to retail sales, in 2012, TEP’s total retail sales were 9,265 gigawatt hours, that's 0.7% below 2011 levels. Full-year 2012 weather was slightly warmer than 2011. Cooling degree days in 2012 were 1.8% above 2011. However, a milder summer relative to the 2011 negatively impacts the sales levels. The lower sales level impact TEP’s retail margin. TEP’s retail margin of $544 million was $7 million or $0.10 per share below 2011.

If we compare the 2012 weather pattern to the average weather pattern over the last 10 years, cooling degree days in 2012 were 4.9% over the 10-year average. We estimate this warmer weather in 2012 relative to the historical average to benefit the retail margin by approximately $5 million.

At UES companies, the overall retail margins in 2012 were less than 1 million lower even compared with 2011. UNS gas retail sales were negatively affected by mild winter weather. UNS Electric benefit from hot summer weather compared to last year.

Turning to our two wholesale contracts, long-term wholesale margins for 2012 on our Salt River Project and Navajo Tribal Utility Authority contracts totaled $5 million. In 2011, the margin totaled $13 million; the difference translates to year-over-year earnings decrease of $0.12 per share. The decline in margin is attributable to the SRP contract, Salt River Project contract.

Prior to 2011, we received a demand component from SRP. Beginning in June 2011, the contracted prices sorely upon market prices and at the beginning of 2012 we estimated based on the forward power curve a margin of $8 million, the power prices declined slightly throughout the year. The other year-over-year drivers, our UNS consolidated base O&M in 2012 was $5 million lower than the $271 million we achieved in 2011.

The lower O&M is due to the part to the success of our cost containment efforts including lower reliance and outside services and closely managing labor costs. This is a $0.07 positive driver in diluted earnings per share. As expected, consolidated depreciation amortization expense was $12 million higher in 2012 due to increase in plant and service.

This negatively impacted diluted earnings per share by about $0.18 relative to 2011. And as Paul mentioned, results in 2012 were negatively affected by unplanned outage at Springerville Unit 3. The outage reduced TEP’s 2012 pretax income by approximately $3 million or $0.05 per diluted share. And TEP rolled out $4.5 million of transmission rated assets; and negatively impacted 2012 earnings by $0.07 per diluted share.

Lastly in 2011, TEP recognized $7 million pretax gain related to the settlement of a transmission dispute between TEP and El Paso Electric. This equates to negative year-over-year driver of $0.11 per share on a diluted basis.

Turning to 2013 due to the uncertainty surrounding the resolution of TEP’s rate case including the timing of when new rates will be implemented, we are not currently providing guidance for earnings or operating cash flows. However the 8-K we filed this morning contains drivers and sensitivities that could impact our earnings in 2013 as well as certain drivers for 2014 and ’15. And some of the key factors include and we estimate that TEP’s 2013 retail sales will be 9211 gigawatt hours. That's 54 gigawatt hours lower than 2012. This represents a year-over-year decrease of 0.6%, but on a normalized basis we expect 2013 retail sales to be 0.2% higher than 2012.

Regarding our long term wholesale contracts, we expect to see some slight upside given the forward power curve, in particular the SOP contract which is based on market prices. We estimate 7 million of total long term wholesale margins in 2013, which should be 2 million above the level we achieved in 2012. Forward curve is at 36 per megawatt hour from our on peak for 2013. (Inaudible) which is primarily a fixed price contract is minimally impacted by changes in wholesale power prices.

Turning to base O&M, since 2009 we've kept annual consolidated base O&M around 270 million, and as mentioned earlier in 2012 UNS consolidated base O&M was 266 million, 5 million below our 2011 amount of 271 million. We are proud of our employees [fully] managed costs and a low to negative sales growth environment, while maintaining safety and reliability. We are confident that we have a process in place continuing and effectively manage operating costs.

Year-to-year changes in O&M are related to the timing of planned outages, unforeseen events such as unplanned outages and various cost pressures. We estimate 2013 consolidated base O&M at $273 million which is approximately 2.6% over 2012. This estimate assumes an August 1 effective day of new rates of TEP related to the post-settlement agreement.

For depreciation and amortization, we estimate that the UNS Energy Consolidated level total expense of 180 million for 2013. This is 3 million higher than 2012. The estimate is based on two key factors. First a provision in TEP’s proposed settlement agreement if ultimately approved extends the depreciation alliance of its utility assets. This lowers the depreciation rates, which helps to reduce TEP’s overall retail revenue requirement and try and mitigating the bill impact on our customers.

Second an offsetting factor to the lower depreciation rate is an incremental depreciation due to new plant added in 2012. The year after the TEP rate case test year of 2011. We also expect to see some benefit in earnings from lower total interest expense. We estimate direct debt interest expense at UNS consolidated will be flat from 2012 to 2013 and approximately $66 million. The capital lease interest expense have declined 10 million in 2013 relative to 2012. In total, we expect consolidated interest expense to be approximately $96 million in 2013.

Another item that’s going to put some downward pressure on earnings includes higher property tax, just given the addition of a larger asset base that we now have. With that, I will turn it back over to Paul for Q&A.

Paul J. Bonavia

Thanks, Kevin. Do we have questions?

Question-and-Answer Session

Operator

Our first question comes from the line of Paul Fremont with Jefferies & Company. Please proceed with your question.

Paul Fremont - Jefferies & Company

My first question is, you're looking at population growth that’s roughly a 1%, but on [weather] normalize basis, it looks like you are projecting sales to only increase by less than 0.2% in 13. Should we assume that the difference between the population growth number and that number is energy efficiency and those types of measures?

Paul J. Bonavia

Yeah, I think its energy efficiency and steps that our industrial customers take to manage their demand.

Paul Fremont - Jefferies & Company

So, for modeling purposes, then, since you are essentially compensated for energy efficiencies, should we be modeling something closer to the 1%?

Paul J. Bonavia

Yeah, I think the sales should probably model in accordance with the estimate, particularly if the settlement is improved, we begun to get a revenue stream from the loss fixed cost recovery mechanism that would offset that or would add to that.

Paul Fremont - Jefferies & Company

And then, does the settlement provide for equal percent increase across all customer classes it seems that’s what the ACC testimony was implying?

Paul J. Bonavia

It’s intended to approximate equality, but one of the groups who have historically had the hardest time not just in Arizona, but everywhere are the small commercial customers and this settlement would begin to move them closer to parity with the other rate classes relative to their cost profile, which we think is a good thing for economic development that’s where jobs are created.

Paul Fremont - Jefferies & Company

Can you provide us with any type of an update on [Rosemont]. I guess the Pima County gave them the L permit a couple of weeks ago, where do things current stand with the forest service and is there any way to project the timing of the decision of the forest service?

Paul J. Bonavia

Yeah even the forest service declines to estimate when the forest service will be finished. Paul you are right that Rosemont did get its air permit, actually got it from the State of Arizona which is taken over the air permitting portion of the festivities. You remember that the forest service was on a schedule to try and get record its recorded decision embodying the final environmental impact statement out by the end of last year.

Back in November when they announced they would not make the deadlines, they said we would not get into the business if predicting when it will be, but at that time they said they were 85% to 90% done with their work that they had some additional modelling to look at and some consultations to hold.

So all of that said [Rosemont] has got seven of their major permits they need this recorded decisions and the last major permit following that is the water permit [plaster] from the army core of engineers but that will await the record and decisions from the port sub, who knows what that means, if you add [Rosemont] they will tell you that they expect to have something from the forest services in the first half of the year.

Paul Fremont - Jefferies & Company

And then last question from me is, does the settlement impacted timing of the final rate order you had 13 sort of guidance, I think has the provisory there that you are assuming affective data on August 1, 2013, does that change on the settlement?

Paul J. Bonavia

Well the parties to the agreement agreed to use their reasonable best efforts to try and get rates in affect by July 1, so we pick up a full month if that holds up. And you know the commission has the last work and when it finishes its work. We are on the schedule that would enable that to have July 1.

Operator

There are no further questions at this time. (Operator Instructions) and our next question comes from the line of Scott Senchak with Decade Capital, please proceed with your question.

Scott Senchak - Decade Capital

Just a quick question for you, you mentioned property tax as a driver in the ‘13, and I was just wondering is that taken in to account in the base O&M or is this a separate line item we should think about from ‘12 to ‘13?

Kevin Larson

Sure, and this is Kevin, there is a separate line item. Other taxes excluding income tax I think is the main relying on the income statement. So separate from O&M.

Scott Senchak - Decade Capital

And you don't have that in the drivers that you've listed out on the exhibits, is that correct?

Kevin Larson

We do not.

Scott Senchak - Decade Capital

And is there any order of magnitude you can give us there, is it a big driver, is it…

Kevin Larson

I think if you look back historically, you probably, it's increasing given the level of added assets that we brought on, maybe its $2 million to $3 million a year.

Operator

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

Brian Russo - Ladenburg Thalmann

Just on the depreciation and amortization expense, assumption in ’13, could you break that down you know what is related to the reduction in the TEP rates and then what is related to just year-over-year net plant additions?

Kevin Larson

Yeah, I guess in terms of 2013, the new rates I think would benefit TEP by approximately a negative $4 million. And so I guess the offset is of course we are adding new plant in 2012 which is post last year embedded balance is going to be greater than the $4 million reduction which puts some pressure on our overall depreciation expense.

Brian Russo - Ladenburg Thalmann

So it looks like that plant is $7 million?

Kevin Larson

Yes.

Brian Russo - Ladenburg Thalmann

And I'm just curious do you have any idea what percent of your capital budget is captured in trackers or other mechanisms with this TEP rate settlement?

Kevin Larson

Brian I don't know the answer to that question. And we are still trying to sort through all the different components of this settlement agreement. We just have to pin that down exactly.

Brian Russo - Ladenburg Thalmann

Also, could you kind of discuss base CapEx or maintenance CapEx versus depreciation?

Kevin Larson

Company at least for two Tucson electric power company, CapEx on an annual basis is probably averages $300 million to $325 million per year. Depreciation in Tucson electric power company is roughly a $150 million per year. So on balance, we expect over the next few years to continue to add a rig base to TEP.

Brian Russo - Ladenburg Thalmann

And can you disclose what your (inaudible) rate is for 2013 or what's included in the settlement?

Unidentified Company Representative

The (inaudible) rate is negative, it’s actually a credit of 0.1388 and that sense and the base fuel rate is 3.2335. So you combine those two and you get a total fuel cost of 3.0947. Sorry for the significant digits.

Brian Russo - Ladenburg Thalmann

3.0947.

Unidentified Company Representative

Yeah.

Brian Russo - Ladenburg Thalmann

Okay and what the UNS Electric and Gas earned ROEs in 2012?

Unidentified Company Representative

For the gas or electric?

Brian Russo - Ladenburg Thalmann

Yes.

Unidentified Company Representative

Yeah, for the gas company I'm sorry for the electric company it’s probably is in the low double-digits and for the…

Brian Russo - Ladenburg Thalmann

Single-digits I'd imagine although double-digits…

Unidentified Company Representative

It’s right about 10%.

Brian Russo - Ladenburg Thalmann

Okay.

Unidentified Company Representative

And then for the gas company, it was for 9.5%.

Brian Russo - Ladenburg Thalmann

Okay and then, previous disclosures of approximately $500 million of accumulating net plan during 2012 and 2015. Is that still good kind of proxy?

Kevin Larson

It's probably a little bit higher at this point. I mean Paul referenced on his comment that we're going to reduce, or slightly reduce the amount of CapEx that we spent at the San Juan plant. His favorite number being close to $200 million, it's more likely the $25 million and so we're seeing the CapEx between 2013 through 2016 on a consolidated basis, CapEx is dropping during that time period by about $230 million. So there is some benefit as a result of the San Juan change to our overall CapEx growth.

Brian Russo - Ladenburg Thalmann

Okay, and then I guess it picks up again when you have to deal with the capacity shortfall from the retirement in ‘17?

Kevin Larson

Yeah, that’s exactly why I… At this point, we're not assuming that we're adding other capacity but there is certainly something the company will consider if the San Juan situation plays out as Paul explained.

Brian Russo - Ladenburg Thalmann

Okay, and then just back on the $500 million with the adjustment of course. Did that previously capture the Springerville 1 acquisition?

Kevin Larson

Yes, it was picking up. The $500 million, it did include the Springerville, Springerville 1 we purchased in 2012.

Brian Russo - Ladenburg Thalmann

It did?

Kevin Larson

Yes.

Brian Russo - Ladenburg Thalmann

It’s inclusive?

Kevin Larson

Yes.

Operator

(Operator Instructions) And our next question comes from the line of (inaudible) from Luminus Management. Please proceed with your question.

Unidentified Analyst

Just looking at the drivers for the quarter, there is a pretty noticeable I guess benefit from other line item changes, can you help me understand that what was?

Paul J. Bonavia

Will you give me a particular reference what’s your looking at?

Unidentified Analyst

Sure. I am looking at page four, of the supplemental disclosure and there is $4.7 million after tax benefit. Just seems like pretty big number I would like to understand what that’s made up of?

Kevin Larson

At the top of the head, I don’t know the details in that particular line item but we can get back to you on that.

Operator

Our next question comes from the line of Kevin Cole with Credit Suisse. Please proceed with your question.

Kevin Cole - Credit Suisse

As Dave said in follow-up all question on the 2013 guidance slides I guess, I don't see a page number here, but we should believe that this guidance includes everything with exception to the rate case revenue change in the property tax, otherwise it’s inclusive of all the other 2013 drivers?

Unidentified Company Speaker

Yeah it picks up the major drivers. That’s right.

Kevin Cole - Credit Suisse

Okay. And then if we take this account like roll it into 2014 and ‘15 are there any note adjustments except for, say it’s like you said O&M should stay flat to grow with volumes, I believe is that correct?

Paul J. Bonavia

Yeah, I think we have been able to manage as we level of O&M change close to the change in sales has been relatively flat over the last few years. Things that can swing that could be planned outage at power plants, but we expect to again closely manage our O&M cost.

Kevin Cole - Credit Suisse

And then depreciation should kind of track this real inflation rate and then upon purchase of (inaudible) that’s the package used and then we will have a true-up in depreciation on roughly January 1 to 15, is that right?

Paul J. Bonavia

I am not sure what you mean by true-up in depreciation.

Kevin Cole - Credit Suisse

I guess it will be factored into?

Paul J. Bonavia

Yeah, that is correct.

Kevin Cole - Credit Suisse

Okay, and then for funding the CapEx program, are you thinking of, it looks like you maybe $100 million of debt each year and then at what point do you issue equity to fund against the CapEx is outlined as well as distributable?

Kevin Larson

Yeah, at this point I think you are correct in terms of the level of additional debt that we may need for the companies to support CapEx. I think in terms of the timing of equity and the amount of equity that’s still kind of unknown at this point, because there are just so many factors moving around. As Paul mentioned we get this San Juan that’s going to completely play out, we have better understanding on that, Springerville Unit 1 we haven't finalized our decision to purchase that and certainly if we decide to purchase that in total that’s like $230 million purchase. So I think until we have a better understanding of those key capital investments at this point, we don't have any immediate plans to issue equity but we’ll closely monitor it as the year plays out.

Kevin Cole - Credit Suisse

You have if I'm looking at just like your general equity needs of trying to factor your [paid] earnings, do you have any big deferred taxes (inaudible) depreciation that are coming in the last couple of years.

Kevin Larson

No I don't think we do.

Kevin Cole - Credit Suisse

Okay, then so broadly I should assume that need to sourcefully the company should stick around the 43% equity there. And so if you do a transaction I should assume that you’ll keep the balance sheet somewhat cheered up.

Kevin Larson

Yes, I think that's true. I think again we will want to continue. We will certainly be able to strive to hold the 43% equity at Tucson Electric Power Company, but we also want to continue to improve the credit quality of the businesses over time and so it could be some amount of equity greater than that for the next few years. But that's the (inaudible) side on just how much that might be.

Kevin Cole - Credit Suisse

And then as the balance sheet stands today, I know what you know today might be forecast; as we get to 2015 timeframe and it looks like you might be able to stay out for let's call it a 2016 test year for TEP. Do you think you have the flexibility to lay the equity into last year..

Kevin Larson

That's certainly possible, we will be monitoring closely just the impact to our credit metrics and our ability to finance because I think that's possible.

Kevin Cole - Credit Suisse

And then with the San Juan with the unit 2, or unit 1 the one you expect a likely sale, what is the book value of that independently of the 2017.

Kevin Larson

It’s about [160 million].

Kevin Cole - Credit Suisse

And does Arizona have any precedence on like securitization or whether do you have plans for a shut down.

Kevin Larson

I don't know about securitization. I think that if we were to go to the Arizona Commission with a plan for replacement capacity for the retirement of unit 2 at San Juan one thing we would do is apply some excess depreciation that has accumulated to that unamortized balance. So it probably, the numbers are probably not going to be so extreme that we would be looking at things like securitization.

Kevin Cole - Credit Suisse

And then the settlement is currently struck with the mechanisms that are offsetting that are helping compensate for energy efficiency. What sort of revenue forecast would you speculate that would be for 2014 per se given the CapEx program that you have in place and the energy efficiency efforts?

Kevin Larson

The fixed costs (inaudible) our mechanism.

Paul J. Bonavia

Yeah I don't know the LSCR numbers right off the top of my head that cap gives you about a $9 million or $10 million and I think we will be below that cap for the energy efficiency resource plan if you are looking for how much we are going to be investing in those programs we estimate remember this is, we invest in one program and you start recovering it the next year. But this year the balance of this year will be around $17 million and then starting in 2014 it will be about $27 million to $30 million for the next couple of years after remaining to that pilot program.

Kevin Cole - Credit Suisse

So how does that math work? So the $17 million what should I assume that would flow into the revenue in the following year.

Kevin Larson

You should look at it just like it was any other rate based asset that was going in and being amortized and earning a return at a weighted average cost of capital and a five year amortization.

Kevin Cole - Credit Suisse

So once your Springerville purchase, does the fuel cost automatically roll in to the [PSA] or the fuel tracker?

Kevin Larson

The purchase are in fuel adjustment cost and it includes and now it will (inaudible).

Kevin Cole - Credit Suisse

And then with [Rosemont] do you have actually, so let’s say like ones it goes in to service there, once all these approvals are had, how long will it take to ramp to their 100 megawatts of load?

Kevin Larson

We only know what they say. They talk about a construction period of like 18 months. So I tend to assume a couple of years.

Kevin Cole - Credit Suisse

And has that clock started yet, the construction cycle does not or does the clock not start till the final approval is done?

Paul J. Bonavia

It doesn’t start until the final approval is done because among other things, the final approval will approve a plan of operations. There still could be some changes and that it will include conditions on [Rosemont] for mitigating environmental affects. They still don’t know exactly what their construction path looks like until they get their record decisions.

Kevin Cole - Credit Suisse

Last question. So with the remaining floating debt that you have, are you still in the opportunity to swap out of that in to fixed rate?

Paul J. Bonavia

We do see some opportunities there. The amount of floating rate debt exposure that we have at this point is about $165 million and that’s substantially down from what we had just a few years ago, which probably would have been an excess of $300 million. So on balance, I think we're pretty comfortable with the amount of variable rate debt that we have, but separate from that we are looking US of debt outstanding, fixed rate debt outstanding that can be called to carve here in the near future. So we will be looking to see we could refinance that at a lower fixed rate. Certainly we’ll focus on ways that we can reduce our overall financing cost and also reduce the availability of our risk.

Operator

(Operator Instructions) We have a follow up question from the line of Brian Russo with Ladenburg Thalmann. Please proceed with your question.

Brian Russo - Ladenburg Thalmann

Just any, any idea what percent of annual sales or margins you capture from August 1 to the end of the year at TEP?

Paul J. Bonavia

Brian I can see what you are thinking in trying to come up with the percentage just hold on just a second. The thing it’s probably on 40% to 45%.

Brian Russo - Ladenburg Thalmann

Can be captured from August to December?

Paul J. Bonavia

Yes.

Brian Russo - Ladenburg Thalmann

Okay. And then that’s of sales or margins?

Paul J. Bonavia

That would be on the sales.

Operator

Mr. Norman there are no further questions at this time. I will now turn the call back to you please continue with your presentation and closing remarks.

Chris Norman - Manager, IR

Well, thank you all for joining us today.

Paul J. Bonavia

Thanks again.

Operator

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

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